Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-K, Received: 03/12/2012 16:36:35)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 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, 2011

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 400, 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  ý     No  o

         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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 ý   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

         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 30, 2011, the last business day of the registrant's second fiscal quarter, was approximately $652,465,825 (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 7, 2012, the number of outstanding shares of the registrant's common stock was 85,783,551.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's proxy statement for the 2011 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.

   



CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

        Certain statements in this annual report on Form 10-K 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 our current assumptions, expectations and beliefs concerning future developments and their potential effect on our business. In some cases, you can identify forward-looking statements by the following words: "may," "will," "could," "would," "should," "expect," "intend," "plan," "anticipate," "believe," "approximately," "estimate," "predict," "project," "potential," "continue," "ongoing," or the negative of these terms or other comparable terminology, although the absence of these words does not necessarily mean that a statement is not forward-looking. We believe that the statements in this annual report on Form 10-K that we make regarding the following subject matters are forward-looking by their nature:

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        The preceding list is not intended to be an exhaustive list of all of our forward-looking statements. Although the forward-looking statements in this annual report on Form 10-K reflect our good faith judgment, based on currently available information, they involve known and unknown risks, uncertainties and other factors that may cause our actual results or our industry's actual results, levels of activity, performance, or achievements to be materially different from any future results, levels of activity, performance, or achievements expressed or implied by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, those discussed in the "Risk Factors" contained in this annual report on Form 10-K. As a result of these factors, we cannot assure you that the forward-looking statements in this annual report on Form 10-K will prove to be accurate. Except as required by law, we undertake no obligation to update publicly any forward-looking statements for any reason after the date we file this annual Report on Form 10-K with the Securities and Exchange Commission, or to conform these statements to actual results or to changes in our expectations. You should, however, review the factors and risks we describe in the reports we will file from time to time with the Securities and Exchange Commission after the date we file this annual report on Form 10-K.

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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, or CNG, and liquefied natural gas, or LNG, delivered. We design, build, operate and maintain fueling stations and supply our customers with CNG fuel for light, medium and heavy-duty vehicles and LNG fuel for medium and heavy-duty vehicles. We also sell non-lubricated natural gas compressors and related equipment used in CNG stations and LNG stations, convert light and medium duty vehicles to run on natural gas, and produce renewable natural gas, or RNG, which can be used as vehicle fuel or sold for power generation. In addition, we help our customers 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 fuel, and are well suited for use by vehicle fleets that consume high volumes of fuel, refuel at centralized locations, or along well defined routes, and are increasingly required to reduce emissions. According to the U.S. Department of Energy's Energy Information Administration, or EIA, the amount of natural gas consumed in the U.S. for vehicle use more than doubled between 2000 and 2011. 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 U.S. 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, light to medium-duty vehicles, refuse trucks, and transit buses as an alternative to gasoline and diesel. 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. We also provide CNG by delivering and vaporizing LNG to turn liquefied natural gas into compressed natural gas, or LCNG, at locations where no gas pipeline service exists or gas pipeline pressures are inadequate. We are also beginning to provide CNG at some of our LNG stations as well. LNG is generally used in trucks and other medium to heavy duty vehicles as an alternative to diesel, where a vehicle must carry a greater amount of fuel energy than can be feasibly provided onboard by CNG. LNG is natural gas that is cooled at a liquefaction facility to approximately -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 58 tanker trailers. At the stations, LNG is stored in above ground tanks until dispensed into vehicles in liquid form.

        We serve fleet vehicle operators in a variety of markets, including trucking, airports, taxis, refuse hauling and public transit. We believe these fleet markets will continue to present a high growth opportunity for natural gas vehicle fuels. At December 31, 2011, we served approximately 530 fleet customers operating approximately 25,000 natural gas vehicles, and we owned, operated or supplied 273 natural gas fueling stations in twenty-three states, in British Columbia and Ontario within Canada, as well as in Peru.

