Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-K, Received: 03/19/2008 17:30:33)
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-K

(Mark One)  

ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2007

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation)
  33-0968580
(IRS Employer Identification No.)

3020 Old Ranch Parkway, Suite 200, Seal Beach CA 90740
(Address of principal executive offices, including zip code)

(562) 493-2804
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
  Name of each exchange on which registered
Common Stock, par value $0.0001 per share   The NASDAQ Global Market

Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o     No  ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o     No  ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý     No  o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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

Large Accelerated filer  o   Accelerated filer  o   Non-accelerated filer  ý
(Do not check if a smaller reporting company)
  Smaller reporting company  o

         (Do not check is a smaller reporting company.) Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes  o     No  ý

         The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 29, 2007, the last business day of the registrant's second fiscal quarter, was approximately $198,544,285 (based on the closing price reported on such date by The NASDAQ Global Market of the registrant's common stock). Shares of common stock held by officers and directors and holders of 10% or more of the outstanding common stock have been excluded from the calculation of this amount because such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

         As of March 10, 2008, the number of outstanding shares of the registrant's common stock was 44,292,374.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's proxy statement for the 2008 Annual Meeting of Stockholders are incorporated herein by reference in Part III of this annual report on Form 10-K to the extent stated herein.




FORWARD LOOKING INFORMATION IS SUBJECT TO RISK AND UNCERTAINTY

        Certain statements in this report may constitute "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based upon current assumptions, expectations and beliefs concerning future developments and their potential effect on our business. These forward-looking statements are not guarantees of future performance and involve risks, uncertainties and assumptions that are difficult to predict. Actual outcomes and results may differ materially from what is expressed or forecast in these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in Item 1A. "Risk Factors." These forward-looking statements speak only as of the date they were made and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Words such as "expects," "intends," "plans," "projects,' "believes," "estimates," and similar expressions are used to identify these forward looking statements, but their absence does not mean that a statement is not forward looking. Forward-looking statements in this Form 10-K include, but are not limited to, statements regarding:

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PART I

Item 1.    Business.

Overview

        We are the leading provider of natural gas as an alternative fuel for vehicle fleets in the United States and Canada, based on the number of stations operated and the amount of gasoline gallon equivalents of compressed natural gas (CNG) and liquefied natural gas (LNG) delivered. We offer a comprehensive solution to enable our customers to run their fleets on natural gas, often with limited upfront expense to the customer. We design, build, finance and operate fueling stations and supply our customers with CNG and LNG. We also help them acquire and finance natural gas vehicles and obtain local, state and federal clean air rebates and incentives. CNG and LNG are cheaper than gasoline and diesel, and are well suited for use by vehicle fleets that consume high volumes of fuel, refuel at centralized locations, and are increasingly required to reduce emissions. According to the U.S. Department of Energy's Energy Information Administration (EIA), the amount of natural gas consumed in the United States for vehicle use nearly doubled between 2000 and 2007. We believe we are positioned to capture a substantial share of the growth in the use of natural gas as a vehicle fuel in the United States given our leading market share and the comprehensive solutions we offer.

        We sell natural gas vehicle fuels in the form of both CNG and LNG. CNG is generally used in automobiles and other light to medium-duty vehicles as an alternative to gasoline. CNG is produced from natural gas that is supplied by local utilities to CNG vehicle fueling stations, where it is compressed and dispensed into vehicles in gaseous form. LNG is generally used in trucks and other medium to heavy-duty vehicles as an alternative to diesel, typically where a vehicle must carry a greater volume of fuel. LNG is natural gas that is super cooled at a liquefaction facility to -162 degrees Celsius (-260 degrees Fahrenheit) until it condenses into a liquid, which takes up about 1/600th of its original volume as a gas. We deliver LNG to fueling stations via our fleet of 60 tanker trailers. At the stations, LNG is stored in above ground containers until dispensed into vehicles in liquid form.

        We serve fleet vehicle operators in a variety of markets, including public transit, refuse hauling, airports, taxis, seaports, and regional trucking. We believe the fleet market will continue to present a high growth opportunity for natural gas vehicle fuels. Some of the largest potential markets are seaports, airports, public transit and refuse hauling. For example, two of the largest seaports in the United States, Los Angeles and Long Beach, together have adopted a plan to mandate the use of alternative fuels for vehicle fleets serving those seaports, and other seaports are also considering alternative fuels. In addition, there is considerable room for growth in our key markets of public transit and refuse hauling, with approximately 19% of public transit buses and approximately 1% of refuse haulers currently using natural gas fuels, as stated by INFORM, Inc., a national nonprofit organization focused on environmental concerns (INFORM), and by the American Public Transportation Association.

        We generate revenues primarily by selling CNG and LNG, and to a lesser extent by building, operating and maintaining CNG and LNG fueling stations. We serve over 275 fleet customers operating over 14,000 natural gas vehicles. We own, operate or supply 170 natural gas fueling stations in Arizona, California, Colorado, Maryland, Massachusetts, Nevada, New Mexico, New York, Texas, Washington, Georgia, Wyoming and Canada. Additionally, we have formed a joint venture and are in the process of opening our first CNG fueling station in Lima, Peru.

        We own and operate an LNG liquefaction plant near Houston, Texas, which we call the Pickens Plant, capable of producing up to 35 million gallons of LNG per year. We are also in the process of building an LNG liquefaction plant in California. We expect this plant will be operational in the fall of 2008, assuming we do not experience significant construction delays. We anticipate this plant will

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initially be capable of producing up to 60 million gallons of LNG per year, and will be expandable to produce up to 90 million gallons of LNG per year.

The Market for Vehicle Fuels

        According to the EIA, the United States consumed an estimated 175 billion gallons of gasoline and diesel in 2006, and demand is expected to grow at an annual rate of 1.4% to 250 billion gallons by 2030. Gasoline and diesel comprise the vast majority of vehicle fuel currently consumed in the United States, while CNG, LNG and other alternative fuels represent less than 3% of this consumption, according to the EIA. Alternative fuels, as defined by the DOE, include natural gas, ethanol, propane, hydrogen, biodiesel, electricity and methanol.

        In recent years, domestic prices for gasoline and diesel fuel have increased significantly, largely as a result of higher crude oil prices in the global market and limited refining capacity. Crude oil prices have been affected by increased demand from developing economies such as China and India, global political issues, weather-related supply disruptions and other factors. Industry analysts believe that crude oil producers will continue to face challenges to find and produce crude oil reserves in quantities sufficient to meet growing global demand, and that the costs of finding crude oil will increase. Some analysts predict that crude oil prices will remain at high levels compared to historical standards. Limited domestic refining capacity is also expected to continue to impact gasoline and diesel prices.

        We believe that crude oil, gasoline and diesel prices that are high relative to historical averages, combined with increasingly stringent federal, state and local air quality regulations, have created a favorable market opportunity for alternative vehicle fuels in the United States and Canada. Natural gas as an alternative fuel has been more widely used for many years in other parts of the world such as in Europe and Latin America, based on the number of natural gas vehicles in operation in those regions. The Gas Vehicles Report estimates that there are approximately 150,000 natural gas vehicles in the United States compared to approximately 7.5 million worldwide as of December 2007.

Natural Gas as an Alternative Fuel for Vehicles

        We believe that natural gas is an attractive alternative to gasoline and diesel for vehicle fuel in the United States and Canada because it is cheaper, cleaner and safer than gasoline or diesel. In addition, almost all natural gas consumed in the United States and Canada is produced from U.S. and Canadian sources. According to the EIA, in 2006 there were approximately 43 billion cubic feet or 300 million gasoline gallon equivalents of natural gas consumed in the United States for vehicle use, which is nearly double the amount consumed in 2000. It is estimated that there are over 800 natural gas fueling stations in the United States, according to the list of available stations provided by the DOE's Energy Efficiency and Renewable Energy Agency, including stations in 46 states.

        Natural gas vehicles use internal combustion engines similar to those used in gasoline or diesel powered engines. A natural gas vehicle uses airtight storage cylinders to hold CNG or LNG, specially designed fuel lines to deliver natural gas to the engine, and an engine tuned to run on natural gas. Natural gas fuels have higher octane content than gasoline or diesel, and the acceleration and other performance characteristics of natural gas vehicles are similar to those of gasoline or diesel powered vehicles of the same weight and engine class. Natural gas vehicles, whether they run on CNG or LNG, are refueled using a hose and nozzle that makes an airtight seal with the vehicle's gas tank. For heavy-duty vehicles, natural gas vehicles operate more quietly than diesel powered vehicles. According to Deere & Company (John Deere), the decibels generated by running one diesel engine equal the decibels generated by running nine natural gas engines.

        Almost any current make or model passenger car, truck, bus or other vehicle is capable of being manufactured or modified to run on natural gas. In other countries, numerous makes and models of vehicles are produced from the factory to run on natural gas. However, in North America only a

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limited number of models of natural gas vehicles are available. Only Honda offers a factory built natural gas passenger vehicle, a version of its Civic 4-door Sedan called the GX. A limited number of other passenger vehicles and light-duty trucks are available through small volume manufacturers. These manufacturers offer current model vehicles made by others that they have modified to use natural gas and which have been certified to meet federal and state emissions and safety standards. Several GM and Ford models are now certified, including the Ford Crown Victoria, Ford E Van, Ford F Series Truck, and GM 6 liter and 8.1 liter vehicles that include pickups, vans, cargo vans, and trucks. We anticipate additional models will be certified in 2008. Modifications involve removing the gasoline storage and fuel delivery system and replacing it with high pressure fuel storage cylinders and fuel delivery lines.

        Heavy-duty natural gas vehicles are manufactured by traditional original equipment manufacturers. These manufacturers offer some of their standard model vehicles with natural gas engines and components, which they make or purchase from engine manufacturers. Cummins Engine Co., through a joint venture with Westport Innovations Inc., and others manufacture natural gas engines for medium and heavy-duty fleet applications, including transit buses, refuse trucks, delivery trucks and street sweepers.

        Heavy-duty natural gas vehicles manufactured by traditional original equipment manufacturers include:

Trucks

    Autocar

    American LaFrance

    Crane Carrier Company

    Kenworth

    McNeilus

    Peterbilt

    Sterling

Shuttles and buses

    Blue Bird (school buses)

    ElDorado National (shuttles and transit buses)

    New Flyer (transit buses)

    North American Bus Industries, Inc. (transit buses)

    Orion Bus Industries (transit buses)

    Thomas Built Buses (school buses)

Specialty

    Allianz Madvac (street sweepers and specialty sweepers and vacuums)

    Capacity (yard hostler trucks for port drayage)

    Kalmar (yard hostler trucks for port drayage)

    Tymco (street sweepers)

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On January 24, 2008, Kenworth Truck Company (Kenworth) announced they will begin production of heavy-duty Kenworth T800 LNG trucks at one their manufacturing facilities beginning in 2009.

Benefits of Natural Gas Vehicles

        Cheaper.     Through 2003 in the United States, based upon EIA data, average CNG prices were generally cheaper than average regular unleaded gasoline prices on a gasoline gallon equivalent basis, and LNG prices were generally comparable to diesel fuel prices on a diesel gallon equivalent basis. Since 2004, CNG and LNG have become increasingly less expensive than gasoline and diesel. For example, in 2007 the average retail CNG price we charged in California, our most significant market, was $0.65 less per gasoline gallon equivalent than the average California regular unleaded gasoline price of $3.08 per gallon according to the EIA. In addition, CNG and LNG are also currently cheaper than the three other most widely available alternative fuels, propane, ethanol blends and biodiesel, as reported by the DOE on a gallon-equivalent basis.

        Tax incentives also enhance the cost-effectiveness of CNG and LNG. Since October 1, 2006, a U.S. federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG sold for vehicle use has been available to sellers of the fuel. A U.S. federal income tax credit is also available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles. The fuel credit and the vehicle credit are scheduled to expire on September 30, 2009 and December 31, 2010, respectively, unless otherwise extended.

        We believe that diesel fuel will become more expensive over the next several years as refineries must meet additional stringent federal sulfur diesel standards by 2010. Additionally, 2007 and later diesel engine models must meet 2007 federal heavy-duty engine emission standards as well as more restrictive standards in 2010, which will require significant modification costs.

        The chart below shows our average pump prices in California for CNG relative to California retail regular gasoline and diesel prices on a gasoline gallon equivalent basis for the periods indicated. CNG and LNG powered vehicles produce roughly the same miles per gallon as comparable to gasoline or diesel powered vehicles.

Average California Retail Prices

(per gasoline gallon equivalent) (1)

 
  Year Ended December 31,
 
 
  2005
  2006
  2007
 
California retail gasoline (2)   $ 2.50   $ 2.83   $ 3.08  
California retail diesel (2)(3)     2.46     2.76     2.81  
California CNG—Clean Energy     2.15     2.16     2.43  
CNG discount to gasoline   $ (0.35 ) $ (0.67 ) $ (0.65 )
CNG discount to diesel     (0.31 )   (0.60 )   (0.38 )

(1)
Industry analysts typically use the gallon equivalent method in an effort to provide a normalized or "apples to apples" comparison of the relative cost of CNG compared to gasoline and diesel. Using this method, the cost of CNG is presented based on the amount of CNG required to generate the same amount of energy, measured in British Thermal Units or BTUs, as a gallon of gasoline.

(2)
Retail gasoline and diesel prices from the EIA.

(3)
Converted to gasoline gallon equivalents assuming 125,000 MMBTU and 139,000 MMBTU per gallon of gasoline and diesel, respectively.

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        The following chart shows the estimated incremental cost in California by market of a natural gas vehicle compared to a gasoline or diesel vehicle and the estimated annual fuel cost savings that may be achieved by the natural gas vehicle.

Representative Annual Per Vehicle Fuel Cost Savings
by Fleet Market for California
Based on Average Fuel Prices During December 2007

Market

  Estimated incremental cost ($) (1)
  Fuel
  Estimated annual fuel usage (gallons) (2)(3)
  Cost of fuel CNG or LNG vs. gasoline or diesel (gallons) (2)(4)
  Estimated annual fuel cost savings
Taxi   $ 0-$3,000   CNG or Gasoline   5,000   $2.65 (5)  vs. $3.31 (5)   $ 3,300
Shuttle van   $ 7,000   CNG or Gasoline   7,500   $2.65 (5)  vs. $3.31 (5)   $ 4,950
Municipal transit bus (CNG)   $ 6,000   CNG or Diesel   16,680   $1.58 (6)  vs. $2.52 (7)   $ 15,679
Refuse truck (CNG)   $ 6,000   CNG or Diesel   11,120   $1.63 (6) (8) vs. $3.13 (7)   $ 16,680
Municipal transit Bus (LNG)   $ 6,000   LNG or Diesel   16,680   $1.78 (9)  vs. $2.52 (7)   $ 12,343
Refuse truck (LNG)   $ 6,000   LNG or Diesel   11,120   $2.18 (8) (9) vs. $3.13 (7)   $ 10,564

(1)
Net of federal, state and local government incentives available to offset the incremental cost of acquiring the natural gas vehicle in California and assuming maximum federal tax credits. In Southern California, as a result of local incentives, it is possible to convert a taxi without paying any incremental costs.

(2)
CNG and LNG volumes are stated on a gasoline gallon equivalent basis. Industry analysts typically use the gasoline gallon equivalent method in an effort to provide a normalized or "apples to apples" comparison of the relative cost of CNG compared to gasoline and diesel. Using this method, the cost of CNG is presented based on the amount of CNG required to generate the same amount of energy, measured in BTUs, as a gallon of gasoline.

(3)
Average fleet vehicle usage estimated by us based on experience with our customers. Estimated usage for a taxi is based on a "single-shift" driving program.

(4)
Fuel prices for municipal transit buses are lower compared to refuse trucks because fuel for municipal buses is not subject to fuel excise taxes.

(5)
CNG retail pricing is based on average Clean Energy retail station pricing in California during December 2007. Gasoline retail pricing is based on California average retail gasoline prices during December 2007 as reported by EIA.

(6)
CNG prices based on average prices paid by Clean Energy's California fleet customers in December 2007.

(7)
Diesel price based on EIA reported diesel price in December 2007.

(8)
Excludes California Board of Equalization taxes of $0.0875 per GGE on CNG vehicles and $0.06 per gallon on LNG vehicles as these customers typically buy an annual permit of $168.00 per truck over 12,000 GVW that allows them to opt out of this tax.

(9)
LNG prices based on wholesale pricing adjusted for taxes and excluding infrastructure costs, which are typically paid by a third party.

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        Cleaner.     Use of CNG and LNG as a vehicle fuel creates less pollution than use of gasoline or diesel, based on data from South Coast Air Quality Management District studies. On-road mobile source emissions reductions are becoming increasingly important because many urban areas have failed to meet federal air quality standards. This failure has led to the need for more stringent governmental air pollution control regulations.

        The table below shows examples of emissions reductions for specified natural gas vehicles versus their gasoline or diesel powered counterparts. Comparisons are based on information submitted to the EPA by the manufacturer and reflect vehicles of the same make, model and engine size.

 
   
  Certified maximum grams per mile
Model

   
  Fuel
  NOx
  CO
  PM
2007 Honda Civic   Gasoline   0.040   2.100   0.010
2007 Honda Civic   CNG   0.010   1.050   0.005
  Emission Reduction       75%   50%   50%
2007 Chevrolet Silverado 2500   Gasoline   0.300   4.200   0.060
2007 Chevrolet Silverado 2500   CNG   0.200   4.200   0.020
  Emission Reduction       33%   0%   67%

        In 2007, new federal emissions requirements became effective for medium and heavy-duty engines, and more stringent requirements go into effect in 2010. These requirements limit the levels of specified emissions from new vehicle engines manufactured in or after these years, and will likely result in cost increases for both acquiring and operating diesel vehicles. In order to comply with these standards, 2007 diesel engine models have employed significant new emissions control technologies such as advanced NOx and particulate matter (PM) traps and exhaust gas recirculation systems, which have resulted in increases to the cost of medium and heavy-duty diesel vehicles. According to industry sources, the purchase price of a 2007 heavy-duty diesel vehicle that meets the 2007 diesel emission standards increased by an average of $10,000 per vehicle. The 2007 and newer diesel vehicles will also require the use of ultra-low sulfur diesel fuel in order to meet the standards, which we believe will also increase the cost of operating and maintaining medium and heavy-duty diesel vehicles. Additionally, we expect the cost of medium and heavy-duty diesel vehicles to increase in 2010 when they must meet the federal 2010 emission standards. The 2010 standards will require diesel vehicles to use additional emission control technologies, which may include the use of selective catalytic reduction strategies that require urea. We expect these additional controls will generally result in lower performance and fuel economy and increase the cost to own and operate diesel vehicles.

        By comparison, the "certified" levels (or the emission levels the vehicles test to) for all 2007 medium and heavy-duty natural gas engines satisfy the federal 2007 emission standards, and one natural gas engine model has already been certified to meet the 2010 standards. The chart below shows the results of comparison tests, published by the South Coast Air Quality Management District, of a sample of natural gas engines (the first two engines in the chart on the left), and diesel engines (the remainder of the engines in the chart below on the right) against the federal emission standards applicable for 2007 and 2010. The chart only shows the NOx standards as the PM standards are identical for 2007 and 2010. The chart demonstrates that all of the diesel engines certified to meet the 2007 standard have "not-to-exceed" levels (values that limit the amount an engine can emit as it deteriorates over time) that actually exceed the 2007 federal emission NOx standard, and no diesel engine is currently certified to meet the 2010 standard. In addition, both natural gas engines do not exceed the 2007 standard with their "not-to-exceed" ratings. Finally, most 2007 model year natural gas engines can achieve the 2010 standards by using an available catalytic converter with an approximate cost of $4,000 to $6,000.

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GRAPHIC

        In addition to the South Coast Air Quality Management District's study of emissions above, he District also compared emissions levels of natural gas and other alternative fuels to those of diesel engines. The results, shown in the chart below, demonstrate that natural gas vehicle fuels produce significantly lower emissions than biodiesel, ethanol blends and diesel technologies. The figures show the percentage reduction in NOx and PM compared to emissions from standard diesel engines.

Proven Commercially Alternative Fuels and Diesel Technologies

Technology

  NOx reduction
  PM reduction
Natural gas   ³ 50%   70%
Diesel emulsions   10-15%   50-65%
Biodiesel (B20)   -5%-0%   15-20%
Ethanol blends   2-6%   35-40%
Oxidation catalysts for diesel engines   0-3%   ~20%
NOx/PM traps for diesel engines   0-25%   >85%
Low-sulfur diesel   Minimal   ~20%

Source: South Coast Air Quality Management District—2007 Air Quality Management Plan Summit Panel

        In September 2006, California Governor Arnold Schwarzenegger signed AB 32 into law, which calls for a cap on greenhouse-gas emissions throughout California and a statewide reduction to 1990 levels, by the year 2020. In October 2007, Governor Schwarzenegger signed into law AB 118, which provides approximately $210 million per year for seven years to fund alternative fuel programs, including CNG and LNG, aimed at reducing greenhouse-gas emissions and improving air quality. Additionally, in February 2007, the governors of five western U.S. states, Oregon, California, Washington, New Mexico and Arizona, announced a joint strategy to implement market-based programs within 18 months to reduce global warming pollution.

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        Transportation accounts for more than 41% of California's annual greenhouse-gas emissions, according to the California Energy Commission. As set forth in a report by TIAX, LLC, on a full life-cycle ("well to wheels") analysis, natural gas as a vehicle fuel already results in greenhouse-gas reductions of up to 30% for light duty vehicles and up to 23% for medium and heavy-duty vehicles.

        Further, in October 2007, the California Energy Commission adopted the AB 1007 State Alternative Fuels Plan that establishes goals of displacing 26% of California's petroleum fuel use by 2022 with alternative fuels, including natural gas.

        Biogas is also a means to reduce greenhouse gas emissions. Biogas is natural gas produced from waste streams such as landfills, animal waste "lagoons" and sewage processing plants, and can reduce greenhouse-gas emissions up to 100%. According to The American Biogas Alliance, biogas can be liquefied or injected into the pipeline and is compatible with existing natural gas fueling infrastructure. Additionally, according to a 1998 DOE study, biogas available from these sources could offset over ten billion gallons of petroleum fuel per year.

        Safer.     As reported by NGV America, CNG and LNG are safer than gasoline and diesel because they dissipate into the air when spilled or in the event of a vehicle accident. When released, CNG and LNG are also less combustible than gasoline or diesel because they ignite only at relatively higher temperatures. The fuel tanks and systems used in natural gas vehicles are subjected to a number of federally required safety tests, such as fire and gunfire tests, pressure extremes and crash testing, according to the U.S. Department of Transportation National Highway Traffic Safety Administration. CNG and LNG are generally stored in above ground tanks, and therefore are not likely to contaminate soil or groundwater.

        Domestic supply.     In 2007, the United States consumed 20.7 million barrels of crude oil per day, of which 36% was supplied from the United States and Canada and 64% was imported from other countries, according to the EIA. By comparison, the EIA estimates that 98% of the natural gas consumed in the United States in 2006 was supplied from the United States and Canada, making it less vulnerable to foreign supply disruption. In addition, the EIA estimates that less than 1% of the estimated 23.0 trillion cubic feet of natural gas consumed in the United States in 2007 was used for vehicle fuel. We believe that a significant increase in use of natural gas as a vehicle fuel would not materially impact the overall demand for natural gas supplies.

        Analysts believe that there is a significant worldwide supply of natural gas relative to crude oil. In addition to reserves of natural gas in North America, there are also significant reserves of natural gas in other parts of the world that are increasingly being developed for export as LNG to high-consumption markets such as the United States. According to the 2007 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2006 natural gas production was 56% greater than the ratio of proven crude oil reserves to 2006 crude oil production. This analysis suggests significantly greater longer term availability of natural gas than crude oil based on current consumption. According to industry analysts, significant investments are being made in the United States in re-gasification plant capacity to increase the amount of LNG that can be imported into the United States. Over the long run, we believe that expected investments in LNG liquefaction capacity worldwide will strengthen the supply outlook for natural gas.

        Bridge to hydrogen.     With the goal of reducing U.S. dependence on foreign energy sources and lowering vehicle emissions, the federal government has launched several initiatives in the last few years that are dedicated to making practical and cost-effective hydrogen fuel cell vehicles widely available by 2020. The most cost-effective approach to produce hydrogen in the near term is to reform hydrogen from natural gas, according to Hydrogen.gov, the U.S. federal government's source of information on hydrogen fuels; and natural gas fueling stations are being considered by government agencies for use in the production of hydrogen for vehicles. In addition, natural gas vehicle fuel suppliers' expertise in

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working with fuels at very low temperatures or high pressure will be useful in a hydrogen-based transportation system because hydrogen is dispensed either in super-cooled liquid form (similar to LNG) or compressed gas form (similar to CNG). Even before wide scale hydrogen production for vehicle fuels goes into effect, natural gas fuel suppliers may begin supplying hydrogen/CNG blends or HCNG (20% hydrogen, 80% CNG), which the DOE has found to reduce NOx emissions by an additional 50% versus pure CNG.

Business Strategy

        Our goal is to capitalize on the anticipated growth in the consumption of natural gas as a vehicle fuel and to enhance our leadership position as that market expands. To achieve these goals, we are pursuing the following strategies:

        Focus on high-volume fleet customers.     We will continue to target fleet customers such as public transit, refuse haulers and regional trucking companies, as well as vehicle fleets that serve airports and seaports. We believe these are ideal customers because they are high-volume users of vehicle fuel and can be served by a centralized fueling infrastructure. We have recently focused on seaports because they are among the biggest air polluters and many are under increasing regulatory pressure to reduce emissions. In November 2006, two of the nation's largest seaports, the Ports of Los Angeles and Long Beach (Ports), adopted the San Pedro Bay Clean Air Action Plan which calls for the retrofit or replacement of approximately 10,600 trucks serving those ports so that they run on cleaner technology, including the replacement of approximately 5,300 trucks by alternative-fueled trucks meeting specified "clean" truck standards. In November 2007, the Ports voted for a progressive ban of the existing trucks from operating at the Ports. The ban begins October 1, 2008 and continues through January 1, 2012, when all trucks servicing the Ports must at least meet the EPA 2007 diesel emission standards. In December 2007, the Ports approved a cargo fee of $35 per loaded twenty-foot equivalent cargo container entering or leaving any terminal by truck, beginning June 1, 2008. The Ports estimate the cargo fees will generate approximately $1.6 billion to help fund replacement trucks as the ban goes into effect and eliminates the existing trucks at the Ports. On February 19, 2008, the Port of Long Beach Commission added a provision to their plan that targets no less than 50% of the trucks at their port that are financed through the container fee will run on alternative fuels proven to be cleaner than diesel, such as LNG. We believe that LNG-powered trucks are currently the only alternative fueled trucks that meet these standards.

        In December 2007, we opened the first fueling station in the port area to fuel these LNG-powered trucks, and have been selected by the Port of Long Beach to design, construct and operate an additional station on Port property. In addition, we have selected other potential fueling station sites for development that would be capable of providing LNG fueling for the trucks servicing the Ports.

        Capitalize on the cost savings of natural gas.     We will continue to capitalize on the cost advantage of natural gas as a vehicle fuel. We educate fleet operators on the advantages of natural gas fuels, which include the cost savings relative to gasoline and diesel, as well as government support to purchase natural gas vehicles. We also educate fleet operators on various incentives, including incentives that reduce the purchase price of natural gas vehiciles, which we believe will accelerate the adoption of natural gas vehicles.

        Leverage first mover advantage.     We plan to continue to capitalize on our initial presence in a number of growing markets for CNG and LNG, such as public transit, refuse hauling, seaports, and airports, where there is increasing regulatory pressure to reduce emissions and where natural gas vehicles are already used in fleets. We plan to expand our business with existing customers as they continue to replace diesel and gasoline powered vehicles with natural gas vehicles. We intend to use our knowledge and reputation in these markets to win business with new customers.

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        Optimize LNG supply advantage.     The supply of LNG in the United States and Canada is limited. We believe that increasing our LNG supply will enable us to increase sales to existing customers and to secure new customers. We use our LNG supply relationships and strategically located LNG production capacity to give us an advantage. In addition to our own LNG liquefaction plant in Texas, we currently have relationships with five LNG supply plants in the western United States. We also are in the process of building an LNG liquefaction plant in California that will enhance our ability to serve California, Arizona and other western U.S. markets and will help us to optimize the allocation of LNG supply we sell to our customers. Also, in October 2007, we entered into an LNG sales agreement with Spectrum Energy Services, LLC (SES), whereby we will purchase, on a take-or-pay basis over a term of 10 years, 16 million gallons of LNG per year from a plant to be constructed by SES in Ehrenberg, Arizona, which is near the California border. In the future, we may also acquire natural gas reserves or rights to natural gas production to supply our LNG plants.

        Expand internationally.     We plan to expand our operations internationally in strategic locations where we believe potential fleet customers are ready to adopt natural gas as a vehicle fuel. For example, in August 2007, we executed a Joint Venture Agreement with Energy Gas del Perú SAC pursuant to which we are in the process of opening our first CNG station in Lima, Peru, targeted initially to serve taxi fleets and transit buses. We anticipate investing approximately $5 million during the first year of the joint venture to develop up to four additional natural gas fueling stations.

Operations

        Our revenue principally comes from selling CNG and LNG fuel to our customers, and to a lesser extent, from operating and maintaining fueling stations and designing and building fueling stations. Each of these is discussed below.

        Natural gas for CNG stations.     We obtain natural gas for CNG stations from local utilities under standard arrangements which provide that we purchase natural gas at a published rate or negotiated prices. The natural gas is delivered via pipelines owned by local utilities to fueling stations where it is compressed on site. In some cases, we receive special rates from local utilities because of our status as a supplier of CNG for transportation.

        LNG production and purchase.     We obtain LNG from our own plant as well as through purchases from five suppliers in the western United States. Combining these sources provides important flexibility and helps to create a reliable supply for our LNG customers. We own and operate a LNG liquefaction plant near Houston, Texas, which we call the Pickens Plant. This plant has the capacity to produce 35 million gallons of LNG per year and also includes tanker trailer loading facilities and an 840,000 gallon storage tank. Additionally, we are building an LNG liquefaction plant in California. We expect this plant will be operational in the fall of 2008, assuming we do not experience significant construction delays. We anticipate this plant will initially be capable of producing up to 60 million gallons of LNG per year (with expansion capabilities to produce up to 90 million LNG gallons per year) and will enable us to supply our operations in California and Arizona more economically as our supply source will be closer to our customers' locations. This plant will have tanker trailer loading facilities similar to the Pickens Plant, and a 1.5 million gallon storage tank.

        As of December 31, 2007, we had purchase contracts with various third-party LNG suppliers in the western United States. For the year ended December 31, 2007, of the LNG we sold, we purchased 64% from these suppliers and the balance was produced at our Pickens Plant. Three of our LNG supply contracts contain "take-or-pay" provisions which require that we purchase specified minimum volumes of LNG at index-based prices or pay for the amounts that we do not purchase. If we need additional LNG and it is available from these suppliers, we generally may purchase it from them, typically at the market price for natural gas plus a liquefaction fee. To date, we have taken and sold the required amounts under these contracts.

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        We have a fleet of 60 tanker trailers that we use to transfer LNG from our third-party suppliers and from our Pickens Plant to individual fueling stations. We typically own the tanker trailers and we contract with third parties to provide tractors and drivers. Each LNG tanker trailer is capable of carrying 10,000 gallons of LNG. To optimize our distribution network, we use an automated tracking system that enables us to monitor the location of a tanker trailer at any time, as well as an automated fueling station tank-monitoring system that enables us to efficiently schedule the refilling of each station, which helps ensure that our customers have sufficient fuel to operate their fleets.

        Operations and maintenance.     Typically, we perform operations and maintenance services for CNG stations, which are either owned by us or our customers. Although we may from time to time operate and maintain LNG stations, LNG stations are most often owned and maintained by our customers and supplied by us. Most of the CNG and LNG stations that we maintain or supply are monitored from our centralized operations center, facilitating increased reliability and safety, as well as lower operating costs. This monitoring helps us to ensure the timely delivery of fuel and to respond rapidly to any technical difficulties that may arise. In addition, we have an automated billing system that enables us to track our customers' usage and bill efficiently. As of December 31, 2007, we had an operations team of 54 employees, including 34 full-time employees dedicated to performing preventative maintenance and available to responding to service requests in 12 states and in Canada.

        Our station network.     As of December 31, 2007, we owned, operated or supplied 170 fueling stations for our customers in Arizona, California, Colorado, Maryland, Massachusetts, Nevada, New Mexico, New York, Texas, Washington, Georgia, Wyoming and Canada. Of these 170 stations, we owned 119 of the stations, and our customers owned the other 51 stations. The breakdown of the services we perform for these stations is set forth below.

 
  As of December 31, 2007
 
  CNG fueling stations
  LNG fueling stations
  Total stations
Operated, maintained and supplied by Clean Energy   92   5   97
Supplied by Clean Energy, operated and maintained by customer   1   26   27
Operated and maintained by Clean Energy, supplied by customer   45   1   46
   
 
 
Total   138   32   170
   
 
 

        For the month of December 2007, 20 of the stations listed in the table above delivered in excess of 100,000 gasoline gallon equivalents, and 29 stations delivered in excess of 25,000 gasoline gallon equivalents (but less than 100,000 gasoline gallon equivalents). Of the 20 stations delivering greater than 100,000 gasoline gallon equivalents per month, 15 relate to transit customers and five relate to airport locations. Of the 29 stations delivering greater than 25,000 gasoline gallon equivalents (but less than 100,000 gasoline gallon equivalents), nine relate to refuse customers, eight relate to airport locations, two relate to public stations in California, nine relate to transit customers and one relates to an industrial customer. In general, stations delivering higher volumes are more cost effective and perform better financially due to operating efficiencies obtained by the spreading of a station's fixed costs over a larger revenue base. With respect to station performance by geographic region, stations located in busy metropolitan areas, particularly near airports, experience higher traffic and deliver higher volumes compared to stations located in areas that are less densely populated.

        Station construction and engineering.     We have built 72 natural gas fueling stations, either serving as general contractor or supervising qualified third-party contractors, for ourselves or our customers. We acquired the additional stations we own that we did not construct through acquisition of assets or businesses. We use a combination of custom designed and off-the-shelf equipment to build fueling stations. Equipment for a CNG station typically consists of dryers, compressors, dispensers and storage

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tanks (which hold a relatively small buffer amount of fuel). Equipment for an LNG station typically consists of storage tanks that hold 10,000 to 25,000 gallons of LNG, plus related dispensing equipment.

        A number of our CNG fueling stations have separate public access areas for retail customers, which have the look, feel and fill rates of a traditional gasoline fueling station. Our CNG dispensers are designed to fuel at five to six gasoline gallon equivalents per minute, which is comparable to a traditional gasoline fueling dispenser. Our LNG dispensers are designed to fuel at 40 diesel gallon equivalents per minute, similar to a diesel fueling dispenser. LNG dispensing requires special training and protective equipment because of the extreme low temperatures of LNG.

Sales and Marketing

        We have sales representatives in all of our major operating territories, including Los Angeles, San Francisco, San Diego, Phoenix region, Boston region, New York, Denver, Dallas, Seattle, New Mexico, Toronto and Vancouver. At December 31, 2007, we had 37 employees in sales and marketing. As our business grows and we enter new markets over the next several years, we intend to continue expanding our sales and marketing team, primarily by adding specialized sales experts to focus on fleet market opportunities in targeted metropolitan areas where we do not yet have a strong presence. We estimate we may need to hire between 20 to 40 sales and marketing employees in the foreseeable future. We market primarily through our direct sales force, attendance at trade shows and participation in industry conferences and events. Our sales and marketing group works closely with federal, state and local government agencies to educate them on the value of natural gas as a vehicle fuel and to keep abreast of proposed and newly adopted regulations that affect the industry. Several of our U.S. sales offices are located in ozone "nonattainment" areas, or near-non-attainment areas, under the Federal Clean Air Act, where government regulations are more likely to mandate vehicle pollution controls.

Customer Vehicle Financing

        We provide, or help our customers obtain, financing to acquire natural gas vehicles or convert their vehicles to operate on natural gas. In 2006, we began to loan our customers up to 100% of the up-front capital needed to purchase natural gas vehicles or convert existing vehicles to use natural gas. We also use our in-house grant specialists to help secure government grants, tax rebates and related incentives for ourselves and our customers, which can be a challenging process. Our specialists have secured over $94.3 million in federal and state funding for ourselves and our customers since 1998. This expertise is important to our customers, as natural gas vehicle fleet operators have access to an increasing number of grants and other incentives to help defray a significant portion of the incremental costs of purchasing natural gas vehicles. As of December 31, 2007, we have not generated significant revenue from financing activities.

        To ensure the availability of vehicles for our customers, we may purchase natural gas vehicles or components of natural gas vehicles in anticipation of customer requirements. For example, we agreed to make cash deposits with Inland Kenworth, Inc. (Inland) to help fund the acquisition from Kenworth Truck Company of up to 125 diesel tractors that will be converted to run on LNG. We expect the converted tractors to be sold to fleet customers servicing the Ports of Los Angeles and Long Beach. We have also advanced funds to Westport Innovations Inc. to facilitate the production of LNG fuel systems for installation in the diesel tractors referenced above. See Part II, Item 9B for more information regarding our arrangements with Inland and Westport.

Customers and Key Markets

        We have over 275 fleet customers operating approximately 14,000 vehicles, including approximately 3,300 transit buses, 1,200 taxis, 800 shuttles and 1,000 refuse trucks. We target customers in a variety of markets, such as airports, public transit, refuse, seaports, regional trucking, taxis and government fleets.

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We do not depend on a single customer or a few customers, the loss of one or more of which would have a material adverse effect on us.

    Airports —Many U.S. airports face emissions problems and are under regulatory directives and political pressure to reduce pollution, particularly as part of any expansion plans. Many of these airports already have adopted various strategies to address tailpipe emissions, including rental car and hotel shuttle consolidation. In order to reduce emissions levels further, many airports require or encourage service vehicle operators to switch their fleets to natural gas, including airport delivery fleets, door-to-door and parking shuttles and taxis. To assist in this effort, airports are contracting with service providers to design, build and operate natural gas fueling stations in strategic locations on their property. Airports we serve include Baltimore-Washington International, Dallas-Ft. Worth International, Love Field (Dallas), Denver International, LaGuardia (New York), Los Angeles International, Oakland International, Phoenix Sky Harbor International, San Francisco International and SeaTac International (Seattle). At these airports, our representative customers include taxi and van fleets, as well as parking and car rental shuttles.

    Transit agencies —According to the American Public Transportation Association there are over 81,000 municipal transit buses operating in the United States. In many areas, increasingly stringent emissions standards have limited the fueling options available to public transit operators. For example, the South Coast Air Quality Management District in California has adopted an Air Toxic Control Plan designed to encourage the use of alternative fuel buses. Eligible buses include hybrid gasoline electric buses (which typically cost $165,000 more than a traditional gasoline or diesel powered bus according to the Union of Concerned Scientists, an environmental watchdog group) or natural gas powered buses (which typically cost $35,000 more than a traditional gasoline or diesel powered bus, a significant portion of which can be recaptured through tax credits). Some public transit authorities also allow hybrid diesel electric buses (which typically cost $200,000 more than a traditional gasoline or diesel powered bus). The cost comparison data in this paragraph are from Hybridcenter.org, a project of the Union of Concerned Scientists. Transit agencies have been early adopters of natural gas vehicles, with almost 19% of all buses in the United States operating on LNG, CNG or CNG blends, according to the American Public Transportation Agency 2007 Public Transportation Factbook. Our representative public transit customers include Dallas Area Rapid Transit, Santa Monica Big Blue Bus, Boston Metropolitan Transit Development Agency, Metropolitan Transit System of San Diego, Phoenix Transit, Tempe Transit and Foothill Transit (California).

    Refuse haulers —According to INFORM, there are nearly 200,000 trucks in the United States, consuming approximately one billion gallons of fuel per year, that haul refuse and recyclables from collection points to landfills and recycling facilities. Many refuse haulers are facing pressure from the municipalities they serve to reduce emissions. We estimate there are fewer than 2,200 natural gas powered refuse hauling vehicles operating in the United States on CNG and LNG. Our representative refuse hauler customers include a portion of the California-based operations of Waste Management and Allied Waste, as well as CR&R, Waste Connections and NORCAL Waste Systems, and the cities of Bakersfield, Fresno and Sacramento.

    Seaports —Seaports are typically large polluters because of emissions from cargo ships, trains, yard hostlers and trucks. Many seaports must reduce emissions levels in connection with any expansion efforts. A practical solution for reducing port emissions is to require that land-based vehicles accessing the seaport use alternative fuels such as natural gas. Such mandates require conversion to alternative fueling systems for regional trucking fleets that transport containers from the seaport to local distribution centers, as well as the yard hostlers that move containers around the shipyard. In November 2006, two of the nation's largest seaports, the Ports of Los Angeles and Long Beach (Ports), adopted the San Pedro Clean Air Action Plan, which calls for

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      the retrofit or replacement of approximately 10,600 trucks serving those ports so that they run on cleaner technology, including the replacement of approximately 5,300 trucks by alternative-fueled trucks meeting specific "clean" truck standards. In November 2007, the Ports introduced a progressive ban, beginning October 1, 2008, that will remove by 2012 all diesel trucks that do not meet 2007 emission standards. In December 2007, the Ports approved a $35 per twenty-foot container unit cargo fee, beginning June 1, 2008, which the Ports estimate will generate approximately $1.6 billion to help fund replacement trucks. In February 2008, the Port of Long Beach Commission approved a provision in their plan calling for no less than 50% of the trucks at their port that are financed through the container fee will run on alternative fuels proven to be cleaner than diesel, such as LNG. We believe that LNG-powered trucks are currently the only alternative fueled trucks that meet these standards.

      In December 2007, we opened the first fueling station in the port area to fuel these LNG-powered trucks, and have been selected by the Port of Long Beach to design, construct and operate an additional station on Port property. In addition, we have selected other potential fueling station sites for development that would be capable of providing LNG fueling for the trucks servicing the Ports.

    Regional trucking —According to the EPA, the average tractor-trailer uses over 11,500 gallons of fuel per year. Most of these trucks run on diesel fuel, which is becoming more expensive and less desirable as emissions standards become increasingly more stringent. For regional fleets that can use centralized refueling facilities, LNG is a more cost-effective fuel alternative that enables trucking companies to meet the evolving emissions standards. Our representative regional trucking customers include the Dallas and Houston distribution centers of Sysco Food Services, a wholesale distributor of food products, the Houston distribution center of H.E. Butt Grocery Company, and Harris Ranch in the San Joaquin Valley.

    Taxis —According to the Automotive Fleet Factbook, there were approximately 162,000 taxis operating in the United States in 2005. We believe that less than 2% of these vehicles were natural gas vehicles. Because taxi fleets travel many miles and can refuel at a central location, they are excellent candidates to use CNG. Natural gas vehicles provide taxi fleets a convenient way to reduce operating costs. We serve approximately 1,200 taxis in Southern California, the San Francisco Bay Area, New York City, Phoenix, Tucson and Seattle. In March 2008, San Francisco Mayor Gavin Newsom signed legislation that will enable the purchase of more alternative-fuel taxi cabs for use in San Francisco.

    Government fleets —According to the Federal Highway Administration, or FHA, in 2005, there were over four million government fleet vehicles in operation in the United States, including those operated by federal, state and municipal entities. In California and Texas, for example, according to the FHA there were over 598,000 and 475,000 government vehicles, respectively. As government regulations on pollution continue to become more stringent, government agencies are evaluating ways to make their fleets cleaner and run more economically. Under the federal Energy Policy Act of 1992, 75% of new light-duty vehicles purchased by federal fleet operators are required to run on alternative fuels. Our representative government fleet customers include the United States Navy (San Diego), California Department of Transportation (Los Angeles and Orange County), State of New York, City of Denver, City and County of Los Angeles, City and County of San Francisco, City and County of Dallas and City of Phoenix.

Tax Incentives and Grant Programs

        U.S. federal and state government tax incentives and grant programs are available to help fleet operators reduce the cost of acquiring and operating a natural gas vehicle fleet. Incentives are typically available to offset the cost of acquiring natural gas vehicles or converting vehicles to use natural gas,

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constructing natural gas fueling stations and selling CNG or LNG. The principal incentive programs available are discussed below.

Tax incentives

        Recent amendments to the federal tax laws created a federal excise tax rebate for sales of CNG and LNG vehicle fuels effective October 1, 2006, and continuing through September 30, 2009, and federal income tax credits for purchases of natural gas vehicles and natural gas fueling equipment for property placed in service on or after January 1, 2006 and through December 31, 2010. These rebates and credits are key incentives designed to enhance the cost-effectiveness of CNG and LNG as vehicle fuels throughout the United States.

        VETC.     Under the Volumetric Excise Tax Credit (VETC) for alternative fuels, sellers of CNG or LNG are entitled to receive a credit of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG sold for vehicle fuel use after September 30, 2006 and before October 1, 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. During this period, we may offset a portion of the $0.50 credit against the federal excise tax paid by our customers of $0.183 per gasoline gallon equivalent of CNG sold or $0.243 per gallon of LNG sold, which was increased to these amounts as part of the same legislation. By comparison, the legislation does not provide any offsetting refund to the federal excise tax of $0.183 per gallon of gasoline or $0.243 per gallon of diesel fuel sold, which tax rates the legislation did not change. These tax credits for CNG and LNG lower the cost of natural gas vehicle fuels to sellers, and the savings can be passed on to the customer if the seller elects to do so. These credits are scheduled to expire on September 30, 2009, unless otherwise extended.

        Vehicle credits.     Effective January 1, 2006, a federal income tax credit became available to taxpayers for 50% of the incremental cost associated with purchasing a new vehicle that operates only on natural gas or another alternative fuel (as compared to the cost of the same vehicle using a gasoline or diesel fuel motor) or a vehicle converted to that form of alternative fuel. The credit is increased to 80% of the incremental cost if the vehicle is certified as meeting the most stringent applicable emission standard for the vehicle under the Federal Clean Air Act or under California law (other than zero emission standards). The amount of the credit is subject to the following maximums: $4,000 if the vehicle purchased weighs 8,500 pounds or less, $8,000 if the vehicle purchased weighs more than 8,500 pounds but 14,000 pounds or less, $20,000 if the vehicle purchased weighs more than 14,000 pounds but 26,000 pounds or less, and $32,000 if the vehicle purchased weighs more than 26,000 pounds.

        For a taxpayer to be eligible for the credit, the vehicle must be acquired by the taxpayer for use or lease predominantly within the United States and not for resale, and the original use of the vehicle must commence with the taxpayer; or the taxpayer must sell the vehicle (which cannot be subject to a lease) to a tax-exempt entity (including the United States, any state and any political subdivision thereof), that places the vehicle into first use and disclose to that entity the amount of the allowable credit. The credit for any year is limited to the taxpayer's regular income tax liability for the year, subject in some cases to certain carryback and carryforward provisions. This federal income tax credit is currently in effect for vehicles purchased before January 1, 2011.

        Equipment credit.     Effective January 1, 2006, a federal income tax credit also became available to taxpayers for 30% of the cost of new equipment used for natural gas vehicle refueling. The credit is available for any equipment, other than equipment that is a structural component of a building, that is used predominantly within the United States for dispensing certain alternative fuels including CNG and LNG as a vehicle fuel or for storing the fuel at the point of fueling.

        For a taxpayer to be eligible for the credit, the original use of the equipment must commence with the taxpayer; or the taxpayer must sell the equipment (which cannot be subject to a lease) to a

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tax-exempt entity (including the United States, any state and any political subdivision thereof), that places the equipment into first use and must disclose to that entity the amount of the allowable credit. The credit is limited to $30,000 in the case of depreciable equipment, or $1,000 in the case of equipment that is installed in the personal residence of a taxpayer. The credit for any year is limited to the taxpayer's regular income tax liability for the year, subject in some cases to certain carryback and carryforward provisions. This federal income tax credit is currently in effect for equipment placed in service before January 1, 2010.

Grant programs

        The following are some of the grant programs available for fleets in several of the states in which we operate. We assist our customers in applying and qualifying for grants under these programs.

    Mobile Source Air Pollution Reduction Review Committee —The Mobile Source Air Pollution Reduction Review Committee, or MSRC, is a Southern California program that funds projects that reduce air pollution from motor vehicles within the South Coast Air Quality Management District in Southern California. The South Coast Air Quality Management District is a geographic region defined in state regulations to include all of Los Angeles and Orange Counties, and portions of Riverside and San Bernardino counties. The MSRC uses a portion of the California Department of Motor Vehicles $4 per vehicle surcharge for the south coast district, estimated to be $44 million in 2007, to fund a variety of clean air programs, including grants to purchase natural gas vehicles and fueling station infrastructure. The annual budget of the MSRC is approximately $12 million to $14 million. The MSRC has a yearly work program designed to fund projects that reduce air pollution from motor vehicles.