        To serve trucks that are moving goods around the country on natural gas, we are building a nationwide network of LNG truck fueling stations, which we refer to as America's Natural Gas Highway, or ANGH, on the interstate highway system and in major metropolitan areas. We expect America's Natural Gas Highway to enable freight trucking coast to coast and border to border within the 48 continental states. Our plans call for the first phase of America's Natural Gas Highway to include approximately 150 fueling stations, with approximately 70 of these stations anticipated to be open in 33 states by the end of 2012, with the remainder scheduled to be completed in 2013. We expect that many ANGH stations will be co-located at Pilot-Flying J Travel Centers already serving goods movement trucking. The opening of these stations is planned to coincide with the expected commercial

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availability of new natural gas truck engines well suited for heavy-duty, over-the-road trucking in the U.S.

The Market for Vehicle Fuels

        According to the EIA's Annual Energy Outlook 2012 Early Release (January 23, 2012), the U.S. consumed an estimated 176 billion gallons of gasoline and diesel in 2010, and demand is anticipated to grow at an annual rate of 0.4% to 194.1 billion gallons by 2035. Fuel use in medium and heavy duty trucks, which was about 36 billion gallons in 2011, is projected to grow to 42 billion gallons by 2035. Gasoline and diesel comprise the bulk of vehicle fuel consumed in the United States, while CNG, LNG and other alternative fuels, including ethanol, propane, hydrogen, biodiesel, electricity and methanol, represent less than 3% of consumption, according to the EIA.

        Since 2009, as world economic growth has resumed and political instability has swept the Middle East, oil, gasoline, and diesel prices have been volatile and generally increased, with prices for a barrel of crude often topping $100.

        Higher oil, gasoline and diesel prices improve the magnitude of the immediate market opportunity for natural gas fuels. Increasingly stringent federal, state and local air quality regulations, a desire to lower greenhouse gas emissions, and regulations mandating low carbon fuels continue to develop, which all supports the case for natural gas fueling options. In addition, the desire for fuel diversity among fleet operators further enhances the opportunity for natural gas fuels. Internationally, natural gas as an alternative fuel has been more widely used for many years in other parts of the world. The February 2012 edition of the Gas Vehicles Report estimates that there are only 112,000 natural gas vehicles in the United States, compared to approximately 14.6 million worldwide.

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 and cleaner 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 2010, there were approximately 300 million gasoline gallon equivalents of natural gas consumed in the United States for vehicle use, which is more than double the amount consumed in 2000. The February 2012 Natural Gas Vehicle Report published by the NGV Journal estimates that there are over 1,100 natural gas fueling stations in the United States.

Benefits of Natural Gas Fuel

        Less Expensive.     Based on EIA data, since 2004, CNG and LNG have been significantly less expensive than gasoline and diesel. For example, in 2011, the average retail CNG price we charged in California, our most significant market, was $1.12 less per gasoline gallon equivalent than the average California regular unleaded gasoline price of $3.82 per gallon. 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 an energy equivalent basis. LNG prices per diesel gallon equivalent are also favorable to diesel prices. In California, for example, Low Sulfur Diesel for 2011 averaged $4.08 per gallon, compared to our LNG diesel gallon equivalent price of $2.60.

        In 2007, new federal emissions requirements became effective for medium and heavy duty engines, and more stringent requirements went into effect in 2010. These requirements limit the levels of specified emissions from new vehicle engines manufactured in or after these years, and have resulted in cost increases for both acquiring and operating diesel vehicles. In order to comply with these standards, 2010 and later diesel engine models have employed significant new emissions control technologies such as advanced particulate matter traps, exhaust gas recirculation systems, and selective catalytic reduction strategies that require urea, all of which have resulted in increases to the cost of medium and heavy

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duty diesel vehicles. According to industry sources, the purchase price of a 2010 heavy duty diesel vehicle that meets the 2010 diesel emission standards increased by more than $10,000 per vehicle. The 2010 and newer diesel vehicles require the use of ultra-low sulfur diesel fuel to meet the standards, which we believe increases the cost of operating and maintaining medium and heavy duty diesel vehicles. We expect these additional emission controls will generally increase the cost to own and operate diesel vehicles.

        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, due to rising crude oil prices. In addition, we believe that more stringent emissions requirements will continue to increase the cost of diesel engines and thereby make natural gas vehicles an attractive alternative.

        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 compared to gasoline or diesel powered vehicles.