    California Carl Moyer Program —The Carl Moyer Memorial Air Quality Standards Attainment Program, or Carl Moyer Program, was initiated in California in 1998 to reduce emissions from heavy-duty, diesel-powered vehicles and other mobile sources. The Carl Moyer Program provides matching grants of over $140 million per year to private companies and public agencies in California to fund efforts to clean up emissions from their heavy-duty engines through retrofitting, repowering or replacing them with newer and cleaner versions. In 2007, approximately $35 million of this budget was allocated to the South Coast Air Quality Management District. The California Air Resources Board has allocated $34.5 million to the South Coast Air Quality Management District under SB1107 for the implementation of its 2008 Carl Moyer Program. Qualifying projects include those that reduce emissions from heavy-duty on and off-road equipment, such as trucks over 14,000 pounds gross vehicle weight and off-road equipment such as construction equipment and airport ground support equipment.

    New York Programs —The New York State Energy Research Development Authority makes funds available to offset the incremental cost of purchasing natural gas vehicles. This agency's programs include funding up to $8,000 per vehicle for the purchase of light duty vehicles including natural gas taxicabs and limousines (black car transportation services), and $2.5 million to offset the incremental cost of light and heavy-duty vehicles. In addition, New York State has an alternative vehicle and infrastructure fuel tax credit and has exempted alternative fuels from sales and use taxes.

    Texas Emissions Reduction Plan —The Texas Emissions Reduction Plan is a comprehensive set of clean air incentive programs, including vehicle programs, designed to improve air quality in Texas. The Texas Commission on Environmental Quality (TCEQ) administers grants under these programs. The grants are used to help reduce air pollution in Texas ozone "nonattainment" areas and in certain other near-non-attainment areas in the state and are often targeted towards reducing emissions from diesel equipment. In 2006, $130 million of these grants were made available to purchase and convert to low emission vehicles. The Texas Legislature approved

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      $290.6 million for TERP grants this biennium, an increase of almost $60 million over the previous period. Of the appropriation, $137.5 million is available for distribution in early 2008. As part of the TCEQ's ongoing efforts to secure real, surplus and quantifiable emission reductions, $5 million of the State's funding was authorized for administration by the Renewal Energy Division of the General Land Office (GLO) through a new program, the Natural Gas Initiative Program Grants (NGIPG). This program provides support to public partners in twenty Texas counties to switch their fleets of heavy-duty diesel vehicles to run on clean-burning natural gas.

    U.S. Department of Energy State Energy Program —The Department of Energy's State Energy Program provides grants to states to design and carry out their own renewable energy and energy efficiency programs. Total funds available in 2005 for clean air State Energy Programs were $14.7 million. Funding from these programs goes to state energy offices in all states and U.S. territories, and the projects are managed by state energy offices. We and our customers have used these grants in various states to fund vehicle purchases and construct fueling stations. The funding from this program has been reallocated by the U. S. Department of Energy. In 2008, we expect to be able to participate in a new $50 million grant program focused on Diesel Reduction Strategies funded by the U.S. Environmental Protection Agency (EPA).

Competition

        The market for vehicular fuels is highly competitive. The biggest competition for CNG, LNG and other alternative fuels is gasoline and diesel, the production, distribution and sale of which are dominated by large integrated oil companies. The vast majority of vehicles in the United States and Canada are powered by gasoline or diesel. There is no assurance that we can compete effectively against other fuels, or that significant competitors will not enter the natural gas fuel market.

        Within the United States, we believe our largest competitors for CNG sales are: Trillium USA / Pinnacle CNG, a privately held provider of CNG fuel infrastructure and fueling services, which we believe focuses primarily on transit fleets in California, Arizona and New York; and Exterran Holdings, Inc. (formerly Hanover Compressor Company), a large publicly-traded international provider of natural gas compressors and related equipment, which we believe focuses its CNG vehicle fuel business primarily on transit fleets in California, Maryland, Massachusetts and Washington D.C. These companies are significant competitors in the market for transit fleets.

        Within the U.S. LNG market, we believe our largest competitors are Earth Biofuels, Inc., a public company, and Prometheus Energy, also a public company, each of whom distributes LNG in the western United States. We have identified no significant competitors in Canada for CNG or LNG sales.

        We own, operate or supply 170 CNG and LNG fueling stations. We operate 138 CNG fueling stations, which we estimate is approximately four times the number of CNG fueling stations as our next largest competitor. We further estimate that in 2005 we supplied approximately twice the amount of natural gas for vehicular use as our next largest competitor. In addition, we believe we are the only company in the United States or Canada that provides both CNG and LNG on a significant scale, and we operate in more states and provinces than any of our competitors.

        Potential entrants to the market for natural gas vehicle fuels include the large integrated oil companies, other retail gasoline marketers and natural gas utility companies. The integrated oil companies produce and sell crude oil and natural gas, and they refine crude oil into gasoline and diesel. They and other retail gasoline marketers own and franchise retail stations that sell gasoline and diesel fuel. In international markets, including to a limited extent in Canada, integrated oil companies and other established fueling companies sell CNG at a number of their vehicle fueling stations that sell gasoline and diesel. Natural gas utility companies own and operate the local pipeline infrastructure that supplies natural gas to retail, commercial and industrial customers.

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        It is possible that any of these competitors, and other competitors who may enter the market in the future, may create product and service offerings that compete with ours. Many of these companies have far greater financial and other resources and name recognition than we have. Entry by these companies into the market for natural gas vehicle fuels may reduce our profit margins, limit our customer base and restrict our expansion opportunities.

        Other alternative fuels compete with natural gas in the retail market and may compete in the fleet market in the future. We believe there is room for all providers of alternative fuels in the vehicle fuels market. However, suppliers of ethanol, biodiesel and hydrogen, as well as providers of hybrid vehicles, may compete with us for fleet customers in our target markets. Many of these companies benefit, as we do, from U.S. state and federal government incentives that allow them to provide fuel more inexpensively than gasoline or diesel.

Bridge to Hydrogen—Implementation of CNG/Hydrogen Fueling Station Activities

        We believe natural gas as a vehicle fuel is the best bridge to a hydrogen-based transportation system because natural gas can be used as a delivery mechanism for hydrogen and leverages the same infrastructure and expertise for vehicle fueling. As part of the Canadian Hydrogen Highway initiative, we are participating, together with a coalition of partners, in a program known as the Integrated Waste Hydrogen Utilization Project (IWHUP). The goal of the project is to take hydrogen from a process waste stream that is being vented to the atmosphere, purify it, and then transport it to a refueling station for use in vehicles. In furtherance of this program, we leveraged our design and engineering expertise with CNG fueling stations to build an integrated CNG/hydrogen (HCNG) dispenser. This dispenser is capable of providing 100% natural gas, 100% hydrogen or any blended combination of the two fuels with more precise mixing than was achieved previously. The station at which this dispenser is located provides CNG daily to approximately 70 buses and HCNG to four buses that are involved in the IWHUP demonstration project. We believe our construction and operation of this modified station demonstrates our ability to leverage existing natural gas infrastructure to introduce hydrogen fuel to customers.

Background on Clean Air Regulation

        The Federal Clean Air Act provides a comprehensive framework for air quality regulation in the United States. Many of the federal, state and local air pollution control programs regulating vehicles have their basis in Title I or Title II of the Federal Clean Air Act.

        Title II of the Federal Clean Air Act authorizes the EPA to establish emission standards for vehicles and engines. Diesel-fueled heavy-duty trucks and buses have recently accounted for substantial portions of NOx and particulate matter emissions from mobile sources, and diesel emissions have received significant attention from environmental groups and state agencies. In 2001, the EPA finalized its Heavy-Duty Highway Rule, also known as the 2007 Highway Rule. The 2007 Highway Rule seeks to limit emissions from diesel-fueled trucks and buses on two fronts: new tailpipe standards requiring significantly reduced NOx and particulate matter emissions for new heavy-duty diesel engines, and new standards requiring refiners to produce low sulfur diesel fuels that will enable more extensive use of advanced pollution control technologies on diesel engines.

        The 2007 Highway Rule's tailpipe standards, which will apply to new diesel engines, take effect in 2007 and 2010. Specifically, new particulate matter standards took effect in the model year 2007 and new NOx standards will be phased-in between 2007 and 2010. The rule's fuel standards call for a shift by U.S. refiners and importers from low sulfur diesel, with a sulfur content of 500 parts per million (ppm), to ultra-low sulfur diesel, with a sulfur content of 15 ppm. The rule, which will effect a transition to ultra-low sulfur diesel between 2006 and 2010, required refiners to begin producing ultra-low sulfur diesel fuels on June 1, 2006.

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        Title I of the Federal Clean Air Act charges the EPA with establishing uniform National Ambient Air Quality Standards for criteria air pollutants anticipated to endanger public health and welfare. States in turn have the primary responsibility under the Federal Clean Air Act for achieving these standards. If any area within a state fails to meet these standards for a criteria air pollutant, the state must develop an implementation plan and local agencies must develop air quality management plans for achieving these standards. Many state programs regulating vehicle pollution or mobile sources of pollution are developed as part of a state implementation plan for achieving these standards for two criteria pollutants in particular: ozone and particulate matter. Many of the nation's metropolitan areas are in "nonattainment" status for one or both of these criteria air pollutants. As components of state implementation plans, individual states have also adopted diesel fuel standards intended to reduce NOx and particulate matter emissions. Texas and California have both adopted optional low-NOx diesel programs. Additionally, many state implementation plans and some quality management plans include vehicle fleet requirements specifying the use of low emission or alternative fuels in government vehicles.

        Although the majority of state air pollution control regulations are components of state implementation plans developed pursuant to Title I of the Federal Clean Air Act, states are not precluded from developing their own air pollution control programs under state law. For example, the California Air Resources Board and the South Coast Air Quality Management District have promulgated a series of airborne toxic control measures under California state law, several of which are directed toward reducing emissions from diesel fueled engines.

Government Regulation and Environmental Matters

        Certain aspects of our operations are subject to regulation under federal, state, local and foreign laws. If we were to violate these laws or if the laws or enforcement proceedings were to change, it could have a material adverse effect on our business, financial condition and results of operations.

        Regulations that significantly impact our operations are described below.

    CNG and LNG stations —To construct a CNG or LNG fueling station, we must obtain a facility permit from the local fire department and either we or a third-party contractor must be licensed as a general engineering contractor. The installation of each CNG and LNG fueling station must be in accordance with federal, state and local regulations pertaining to station design, environmental health, accidental release prevention, above-ground storage tanks, hazardous waste and hazardous materials. We are also required to register with certain state agencies as a retailer/wholesaler of CNG and LNG.

    Transfer of LNG —Federal Safety Standards require each transfer of LNG to be conducted in accordance with specific written safety procedures. These procedures must be located at each place of transfer and must include provisions for personnel to be in constant attendance during all LNG transfer operations.

    LNG liquefaction plants —To build and operate LNG liquefaction plants, we must apply for facility permits or licenses to address many factors, including storm water or wastewater discharges, waste handling and air emissions related to production activities or equipment operations. The construction of LNG plants must also be approved by local planning boards and fire departments.

    Financing —State agencies generally require the registration of finance lenders. For example, in California, pursuant to the California Finance Lenders Law, one of our subsidiaries is a registered Finance Lender and Broker with the California Department of Corporations.

        We believe we are in substantial compliance with environmental laws and regulations and other known regulatory requirements. Compliance with these regulations has not had a material effect on our

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capital expenditures, earnings or competitive position. It is possible that more stringent environmental laws and regulations may be imposed in the future, such as more rigorous air emissions requirements or proposals to make waste materials subject to more stringent and costly handling, disposal and clean-up requirements. Accordingly, new laws or regulations or amendments to existing laws or regulations might require us to undertake significant capital expenditures, which may have a material adverse effect on our business, consolidated financial condition, results of operations and cash flows.

Employees

        As of December 31, 2007, we employed 121 people, of whom 37 were in sales and marketing, 61 were in operations and engineering, and 23 were in finance and administration. We have not experienced any work stoppages and none of our employees is subject to collective bargaining agreements. We believe that our employee relations are good.

Financial Information about Segments and Geographic Areas

        We operate our business in one reportable segment. For information about (1) our revenues from external customers, measures of profits and losses and total assets, and (2) our revenues from external customers and long-lived assets broken down by geographic area, see note 9 to our consolidated financial statements.

Additional Information

        Our web site is located at www.cleanenergyfuels.com. We make available free of charge on our web site our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Securities Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. The contents of our web site are not a part of this report.

Item 1A.    Risk Factors.

         An investment in our stock involves significant risks. You should carefully consider the risks described below, together with all of the other information in this report, before making a decision to invest in our stock. If any of these risks actually occurs, our business, results of operations, financial condition and prospects could suffer. As a result, the trading price of our stock could decline and you may lose part or all of your investment.

We have a history of losses and may incur additional losses in the future.

        In 2006 and 2007, we incurred pre-tax losses of $10.8 million and $7.7 million, respectively, related to our operations, which consist of natural gas fueling activities and station operations, and derivative losses of $79.0 million and $0.0 million, respectively, combining for overall pre-tax losses of $89.8 million and $7.7 million, respectively. In 2004 and 2005, excluding derivative gains, we incurred pre-tax losses of $6.8 million and $15.2 million, respectively, related to our operations. We must continue to invest in developing the natural gas vehicle fuel market, and our natural gas sales activities and station operations may not achieve or maintain profitability. If our natural gas sales activities and station operations continue to lose money, our business will suffer and the price of our common stock may drop.

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We will need to raise debt or equity capital to have sufficient cash to fund our 2008 capital expenditure program.

        We anticipate we will need approximately $40 million of additional capital in the next twelve months to fund our 2008 capital expenditure program in full. We first intend to pursue bank financing options; however, we may not be able to obtain bank financing on favorable terms, or at all. If we are unable to obtain debt financing, we would then pursue equity financing options, which also may not be available on terms favorable to us or at all. If we are unable to obtain debt or equity financing in amounts sufficient to fund our 2008 capital expenditure program fully, we will be forced to suspend or curtail certain of our planned expansion activities, including new station construction and vehicle financing programs, which could harm our business, results of operations, and future prospects.

Our growth depends in part on environmental regulations and programs mandating the use of cleaner burning fuels, and modification or repeal of these regulations may adversely impact our business.

        Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. In particular, the Ports of Los Angeles and Long Beach have adopted the San Pedro Clean Air Action Plan which calls for the replacement of 5,300 trucks that meet certain "clean" truck standards. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles, and in particular the San Pedro Clean Air Action Plan, could have a detrimental effect on the U.S. natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

Our growth depends in part on tax and related government incentives for clean burning fuels. A reduction in these incentives would increase the cost of natural gas fuel and vehicles for our customers and could significantly reduce our revenue.

        Our business depends in part on tax credits, rebates and similar federal, state and local government incentives that promote the use of natural gas as a vehicle fuel in the United States. The federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which began on October 1, 2006, is scheduled to expire after September 30, 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. In 2007, we recorded $17.0 million of revenue related to fuel tax credits, representing approximately 14.5% of our total revenue during the period. The failure to extend the federal excise tax credit for natural gas, or the repeal of federal or state tax credits for the purchase of natural gas vehicles or natural gas fueling equipment, could have a detrimental effect on the natural gas vehicle industry, which, in turn, could adversely affect our business and results of operations. In addition, if grant funds were no longer available under existing government programs, the purchase of or conversion to natural gas vehicles could slow and our business and results of operations could be adversely affected.

The volatility of natural gas prices could adversely impact the adoption of CNG and LNG vehicle fuel and our business.

        In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 to the end of 2007, the price for natural gas, based on the New York Mercantile Exchange (NYMEX) daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. As of December 31, 2007, the NYMEX index price for natural gas was $7.21 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without a futures contract or with an

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ineffective futures contract that does not fully mitigate the price risk or where we otherwise cannot pass on the increased costs to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel. Among the factors that can cause price fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions.

The use of natural gas as a vehicle fuel may not become sufficiently accepted for us to expand our business.

        To expand our business, we must develop new fleet customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We cannot guarantee that we will be able to develop these customers or obtain these fueling contracts. Whether we will be able to expand our customer base will depend on a number of factors, including: the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales, and our ability to supply CNG and LNG at competitive prices.

The infrastructure to support gasoline and diesel consumption is vastly more developed than the infrastructure for natural gas vehicle fuels.

        Gasoline and diesel fueling stations and service infrastructure are widely available in the United States. For natural gas vehicle fuels to achieve more widespread use in the United States and Canada, they will require a promotional and educational effort, and the development and supply of more natural gas vehicles and fueling stations. This will require significant continued effort by us, as well as government and clean air groups, and we may face resistance from oil companies and other vehicle fuel companies. There is no assurance natural gas will ever achieve the level of acceptance as a vehicle fuel necessary for us to expand our business significantly.

A decline in the demand for vehicular natural gas would reduce our revenue and negatively affect our ability to sustain our revenue growth.

        We derive our revenue primarily from sales of CNG and LNG as a fuel for fleet vehicles, and we expect this trend will continue. A downturn in demand for CNG and LNG would adversely affect our revenue and ability to sustain and grow our operations. Circumstances that could cause a drop in demand for CNG and LNG vehicle fuel are described in other risk factors and include a reduction in supply of natural gas, changes in governmental incentives, the development of other alternative fuels and technologies, an economic slowdown and a sustained increase in the price of natural gas relative to gasoline and diesel.

If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline and diesel, potential fleet customers will have less incentive to purchase natural gas vehicles or convert their fleets to natural gas, which would decrease demand for CNG and LNG and limit our growth.

        Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because converting a vehicle to use natural gas adds to its base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, fleet operators may be unable to recover the additional costs of acquiring or converting to natural gas vehicles in a timely manner, and they may choose not to use natural gas vehicles. In that event, our growth would be slowed and our business would suffer.

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Automobile and engine manufacturers produce very few originally manufactured natural gas vehicles and engines for the U.S. and Canadian markets, which may restrict our sales.

        Limited availability of natural gas vehicles restricts their wide scale introduction and narrows our potential customer base. Currently, original equipment manufacturers produce a small number of natural gas engines and vehicles, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. For the North American market, there is only one automobile manufacturer that makes natural gas powered passenger vehicles, and manufacturers of medium and heavy-duty vehicles produce only a narrow range and number of natural gas vehicles. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our sales may be restricted, even if there is demand.

There are a small number of companies that convert vehicles to operate on natural gas, which may restrict our sales.

        Conversion of vehicle engines from gasoline or diesel to natural gas is performed only by a small number of vehicle conversion suppliers that must meet stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. Without an increase in vehicle conversion options, vehicle choices for fleet use will remain limited and our sales may be restricted, even if there is demand.

If there are advances in other alternative vehicle fuels or technologies, or if there are improvements in gasoline, diesel or hybrid engines, demand for natural gas vehicles may decline and our business may suffer.

        Technological advances in the production, delivery and use of alternative fuels that are, or are perceived to be, cleaner, more cost-effective or more readily available than CNG or LNG have the potential to slow adoption of natural gas vehicles. Advances in gasoline and diesel engine technology, especially hybrids, may offer a cleaner, more cost-effective option and make fleet customers less likely to convert their fleets to natural gas. Technological advances related to ethanol or biodiesel, which are increasingly used as an additive to, or substitute for, gasoline and diesel, may slow the need to diversify fuels and impact the growth of the natural gas vehicle market. In addition, hybrid, electric, hydrogen, and other alternative fuels in experimental or developmental stages may eventually offer a cleaner, more cost-effective alternative to gasoline and diesel than natural gas. Advances in technology that slow the growth of or conversion to natural gas vehicles or which otherwise reduce demand for natural gas as a vehicle fuel will have an adverse effect on our business. Failure of natural gas vehicle technology to advance at a sufficient pace may also limit its adoption and ability to compete with other alternative fuels.

Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to source LNG without interruption and near our target markets.

        Production of LNG in the United States is fragmented. LNG is produced at a variety of smaller natural gas plants around the United States as well as at larger plants where it is a byproduct of their primary natural gas production. It may become difficult for us to obtain additional LNG without interruption and near our current or target markets at competitive prices. If our current LNG liquefaction plant, or any of those from which we purchase LNG, is damaged by severe weather, earthquake or other natural disaster, or otherwise experiences prolonged downtime, our LNG supply will be restricted. In addition, the LNG liquefaction plant we are in the process of building in California may be significantly delayed or never completed. If we are unable to supply enough of our own LNG or purchase it from third parties to meet existing customer demand, we may be liable to our customers for penalties. An LNG supply interruption would also limit our ability to expand LNG sales to new customers, which would hinder our growth. Furthermore, because transportation of LNG is

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relatively expensive, if we are required to supply LNG to our customers from distant locations, our operating margins will decrease on those sales.

Two of our third-party LNG suppliers may cancel their supply contracts with us on short notice or increase their LNG prices, which would hinder our ability to meet customer demand and increase our costs.

        Two third-party LNG suppliers supplied approximately 64% of the LNG we sold for the year ended December 31, 2006 and 47% for the year ended December 31, 2007. Our contracts with these LNG suppliers generally may be terminated by the supplier on short notice. Our supply agreement with Williams Gas Processing Company, which supplied 47% and 32% of our LNG for the years ended December 31, 2006 and 2007, respectively, expires on June 30, 2008. In addition, under certain circumstances, Williams may significantly increase the price of LNG we purchase upon 24 hours' notice if Williams' costs to produce LNG increases, and we may be required to reimburse Williams for certain other expenses. Our contract with ExxonMobil Corporation, which supplied 17% of our LNG for the year ended December 31, 2006 and 15% for the year ended December 31, 2007, also expires on June 30, 2008. We may be unable to renew these supply contracts in a timely manner or at all, or upon favorable economic terms. Furthermore, there are a limited number of LNG suppliers in or near the areas where our LNG customers are located. It may be difficult to replace an LNG supplier, and we may be unable to obtain alternate suppliers at acceptable prices, in a timely manner or at all. If supply interruptions were to occur, our ability to meet customer demand would be impaired, customers may cancel orders and we may be subject to supply interruption penalties. If we are subject to LNG price increases, our operating margins may be impaired and we may be forced to sell LNG at a loss under our LNG supply contracts.

If we are unable to obtain natural gas in the amounts needed on a timely basis or at reasonable prices, we could experience an interruption of CNG or LNG deliveries or increases in CNG or LNG costs, either of which could have an adverse effect on our business.

        Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases fuel price. If there are interruptions in field production, pipeline capacity, equipment failure, liquefaction production or delivery, we may experience supply stoppages which could result in our inability to fulfill delivery commitments. This could result in our being liable for contractual damages and daily penalties or otherwise adversely affect our business.

Oil companies and natural gas utilities, which have far greater resources and brand awareness than we have, may expand into the natural gas fuel market, which could harm our business and prospects.

        There are numerous potential competitors who could enter the market for CNG and LNG as vehicle fuels. Many of these potential entrants, such as integrated oil companies and natural gas utilities, have far greater resources and brand awareness than we have. If the use of natural gas vehicles increases, these companies may find it more attractive to enter the market for natural gas vehicle fuels and we may experience increased pricing pressure, reduced operating margins and fewer expansion opportunities.

We are in the process of constructing a new LNG liquefaction plant, which could cost more to build and operate than we estimate and divert resources and management attention.

        We are in the process of constructing an LNG liquefaction plant in California, which we plan to operate upon completion. The construction, implementation and operation of any plant of this nature has inherent risks. Permitting, environmental issues, lack of materials and lack of human resources,

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among other factors, could delay implementation and start up of the new LNG liquefaction plant and affect the operation of the plant. Building the new facility could also present increased financial exposure through project delays, cost-overruns and incomplete production capability. If the new plant has higher than expected construction or operating costs and is not able to produce expected amounts of LNG, we may be forced to sell LNG at a price below production costs and we may lose money. Additionally, if the quality of LNG produced at the plant does not meet contractual specifications, our customers may not be required to purchase it, which would harm our business.

If we do not have effective futures contracts in place, increases in natural gas prices may cause us to lose money.

        From 2005 to 2007, we sold and delivered approximately 27% of our total gasoline gallon equivalents of CNG and LNG under contracts that provided a fixed price or a price cap to our customers over terms typically ranging from one to three years, and in some cases up to five years. At any given time, however, the market price of natural gas may rise and our obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase or production price if we do not have effective futures contracts in place. This circumstance has in the past and may again in the future compel us to sell fuel at a loss, which would adversely affect our results of operations and financial condition. Commencing with the adoption of our revised natural gas hedging policy in February 2007, we expect to purchase futures contracts to hedge our exposure to variability related to substantial fixed price contracts. However, such contracts may not be available or we may not have sufficient financial resources to secure such contacts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not economically hedged with respect to our fixed price contracts, we will lose money in connection with those contracts during periods in which natural gas prices increase above the prices of natural gas included in our customers' contracts. As of December 31, 2007, we were not economically hedged with respect to any of the anticipated requirements of our fixed price contracts, having sold the related futures contracts which we previously held. Based on natural gas prices as of December 31, 2007, we estimate we will incur between $3.3 million to $4.0 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.

Our futures contracts may not be as effective as we intend.

        Our purchase of futures contracts can result in substantial losses under various circumstances, including if we do not accurately estimate the volume requirements under our fixed price or price cap customer contracts when determining the volumes included in the futures contracts we purchase. We also could incur significant losses if a counterparty does not perform its obligations under the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot assure that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

A decline in the value of our futures contracts may result in margin calls that would adversely impact our liquidity.

        We are required to maintain a margin account to cover losses related to our natural gas futures 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. Payments we make to satisfy

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margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us.

Boone Pickens cancelled his guarantee of our futures contracts, which will require us to make significantly larger initial margin deposits when we purchase futures contracts. This will adversely affect our cash flows, and we may be unable to secure these contracts on terms that are favorable or affordable to us or at all.

        Historically, we have purchased all of our natural gas futures contracts through Sempra Energy Trading Corp. We did not have any futures contracts outstanding at December 31, 2007. Our past obligations under our contract with Sempra were guaranteed by Boone Pickens. Mr. Pickens is our largest stockholder, a director and the principal of BP Capital, L.P., which advises us regarding our hedging activities. As Mr. Pickens cancelled his guarantee with Sempra in March 2007, Sempra may cancel our contract with them at any time. Without Mr. Pickens' guarantee, we expect to have significantly larger requirements for upfront margin deposits, on the order of up to fifteen times greater than our previous deposit requirements. We also anticipate that it will be more difficult to purchase futures contracts generally (i.e., through Sempra or other third parties) without his guarantee. If we cannot enter into futures contracts, our ability to offer fixed price supply contracts to our customers may be impaired and we will become more susceptible to price fluctuations and losses if this were to occur.

If our futures contracts do not qualify for hedge accounting, our net income and stockholders' equity will fluctuate more significantly from quarter to quarter based on fluctuations in the market value of our futures contracts.

        We account for our futures activities under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended (SFAS 133), which requires us to value our futures contracts at fair market value in our financial statements. Our futures contracts historically have not qualified for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item "derivative (gains) losses" along with any realized gains or losses during the period. In the future, we will attempt to qualify all of our futures contracts for hedge accounting under SFAS 133, but there can be no assurances that we will be successful in doing so. To the extent that all or some of our futures contracts do not qualify for hedge accounting, we could incur significant increases and decreases in our net income and stockholders' equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. For example, we experienced a derivative gain of $33.1 million 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, September 30, 2007 and December 31, 2007. Any negative fluctuations may cause our stock price to decline due to our failure to meet or exceed the expectations of securities analysts or investors.

Natural gas operations entail inherent safety and environmental risks that may result in substantial liability to us.

        Natural gas operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past

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been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Additionally, CNG fuel tanks, if damaged or improperly maintained, may rupture and the contents of the tank may rapidly decompress and result in injury. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits.

Our business is heavily concentrated in the western United States, particularly in California and Arizona. Economic downturns in these regions could adversely impact our business.

        Our operations to date have been concentrated in California and Arizona. For the years ended December 31, 2006 and 2007, sales in California accounted for approximately 38% and 40%, respectively, and sales in Arizona accounted for approximately 23% and 20%, respectively, of the total amount of gallons we delivered. A decline in the economy in these areas could slow the rate of adoption of natural gas vehicles or impact the availability of incentive funds, both of which could negatively impact our growth.

We provide financing to fleet customers for natural gas vehicles, which exposes our business to credit risks.

        We loan to our customers up to 100% of the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. Some of these risks include: most of the equipment financed is vehicles, which are mobile and easily damaged, lost or stolen; there is a risk the borrower may default on payments; we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service; and the amount of capital available to us is limited and may not allow us to make loans required by customers.

Our finance and leasing activities may be unsuccessful due to competitive pressures.

        The fleet financing and leasing marketplace is competitive and dominated by large finance companies. These companies may have greater financial resources than we do, offer more attractive rates to customers, finance other types of vehicles and equipment and offer a wider range of financial services to the customer. If these large finance companies do finance natural gas vehicles and if potential customers prefer to work with these companies, our business may be disadvantaged.

We may incur losses and use working capital if we are unable to place with customers the natural gas vehicles that we or our business partners order from manufacturers.

        To ensure availability for our customers, we from time to time enter into binding purchase agreements for natural gas vehicles when there is a production lead time. Although we attempt to arrange for customers to purchase the vehicles before delivery to us, we may be unable to locate purchasers on a timely basis and consequently may need to take delivery of and title to the vehicles. These purchases would adversely affect our cash reserves until such time as we can sell the vehicles to our customers, and we may be forced to sell the vehicles at a loss. At December 31, 2007, we had approximately $17.5 million of vehicles under binding purchase agreements, of which $15.4 million had been paid at December 31, 2007, without corresponding customer orders.

        We may also agree to guaranty the purchase of natural gas vehicles on behalf of our business partners. For example, in July 2006, we entered into an agreement with Inland Kenworth, Inc. (Inland) pursuant to which we agreed to deposit certain amounts with Inland, as security for a guaranty, to help fund the acquisition by Kenworth Truck Company (Kenworth) of up to 125 diesel tractors. At December 31, 2007, we had made approximately $9.5 million of deposits under this agreement. If any

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tractor purchased by Inland remains unsold after a period of 365 days, we must either purchase the tractor or instruct Inland to sell the tractor.

We have advanced deposits to a business partner to help fund the conversion of diesel tractors to run on LNG. To the extent any converted tractor is not sold within 24 months of the date of the applicable deposit agreement, we may forfeit the deposit related to such vehicle.

        We entered into two deposit agreements with Westport in 2007 to facilitate the production of LNG fuel systems for installation in the tractors purchased by Inland. At December 31, 2007, we had advanced a total of $5.9 million to Westport under these agreements. Repayment of these deposits will occur incrementally upon the sale of the converted tractors to customers; however, to the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the applicable deposit agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel system.

If we are unable to attract, retain and motivate our executives and other key personnel, our business would be harmed.

        Our ability to manage and expand our business depends significantly on the skills and services of our management team, each of whom may terminate his or her service with us at any time and none of whom are subject to non-compete restrictions. We believe the loss of one or more members of our management team would harm our business because few people have comparable experience working in the natural gas vehicle industry or managing companies similar to ours. Moreover, we expect our operations to grow, and to do so, we will need to hire additional personnel in all areas of our business, particularly in sales and marketing. Competition for qualified personnel is intense, and we may be unable to attract or retain qualified personnel and expand our business as planned.

We rely on related parties for advice regarding our derivative activities, and this advice may not be available to us in the future.

        We depend upon Boone Pickens and his firm, BP Capital, L.P., for advice regarding energy markets and derivative activities. We cannot guarantee that we will be able to retain these services for any period of time. BP Capital may terminate its investment advisory agreement with us at any time upon 30 days written notice to us.

We may have difficulty managing our planned growth.

        If our business grows as planned, our management team and our operational, financial and accounting systems will also need to be expanded. This expansion would result in increased expenses and may strain our resources. If we are unable to manage this growth, we may experience higher expenses, poor internal controls, employee attrition and customer dissatisfaction, any of which could harm our business. Additionally, we may find it difficult to maintain important aspects of our corporate culture, which could negatively affect our ability to retain and recruit personnel, and otherwise adversely affect our future success.

There are many risks associated with conducting operations in international markets.

        We are in the process of expanding our operations outside of the United States and Canada. For example, in August 2007, we executed a joint venture agreement with Energy Gas del Peru pursuant to which we intend to build and operate natural gas fueling stations in Lima, Peru. Changes in local economic or political conditions in foreign countries could have a material adverse effect on our business, consolidated financial condition, results of operations and cash flows. Additional risks inherent in our international business activities include the following: difficulties in managing international

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operations, including our ability to timely and cost effectively execute projects; unexpected changes in regulatory requirements; tariffs and other trade barriers that may restrict our ability to enter into new markets; governmental actions that result in the deprivation of contract rights; changes in political and economic conditions in the countries in which we operate, including civil uprisings, riots, kidnappings and terrorist acts; changes in foreign currency exchange rates; potentially adverse tax consequences; restrictions on repatriation of earnings or expropriation of property without fair compensation; difficulties in establishing new international offices and risks inherent in establishing new relationships in foreign countries; and the burden of complying with the various laws and regulations in the countries in which we operate.

        Our future plans involve expanding our business in international markets where we do not conduct business. The risks inherent in establishing new business ventures, especially in international markets where local customs, laws and business procedures present special challenges, may affect our ability to be successful in these ventures or avoid losses which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

If we are unable to adequately protect our intellectual property, our business could be harmed.

        We protect our intellectual property through a combination of trademark laws, confidentiality procedures, contractual provisions and seeking patents, when appropriate. Nonetheless, our intellectual property rights may not be successfully asserted in the future or may be invalidated, circumvented or challenged. Enforcement of intellectual property rights against alleged infringers can sometimes lead to costly litigation and counterclaims. Our inability to protect our proprietary information could harm our business.

We have significant contracts with federal, state and local government entities, which are subject to unique risks.

        We have existing, and will continue to seek, long-term LNG and CNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long-term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition.

Our business is subject to a variety of governmental regulations that may restrict our business and may result in costs and penalties.

        We are subject to a variety of federal, state and local laws and regulations relating to the environment, health and safety, labor and employment and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities.

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        In connection with our LNG liquefaction activities, we need to apply for additional facility permits or licenses to address storm water or wastewater discharges, waste handling, and air emissions related to production activities or equipment operations. This may subject us to permitting conditions that may be onerous or costly. Compliance with laws and regulations and enforcement policies by regulatory agencies could require us to make material expenditures.

The requirements of being a public company, including the costs of complying with Section 404 of the Sarbanes-Oxley Act of 2002, may strain our resources and distract management.

        As a public company, we are incurring significant legal, accounting and other expenses that we did not incur as a private company. The Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act"), as well as rules subsequently implemented by the Securities and Exchange Commission (SEC), NASDAQ and other stock exchanges, have required changes in corporate governance practices of public companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. For example, as a result of becoming a public company, we have created additional board committees and have implemented a number of new corporate policies. In addition, we are incurring additional costs associated with our public company reporting. We also expect these new rules to make it more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage.

        Ensuring that we have adequate financial and accounting controls to produce accurate financial statements on a timely basis is a costly and time-consuming effort that needs to be re-evaluated frequently. We will need to begin the process of documenting, reviewing and improving our internal controls in order to comply with Section 404 of the Sarbanes-Oxley Act, which requires management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm addressing these assessments. Both we and our independent registered public accounting firm will be testing our internal controls in connection with the Section 404 requirements and, as part of that documentation and testing, identifying areas for further attention and improvement. Improving our internal controls will likely involve substantial costs and take significant time to complete, which may distract our officers, directors and employees from the operation of our business. These efforts may not ultimately be effective to maintain adequate internal controls. If we fail to establish and maintain effective controls and procedures for financial reporting, we could be unable to provide timely and accurate financial information. In addition, investor perceptions that our internal controls are inadequate or that we are unable to produce accurate financial statements may negatively affect our stock price.

        Our independent registered public accounting firm has identified certain internal controls over financial reporting that we will need to strengthen in connection with being a public company, and we have not yet implemented all the suggested improvements. Specifically, we will need to further automate several of our processes, hire additional personnel with finance and accounting expertise and add additional policies and procedures to bolster our control and disclosure environments. Hiring qualified employees is challenging, and we may be unable to find the people with the skill sets we require in a timely manner. Modifying and changing systems and procedures is also challenging, and new systems or procedures may not prove to be efficient and effective once they are in place. Our accounting and financial reporting department may not have all of the necessary resources to ensure that we will not have significant deficiencies or material weaknesses in our system of internal control over financial reporting. The effectiveness of our internal control over financial reporting may be limited by a variety of factors including: faulty human judgment and errors, omissions or mistakes, inappropriate management override of policies and procedures, and the possibility that any enhancements to disclosure controls and procedures may still not be adequate to assure timely and accurate financial information.

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Our quarterly results of operations have not been predictable in the past and have fluctuated significantly and may not be predictable and may fluctuate in the future.

        Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were $3.0 million, $1.1 million, $58.8 million, $14.6 million, $0.9 million, $3.6 million, $1.5 million and $2.9 million for the three months ended March 31, 2006, June 30, 2006, September 30, 2006, December 31, 2006, March 31, 2007, June 30, 2007, September 30, 2007 and December 31, 2007, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations historically have primarily been attributable to our derivative gains and losses, but also may be due to a number of other factors, including, but not limited to: our ability to increase sales to existing customers and attract new customers; the addition or loss of large customers; construction cost overruns; the amount and timing of operating costs and capital expenditures related to the maintenance and expansion of our business, operations and infrastructure; changes in the price of natural gas; changes in the prices of CNG and LNG relative to gasoline and diesel; changes in our pricing policies or those of our competitors; the costs related to the acquisition of assets or businesses; regulatory changes; and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

The price of our common stock may be volatile as a result of market conditions unrelated to our company, and the value of your investment could decline.

        The trading price of our common stock may fluctuate substantially due to factors in the market beyond our control. These fluctuations could cause you to lose all or part of your investment in our common stock. Factors that could cause fluctuations in the trading price of our common stock include: price and volume fluctuations in the overall stock market from time to time; actual or anticipated changes or fluctuations in our results of operations; actual or anticipated changes in the expectations of investors or securities analysts; actual or anticipated developments in our competitors' businesses or the competitive landscape generally; litigation involving us or our industry; domestic and international regulatory developments; general economic conditions and trends; widespread adoption of other alternative fuels and technologies; major catastrophic events or sales of large blocks of our stock. Since our initial public offering, which was completed in May 2007, the price of our common stock has ranged from an intra-day low of $10.81 to an intra-day high of $20.65 through March 10, 2008.

Sales of outstanding shares of our stock into the market in the future could cause the market price of our stock to drop significantly, even if our business is doing well.

        If our existing stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline. At December 31, 2007, 44,274,375 shares of our common stock were outstanding. The 11,500,000 shares sold in our initial public offering are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. All other outstanding shares of common stock may be sold under Rule 144 under the Securities Act of 1933, as amended (the Securities Act), subject to applicable restrictions.

        In addition, as of December 31, 2007, there were 6,553,036 shares underlying outstanding options and 15,000,000 shares underlying an outstanding warrant. These shares are eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements and Rule 144. If these additional shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our stock could decline.

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If securities analysts stop publishing research or reports about our business, or if they downgrade our stock, the price of our stock could decline.

        The trading market for our common stock relies in part on the research and reports that industry or financial analysts publish about us. We do not control these analysts. If one or more of the analysts who do cover us downgrade our stock, our stock price would likely decline. Further, if one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.

A majority of our stock is beneficially owned by a single stockholder whose interests may differ from yours and who will be able to exert significant influence over our corporate decisions, including a change of control.

        As of December 31, 2007, Boone Pickens and affiliates (including Madeleine Pickens, his wife) beneficially owned in the aggregate approximately 55.6% of our outstanding common stock (according to a Schedule 13D filed on such date), inclusive of the 15,000,000 shares underlying the warrant held by Mr. Pickens. As a result, Mr. Pickens will be able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may also have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

Provisions in our certificate of incorporation and bylaws and Delaware law may discourage, delay or prevent a change of control of our company or changes in our management and, therefore, depress the trading price of our stock.

        Our certificate of incorporation and bylaws contain provisions that could depress the trading price of our stock by acting to discourage, delay or prevent a change of control of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions:

    authorize the issuance of "blank check" preferred stock that our board of directors could issue to increase the number of outstanding shares to discourage a takeover attempt,

    provide that a special meeting of stockholders may only be called by our board of directors or our chief executive officer,

    provide that the board of directors is expressly authorized to make, alter or repeal our bylaws, and

    establish advance notice requirements for nominations for elections to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

        Additionally, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any "interested" stockholder for a period of three years following the date on which the stockholder became an "interested" stockholder and which may discourage, delay or prevent a change of control of our company.

Item 1B.    Unresolved Staff Comments.

        We have no unresolved comments from the SEC.

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Item 2.    Properties.

        Our executive offices are located at 3020 Old Ranch Parkway, Suite 200, Seal Beach, CA 90740, where we occupy approximately 20,750 square feet. Our monthly rental payments for these offices are approximately $51,500. Our office lease expires in December 2010. We believe our existing facilities are adequate for our current needs.

        We also lease facilities for our satellite sales and service offices in Boston, Denver, Dallas, Vancouver, Toronto and Phoenix, and our monthly rent payments for such facilities are approximately $17,000 per month in the aggregate.

        We own and operate the Pickens Plant located in Willis, Texas, approximately 50 miles north of Houston. We own approximately 24 acres on which the plant is situated, along with approximately 34 acres surrounding the plant.

        We are building an LNG liquefaction plant in California and expect this plant to be operational in the fall of 2008, assuming we do not experience significant construction delays. In November 2006, we entered into a ground lease for the 36 acres on which this plant will be situated. 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. In addition, 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.

        We lease the land upon which we construct, operate and maintain some of our CNG and LNG fueling stations for our customers. We often own the equipment and fixtures that comprise the CNG fueling stations. The ground leases for our stations typically have a term of 10 years and require payments of a fixed amount or a variable amount based on the number of gallons sold at the site during the period. As of December 31, 2007, we leased the land for 61 stations and for the year ended December 31, 2007, paid a total of approximately $887,000 in rent under the station ground leases.

Item 3.    Legal Proceedings.

        We may become party to various legal actions that arise in the ordinary course of our business. 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 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 our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse affect on our consolidated financial position, results of operations, or liquidity.

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

        None

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

        Our common stock has been quoted on the Nasdaq Global Market under the symbol "CLNE" since May 25, 2007. Prior to that time, there was no public market for our stock. Set forth below are the high and low sales prices as reported by Nasdaq for our common stock for the periods indicated.

 
  Sales Prices
 
  High
  Low
Fiscal Year 2007
           
  Second Quarter   $ 13.90   $ 11.40
  Third Quarter   $ 18.80   $ 10.81
  Fourth Quarter   $ 20.65   $ 12.55

Holders

        There were approximately 96 stockholders of record as of March 10, 2008. We believe there are approximately 12,770 stockholders of our common stock held in street name.

Dividend Policy

        We have not paid any dividends to date and do not anticipate paying any dividends on our common stock in the foreseeable future. We anticipate that all future earnings will be retained to finance future growth.

Use of Proceeds

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

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

        Through December 31, 2007, we have used the net proceeds from the offering as follows:

    construction of our LNG liquefaction plant in California ($16.8 million),

    construction and installation of CNG and LNG stations ($3.2 million),

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    financing customer vehicle purchases ($1.4 million), and

    working capital ($14.1 million), including advances to Westport Innovations Inc. of approximately $5.9 million in the aggregate to facilitate the production of LNG fuel systems for installation in trucks we expect to be sold to fleet customers servicing the Ports of Los Angeles and Long Beach (see Part II, Item 9B for more information regarding these advances).

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

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Performance Graph

        This performance graph shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or incorporated by reference into any filing of Clean Energy Fuels Corp. under the Securities Act, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

        The following graph shows a comparison from May 25, 2007 (the date our common stock commenced trading on The Nasdaq Global Market) through December 31, 2007 of the cumulative total return for our common stock, the Nasdaq Global Market Index, and the Russell 2000 Growth Index. We chose to include the Russell 2000 Growth Index as a comparable index due to the lack of a comparable industry index or peer group. We are the only actively-traded public company whose only line of business is to sell natural gas as a vehicle fuel. Such returns are based on historical results and are not intended to suggest future performance. Data for the Nasdaq Global Market Index and the Russell 2000 Growth Index assumes reinvestment of dividends.

GRAPHIC


*
Assumes $100 was invested on May 25, 2007 in our common stock, the Nasdaq Global Market Index, and the Russell 2000 Growth Index. The Nasdaq Global Market Index and the Russell 2000 Growth Index results include reinvestment of dividends.

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Item 6.    Selected Financial Data.

        You should read the following selected historical consolidated financial data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the notes elsewhere in this Form 10-K.

        The consolidated statements of operations data for the years ended December 31, 2005, 2006 and 2007 and the consolidated balance sheet data at December 31, 2006 and 2007 are derived from our audited consolidated financial statements in this Form 10-K. The consolidated statements of operations data for the years ended December 31, 2003 and 2004, and the consolidated balance sheet data at December 31, 2003, 2004 and 2005 are derived from our audited consolidated financial statements that are not included in this Form 10-K. The historical results are not necessarily indicative of the results to be expected in any future period.

 
  Year Ended December 31,
 
 
  2003
  2004
  2005
  2006
  2007
 
Statement of Operations Data:                                
Revenue (1)   $ 40,293,500   $ 57,641,605   $ 77,955,083   $ 91,547,316   $ 117,716,233  
Operating expenses:                                
Costs of sales     37,622,166     48,772,296     72,004,077     74,047,901     85,660,329  
Derivative (gains) losses (2)     (12,161,875 )   (10,572,349 )   (44,067,744 )   78,994,947      
Loss on extinguishment of derivative liability                 2,142,095      
Selling, general and administrative     11,131,743     11,112,878     17,108,425     20,860,181     35,933,694  
Depreciation and amortization     2,972,315     3,810,419     3,948,544     5,765,001     7,107,942  
   
 
 
 
 
 
Total operating expenses:     39,564,349     53,123,244     48,993,302     181,810,125     128,701,965  
   
 
 
 
 
 
Operating income (loss)     729,151     4,518,361     28,961,781     (90,262,809 )   (10,985,732 )
Interest income (expense), net     29,948     (96,983 )   59,780     746,339     3,505,597  
Other (expense), net     (532,840 )   (605,312 )   (140,921 )   (255,479 )   (192,347 )
   
 
 
 
 
 
Income (loss) before income taxes     226,259     3,816,066     28,880,640     (89,771,949 )   (7,672,482 )
Income tax expense (benefit)     210,797     1,686,825     11,623,053     (12,271,208 )   1,221,880  
   
 
 
 
 
 
Net income (loss)   $ 15,462   $ 2,129,241   $ 17,257,587   $ (77,500,741 ) $ (8,894,362 )
   
 
 
 
 
 
Basic earnings (loss) per share   $ 0.00   $ 0.11   $ 0.76   $ (2.45 ) $ (0.22 )
   
 
 
 
 
 
Fully diluted earnings (loss) per share   $ 0.00   $ 0.11   $ 0.75   $ (2.45 ) $ (0.22 )
   
 
 
 
 
 
Weighted average common shares outstanding:                                
Basic     17,572,636     18,949,636     22,602,033     31,676,399     40,258,440  
   
 
 
 
 
 
Diluted     17,572,636     18,949,636     23,191,674     31,676,399     40,258,440  
   
 
 
 
 
 

(1)
Revenue includes the following amounts:

 
  Year Ended December 31,
 
  2003
  2004
  2005
  2006
  2007
Fuel tax credits (VETC)   $ 0   $ 0   $ 0   $ 3,810,109   $ 17,046,412
   
 
 
 
 
(2)
2006 amount includes $78,712,599 of losses on certain derivative contracts. The contracts were assumed by our largest stockholder, Boone Pickens, on December 28, 2006. See note 10 to our consolidated financial statements.