Average California Retail Prices

(per gasoline gallon equivalent)(1)

 
  Year Ended December 31,  
 
  2009   2010   2011  

California retail gasoline(2)

  $ 2.68   $ 3.09   $ 3.82  

California retail diesel(2)(3)

    2.34     2.84     3.67  

California CNG—Clean Energy

    2.14     2.51     2.70  

CNG discount to gasoline

    (0.54 )   (0.58 )   (1.12 )

CNG discount to diesel

  $ (0.20 ) $ (0.33 ) $ (0.97 )

California LNG—Clean Energy

  $ 1.93   $ 2.03   $ 2.33  

LNG discount to diesel

  $ (0.41 ) $ (0.81 ) $ (1.34 )

(1)
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 and LNG compared to gasoline and diesel. Using this method, the cost of CNG and LNG is presented based on the amount of CNG and LNG required to generate the same amount of energy, measured in British Thermal Units, or BTUs, as a gallon of gasoline. Diesel prices were also converted to the energy equivalent of a gallon of gasoline.

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

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

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        The following chart shows 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 2011

Market
  Fuel   Estimated annual
fuel usage
(gallons)(1)(2)
  Cost of fuel CNG or
LNG vs. gasoline or
diesel (gallons)(1)(3)
  Estimated
annual
fuel cost
savings
 

Taxi

  CNG or Gasoline     5,000   $ 2.70 (4) vs. $ 3.82 (4) $ 5,600  

Shuttle van

  CNG or Gasoline     7,500   $ 2.70 (4) vs. $ 3.82 (4) $ 8,400  

Municipal transit bus (CNG)

  CNG or Diesel     16,680   $ 1.62 (5) vs. $ 3.02 (6) $ 23,352  

Refuse truck (CNG)

  CNG or Diesel     11,120   $ 1.61 (5)(7) vs. $ 3.67 (6) $ 22,907  

Municipal transit Bus (LNG)

  LNG or Diesel     16,680   $ 1.77 (5) vs. $ 3.02 (6) $ 20,850  

Refuse truck (LNG)

  LNG or Diesel     11,120   $ 1.72 (5)(7) vs. $ 3.67 (6) $ 21,684  

Heavy-duty truck (LNG)

  LNG or Diesel     20,000   $ 2.33 (8) vs. $ 3.67 (6) $ 26,800  

(1)
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 and LNG compared to gasoline and diesel. Using this method, the cost of each fuel is presented based on the same amount of energy, measured in BTUs, as a gallon of gasoline.

(2)
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.

(3)
Fuel prices for municipal transit buses are lower compared to refuse trucks because fuel for municipal buses is not subject to fuel excise taxes.

(4)
CNG retail pricing is based on average Clean Energy retail station pricing in California during 2011. Gasoline retail pricing is based on California average retail gasoline prices during 2011 as reported by EIA.

(5)
CNG and LNG prices based on average prices paid by representative Clean Energy California fleet customers in 2011.

(6)
Diesel price based on EIA reported average diesel price in California in 2011.

(7)
Excludes California Board of Equalization taxes of $0.0875 per gasoline gallon equivalent 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 gross vehicle weight that allows them to opt out of this tax.

(8)
LGN retail price is based on average Clean Energy retail station pricing at the Port of Long Beach station in 2011.

        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.

        Transportation is responsible for approximately 29% of total U.S. greenhouse-gas emission, and over 5% of global greenhouse gas emissions. Under the California Air Resource Board, or CARB's, low carbon fuel standard, or LCFS, CARB recognizes that the "well to wheels" analysis of natural gas

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as a vehicle fuel indicates that natural gas provides an up to 29% reduction in greenhouse gas emissions for light duty vehicles and up to a 23% reduction for medium and heavy-duty vehicles.

        RNG use is also a means to reduce greenhouse gas emissions. RNG is produced from waste streams such as landfills, animal waste digesters and waste water treatment plants. A full lifecycle analysis performed by CARB has determined that use of RNG generated from landfills as a vehicle fuel can reduce greenhouse gas emissions up to 88% as compared to gasoline. According to The American Biogas Alliance, RNG can be liquefied or injected into a pipeline and is compatible with existing natural gas fueling infrastructure. Further, in February 2010, the U.S. Environmental Protection Agency finalized the Renewable Fuel Standard Phase 2 that creates tradable credits, or RINS, that can be generated by production and use of RNG in the transportation sector and can be sold to fuel providers that are not compliant under the rule. Finally, RNG can also be sold to private and municipal California utilities that are required to meet the 33 percent Renewable Portfolio Standard by 2020. We are evaluating our options for generating tradable RINs through our subsidiaries.