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  December 31,
 
  2003
  2004
  2005
  2006
  2007
Balance Sheet Data:                              
Cash and cash equivalents   $ 6,774,456   $ 1,299,746   $ 28,763,445   $ 937,445   $ 67,937,602
Short-term investments                     12,479,684
Working capital     4,255,035     8,375,627     27,426,766     44,811,284     119,480,877
Total assets     73,117,214     79,812,007     128,613,650     136,932,636     249,024,944
Long-term debt, inclusive of current portion     7,161,461     5,921,999     5,100,256     282,396     224,897
Stockholders' equity     49,950,326     62,063,424     93,489,868     122,915,857     230,932,474
 
 
  Year Ended December 31,
 
  2005
  2006
  2007
Key Operating Data:            
  Gasoline gallon equivalents delivered (in millions):            
    CNG   36.1   41.9   48.0
    LNG   20.7   26.5   27.3
   
 
 
    Total   56.8   68.4   75.3

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

         The discussion in this section contains forward-looking statements. These statements relate to future events or our future financial performance. We have attempted to identify forward-looking statements by terminology such as "anticipate," "believe," "can," "continue," "could," "estimate," "expect," "intend," "may," "plan," "potential," "predict," "should," "would" or "will" or the negative of these terms or other comparable terminology, but their absence does not mean that a statement is not forward looking. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, which could cause our actual results to differ from those projected in any forward-looking statements we make. See "Risk Factors" in Part I, 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.

        Key operating data.     In evaluating our operating performance, our management focuses primarily on (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as the volume of gasoline gallon equivalents we sell to our customers plus the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide O&M services but do not directly sell the CNG or LNG) and (2) our revenue and net income (loss). The following table, which you should read in conjunction with our consolidated financial statements and notes contained elsewhere in this Form 10-K, presents our key operating data for the years ended December 31, 2005, 2006 and 2007:

 
  Year Ended December 31,
 
Gasoline gallon equivalents delivered (in millions)

 
  2005
  2006
  2007
 
CNG     36.1     41.9     48.0  
LNG     20.7     26.5     27.3  
   
 
 
 
Total     56.8     68.4     75.3  
Operating data                    
Revenue   $ 77,955,083   $ 91,547,316   $ 117,716,233  
Net income (loss)     17,257,587     (77,500,741 )   (8,894,362 )

        Key trends in 2005, 2006 and 2007.     Vehicle fleet demand for natural gas fuels increased significantly during the years ended December 31, 2005, 2006 and 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.

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        The number of fueling stations we served grew from 147 at December 31, 2004 to 170 at December 31, 2007 (a 15.6% increase), and the total annual amount of CNG and LNG gasoline gallon equivalents we delivered increased by 32.6% from 2005 to 2007. The increase in gasoline gallon equivalents delivered, together with 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 have built a natural gas fueling station, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the ports of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, refuse hauling and airports. Consistent with the anticipated growth of our business, we also expect that our operating costs 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 process 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. Our business plan calls for approximately $105 million in capital expenditures in 2008, primarily related to building an LNG liquefaction plant in California, constructing new fueling stations, 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. As of the date of this report, we project a budget shortfall of approximately $40 million for 2008 related to planned capital expenditures. If we are unable to raise sufficient capital in the debt or equity markets to make up for this shortfall, we will be forced to suspend or curtail certain expansion projects. For more information, see "Liquidity and Capital Resources" below.

        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, have materially impacted our results of operations in recent periods. For the years ended December 31, 2005, 2006 and 2007 derivative (gains) losses were $(44,067,744), and $78,994,947 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, please read "Volatility of Earnings and Cash Flows" and "Risk Management Activities" below.

        Business risks and uncertainties.     Our business and prospects are exposed to numerous risks and uncertainties. For more information, see "Risk Factors" in Part I, Item 1A.

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Operations

        We generate revenues principally by selling CNG and LNG to our vehicle fleet customers. For the year ended December 31, 2007, CNG represented 64% and LNG represented 36% 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. A significant portion of our CNG sales are made through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. We sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

        We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. For LNG that we purchase from third-parties, we typically enter into "take or pay" contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 60 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we 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.

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Operation and Maintenance

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

Station Construction

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

Vehicle Acquisition and Finance

        In 2006, we commenced offering vehicle finance services for some of our customers' purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to our customers up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. As of December 31, 2007, we have not generated significant 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 No. 133. See "Critical Accounting Policies—Derivative Activities" below. We have therefore recorded any changes in the fair market value of these contracts directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $33.1 million for the three months ended September 30, 2005 and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million and $13.7 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006 and December 31, 2006, respectively. We had no derivative gains or losses for the year ended December 31, 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 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.

        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 December 31, 2007, we had no futures contracts outstanding and no amounts on deposit.

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Risk Management Activities

        A significant portion of our natural gas fuel sales are covered by contracts to sell LNG or CNG to our customers at a fixed price or a variable index-based price subject to a cap. These contracts expose us to the risk that the price of natural gas may increase above the natural gas cost component included in the price at which we are committed to sell gas to our customers. We account for sales of natural gas under these contracts as described below in "Critical Accounting Policies—Fixed Price and Price Cap Sales Contracts."

Risk Management Practices Before February 2007

        Historically, when we entered into a contract to sell natural gas fuel to a customer at a fixed price or a variable price subject to a cap, we generally sought to manage our exposure to natural gas price increases for some or all of the expected contract volumes in the natural gas futures market. We did this by purchasing futures contracts that were designed to cover the difference between the commodity portion of the price at which we were committed to sell natural gas and the price we had to pay for gas at delivery, thereby fixing the cost of natural gas we were paying. We generally purchased futures 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 often 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. These futures contracts were transferred to and assumed by Boone Pickens in December 2006. See note 10 to our consolidated financial statements.

        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 March 31, 2007, 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 remits realized net gains to us, less its applicable commissions, on a monthly basis. We paid fees to BP Capital of $11.7 million in 2005, $2.4 million in 2006 and $120,000 in 2007. In March 2007, we amended our agreement with BP Capital to remove the 20% commission on our realized gains and losses during a calendar year.

        We historically have purchased our natural gas futures contracts from Sempra Energy Trading Corp. 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 has historically required a deposit of $1,000, which is below market due to the fact that Boone Pickens

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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 December 31, 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

        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. See note 10 to our consolidated financial statements. 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. For example, based on the closing price of our common stock on December 31, 2007 ($15.14 per share), this warrant would contribute approximately 5.1 million shares to our fully diluted shares outstanding calculation.

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 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;

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

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

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

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

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

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

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

    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 No. 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.

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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. We use historical experience, market quotes, and other assumptions as the basis for making estimates. Actual results could differ from those estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Revenue Recognition

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

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

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

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

Derivative Activities

        We account for our derivative instruments, specifically our futures contracts, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended. SFAS No. 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 No. 133 for the years ended December 31, 2005 and 2006. As such, changes in the fair value of the derivatives were recorded directly to our consolidated statements of operations.

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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 own any derivative instruments during the year ended December 31, 2007.

        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. Under U.S. generally accepted accounting principles, or GAAP, we record the actual results of delivering the fuel under the contract as the sale of the natural gas occurs. When we enter into these fixed price or price cap contracts with our customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer's contract price and the corresponding index price of natural gas typically develops after we enter into the sales contract. If at the time we sell natural gas under the contract the prevailing index price for natural gas exceeds the commodity portion of our contracted sale price, we incur a loss. During the year ended December 31, 2005, the price of natural gas generally increased, and during the years ended December 31, 2006 and 2007, the price of natural gas generally decreased. During these periods, we 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.

        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 December 31, 2007:

 
  Estimated volumes(a)
  Average price(b)
  Contracts Duration
CNG fixed price contracts   1,383,707   $ 1.14   through 12/13
LNG fixed price contracts   12,810,483   $ 0.39   through 07/09
CNG price cap contracts   4,334,091   $ 0.86   through 12/09
LNG price cap contracts   7,614,390   $ 0.49   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 the remaining duration of the contracts.

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

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

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we estimate our pre-tax net income would have been lower (higher) by the following ranges for the periods indicated:

Year Ended
   
   
   
 
December 31, 2005   $ 15,148,070   to   $ 18,514,308  
December 31, 2006   $ (14,267,259 ) to   $ (17,437,761 )
December 31, 2007   $ (4,122,914 ) to   $ (5,039,117 )

        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.

        At December 31, 2007, we estimate we will incur between $3.3 million and $4.0 million to cover the increased price of natural gas above the inherent price of natural gas embedded in our customer's fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on December 31, 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:

2008   15,709,619
2009   2,486,896
2010   230,000
2011   230,000
2012   230,000
2013   230,000

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.

Stock-Based Compensation

        Effective January 1, 2006, we account for stock options granted using Statement of Financial Accounting Standards No. 123(R) (SFAS No. 123(R)), Share-Based Payment , which has replaced SFAS No. 123 and APB 25. Under SFAS No. 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 No. 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 No. 123. Under SFAS No. 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

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the use of management's judgment in estimating the inputs used to determine fair value. We elected, under the provisions of SFAS No. 123, to account for employee stock-based compensation under APB 25 during the year ended December 31, 2005. In the consolidated statements of operations, we recorded no compensation expense in 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 statement of operations. However, our footnotes disclose the impact on net income in 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 No. 123(R) has been reflected in the consolidated statements of operations for share-based awards granted in 2006 and 2007.

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 No. 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 No. 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, 2005, 2006 and 2007, and there was no impairment indicated.

Recently Issued Accounting Pronouncements

        See Note 1(d) to our consolidated financial statements.

Results of Operations

Fiscal Year Ended December 31, 2007 Compared to Fiscal Year Ended December 31, 2006

        Revenue.     Revenue increased by $26.2 million to $117.7 million in the year ended December 31, 2007, from $91.5 million in the year ended December 31, 2006. A portion of this increase was the result of an increase in the number of CNG and LNG gallons delivered from 68.4 million gasoline gallon equivalents to 75.3 million gasoline gallon equivalents, together with an increase in our average price per gallon between periods. Our effective price per gallon was $1.27 in the year ended December 31, 2007, which represents a $0.01 per gallon increase from $1.26 in the year ended December 31, 2006. 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 5.6 million gasoline gallons 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. We recorded $13.2 million of additional revenue related to fuel tax credits in 2007 compared to 2006. The credits first became available in October 2006. We also experienced an increase between periods of $3.2 million in station construction revenue.

        Cost of sales.     Cost of sales increased by $11.7 million to $85.7 million in the year ended December 31, 2007, from $74.0 million in the year ended December 31, 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 $3.2 million increase in costs related to construction activities during the year ended December 31, 2007. In addition, our cost of sales increased between periods as our effective cost per gallon rose to $1.08 in 2007, which represents a $0.02 per gallon increase over 2006.

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        Derivative losses.     We incurred derivative losses of $79.0 million in the year ended December 31, 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 year ended December 31, 2007 because we did not own any derivative instruments during this period.

        Selling, general and administrative.     Selling, general and administrative expenses increased by $15.0 million to $35.9 million in the year ended December 31, 2007, from $20.9 million in the year ended December 31, 2006. The increase was primarily related to recording an aggregate of $7.4 million of stock option expense in the second, third and fourth quarters of 2007 associated with the stock options we granted to our employees in May 2007, September 2007 and December 2007. There was also an increase of $2.7 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 97 at December 31, 2006 to 121 at December 31, 2007. In addition, our travel and entertainment expenses increased $0.6 million between periods, primarily due to increased travel related to our sales team. Our marketing expenses increased $1.3 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 $1.1 million between periods as we provided a reserve against loans made to a vehicle manufacturer and two of our vehicle financing customers during 2007. Our professional service fees increased $1.1 million between periods primarily for legal, audit and consulting services related to our status as a public company. Our business insurance costs also increased $0.8 million between periods, primarily due to premium increases in our directors' and officers' insurance between periods.

        Depreciation and amortization.     Depreciation and amortization increased by $1.3 million to $7.1 million in the year ended December 31, 2007, from $5.8 million in the year ended December 31, 2006. This increase was primarily related to the result of additional depreciation expense in 2007 related to increased property and equipment balances between periods, primarily related to our expanded station network and fleet of LNG tanker trailers.

        Interest income, net.     Interest income, net, increased by $2.8 million from $0.7 million in the year ended December 31, 2006, to $3.5 million for the year ended December 31, 2007. This increase was primarily the result of a decrease in interest expense in 2007 due to the conversion of $4 million of convertible notes in April 2007, which eliminated the interest expense on these notes. In addition, interest income in 2007 increased in comparison to 2006 due to higher average cash balances on hand in 2007 associated with the proceeds received from our initial public offering in May 2007.

        Other expense, net.     Other expense, net, was $192,000 in the year ended December 31, 2007, as compared to $255,000 in the year ended December 31, 2006. In 2006, costs related to station closures were higher due to the closing of six CNG stations in Canada.

Fiscal Year Ended December 31, 2006 Compared to Fiscal Year Ended December 31, 2005

        Revenue.     Revenue increased by $13.5 million to $91.5 million in the year ended December 31, 2006, from $78.0 million in the year ended December 31, 2005. This increase was primarily the result of an increase in the number of CNG and LNG gallons delivered from 56.8 million gasoline gallon equivalents to 68.4 million gasoline gallon equivalents. Included in our new customers for 2006 were two transit customers (Santa Monica Big Blue Bus and Toronto Transit) and two airport customers (Baltimore/Washington International Airport and the Los Angeles International Airport parking shuttle buses), which in the aggregate accounted for 3.0 million gallons of the increase. The remaining increase in gallons delivered was due to the addition of several other new smaller customers between periods and incremental growth at several of our previously existing customers and stations. 2006 revenue also included $3.8 million of fuel tax credits related to the sale of alternative fuels which began October 1, 2006. Excluding the fuel tax credits we received during the year, our effective price per gallon was

52


consistent between years. The change in our revenues related to the change in our gallons sold between periods was $14.4 million. Offsetting these increases was a $5.0 million decrease in station construction revenues between periods.

        Cost of sales.     Cost of sales increased by $2.0 million to $74.0 million in the year ended December 31, 2006, from $72.0 million in the year ended December 31, 2005. This increase was primarily due to the increased number of CNG and LNG gallons delivered in 2006. This increase was offset by a decrease in the price we paid for natural gas in 2006. Our effective cost per gallon decreased to $1.06 per gallon in 2006, which represents a $.10 per gallon decrease over 2005. Cost of sales also decreased between periods due to a decrease of $5.4 million in station construction costs between periods.

        Derivative (gains) losses.     Derivative losses were $79.0 million in the year ended December 31, 2006, as compared to derivative gains of $44.1 million in the year ended December 31, 2005. This decrease was primarily the result of fewer futures contracts sold in 2006 as opposed to 2005 (and at reduced prices), plus a $78.7 million loss incurred in 2006 on certain futures contracts that were transferred to and assumed by our majority stockholder, Boone Pickens, in December 2006. Unrealized losses also increased in 2006 by $7.8 million based on the mark-to-market adjustments of our open positions between periods. We did not have any open futures positions at December 31, 2006.

        Loss on extinguishment of derivative liability.     In December 2006, Boone Pickens, our majority stockholder, assumed all of our outstanding 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 $100 million line of credit with Mr. Pickens. At the time of assumption, the 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 for 2006 as a loss on extinguishment of derivative liability. We had no similar expense in 2005.

        Selling, general and administrative.     Selling, general and administrative expenses increased by $3.8 million to $20.9 million in the year ended December 31, 2006, from $17.1 million in the year ended December 31, 2005. This increase was primarily the result of an increase in salaries and benefits between periods of $2.4 million related to the hiring of additional employees and pay raises provided to our existing employees. Our employee count increased from 84 at December 31, 2005 to 97 at December 31, 2006. $275,000 of the salaries and benefits increase was related to increased salaries related to hiring an incremental 13 employees during the year. In addition, our travel and entertainment expenses increased by $372,000 between periods, primarily due to increased travel expenses related to our sales team in 2006. Our legal, accounting and auditing, and software implementation expenses increased by a combined $1.3 million between periods as we implemented several new software packages, including new CNG and LNG billing systems and our new inventory and repair and maintenance tracking system, and we increased our legal and accounting infrastructure in anticipation of becoming a public company. We also spent an additional $200,000 in 2006 on maintenance projects for the Pickens Plant. These increases were offset by a $2.0 million decrease in marketing and policy and promotion expenses between periods.

        Depreciation and amortization.     Depreciation and amortization increased by $1.9 million to $5.8 million in the year ended December 31, 2006, from $3.9 million in the year ended December 31, 2005. This increase was primarily the result of a full-year's depreciation in 2006 on the assets placed in service in 2005, including the Pickens Plant, and the depreciation on the LNG tanker trailers and station assets placed in service during 2006.

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        Interest income, net.     Interest income, net increased by $686,000 to $746,000, in the year ended December 31, 2006, from $60,000 in the year ended December 31, 2005. This increase was primarily the result of an increase in interest income during 2006 due to higher average cash balances on hand in 2006 associated with additional capital contributions received in 2006 and the increased interest income earned in 2006 on excess margin deposits made on certain futures contracts. These increases were offset by increased interest expense during 2006 on advances made from a stockholder to fund the excess margin deposits on the associated futures contracts. See note 10 to our consolidated financial statements.

        Other expense, net.     Other expense, net, was $255,000 in the year ended December 31, 2006, as compared to $141,000 in the year ended December 31, 2005. The increase is primarily due to recording the expenses associated with closing six CNG stations in Canada during 2006.

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, 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 2007 primarily through cash provided by operations and financing activities. At December 31, 2007, we had total cash and cash equivalents of $67.9 million, compared to $0.9 million at December 31, 2006. At December 31, 2007, we also had $12.5 million of short-term investments, compared to $0 at December 31, 2006.

        Cash provided by operating activities was $7.1 million for the year ended December 31, 2007, compared to cash used in operating activities of $36.6 million for the year ended December 31, 2006. This increase in operating cash flow was primarily due to (1) the collection of a $22.9 million receivable in January 2007 that was generated on December 28, 2006 related to the transfer of certain futures contracts to Boone Pickens, and (2) the receipt in 2007 of $3.3 million of fuel tax credits (VETC). We also received an income tax refund in 2007 of $4.4 million, which is net of $1.2 million of tax payments we made related to 2007 taxes. Offsetting these increases were incremental deposits of $13.6 million we made in 2007 related to the production of certain LNG trucks we anticipate will be operated in the

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Ports of Los Angeles and Long Beach (see Part II, Item 9B for more information regarding the deposits).

        Cash used in investing activities was $50.6 million for the year ended December 31, 2007, compared to $12.4 million for the year ended December 31, 2006. The $38.2 million increase between periods was primarily due to increased purchases of property and equipment and increased construction in progress activity during 2007, including an increase of approximately $24.2 million related to our LNG liquefaction plant in California. We also purchased a net $12.5 million of short-term investments in the third quarter of 2007 with excess cash balances.

        Cash provided by financing activities for the year ended December 31, 2007 was $110.5 million, compared to cash provided by financing activities of $21.2 million for the year ended December 31, 2006. The $89.3 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 year ended December 31, 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 anticipate we will need approximately $40 million of additional capital in the next twelve months to fund our 2008 capital expenditure program in full. We first intend to pursue bank financing options; however, we may not be able to obtain bank financing on favorable terms, or at all. If we are unable to obtain debt financing, we intend to pursue equity financing options. If we are unable to obtain debt or equity financing in amounts sufficient to fund our 2008 capital expenditure program fully, we will be forced to suspend or curtail certain of our planned expansion activities, which could harm our business, results of operations, or future prospects.

Capital Expenditures

        We expect to make capital expenditures, net of grant proceeds, of approximately $56.2 million in 2008 to construct new natural gas fueling stations, and for general corporate purposes. Additionally, we have budgeted approximately $49.1 million during 2008 to complete the construction of our LNG liquefaction plant in California, which we anticipate will be operational in the fall of 2008. We also anticipate using approximately $10 million to finance the purchase of natural gas vehicles by our customers during 2008.

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Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of December 31, 2007:

 
  Payments Due by Period
Contractual Obligations:

  Total
  Less than 1 year
  1-3 years
  3-5 years
  More than 5 years
Capital lease obligations (a)   $ 224,897   $ 63,520   $ 147,690   $ 13,687   $ 0
Operating lease commitments (b)     4,812,677     1,306,579     2,176,077     616,317     713,704
"Take or pay" LNG purchase contracts (c)     3,453,350     3,453,350     0     0     0
Construction contracts (d)     12,396,993     12,396,993     0     0     0
Other long-term contract liabilities (e)     46,707,912     46,707,912     0     0     0
   
 
 
 
 
Total   $ 67,595,829   $ 63,928,354   $ 2,323,767   $ 630,004   $ 713,704
   
 
 
 
 

(a)
Consists of obligations under a lease of capital equipment used to finance such equipment. Amounts do not include interest as the amounts are 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 three "take-or-pay" contracts. In October 2007, we entered into a 10-year contingent take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be constructed in Arizona, which commitment is not reflected in the table above because of the contingent nature of the obligation. On January 1, 2008, we entered into a take-or-pay contract that expires December 31, 2008 for 20,000 LNG gallons per day. Our commitment for this contract is included in the table above.

(d)
Consists of our obligations to fund various fueling station construction projects, net of amounts funded through December 31, 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 and contracts we have entered into to acquire certain equipment and services related to the construction of our LNG plant in California.

Off-Balance Sheet Arrangements

        At December 31, 2007, we had the following off-balance sheet arrangements:

    outstanding standby letters of credit totaling $650,000,

    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.

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

        At December 31, 2007, 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. On January 1, 2008, we entered into a take-or-pay contract that expires December 31, 2008 that is included in the table above, and in October 2007, we entered into a contingent take-or-pay contract from an LNG plant that is under construction that is not included in the table above.

        We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2016. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we are building an LNG liquefaction plant. We have budgeted approximately $49.1 million in 2008 to finish construction of this plant. The lease is for an initial term of 30 years, beginning on the date that the plant commences operations, and requires annual base rent payments of $230,000 per year, plus $130,000 per year for each 30 million gallons of production capacity, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as for certain other services that the landlord will provide. As the payments are contingent obligations, they are not included in "Operating lease commitments" in the "Contractual obligations" table set forth above.

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

Item 7A.    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 58% of our cost of sales for 2007. Prices for natural gas over the eight-year period from December 31, 1999 through December 31, 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 December 31, 2007, the NYMEX index price of natural gas was $7.21 per Mcf.

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

        We account for these futures contracts in accordance with SFAS 133. Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a

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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, 2005, 2006 and 2007, 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 year ended December 31, 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 year ended December 31, 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 December 31, 2007. Market risk is estimated as the potential loss resulting from a hypothetical 10.0% adverse change in the fair market value of natural gas prices. The results of this analysis, which assumes natural gas prices are in excess of our customer's price cap arrangements, and may differ from actual results, are as follows:

 
  Hypothetical adverse change in price
  Change in annual pre-tax income
 
 
   
  (in millions)

 
Fixed price contracts   10.0%   $ (0.9 )
Price cap contracts   10.0%   $ (0.8 )

        As of December 31, 2007 we did not have any futures contracts outstanding.

Quarterly Results of Operations

        The following table sets forth the Company's quarterly consolidated statements of operations data for the eight quarters ended December 31, 2007. The information for each quarter is unaudited and the Company has prepared it on the same basis as the audited consolidated financial statements appearing elsewhere in this Form 10-K. This information includes all adjustments that management considers necessary for the fair presentation of such data. The quarterly data should be read together with the Company's consolidated financial statements and related notes appearing elsewhere in this Form 10-K. The results of operations for any one quarter are not necessarily indicative of results for any future period.

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Quarterly Financial Data (Unaudited)

 
  For the Quarter Ended
 
 
  Mar 31, 2006
  June 30, 2006
  Sept 30, 2006
  Dec 31, 2006
 
Revenue   $ 21,033,865   $ 21,521,127   $ 22,245,867   $ 26,746,457  
Operating expenses:                          
  Cost of sales     19,142,726     17,552,518     18,237,804     19,114,853  
  Derivative (gains) losses (1)     282,348         64,999,238     13,713,361  
  Loss on extinguishment of derivative liability                 2,142,095  
  Selling, general and administrative     4,882,141     4,383,543     5,599,136     5,995,360  
  Depreciation and amortization     1,199,720     1,401,009     1,620,387     1,543,883  
   
 
 
 
 
Total operating expenses     25,506,935     23,337,070     90,456,565     42,509,552  
   
 
 
 
 
Operating income (loss)     (4,473,070 )   (1,815,943 )   (68,210,698 )   (15,763,095 )
Interest income (expense), net     165,306     245,494     408,143     (72,604 )
Other income (expense), net     (24,972 )   67,038     (53,141 )   (244,404 )
   
 
 
 
 
Income (loss) before income taxes     (4,332,736 )   (1,503,411 )   (67,855,696 )   (16,080,103 )
Income tax expense (benefit)     (1,286,823 )   (446,513 )   (9,040,439 )   (1,497,433 )
   
 
 
 
 
Net income (loss)   $ (3,045,913 ) $ (1,056,898 ) $ (58,815,257 ) $ (14,582,673 )
   
 
 
 
 
 
  For the Quarter Ended
 

 

 

Mar 31, 2007


 

June 30, 2007


 

Sept 30, 2007


 

Dec 31, 2007


 
Revenue   $ 28,167,044   $ 30,663,597   $ 29,210,164   $ 29,675,428  
Operating expenses:                          
  Cost of sales     21,321,159     22,526,562     20,252,744     21,559,864  
  Derivative (gains) losses                  
  Selling, general and administrative     6,299,878     10,440,718     9,528,605     9,664,493  
  Depreciation and amortization     1,576,057     1,700,164     1,814,176     2,017,545  
   
 
 
 
 
Total operating expenses     29,197,094     34,667,444     31,595,525     33,241,902  
   
 
 
 
 
Operating income (loss)     (1,030,050 )   (4,003,847 )   (2,385,361 )   (3,566,474 )
Interest income (expense), net     292,212     546,750     1,414,120     1,252,515  
Other income (expense), net     (123,372 )   (55,805 )   (50,000 )   36,830  
   
 
 
 
 
Income (loss) before income taxes     (861,210 )   (3,512,902 )   (1,021,241 )   (2,277,129 )
Income tax expense (benefit)     8,969     50,000     523,729     639,182  
   
 
 
 
 
Net income (loss)   $ (870,179 ) $ (3,562,902 ) $ (1,544,970 ) $ (2,916,311 )
   
 
 
 
 

(1)
September 30, 2006 and December 31, 2006 amounts include losses on certain derivative contracts that were assumed by our largest stockholder, Boone Pickens. See note 10 to our consolidated financial statements.

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Item 8.    Financial Statements and Supplementary Data.


INDEX TO FINANCIAL STATEMENTS/SCHEDULE

 
  Page

Consolidated Financial Statements

 

 
  Report of Independent Registered Public Accounting Firm   61
  Consolidated Balance Sheets as of December 31, 2006 and 2007   62
  Consolidated Statements of Operations for the Years Ended December 31, 2005, 2006 and 2007   63
  Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2006 and 2007   64
  Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2006 and 2007   65
  Notes to Consolidated Financial Statements   66

Financial Statement Schedule

 

 
  Schedule II—Valuation and Qualifying Accounts   93

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Clean Energy Fuels Corp.:

        We have audited the accompanying consolidated balance sheets of Clean Energy Fuels Corp. and subsidiaries (the "Company") as of December 31, 2006 and 2007, and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2007. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Clean Energy Fuels Corp. and subsidiaries as of December 31, 2006 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

        As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007, the Company changed its method of accounting for uncertain tax positions as required by Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes . Effective January 1, 2006, the Company adopted the fair value method of accounting for stock-based compensation as required by Statement of Financial Accounting Standards No. 123(R), Share-Based Payment.

/s/ KPMG, LLP

Los Angeles, California
March 17, 2008

61



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Balance Sheets

 
  December 31,
 
 
  2006
  2007
 
Assets              
Current assets:              
  Cash and cash equivalents   $ 937,445   $ 67,937,602  
  Short-term investments         12,479,684  
  Accounts receivable, net of allowance for doubtful accounts of $352,050 and $501,751 as of December 31, 2006 and 2007, respectively     10,997,328     11,026,890  
  Other receivables     37,818,905     23,153,904  
  Inventory, net     2,558,689     2,403,890  
  Deposits on LNG trucks     975,620     15,515,927  
  Prepaid expenses and other current assets     3,886,715     3,633,318  
   
 
 
    Total current assets     57,174,702     136,151,215  

Land, property and equipment, net

 

 

54,888,739

 

 

88,676,318

 
Capital lease receivables     1,412,500     763,500  
Notes receivable and other long term assets     2,499,106     2,511,813  
Goodwill and other intangible assets     20,957,589     20,922,098  
   
 
 
    $ 136,932,636   $ 249,024,944  
   
 
 
Liabilities and Stockholders' Equity              
Current liabilities:              
  Current portion of capital lease obligation   $ 57,499   $ 63,520  
  Accounts payable     6,697,363     10,547,451  
  Accrued liabilities     5,023,051     5,381,541  
  Deferred revenue     585,505     677,826  
   
 
 
    Total current liabilities     12,363,418     16,670,338  
Capital lease obligation, less current portion     224,897     161,377  
Other long term liabilities     1,428,464     1,260,755  
   
 
 
    Total liabilities     14,016,779     18,092,470  
   
 
 
Commitments and contingencies              

Stockholders' equity:

 

 

 

 

 

 

 
  Preferred stock, $0.0001 par value. Authorized 1,000,000 shares; issued and outstanding no shares          
  Common stock, $0.0001 par value. Authorized 99,000,000 shares; issued and outstanding 34,192,161 shares and 44,274,375 shares at December 31, 2006 and 2007, respectively     3,419     4,428  
  Additional paid-in capital     181,678,861     297,866,745  
  Accumulated deficit     (60,192,221 )   (69,086,583 )
  Accumulated other comprehensive income     1,425,798     2,147,884  
   
 
 
    Total stockholders' equity     122,915,857     230,932,474  
   
 
 
    $ 136,932,636   $ 249,024,944  
   
 
 

See accompanying notes to consolidated financial statements.

62



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Statements of Operations

 
  Years Ended December 31,
 
 
  2005
  2006
  2007
 
Revenue   $ 77,955,083   $ 91,547,316   $ 117,716,233  
Operating expenses:                    
  Cost of sales     72,004,077     74,047,901     85,660,329  
  Derivative (gains) losses     (44,067,744 )   78,994,947      
  Loss on extinguishment of derivative liability         2,142,095      
  Selling, general and administrative     17,108,425     20,860,181     35,933,694  
  Depreciation and amortization     3,948,544     5,765,001     7,107,942  
   
 
 
 
    Total operating expenses     48,993,302     181,810,125     128,701,965  
   
 
 
 
    Operating income (loss)     28,961,781     (90,262,809 )   (10,985,732 )

Interest income, net

 

 

59,780

 

 

746,339

 

 

3,505,597

 
Other (expense), net     (140,921 )   (255,479 )   (192,347 )
   
 
 
 
    Income (loss) before income taxes     28,880,640     (89,771,949 )   (7,672,482 )
Income tax expense (benefit)     11,623,053     (12,271,208 )   1,221,880  
   
 
 
 
    Net income (loss)   $ 17,257,587   $ (77,500,741 ) $ (8,894,362 )
   
 
 
 
Earnings (loss) per share                    
  Basic   $ 0.76   $ (2.45 ) $ (0.22 )
   
 
 
 
  Diluted   $ 0.75   $ (2.45 ) $ (0.22 )
   
 
 
 
Weighted average common shares outstanding                    
  Basic     22,602,033     31,676,399     40,258,440  
   
 
 
 
  Diluted     23,191,674     31,676,399     40,258,440  
   
 
 
 

See accompanying notes to consolidated financial statements.

63



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Statements of Stockholders' Equity and

Comprehensive Income (Loss)

 
  Common stock
   
   
   
   
   
 
 
  Additional Paid-In Capital
  Retained Earnings (Accumulated Deficit)
  Accumulated Other Comprehensive Income
  Total Stockholders' Equity
  Total Comprehensive Income/(Loss)
 
 
  Shares
  Amount
 
Balance, December 31, 2004   20,828,384   $ 2,083   $ 60,755,522   $ 50,933   $ 1,254,886   $ 62,063,424        
  Issuance of common stock upon exercise of warrants   4,729,730     473     13,999,527             14,000,000        
  Foreign currency translation adjustment                   168,857     168,857   $ 168,857  
  Net income               17,257,587         17,257,587     17,257,587  
   
 
 
 
 
 
 
 
Balance, December 31, 2005   25,558,114     2,556     74,755,049     17,308,520     1,423,743     93,489,868     17,426,444  
                                     
 
  Issuance of common stock upon exercise of warrants   7,094,594     709     20,999,288             20,999,997        
  Issuance of common stock upon exercise of options   359,500     36     994,676             994,712        
  Conversion of debt   1,179,953     118     4,022,522             4,022,640        
  Assumption of derivative contract obligations by shareholder and issuance of warrant           80,854,694             80,854,694        
  Stock-based compensation           52,632             52,632        
  Foreign currency translation adjustment                   2,055     2,055     2,055  
  Net loss               (77,500,741 )       (77,500,741 )   (77,500,741 )
   
 
 
 
 
 
 
 
Balance, December 31, 2006   34,192,161     3,419     181,678,861     (60,192,221 )   1,425,798     122,915,857     (77,498,686 )
                                     
 
  Issuance of common stock, net   10,000,000     1,000     108,520,933             108,521,933        
  Issuance of common stock upon exercise of options   82,214     9     296,077             296,086        
  Stock-based compensation           7,370,874             7,370,874        
  Foreign currency translation adjustment                   722,086     722,086     722,086  
  Net loss               (8,894,362 )       (8,894,362 )   (8,894,362 )
   
 
 
 
 
 
 
 
Balance, December 31, 2007   44,274,375   $ 4,428   $ 297,866,745   $ (69,086,583 ) $ 2,147,884   $ 230,932,474   $ (8,172,276 )
   
 
 
 
 
 
 
 

See accompanying notes to consolidated financial statements.

64



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Statements of Cash Flows

Years Ended December 31, 2005, 2006 and 2007

 
  2005
  2006
  2007
 
Cash flows from operating activities:                    
Net income (loss)   $ 17,257,587   $ (77,500,741 ) $ (8,894,362 )
  Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:                    
    Depreciation and amortization     3,948,544     5,765,001     7,107,942  
    Provision for doubtful accounts     385,721     230,486     1,309,428  
    Unrealized loss on futures contracts     1,233,110     8,956,599      
    Loss on extinguishment of derivative liability         2,142,095      
    Loss on disposal of assets     112,073     362,653     237,783  
    Deferred income taxes     4,861,314     (7,020,994 )    
    Non-cash derivative contract loss         78,712,599      
    Stock option expense         52,632     7,370,874  
    Changes in operating assets and liabilities:                    
      Accounts and other receivables     (5,641,577 )   (35,273,741 )   13,313,304  
      Inventory     (581,079 )   (610,781 )   154,799  
      Capital lease receivables     899,000     649,000     649,000  
      Margin deposits on futures contracts     1,709,900     196,600      
      Deposits on LNG trucks         (975,620 )   (14,540,307 )
      Prepaid expenses and other assets     (489,108 )   (2,354,700 )   (1,942,715 )
      Accounts payable     3,296,782     (3,433,773 )   1,556,817  
      Income taxes payable     6,761,739     (6,761,739 )    
      Accrued expenses and other     2,852,376     253,001     778,543  
   
 
 
 
        Net cash provided by (used in) operating activities     36,606,382     (36,611,423 )   7,101,106  
   
 
 
 
Cash flows from investing activities:                    
  Purchases of property and equipment     (7,562,911 )   (12,414,066 )   (38,082,456 )
  Purchase of LNG plant and related assets     (14,758,029 )        
  Purchase of short-term investments             (19,339,799 )
  Sale of short-term investments             6,860,115  
   
 
 
 
        Net cash used in investing activities     (22,320,940 )   (12,414,066 )   (50,562,140 )
   
 
 
 
Cash flows from financing activities:                    
  Repayment of notes payable, line of credit, and capital lease obligations     (821,743 )   (795,220 )   (57,499 )
  Proceeds from issuance of common stock     14,000,000     21,994,709     110,222,604  
  Proceeds from exercise of stock options             296,086  
   
 
 
 
        Net cash provided by financing activities     13,178,257     21,199,489     110,461,191  
   
 
 
 
        Net increase (decrease) in cash     27,463,699     (27,826,000 )   67,000,157  
Cash, beginning of year     1,299,746     28,763,445     937,445  
   
 
 
 
Cash, end of year   $ 28,763,445   $ 937,445   $ 67,937,602  
   
 
 
 
Supplemental disclosure of cash flow information:                    
  Income taxes paid   $ 1,353   $ 6,318,954   $ 1,214,464  
   
 
 
 
  Interest paid   $ 457,431   $ 1,414,908   $ 27,038  
   
 
 
 
Non-cash financing activities:                    
  Margin deposits directly advanced by majority stockholder to broker under line of credit   $   $ 69,500,000   $  
   
 
 
 
  Extinguishment of line of credit in exchange for rights to margin deposits   $   $ (69,500,000 ) $  
   
 
 
 

See accompanying notes to consolidated financial statements.

65



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements

(1) Summary of Significant Accounting Policies

(a)    The Company

        Clean Energy Fuels Corp., together with its wholly owned subsidiaries (hereinafter collectively referred to as Clean Energy or the Company), is engaged in the business of selling natural gas fueling solutions to its customers in the United States and Canada. Clean Energy was incorporated in April 2001. In June 2001, the Company acquired certain assets and interests of Pickens Fuel Corp. (a private company owned by Boone Pickens) and BCG eFuels, Inc. (owned by Terasen, Inc. (Terasen) (formerly BC Gas, Inc.)), and Westport Innovations Inc. (Westport Innovations) of Vancouver, British Columbia. For accounting purposes, BCG eFuels, Inc. was deemed the acquiring entity in the formation of the Company and was accounted for on a carryover cost basis. On December 31, 2002, the Company acquired all the outstanding membership interests of Blue Energy & Technologies, L.L.C. (Blue Energy).

        Clean Energy has a broad customer base in a variety of markets, including public transit, refuse, airports, and regional trucking. Clean Energy operates or supplies approximately 170 fueling locations in California, Texas, Colorado, Maryland, New York, New Mexico, Nevada, Washington, Massachusetts, Georgia, Wyoming and Arizona 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.

(b)    Principles of Consolidation

        The consolidated financial statements include the financial statements of Clean Energy and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

(c)    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.

(d)    Recently Issued Accounting Pronouncements

        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 was effective for the Company on January 1, 2007. The Company has presented sales taxes and excise taxes on sales to its customers on a net basis in its financial statements both prior to and subsequent to the adoption of EITF 06-3.

66


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)

        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. The Company is currently evaluating the impact, if any, that SFAS 157 may have on its 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. The Company is currently evaluating the impact, if any, that SFAS 159 may have on its financial statements.

        In December 2007, the FASB finalized the provisions of the Emerging Issues Task Force (EITF) issue No. 07-1, Accounting for Collaborative Arrangements (EITF 07-1). EITF 07-1 provides guidance and required financial statement disclosures for collaborative arrangement. EITF 07-01 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company is currently evaluating the impact, if any, EITF 07-1 may have on its financial statements.

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations (SFAS 141(R)). SFAS 141(R) provides new accounting guidance and disclosure requirements for business combinations. SFAS 141(R) is effective for business combinations which occur in the first fiscal year beginning on or after December 15, 2008.

        In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (SFAS 160). SFAS 160 provides new accounting guidance and disclosure and presentation requirements for non-controlling interests in a subsidiary. SFAS 160 is effective for the first fiscal year beginning on or after December 15, 2008. The Company is currently evaluating the impact, if any, SFAS 160 may have on its financial statements.

(e)    Recently Adopted Accounting Changes

        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. Clean Energy adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on its financial statements.

67


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)

(f)    Foreign Currency Translation

        The Company follows the principles of Statement of Financial Accounting Standards No. 52, Foreign Currency Translation, using the local currency as the functional currency of its foreign subsidiary. Accordingly, all assets and liabilities outside the United States are translated into U.S. dollars at the rate of exchange in effect at the balance sheet date. Income and expense items are translated at the weighted average exchange rates prevailing during the period. Net foreign currency translation adjustments are recorded as accumulated other comprehensive income in stockholders' equity. The Company realized net foreign currency transaction exchange gains of $18,287, $26,540 and $10,286 in 2005, 2006 and 2007, respectively. The functional currency for the Company's subsidiary in Canada is the Canadian dollar.

        The accompanying consolidated balance sheets include total assets of the Canadian subsidiary of $6,135,314 and $5,851,602, respectively, expressed in U.S. dollars, as of December 31, 2006 and 2007. Sales made by the Canadian subsidiary totaled $2,673,221, $2,550,066 and $1,360,593, respectively, in U.S. dollars for the years ended December 31, 2005, 2006 and 2007.

(g)    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.

(h)    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 consolidated balance sheets under the line item accumulated other comprehensive income. At December 31, 2007, carrying value approximated fair market value for the respective securities.

(i)    Inventories

        Parts inventories, which consist of spare parts for service of fueling locations, are stated at the lower of cost or market on a first-in, first-out basis. Management's estimate of market includes a provision for obsolete, slow moving, and unsaleable inventory based upon inventory on hand and forecasted demand. The Company also has LNG inventory related to its LNG liquefaction plant which it values at the lower of cost or market on a first-in, first-out basis.

(j)    Research and Development and Advertising

        Research and development costs related to the design, development, and testing of new products, applications, and technologies are charged to expense as incurred. No research and development costs were incurred during the years ended December 31, 2005, 2006 and 2007.

        Advertising costs are expensed as incurred. Advertising costs amounted to approximately $334,000, $560,000 and $1,316,000 for the years ended December 31, 2005, 2006 and 2007, respectively.

68


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)

(k)    Property and Equipment

        Property and equipment are recorded at cost. Depreciation and amortization are recognized over the estimated useful lives of the assets using the straight-line method. The estimated useful lives of depreciable assets are 20 years for LNG liquefaction plant assets, ten years for station equipment and LNG trailers, and three to seven years for all other depreciable assets. Leasehold improvements are amortized over the shorter of their estimated useful lives or lease terms. Periodically, the Company receives grant funding to assist in the financing of natural gas fueling station construction. The Company records the grant proceeds as a reduction of the cost of the respective asset. Total grant proceeds received were approximately $185,000, $775,000 and $300,000 for the years ended December 31, 2005, 2006 and 2007, respectively.

(l)    Long-Lived Assets

        The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of long-lived assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or the fair value less costs to sell.

(m)    Goodwill and Intangible Assets

        Goodwill represents the excess of costs incurred over the fair value of the net assets of acquired businesses. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead are tested for impairment at least annually in accordance with the provisions of SFAS No. 142, Goodwill and Other Intangible Assets . Intangible assets with estimable useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144, Accounting for Impairment or Disposal of Long-Lived Assets .

(n)    Asset Retirement Obligations

        The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred or becomes reasonably estimable and if there is a legal obligation to restore or remediate the property at the end of a lease term. All of the Company's fueling and storage equipment is located above-ground. The liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as the costs to restore the property, future inflation rates, and the adjusted risk free rate of interest. When the liability is initially recorded, the Company capitalizes the cost by increasing the related property and equipment balances. Over time, the liability is increased and expense is recognized for the change in present value, and the initial capitalized cost is depreciated over the useful life of the asset.

69


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)

        The following table summarizes the activity of the asset retirement obligation, of which $89,080 and $164,441 is included in other long-term liabilities, with the remaining current portion included in accrued liabilities, at December 31, 2006 and 2007, respectively:

 
  2006
  2007
 
Beginning balance   $ 158,418   $ 170,012  
  Liabilities incurred     6,760     53,584  
  Liabilities settled     (600 )   (6,185 )
  Accretion expense     5,434     7,044  
   
 
 
Ending balance   $ 170,012   $ 224,455  
   
 
 

(o)    Stock-Based Compensation

        During 2005, the Company accounted for stock-based compensation arrangements in accordance with SFAS No. 123, Accounting for Stock-Based Compensation . SFAS No. 123 requires disclosure of the fair value method of accounting for stock options and other equity instruments. Under the fair value method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the service period which is usually the vesting period. The Company elected, under the provisions of SFAS No. 123, to account for employee stock-based transactions in the statements of operations under Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in 2005.

        Pursuant to the guidance in APB Opinion No. 25, compensation expense is only recognized in the statement of operations to the extent the exercise price of the stock option is less than the fair value of the Company's common stock on the date of grant, i.e. the "intrinsic value" of the stock option. The Company recorded no compensation expense in the statements of operations for stock option grants during 2005 because the fair value of the Company's 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 Company is required to disclose the impact of using the grant date fair value using the Black-Scholes option pricing model, which requires the use of management's judgement in estimating the inputs used to determine fair value.

        The per share weighted average fair value of stock options granted during 2005 was $0.79 on the date of grant using the fair-value-method defined in SFAS No. 123 with the following assumptions:

 
  2005
Weighted average risk free interest rate   5.0%
Expected lives   3 years
Dividend yield   None

70


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)

        Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below:

 
  2005
 
Net income as reported   $ 17,257,587  
Assumed stock compensation cost, net of tax     (881,212 )
   
 
Pro forma net income   $ 16,376,375  
   
 
Earnings Per Share        
  Basic—as reported   $ 0.76  
  Basic—pro forma   $ 0.72  
Diluted Earnings Per Share        
  Diluted—as reported   $ 0.75  
  Diluted—pro forma   $ 0.71  

        Effective January 1, 2006, the Company adopted FASB Statement No. 123(R), Share-Based Payment (SFAS No. 123(R)). This statement replaces SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) requires that all stock-based compensation be recognized as an expense in the financial statements and that such cost be measured at the fair value of the award. SFAS No. 123(R) was adopted using the modified prospective method of application, which requires the Company to recognize compensation expense on a prospective basis. Therefore, prior years' financial statements have not been restated. For stock-based awards granted after January 1, 2006, the Company recognizes compensation expense based on estimated grant-date fair value using the Black-Scholes option-pricing model.

(p)    Revenue Recognition

        Revenue from the sale of natural gas and from operations and maintenance agreements is recognized in accordance with SEC Staff Accounting Bulletin No. 104, Revenue Recognition , which is typically at the time fuel is dispensed or when the operations and maintenance services are provided.

        In certain transactions with its customers, the Company agrees 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. The Company evaluates 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 the Company has adequate objective evidence of the values of separate deliverable items under a contract, it allocates the revenue from the contract on a relative fair value basis at the inception of the arrangement. If the arrangement contains a lease, the Company uses the existing evidence of fair value to separate the lease from the other deliverables.

        The Company accounts for its leasing activities in accordance with SFAS No. 13, Accounting for Leases . The Company's existing station leases are sales-type leases, giving rise to profit at the delivery of the leased station. Any remaining unearned revenue is amortized into income over the life of the lease using the effective interest method. For these arrangements, the Company recognizes gas sales

71


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)


and operations and maintenance service revenues as earned from the customer on a volume-delivered basis.

        The Company has evaluated the relative fair values of the deliverables for the two stations that it sold during 2005, the one station that it sold during 2006, and three stations that it sold in 2007, and concluded that there is not sufficient objective evidence to separate those deliverables. The Company is recognizing profit on the sale of those stations over the respective lives of the associated contracts. Additionally, the Company sold one station during 2007 that was not part of a multi-deliverable contract and recognized the associated revenue and costs during the period.

        Revenue on construction contracts has been recognized using the completed contract method in accordance with AICPA Statement of Position 81-1, Accounting for Performance of Construction Type and Certain Production Type Contracts.

(q)    Income Taxes

        The Company computes 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 the Company's assets and liabilities. The impact on deferred taxes of changes in tax rates and laws, if any, is applied to the years during which temporary differences are expected to be settled and is reflected in the consolidated financial statements in the period of enactment. The Company records a valuation allowance against its deferred tax assets when management determines it is more likely than not that the assets will not be realized.

(r)    Concentration of Credit Risk

        Credit is extended to all customers based on financial condition, and collateral is generally not required. Concentrations of credit risk with respect to trade receivables are limited because of the large number of customers comprising the Company's customer base and dispersion across many different industries and geographies.

        The Company continuously monitors collections and payments from its customers and maintains a provision for estimated credit losses based upon its historical experience and any specific customer collection issues that it has identified. While such credit losses have historically been within the Company's expectations and the provisions established, the Company cannot guarantee that it will continue to experience the same credit loss rates that it has in the past.

(s)    Derivative Financial Instruments and Long Term Sales Commitments

        The Company, in an effort to manage its natural gas commodity price risk exposures, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. The Company's derivative instruments did not qualify for hedge accounting under SFAS No. 133 for the years ended December 31, 2005 and 2006. As such, changes in the fair value of the derivatives were recorded

72


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(1) Summary of Significant Accounting Policies (Continued)


directly to the consolidated statements of operations. The Company did not have any derivative instruments during the year ended December 31, 2007.

        The Company enters into contracts with various customers, primarily municipalities, to sell LNG or CNG at fixed prices or at prices subject to a price cap. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.

        As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Company's customers do not agree to purchase a minimum amount of volume or guarantee their volume of purchases. Rather, 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 No. 133.

        The Company's agreements to fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer's contract and the corresponding index price of natural gas typically develops after the Company enters into the contract. During the year ended December 31, 2005, the price of natural gas generally increased, and during the years ended December 31, 2006 and 2007, the price of natural gas generally decreased. During these time periods, the Company 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. The Company has also from time to time entered into natural gas futures contracts to offset economically the adverse impact of the rising natural gas prices. From an accounting perspective, during the periods of rising natural gas prices (when the Company conducted the majority of its hedging activities), the Company's futures contracts were generally marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in its statements of operations. However, because the Company's contracts to sell LNG or CNG to its customers at fixed prices or an index-based price that is subject to a fixed price cap are not derivatives for purposes of U.S. generally accepted accounting principles, a liability or a corresponding loss has not been recognized in the Company's statements of operations for the increased market price of natural gas above the cost of natural gas included in the Company's sales price to its customers under these contracts. As a result, the Company's statements of operations do not reflect its firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

(t)    LNG Transportation Costs

        The Company records the costs incurred to transport LNG to its customers in the line item cost of sales in the accompanying statements of operations.

73


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(2) LNG Plant Purchase

        On November 28, 2005, the Company purchased an LNG liquefaction plant, which it renamed the Pickens Plant, including the inventory located in the storage tank at the plant, five LNG trailers, and certain station equipment for approximately $14,800,000. The Company accounted for the acquisition as an asset purchase in which the Company allocated the entire purchase price to the assets acquired based on their respective fair values.

(3) Other Receivables

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

 
  2006
  2007
Loans to customers to finance vehicle purchases   $ 816,837   $ 1,393,549
Advances to vehicle manufacturers     2,465,776     4,871,373
Fuel tax credits     3,810,109     14,920,145
Futures contracts deposit receivable     22,900,000    
Income tax receivable     5,600,071    
Other     2,226,112     1,968,837
   
 
    $ 37,818,905   $ 23,153,904
   
 

(4) Land, Property and Equipment

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

 
  2006
  2007
 
Land   $ 472,616   $ 472,616  
LNG liquefaction plant     12,898,178     12,898,178  
Station equipment     36,913,552     48,318,709  
LNG trailers     8,253,415     11,698,145  
Other equipment     6,144,553     6,937,083  
Construction in progress     7,304,612     32,297,191  
   
 
 
      71,986,926     112,621,922  
Less accumulated depreciation     (17,098,187 )   (23,945,604 )
   
 
 
    $ 54,888,739   $ 88,676,318  
   
 
 

(5) Accrued Liabilities

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

 
  2006
  2007
Salaries and wages   $ 1,286,196   $ 1,495,196
Accrued gas purchases     1,566,847     1,837,005
Other     2,170,008     2,049,340
   
 
    $ 5,023,051   $ 5,381,541
   
 

74


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(6) Stockholders' Equity

(a)    Authorized Shares

        The Company's certificate of incorporation authorizes the issuance of two classes of capital stock designated as common stock and preferred stock, each having $0.0001 par value per share. As of December 31, 2007, the Company was authorized to issue 100,000,000 shares, of which 99,000,000 shares are designated common stock and 1,000,000 shares are designated preferred stock.

Dividend Provisions

        The Company did not declare nor pay any dividends during the years ended December 31, 2005, 2006 or 2007.

Voting Rights

        Each holder of common stock has the right to one vote per share owned on matters presented for stockholder action.

(b)    Stock Option Plans

        In December 2002, the Company adopted its 2002 Stock Option Plan (2002 Plan). The board of directors determines eligibility, vesting schedules, and exercise prices for options granted under the 2002 Plan. Options generally have a term of ten years.

        Under the 2002 Plan, eligible persons may be issued options for services rendered to the Company. Under the 2002 Plan, the purchase price per share for each option granted shall not be less than 100% of the fair market value of the Company's common stock on the date of such option grant; provided, however, that the purchase price per share of common stock issued to a 10% stockholder shall not be less than 110% of such fair market value on the date of such option grant. Options generally vest over three to five year periods.

        In December 2006, the Company adopted its 2006 Equity Incentive Plan (2006 Plan). The 2006 Plan was effective on May 24, 2007, the date the Company completed its initial public offering of common stock. Under the 2006 Plan, 6,390,500 shares of common stock were initially authorized for issuance, and on January 1, 2007 and 2008, this number was automatically increased by 1,000,000 shares at each date in accordance with the terms of the 2006 Plan. The 2002 Plan became unavailable for new awards upon the effectiveness of the 2006 Plan. If any outstanding option under the 2002 Plan expires or is cancelled, the shares allocable to the unexercised portion of that option will be added to the share reserve under the 2006 Plan and will be available for grant under the 2006 Plan. As of December 31, 2007, the Company had 7,390,500 shares reserved for issuance in total under the 2006 Plan. At December 31, 2007, the Company had 780,250 shares available for grant in total under the 2006 Plan.

75


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(6) Stockholders' Equity (Continued)

        Option activity for 2005, 2006, and 2007 was as follows:

 
  Number of Shares
  Weighted Average Exercise Price
  Weighted Average Remaining Contractual Term (in years)
  Aggregate Intrinsic Value (in thousands)
Balance, December 31, 2004   1,422,475   $ 2.96          
  Options granted   1,340,275     2.96          
  Options forfeited   (25,000 )   2.96          
   
               
Balance, December 31, 2005   2,737,750     2.96          
  Options exercised   (359,500 )   2.77          
  Options granted   25,000     3.86          
  Options forfeited   (1,000 )   2.96          
   
               
Balance, December 31, 2006   2,402,250     2.97          
  Options granted   4,266,500     12.85          
  Options exercised   (82,214 )   3.60          
  Options forfeited   (33,500 )   12.00          
   
               
Balance, December 31, 2007   6,553,036     9.37   8.3   $ 38,089
   
               
Exercisable, December 31, 2007   3,248,869     5.54   6.9   $ 31,205
   
               

        A summary of the Company's non-vested stock options as of December 31, 2007 and the changes during the year ended December 31, 2007 are presented below:

 
  Shares
  Weighted Average Grant-Date Fair Value
Non-vested options at December 31, 2006   25,000   $ 6.74
Granted   4,266,500     7.16
Vested   (953,833 )   6.71
Forfeited   (33,500 )   6.71
   
     
Non-vested options at December 31, 2007   3,304,167     7.29
   
     

        As of December 31, 2007, there was $24.1 million of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 2.4 years. The total fair value of shares vested during the year ended December 31, 2007 was $6.4 million.

        All options granted in 2005, 2006 and 2007 were pursuant to the 2002 Plan and 2006 Plan, except for a special stock option for 25,000 shares of common stock granted at $3.86 per share to a consultant in May 2006, for which the Company recorded approximately $53,000 of expense during the year ended December 31, 2006 under the provisions of SFAS No. 123(R). The grant date fair market value of this option was $6.74 per share and the intrinsic value of this option was $6.14 per share. The Company did not recognize any tax benefit related to this expense. The option has a term of ten years and vested in full upon the Company completing its initial public offering of its common stock. The fair value of the option award was estimated on the grant date using the Black-Scholes option-pricing model using an expected dividend yield of 0%, expected volatility of 60%, an expected life of 2 years, and a risk-free

76


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(6) Stockholders' Equity (Continued)


interest rate of 4.8%. The volatility amount was estimated based on several comparable companies. The expected life was based on the Company's estimate of when the individual will exercise the option, and the risk free rate was based on the U.S. Treasury yield curve at the time of grant. No other expense was recorded in 2006 under the provisions of SFAS No. 123(R) as all the Company's previously issued options vested in 2005 or earlier.

        All of the Company's unvested options issued prior to October 2005 vested in October 2005 when the Company experienced a change in control in accordance with the 2002 Plan. The Company plans to issue new shares to its employees upon the employee's exercise of their options. The intrinsic value of all options exercised during 2005, 2006 and 2007 was $0, $482,076 and $981,886, respectively.

        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 during the year ended December 31, 2007:

Dividend yield   0.00%
Expected volatility   55.00%
Risk-free interest rate   4.53%
Expected life in years   5.80

        The weighted average grant date fair value of options granted using these assumptions was $7.16 for the year ended December 31, 2007. The volatility amounts used during the year were estimated based on several comparable companies. The expected useful lives used during the year were based on the weighted average of the vesting periods averaged with the term of the respective options. The risk free rates used during the year were based on the U.S. Treasury yield curve at the time of grant. The Company recorded approximately $7,371,000 of expense during the year ended December 31, 2007 under the provisions of SFAS No. 123(R). The Company did not record any tax benefit during the year ended December 31, 2007 related to its stock option expense.

(c)    Equity Option Agreements and Warrants

        On April 8, 2005, the Company entered into equity option agreements with two stockholders under which the stockholders, at the Company's option (expiring February 28, 2007), became obligated to purchase up to an aggregate of 11,824,324 shares of the Company's common stock at an exercise price of $2.96 per share. On each of May 31, 2005 and November 29, 2005, the Company exercised its option and required the stockholders to purchase an aggregate of 2,364,865 shares for proceeds of approximately $7 million. On January 31, 2006, the Company exercised its option and required the stockholders to purchase the remaining 7,094,594 shares outstanding under the equity option agreements for proceeds of approximately $21 million.

        On December 28, 2006, the Company issued to Boone Pickens a five-year warrant to purchase 15,000,000 shares of the Company's common stock at an exercise price of $10.00 per share. See note 10.

(d)    Conversion of Promissory Notes

Boone Pickens Convertible Promissory Note

        On June 12, 2001, the Company signed a secured convertible promissory note payable to Boone Pickens (the Note) in the original principal amount of $3,200,000. Interest accrued at 8% per annum and was payable quarterly in arrears on the first business day of each calendar quarter. The principal

77


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(6) Stockholders' Equity (Continued)


amount and any accrued interest was convertible into the number of shares determined by dividing the convertible amount by the conversion price then in effect. The conversion price was $3.41 per share. On April 28, 2006, this note was converted into 944,255 shares of the Company's common stock.

Pickens Grandchildren's Trust Convertible Promissory Note

        On June 12, 2001, the Company signed a secured convertible promissory note payable to the Pickens Grandchildren's Trust (the Trust Note) in the original principal amount of $800,000. Interest accrued at 8% per annum and was payable quarterly in arrears on the first business day of each calendar quarter. The principal amount and any accrued interest was convertible into the number of shares determined by dividing the convertible amount by the conversion price then in effect. The conversion price was $3.41 per share. On April 21, 2006, this note was converted into 235,698 shares of the Company's common stock. The converted shares were simultaneously sold to Boone Pickens.

(7) Income Taxes

        The components of income (loss) before income taxes for the years ended December 31, 2005, 2006, and 2007 are as follows:

 
  2005
  2006
  2007
 
U.S.    $ 28,560,579   $ (89,370,978 ) $ (6,717,982 )
Foreign     320,061     (400,971 )   (954,500 )
   
 
 
 
    $ 28,880,640   $ (89,771,949 ) $ (7,672,482 )
   
 
 
 

        The provision (benefit) for income taxes consists of the following:

 
  2005
  2006
  2007
 
Current:                    
  State   $ 1,194,398   $ (109,284 ) $ 536,970  
  Federal     5,567,341     (5,140,930 )   684,910  
   
 
 
 
  Total current     6,761,739     (5,250,214 )   1,221,880  
   
 
 
 
Deferred:                    
  State     987,368     (6,338,146 )   (380,091 )
  Federal     3,773,470     (21,818,295 )   (2,026,323 )
  Foreign     100,476     (102,941 )   (284,869 )
  Change in valuation allowance         21,238,388     2,691,283  
   
 
 
 
  Total deferred     4,861,314     (7,020,994 )    
   
 
 
 
  Total   $ 11,623,053   $ (12,271,208 ) $ 1,221,880  
   
 
 
 

        Income tax expense (benefit) for the years ended December 31, 2005, 2006 and 2007 differs from the "expected" amount computed using the federal income tax rate of 34% as a result of the following:

 
  2005
  2006
  2007
 
Computed expected tax expense (benefit)   $ 9,819,418   $ (30,522,462 ) $ (2,608,644 )
State and local taxes, net of federal benefit     1,439,966     (4,359,324 )   354,400  
Nondeductible expenses     362,214     1,339,770     1,186,137  
Other     1,455     32,420     (491,290 )
Change in valuation allowance         21,238,388     2,781,277  
   
 
 
 
Total tax expense (benefit)   $ 11,623,053   $ (12,271,208 ) $ 1,221,880  
   
 
 
 

78


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(7) Income Taxes (Continued)

        Deferred tax assets and liabilities result from differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The tax effect of temporary differences that give rise to deferred tax assets and liabilities as of December 31, 2006 and 2007 are as follows:

 
  2006
  2007
 
Deferred tax assets:              
  Accrued expenses   $ 566,870   $ 907,688  
  Sales-type leases     491,352     508,014  
  Alternative minimum tax and general business credits     773,183     1,980,646  
  Derivative loss         13,588,013  
  Stock option expense         1,883,231  
  Net operating loss carryforwards     26,302,430     12,745,504  
   
 
 
    Total deferred tax assets     28,133,835     31,613,096  
  Less valuation allowance     (21,238,388 )   (24,019,665 )
   
 
 
    Net deferred tax assets     6,895,447     7,593,431  
   
 
 
Deferred tax liabilities:              
  Depreciation and amortization—domestic     (6,476,492 )   (7,174,476 )
  Depreciation and amortization—foreign     (418,955 )   (418,955 )
   
 
 
    Total deferred tax liabilities     (6,895,447 )   (7,593,431 )
   
 
 
    Net deferred tax assets (liabilities)   $   $  
   
 
 

        At December 31, 2007, the Company had federal and state net operating loss carryforwards of approximately $32,173,600 and $42,423,613, respectively. The Company's federal net operating loss carryforward will expire beginning in 2026. The Company also has a foreign net operating loss carryforward of approximately $3,520,000 at December 31, 2007, which will expire beginning in 2008.

        During 2005, the Company experienced a change in control when Boone Pickens acquired all shares of common stock held by Terasen and other minority stockholders. Consequently, in accordance with Internal Revenue Code Section 382, the annual utilization of net operating loss carryforwards and credits existing prior to the change in control of the Company may be limited.

        In assessing the realizability of the net deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers projected future taxable income and tax planning strategies in making this assessment. At December 31, 2005, management deemed it more likely than not that the assets would be utilized and did not record a valuation allowance during these years. In 2006 and 2007, the Company provided a valuation allowance of $21,238,388 and $24,019,665, respectively, to reduce the net deferred tax assets due to uncertainty surrounding the realizability of these assets. The net change in the valuation allowance for the years ended December 31, 2005, 2006 and 2007 was $0, $(21,238,388) and $(2,781,277), respectively.

        On January 1, 2007, the Company adopted the provisions of FIN 48, which clarifies the accounting for uncertain positions. FIN 48 requires that the Company recognizes the impact of a tax position in its financial statements if the position is more likely than not of being sustained upon examination, based on the technical merits of the position. The impact of the adoption of FIN 48 was immaterial to the Company's consolidated financial statements. The total amount of unrecognized tax benefits as of

79


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(7) Income Taxes (Continued)


January 1, 2007 and December 31, 2007 were $50,000 and $369,000, respectively, which if recognized, would primarily affect the effective tax rate in future periods.

        The following is a tabular reconciliation of the total amounts of unrecognized tax benefits for the year ended December 31, 2007:

Unrecognized tax benefit—January 1, 2007   $ 50,000
Gross increases—tax positions in prior years     319,000
   
Unrecognized tax benefit—December 31, 2007   $ 369,000
   

        FIN 48 requires the Company to accrue interest and penalties where there is an underpayment of taxes, based on the Company's best estimate of the amount ultimately to be paid. The Company's policy is to recognize interest accrued related to unrecognized tax benefits and penalties as income tax expense. During the year ended December 31, 2007, the Company accrued $60,000 of interest. No penalties have been accrued by the Company.

        The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company's tax years for 2003 through 2006 are subject to examination by various tax authorities. The Company is no longer subject to U.S. examination for years before 2004, and state examinations for years before 2003.

        A number of years may elapse before an uncertain tax position is finally resolved. It is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, but the Company believes that its reserves for income taxes reflect the most probable outcomes. The Company adjusts the reserve, as well as the related interest, in light of changing facts and circumstances. Settlement of any particular position would usually require the use of cash and result in the reduction of the related reserve. The resolution of a matter would be recognized as an adjustment to the provision for income taxes and the effective tax rate in the period of resolution. As of December 31, 2007, it is possible that the Company's liability for uncertain tax positions will be reduced by as much as $319,000 during the year ended December 31, 2008 as a result of the settlement of tax positions with various tax authorities.

(8) Commitments and Contingencies

Environmental Matters

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

Litigation, Claims and Contingencies

        The Company may become party to various legal actions that arise in the ordinary course of its business. During the course of its operations, the Company is also subject to audit by tax authorities for varying periods in various federal, state, local and foreign tax jurisdictions. Disputes may arise during the course of such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that the Company may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of these liabilities, if any. If these

80


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(8) Commitments and Contingencies (Continued)


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.

Operating Lease Commitments

        The Company leases facilities and certain equipment under noncancelable operating leases expiring at various dates through 2016. The following schedule represents the future minimum lease obligations for all noncancelable operating leases as of December 31, 2007:

Fiscal year:      
2008   $ 1,306,579
2009     1,131,957
2010     1,044,120
2011     360,796
2012     255,521
Thereafter     713,704
   
Total future minimum lease payments   $ 4,812,677
   

        In November 2006, the Company entered into a ground lease for 36 acres in California on which the Company plans to build an LNG liquefaction plant. The lease is for a 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. The Company 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. The Company's obligations under the ground lease are contingent on the Company obtaining the necessary permits and approvals required in the lease related to the construction and operation of the LNG liquefaction plant. At December 31, 2007, the Company has remaining contractual commitments related to the plant of $44.7 million.

        Rent expense totaled $1,060,496, $1,183,061 and $1,692,982 for the years ended December 31, 2005, 2006 and 2007, respectively.

    Take-or-Pay LNG Supply Contracts

        At December 31, 2007, the Company has entered into two LNG supply contracts at market prices that contain minimum take or pay provisions covering 9,530,000 gallons per year over the term of the contracts. The contracts contain fixed amounts the Company must pay for any shortfall below its minimum volume requirements, and one of the contracts contains a variable amount that is based on the price of natural gas at the beginning and end of the month where a shortfall occurs. Both of the contracts expire in June 2008. For the years ended December 31, 2005, 2006 and 2007, the Company paid approximately $12,215,000, $12,790,928 and $10,100,054, respectively, under the contracts. At December 31, 2007, the fixed commitments under these contracts totaled approximately $1,253,000 for the year ending December 31, 2008.

81


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(8) Commitments and Contingencies (Continued)

        Additionally, in October 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 ten 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.

        On January 1, 2008, the Company entered into a take-or-pay contract that expires December 31, 2008 for 20,000 LNG gallons per day. The Company's commitment related to this contract is $2.2 million.

(9) Geographic Information

        Several of the Company's functions, including marketing, engineering, and finance are performed at the corporate level. As a result, significant interdependence and overlap exists among the Company's geographic areas. Accordingly, revenue, operating income (loss), and long-lived assets shown for each geographic area may not be the amounts which would have been reported if the geographic areas were independent of one another. Revenue by geographic area is based on where fuel is dispensed.

 
  2005
  2006
  2007
 
Revenue:                    
  United States   $ 75,281,862   $ 88,997,250   $ 116,355,640  
  Canada     2,673,221     2,550,066     1,360,593  
   
 
 
 
    Total revenue   $ 77,955,083   $ 91,547,316   $ 117,716,233  
   
 
 
 
Operating income (loss):                    
  United States   $ 28,633,674   $ (90,709,364 ) $ (10,049,214 )
  Canada     328,107     446,555     (936,518 )
   
 
 
 
    Total operating income (loss)   $ 28,961,781   $ (90,262,809 ) $ (10,985,732 )
   
 
 
 
Long-lived assets:                    
  United States         $ 70,957,274   $ 105,502,811  
  Canada           4,889,054     4,873,217  
         
 
 
    Total long-lived assets         $ 75,846,328   $ 110,376,028  
         
 
 

        The Company's goodwill and intangible assets at December 31, 2006 and 2007 reside in the United States.

(10) Related Party Transactions

        In 2005, 2006 and 2007, under an advisory agreement, the Company paid $10,000 a month for energy market advice to BP Capital L.P. (BP Capital), which is owned by Boone Pickens, the majority stockholder and a director of the Company. During 2005, 2006 and 2007, under the agreement, the Company also paid BP Capital approximately $11,622,000, $2,253,000, and $0, respectively, in commissions related to gains on its hedging activities. In addition, the Company reimbursed Terasen, a former stockholder, approximately $39,000 in 2005 for certain operational, financial, and executive services. At December 31, 2006 and 2007, BP Capital owed the Company $86,780 and $0, respectively.

        On August 2, 2006, the Company entered into certain futures contracts related to January 2008 through December 2011 (Positions). During the period August 3, 2006 through December 28, 2006, the

82


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(10) Related Party Transactions (Continued)


Positions decreased in value by $78.7 million. On December 28, 2006, the Company entered into a transaction with Boone Pickens, its majority stockholder, whereby Mr. Pickens assumed the obligations related to the Positions in exchange for a five-year warrant to purchase 15 million shares of the Company's common stock at $10 per share. The derivative obligation of $78.7 million was removed from the Company's balance sheet, and the warrant (valued at $80.9 million) was recorded as an increase of stockholders' equity. The difference between the value of the warrant and the value of the derivative obligation ($2.2 million) was recorded in the Company's consolidated statement of operations for the year ended December 31, 2006 as a loss on extinguishment of derivative liability.

        As the Positions decreased in value, the Company was required to make certain additional margin deposits to cover the losses. Mr. Pickens agreed to loan the Company up to $100 million to make such deposits under a revolving line of credit (the Revolver). At December 28, 2006, Mr. Pickens had advanced the Company $69.7 million under the Revolver to make additional margin deposits which he remitted directly to the broker. As part of the transaction, Mr. Pickens received back the deposits he had funded with advances under the Revolver as payment of the outstanding Revolver balance. The Company paid Mr. Pickens $1.2 million of interest expense on advances made under the Revolver during the period. The Revolver was cancelled on December 28, 2006 after the transaction was completed.

        In July 2006, the Company entered into an agreement with Inland Kenworth, Inc. (Inland) and Westport Innovations pursuant to which the Company agreed to deposit certain amounts with Inland, as security for a guaranty, to help fund Inland's acquisition from Kenworth Truck Company (Kenworth) of up to 125 diesel tractors, which tractors Westport Innovations will convert to run on LNG. Westport Innovations is a stockholder of the Company and Westport Innovation's chief executive officer is a member of the Company's Board of Directors. In addition, the president and chief executive officer of the Company is also a director of Westport Innovations, and Boone Pickens, a director and the largest stockholder of the Company, is a stockholder of Westport Innovations. At December 31, 2007, the Company had made approximately $9.5 million of deposits to Inland under this agreement. If any tractor purchased by Inland remains unsold after a period of 365 days, the Company must either purchase the tractor or instruct Inland to sell the tractor. In 2007, the Company also entered into two separate deposit agreements with Westport Innovations to facilitate the production of LNG fuel systems for installation in the diesel tractors referenced above. At December 31, 2007, the Company had advanced a total of $5.9 million to Westport Innovations under these agreements. Repayment of these deposits will occur incrementally upon the sale of the converted tractors to third parties, however, to the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the applicable deposit agreement (or such other time period as is agreed by both the Company and Westport Innovations), Westport Innovations is not obligated to repay any of the deposit with respect to such LNG fuel system.

(11) 401(k) Plan

        The Company has established a savings plan (Savings Plan) which is qualified under Section 401(k) of the Internal Revenue Code. Eligible employees may elect to make contributions to the Savings Plan through salary deferrals of up to 20% of their base pay, subject to limitations. The Company may make discretionary contributions to the Savings Plan that are subject to limitations. For the years ended December 31, 2005, 2006 and 2007, the Company contributed approximately $139,000, $217,000, and $289,000 of matching contributions to the Savings Plan, respectively.

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(12) Supplier Concentrations

        During 2005, 2006, and 2007, the Company acquired approximately 50%, 47%, and 32%, respectively, of its natural gas related to its LNG sales from Williams Gas Processing Company pursuant to a floating rate purchase contract that includes minimum purchase commitments. Any inability to obtain natural gas in the amounts needed on a timely basis or at commercially reasonable prices could result in interruption of gas deliveries or increases in gas costs, which could have a material adverse effect on the Company's business, financial condition, and results of operations until alternative sources could be developed at a reasonable cost.

(13) Capitalized Lease Obligation and Receivables

        The Company leases a piece of equipment under a capital lease with an interest rate of 10.0%. The lease is payable in monthly installments of $6,929 through February 2011. At December 31, 2007, future payments under this capital lease are as follows:

2008   $ 83,151  
2009     83,151  
2010     83,151  
2011     13,858  
   
 
  Total minimum lease payments     263,311  
Less amount representing interest     (38,414 )
   
 
  Present value of future minimum lease payments     224,897  
Less current portion     (63,520 )
   
 
  Capital lease obligation, less current portion   $ 161,377  
   
 

        The value of the equipment under capital lease as of December 31, 2007 is $596,360, with related accumulated depreciation of $438,961.

        The Company also leases certain fueling station equipment, including the asset leased above under capital lease, to certain customers under sales-type leases at a 10% interest rate. The leases are payable in varying monthly installments through 2012.

        At December 31, 2007, future receipts under these leases are as follows:

2008   $ 649,000  
2009     399,000  
2010     249,000  
2011     99,000  
2012     16,500  
   
 
  Total     1,412,500  
Less amount representing interest     (252,875 )
   
 
    $ 1,159,625  
   
 

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(14) Derivative Transactions

        The Company, from time to time, enters into natural gas futures contracts in an effort to fix its cost of natural gas for certain volumes over certain periods of time. These futures contracts are over-the-counter swap transactions that convert its index-priced gas supply arrangements to fixed-price arrangements. The Company historically has purchased all of its contracts from Sempra Energy Trading Corp., which contracts have been based on the price of the Henry Hub natural gas futures contract on the New York Mercantile Exchange. The Company, from time to time, entered into contracts covering the entire amount of its anticipated volumes in future periods, and from time to time purchased contracts for these volumes as far into the future as it deemed appropriate. The Company, from time to time, sold these contracts and realized a gain or loss on the contracts if it believed natural gas prices would decline in the future. The Company also from time to time repurchased contracts for positions previously sold if it believed natural gas prices would increase in the future. The Company typically did not enter into futures contracts to account for the basis difference between the Henry Hub delivery point and the local delivery point where it would purchase the gas for its customers.

        The Company marks to market its open futures positions, which historically have not qualified for hedge accounting under SFAS No. 133, at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the accompanying consolidated statements of operations. At December 31, 2005 and 2006, the Company's net unrealized loss amount totaled $1,233,110 and $8,956,599, respectively. The Company did not own any futures contracts in 2007.

        During 2005 and 2006, the Company recognized net gains of $9,528,854 and $8,674,251, respectively, related to contracts with expiration dates during the period. In 2005, the Company also recognized net gains of $35,772,000, respectively, related to contracts with expiration dates beyond the current period. In 2006, the Company realized a net loss of $78,712,599 related to contracts with expiration dates beyond the current period. See note 10. The realized gains and losses have all been recorded in derivative (gains) losses in the Company's consolidated statements of operations.

        The Company is required to make certain deposits on its futures contracts. At December 31, 2005, the Company had made deposits totaling $196,600, all of which related to futures contracts that were current as of December 31, 2005. At December 31, 2006 and 2007, the Company did not have any outstanding futures contracts or associated deposits. See note 10.

        The Company historically has relied on the advice of BP Capital when conducting its futures activities. BP Capital is an entity whose principal is Boone Pickens, the Company's majority stockholder and one of its directors. At the advice of BP Capital, the Company historically has liquidated and subsequently re-established its futures positions based on market conditions.

(15) Futures Contracts and Fixed Price and Price Cap Sales Contracts

        The Company enters into contracts with various customers, primarily municipalities, to sell LNG or CNG at fixed prices or at prices subject to a price cap. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.

        As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Company's customers do not agree to purchase a minimum amount of volume or guarantee their volume of purchases. There is not an explicit volume in the contract as the Company agrees to sell its customers volumes on an "as needed" basis, also known as a "requirements contract." The volume required under these contracts

85


Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(15) Futures Contracts and Fixed Price and Price Cap Sales Contracts (Continued)


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 No. 133.

        The Company's sales agreements that fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer's contract and the corresponding index price of natural gas typically develops after the Company enters into the contract. During 2005, the price of natural gas generally increased. During 2006 and 2007, the price of natural gas generally decreased. During these time periods, the Company 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. The Company has also generally entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices. From an accounting perspective, during periods of rising natural gas prices, the Company's futures contracts have generally been marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in its statements of operations. However, because the Company's contracts to sell LNG or CNG to its customers at fixed prices or an index-based price that is subject to a fixed price cap are not derivatives for purposes of U.S. generally accepted accounting principles, a liability or a corresponding loss has not been recognized in the Company's statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, the Company's statements of operations do not reflect its firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

        The following table summarizes important information regarding the Company's fixed price and price cap supply contracts under which it is required to sell fuel to its customers as of December 31, 2007:

 
  Estimated Volumes (a)
  Average Price (b)
  Contracts Duration
CNG fixed price contracts   1,383,707   $ 1.14   through 12/13
LNG fixed price contracts   12,810,483   $ 0.39   through 07/09
CNG price cap contracts   4,334,091   $ 0.86   through 12/09
LNG price cap contracts   7,614,390   $ 0.49   through 12/08

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

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

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(15) Futures Contracts and Fixed Price and Price Cap Sales Contracts (Continued)

        At December 31, 2007, based on natural gas futures prices as of that date, the Company estimates it will incur between $3.3 million and $4.0 million to cover the increased price of natural gas above the inherent price of natural gas embedded in its customer's fixed price and price cap contracts over the duration of the contracts. The Company's volumes under these contracts, in gasoline gallon equivalents, expire as follows:

2008   15,709,619
2009   2,486,896
2010   230,000
2011   230,000
2012   230,000
2013   230,000

        The price of natural gas has generally increased since the Company entered into these agreements to fix the price or cap the price of LNG or CNG that it sells to these customers. However, this difference has not been reflected in the Company's financial statements as these are executory contracts and are not derivatives under U.S. generally accepted accounting principles.

(16) 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, warrants and convertible promissory notes. The information required to compute basic and diluted earnings per share is as follows:

 
  2005
  2006
  2007
 
Basic:                    
  Weighted average number of common shares outstanding     22,602,033     31,676,399     40,258,440  
   
 
 
 
Diluted:                    
  Net income (loss)   $ 17,257,587   $ (77,500,741 ) $ (8,894,362 )
  Interest expense related to convertible promissory notes, net of tax     32,533     62,933      
   
 
 
 
  Adjusted net income (loss)   $ 17,290,120   $ (77,437,808 ) $ (8,894,362 )
   
 
 
 
  Weighted average number of common shares outstanding     22,602,033     31,676,399     40,258,440  
  Shares issued upon assumed exercise of stock options     108,517          
  Shares issued upon assumed exercise of warrants     281,710          
  Shares issued upon assumed conversion of convertible promissory notes     199,414          
   
 
 
 
  Shares used in computing diluted earnings per share     23,191,674     31,676,399     40,258,440  
   
 
 
 

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(16) Earnings Per Share (Continued)

        Certain securities were excluded from the diluted earnings per share calculation in 2006 and 2007 as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of December 31, 2006 and 2007 for these instruments are as follows:

 
  2006
  2007
Options   2,402,250   6,553,036
Warrants   15,000,000   15,000,000

(17) Fair Value of Financial Instruments

        The carrying amount and fair values of financial instruments, expressed in dollars, are as follows:

 
  December 31,
 
  2006
  2007
 
  Carrying Value
  Fair Value
  Carrying Value
  Fair Value
Capital lease receivables   $ 2,061,500   $ 2,022,251   $ 1,412,500   $ 1,402,083
Other receivables     37,818,905     37,818,905     21,760,355     21,177,537
Notes receivable     3,250,946     3,250,946     3,068,159     3,068,159
Capital lease obligations     282,396     282,396     224,897     224,897

        As of December 31, 2006 and 2007, the carrying amounts of the Company's other current assets and current liabilities not included in the table above approximate fair value due to the short-term maturities of those instruments. The fair values of capital lease receivables, other receivables, notes receivable, and capital lease obligations were determined by discounting the respective instrument's future cash flows by an interest rate commensurate with existing market rates at the time and the inherent risk of the respective instrument.

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Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

        None.

Item 9A.    Controls and Procedures.

        Not applicable.

Item 9A(T).    Controls and Procedures.

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

Management's Report on Internal Control Over Financial Reporting

        This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm, as permitted by temporary rules established by the Securities and Exchange Commission that are applicable to registrants that are neither "large accelerated filers" nor "accelerated filers," as those terms are defined in Rule 12b-2 under the Exchange Act.

Item 9B.    Other Information.

Amendment No. 1 to Amended and Restated 2002 Stock Option Plan

        On February 28, 2008, our board of directors adopted Amendment No. 1 to our Amended and Restated 2002 Stock Option Plan which permits the transferability of option awards to the same extent permitted under our 2006 Equity Incentive Plan. The board of directors concluded this amendment was immaterial and did not require stockholder approval pursuant to Nasdaq Marketplace Rule 4350(i). The amendment is attached to this report as Exhibit 10.36 and is incorporated by reference herein. The summary of the amendment set forth above does not purport to be complete and is qualified in its entirety by reference to such exhibit.

        This disclosure is provided in lieu of Item 8.01 of Form 8-K.

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Agreement Regarding Acquisition, Conversion and Sale of Vehicles

        On July 21, 2006, we entered into an Agreement Regarding Acquisition, Conversion and Sale of Vehicles (Vehicle Agreement) with Inland Kenworth, Inc. (Inland), Westport Innovations Inc. and Westport Fuel Systems Inc., its wholly-owned subsidiary (together, Westport). David Demers, a director of our company, serves as chief executive officer and a director of Westport Innovations, Inc.; Andrew Littlefair, our chief executive officer, is a director of Westport; Kenneth M. Socha, a director of our company, was formerly a director of Westport, and Boone Pickens, a director and the largest shareholder of our company, is a stockholder of Westport.

        Pursuant to the Vehicle Agreement, Inland agreed to purchase up to 125 diesel tractors from Kenworth Truck Company (Kenworth), which Westport agreed to convert to operate on LNG. We guaranteed and agreed to pay to Inland the full vehicle purchase price (roughly $95,000 each, plus sales tax and licensing charges) for each vehicle that remained unsold and not purchased by a third-party purchaser within 180 days from the date such vehicle was delivered to Inland by Kenworth (the sale period). Concurrently with the signing of the Vehicle Agreement, we paid Inland $500,000 as a deposit to secure our performance under the agreement, and we also agreed to make interim payments to Inland to support our guaranty to purchase any unsold vehicles (for each vehicle delivered to Inland, 25% of the full vehicle purchase price at the time of delivery). Upon the expiration of the sale period with respect to any vehicle, we must either purchase the vehicle or instruct Inland to sell the vehicle. We do not take title to a vehicle under the agreement unless we elect to purchase it.

        On July 15, 2007, we entered into a First Amendment to the Vehicle Agreement with Inland and Westport, pursuant to which the length of the sale period for unsold vehicles was extended from 180 days to 365 days. Concurrently with the signing of the amendment, we also agreed to make an additional interim payment to Inland in the amount of $2.9 million to support our guaranty to purchase any unsold vehicles ($60,000 for each of the 48 unsold vehicles at that time).

        The Vehicle Agreement and the First Amendment thereto are attached to this report as Exhibits 10.37 and 10.38, respectively, and are incorporated by reference herein. The summary of the agreements set forth above does not purport to be complete and is qualified in its entirety by reference to such exhibits.

        This disclosure is provided in lieu of Items 1.01 and 2.03 of Form 8-K.

Deposit Agreements with Westport Innovations Inc.

        To ensure that a ready supply of LNG-powered vehicles would be available for fleet customers in connection with the Clean Truck Program initiated by the Ports of Los Angeles and Long Beach, we agreed to advance to Westport a total of $6,000,000 to facilitate the production of LNG fuel systems for installation in such vehicles, in accordance with the deposit agreements described below:

    On November 30, 2007, we entered into Deposit Agreement No. 1 with Westport. Under this agreement, we agreed to advance to Westport a deposit of $4,000,000 for the purpose of financing the establishment and maintenance of LNG fuel systems for subsequent installation in the vehicles to be purchased by Inland under the Vehicle Agreement. The deposit does not bear interest, and Westport is only obligated to repay such deposit (1) as each LNG fuel system incorporated into a vehicle is sold to a customer (Westport will separately invoice customers), or (2) if there is a specified event of default, such as Westport going bankrupt or failing to remit to us a payment when an LNG fuel system incorporated into a vehicle is sold. To the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel system.

90


    On December 13, 2007, we entered into Deposit Agreement No. 2 with Westport. Under this agreement, we agreed to advance to Westport a deposit of $2,000,000 for the purpose of financing the establishment and maintenance of LNG fuel systems for subsequent installation in the vehicles to be purchased by Inland under the Vehicle Agreement. The deposit does not bear interest, and Westport is only obligated to repay such deposit (1) as each LNG fuel system incorporated into a vehicle is sold to a customer (Westport will separately invoice customers), or (2) if there is a specified event of default, such as Westport going bankrupt or failing to remit to us a payment when an LNG fuel system incorporated into a vehicle is sold. To the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel system.

        Deposit Agreement No. 1 and Deposit Agreement No. 2 are attached to this report as Exhibits 10.39 and 10.40, respectively, and are incorporated by reference herein. The summary of the agreements set forth above does not purport to be complete and is qualified in its entirety by reference to such exhibits.

        This disclosure is provided in lieu of Item 1.01 of Form 8-K.

Other Transactions with Westport Innovations, Inc.

    In April 2006, we agreed to purchase two LNG fuel systems from Westport for a total of $199,000.

    In April 2007, we agreed to purchase five LNG fuel systems from Westport for a total of $400,000.

    In June 2007, we agreed to purchase 20 LNG fuel systems from Westport for a total of $1,600,000.

    In 2007, we leased one LNG delivery system from Westport and paid a total of $36,000 in related rental payments.

        This disclosure is provided in lieu of Item 8.01 of Form 8-K.

        On March 13, 2008, our compensation committee approved annual cash bonuses to be paid to our named executive officers, which bonuses were based on the achievement by our company in fiscal 2007 of specific performance criteria related to EBITDA and the amount of natural gas gallons sold. The bonus payments made were in the following amounts: Andrew J. Littlefair—$325,600; Richard R. Wheeler—$143,000; James N. Harger—$130,000; and Mitchell W. Pratt—$130,000. Barclay F. Corbus, who joined us in September 2007, also received an annual cash bonus of $43,734 based on the same performance criteria, which bonus was pro-rated based on the number of months Mr. Corbus was employed with us during 2007. In calculating the EBITDA-based portion of annual cash bonuses for 2007, the compensation committee determined that the EBITDA number should exclude non-cash stock-based compensation expense that was not budgeted in setting the performance criteria targets. The compensation committee determined that for 2008 the EBITDA-based portion of the annual cash bonuses will exclude all non-cash stock-based compensation expense.

        On March 17, 2008, our compensation committee also approved the following items related to the compensation of our named executive officers:

    With respect to annual cash bonuses for 2008, increases in the percentages of base salary that may be paid to our named executive officers upon the company's achievement of specific performance criteria established by the compensation committee for 2008, as follows: Mr. Littlefair will be eligible to receive a bonus equal to 70%, 100% or 150% of his 2008 base salary for achievement of the base, middle and maximum performance targets, and each of our

91


      other named executive officers will be eligible to receive a bonus equal to 50%, 70% or 100% of his respective 2008 base salary for achievement of the base, middle and maximum performance targets; and

    Increases in the annual base salaries of our named executive officers, retroactive to January 1, 2008, to the following amounts: Mr. Littlefair—$475,200; Mr. Wheeler—$313,250; Mr. Harger—$287,500 and Mr. Pratt—$280,000.

        This disclosure is provided in lieu of disclosure under Item 5.02(e) of Form 8-K.


PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

        The information required by this item is incorporated by reference to the proxy statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007.

Item 11.    Executive Compensation.

        The information required by this item is incorporated by reference to the proxy statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

        The information required by this item is incorporated by reference to the proxy statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007.

Item 13.    Certain Relationships and Related Transactions and Director Independence.

        The information required by this item is incorporated by reference to the proxy statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007.

Item 14.    Principal Accounting Fees and Services.

        The information required by this item is incorporated by reference to the proxy statement for our 2008 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2007.

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PART IV

Item 15.    Exhibits and Financial Statement Schedules.

        (a)(1) Consolidated Financial Statements .

    The following documents are filed in Part II, Item 8 of this annual report on Form 10-K:

    Report of Independent Registered Public Accounting Firm

    Consolidated Balance Sheets as of December 31, 2006 and 2007

    Consolidated Statements of Operations for the Years Ended December 31, 2005, 2006 and 2007

    Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2006 and 2007

    Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2006 and 2007

    Notes to Consolidated Financial Statements

    (a)(2) Financial Statement Schedules.

        The following financial statement schedule is filed as a part of this annual report on Form 10-K:

    Schedule II: Valuation and Qualifying Accounts

        All other schedules have been omitted as they are not required, not applicable, or the required information is otherwise included.

 
  Allowances for Doubtful Trade Receivables
  Reserve for Excess and Obsolete Inventory
  Allowance for Doubtful Notes Receivables
Balance at December 31, 2004   $ 398,224   $ 199,894   $ 0
  Charges to operations     385,721     75,000     0
  Deductions     (337,133 )   (56,543 )   0
   
 
 
Balance at December 31, 2005     446,812     218,351     0
  Charges to operations     230,486     50,000     541,521
  Deductions     (325,248 )   (143,775 )   0
   
 
 
Balance at December 31, 2006     352,050     124,576     541,521
  Charges to operations     253,890     0     708,885
  Deductions     (104,189 )   0     0
   
 
 
Balance at December 31, 2007   $ 501,751   $ 124,576   $ 1,250,406
   
 
 

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        (a)(3) Exhibits.

 
   
  Incorporated by reference herein
Exhibit Number

   
  Description
  Form
  Date
  2.1   Stock Purchase Agreement dated June 13, 2001, among the registrant, the stockholder of BCG eFuels, Inc. and the stockholders of Pickens Fuel Corp.   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
  2.2   Membership Interest Purchase Agreement dated December 31, 2002, among the registrant and the individuals holding member interests of Blue Energy & Technologies, LLC   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
  3.1   Restated Certificate of Incorporation   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
  3.2   Amended and Restated Bylaws   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
  4.1   Specimen Common Stock Certificate   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
  4.2   Registration Rights Agreement dated December 31, 2002   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
  4.3   Amendment No. 1 to Registration Rights Agreement, dated August 8, 2006   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
  4.4   Amendment No. 2 to Registration Rights Agreement, dated May 1, 2007   Registration Statement on Form S-1, as amended (File No. 333-137124)   May 9, 2007
10.1   Amended and Restated 2002 Stock Option Plan+   Registration Statement on Form S-8 (File No. 333-145434)   August 14, 2007
10.2   2002 Stock Option Plan—Form of Notice of Grant of Stock Option Agreement+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.3   2006 Equity Incentive Plan+   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.4   2006 Equity Incentive Plan—Form of Notice of Grant of Stock Option and Stock Option Agreement+   Registration Statement on Form S-8 (File No. 333-145434)   August 14, 2007
10.5   Lease and amendments for facilities in Seal Beach, California   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.6   Form of Indemnification Agreement between the registrant and its officers and directors+   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.7   Employment Agreement dated January 1, 2006, between the registrant and Andrew J. Littlefair+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.8   Employment Agreement dated January 1, 2006, between the registrant and Richard R. Wheeler+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.9   Employment Agreement dated January 1, 2006, between the registrant and James N. Harger+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006

94


10.10   Employment Agreement dated January 1, 2006, between the registrant and Mitchell W. Pratt+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.11   Letter Agreement dated April 20, 2005, between the registrant and Warren I. Mitchell+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.12   Letter Agreement dated October 15, 2003, between the registrant and Warren I. Mitchell+   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.13   Buyer's Order and Purchase Agreement with Inland Kenworth, Inc. dated April 12, 2006   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.14   Stock Purchase and Buy-Sell Agreement dated February 1, 2006, between the registrant and the individuals and entities named therein   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.15   ISDA Master Agreement dated March 23, 2006, between the registrant and Sempra Energy Trading Corp.   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.16   ISDA Credit Support Annex dated March 23, 2006, between the registrant and Sempra Energy Trading Corp.   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.17   Trading Authorization dated March 23, 2006   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.18   Guarantee dated March 23, 2006, by Boone Pickens in favor of Sempra Energy Trading Corp.   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.19   Guarantee dated March 28, 2006, by Sempra Energy in favor of the registrant   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.20   LNG Sales Agreement dated May 23, 2003, between the registrant and Williams Gas Processing Company†   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.21   Amendment to LNG Sales Agreement, dated March 3, 2005, between the registrant and Williams Gas Processing Company†   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.22   Investment Advisory Agreement dated July 24, 2006, between the registrant and BP Capital LP   Registration Statement on Form S-1, as amended (File No. 333-137124)   September 6, 2006
10.23   Pickens Plant Purchase and Sale Agreement dated November 3, 2005†   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.24   $50 Million Revolving Promissory Note with Boone Pickens dated August 31, 2006   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.25   Equity Option Agreement dated April 8, 2005 between the registrant and Boone Pickens   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007

95


10.26   Equity Option Agreement dated April 8, 2005 between the registrant and Perseus ENRG Investment, L.L.C.   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.27   Ground Lease dated November 3, 2006 between the registrant and U.S. Borax, Inc.†   Registration Statement on Form S-1, as amended (File No. 333-137124)   May 24, 2007
10.28   Warrant to Purchase Common Stock dated December 28, 2006 issued to Boone Pickens   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.29   Obligation Transfer and Securities Purchase Agreement dated December 28, 2006, between the registrant and Boone Pickens   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.30   $100 Million Revolving Promissory Note with Boone Pickens dated November 15, 2006   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.31   Letter agreement dated September 11, 2006 with Williams Gas Processing Company   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.32   Investment Advisory Agreement dated March 9, 2007 between the registrant and BP Capital LP   Registration Statement on Form S-1, as amended (File No. 333-137124)   March 27, 2007
10.33   Underwriting Agreement dated May 25, 2007 between the registrant and W.R. Hambrecht + Co, LLC.   Quarterly Report on Form 10-Q   August 14, 2007
10.34   Letter Agreement dated August 21, 2007, between the registrant and Barclay Corbus+   Quarterly Report on Form 10-Q   November 13, 2007
10.35   LNG Sales Agreement dated October 17, 2007 between the registrant and Spectrum Energy Services, LLC†   Quarterly Report on Form 10-Q   November 13, 2007
10.36   Amendment No. 1 to Amended and Restated 2002 Stock Option Plan*+        
10.37   Agreement Regarding Acquisition, Conversion and Sale of Vehicles dated July 21, 2006 between the registrant, Inland Kenworth, Inc., Westport Fuels Systems Inc., and Westport Innovations Inc.*        
10.38   First Amendment to Agreement Regarding Acquisition, Conversion and Sale of Vehicles dated July 15, 2007 between the registrant, Inland Kenworth, Inc., Westport Fuels Systems Inc., and Westport Innovations Inc.*        

96


10.39   Deposit Agreement No. 1 dated November 30, 2007 between the registrant and Westport Fuel Systems Inc.*        
10.40   Deposit Agreement No. 2 dated December 13, 2007 between the registrant and Westport Fuel Systems Inc.*        
21.1   Subsidiaries*        
23.1   Consent of KPMG LLP*        
24.1   Power of Attorney (incorporated by reference to the signature page of this annual report on Form 10-K)*        
31.1   Certification of Andrew J. Littlefair, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*        
31.2   Certification of Richard R. Wheeler, Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*        
32.1   Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, executed by Andrew J. Littlefair, President and Chief Executive Officer, and Richard R. Wheeler, Chief Financial Officer.**        

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

*
Filed herewith.

**
Furnished herewith.

+
Management contract or compensatory plan or arrangement.

97



SIGNATURES

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