        Safety.     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, environmental hazard tests, burst pressures, and crash testing, according to the U.S. Department of Transportation National Highway Traffic Safety Administration. CNG and LNG are stored in above ground tanks and therefore cannot contaminate soil or groundwater.

        Domestic and plentiful supply.     In 2011, the U.S. consumed 18.9 million barrels of crude oil per day, of which 38% was supplied from the U.S. and Canada and 62% was imported from other countries, according to the EIA. By comparison, the EIA estimates that over 98% of the natural gas consumed in the United States in 2011 was supplied from the United States and Canada making it less vulnerable to foreign supply disruption. In addition, the EIA estimates that less than 0.2% of the estimated 24.4 trillion cubic feet of natural gas consumed in the U.S. in 2011 was used for vehicle fuel.

        Analysts believe that there is a significant worldwide supply of natural gas relative to crude oil. According to the 2010 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2009 natural gas production was 37% greater than the ratio of proven crude oil reserves to 2009 crude oil production. This analysis suggests significantly greater long-term availability of natural gas than crude oil based on current consumption.

        On June 18, 2009, the Potential Gas Committee, or PGC, released its report on the natural gas resource base in the U.S. The report states that the U.S. possesses a total resource base of 1,836 trillion cubic feet, or Tcf. This is the highest resource evaluation in the PGC's 44 year history. Another study published by Navigant Consulting in 2008, and further updated in 2009, defined the recoverable natural gas resources at 2,247 Tcf, or 118 years at current consumption levels.

        A 2010 IHS CERA special report "Fueling America's Energy Future" stated "North American discovered natural gas resources have increased by more than 1,800 Tcf over the prior three years, bringing the total natural gas resource base to more than 3,000 Tcf, a level that could supply current consumption for well over 100 years."

        In addition, the preliminary 2012 Annual Energy Outlook report from the EIA estimates that shale gas could represent 49% (13.6 Tcf) of U.S. natural gas production by the year 2035, up from the 14% and 23% (5 Tcf) of domestic natural gas produced in 2009 and 2010, respectively. The EIA estimates that, based upon 2010 consumption levels, there is enough available shale gas to satisfy demand for the next 100 years. The primary reason for the availability of additional natural gas is the increased successful use of recent shale drilling technology and continued drilling in shale plays with high

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concentrations of natural gas liquids and crude oil, which have a higher energy value than dry natural gas.

Natural Gas Vehicles and Engines

        Natural gas vehicles use internal combustion engines similar to those used in gasoline or diesel powered vehicles. 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, spark ignited natural gas vehicles generally operate more quietly than diesel powered vehicles. Natural gas vehicles typically cost more than gasoline or diesel powered vehicles, primarily due to the additional cost of the storage cylinders that hold the CNG or LNG.

        Almost any 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. In the U.S., however, a limited number of models of natural gas engines and vehicles have been historically available. We believe that in the near-term new heavy-duty natural gas engines and trucks will be offered. We further expect that additional models of other natural gas vehicles will continue to become available as natural gas is increasingly adopted as a vehicle fuel in the U.S.

        In the U.S., there are currently three factory built natural gas passenger and light-duty vehicles: Honda offers the Civic NG, a 4-door passenger sedan; General Motors Company ("GM") offers a light-duty Chevy Express/GMC Savana cargo van; and The Vehicle Production Group offers the MV-1, a wheelchair accessible sedan that uses a Ford Motor Company ("Ford") engine. Chrysler Group, LLC and GM have announced plans to offer bi-fuel pickup trucks in 2012. Bi-fuel vehicles can run on either natural gas or gasoline and have tanks for each fuel onboard. A limited number of other dedicated (uses only natural gas fuel) and bi-fuel passenger vehicles, vans and light duty trucks are available through small volume manufacturers, such as our wholly-owned subsidiary, BAF Technologies, Inc., or BAF. These small volume manufacturers offer model vehicles made by major automobile manufacturers that they have modified to use natural gas and have been certified to meet federal and state emissions and safety standards. Several GM and Ford models are now available from these manufacturers, including the Ford Transit Connect, Ford E Series vehicles, Ford F Series trucks, and GM vehicles that include pickups and vans. We anticipate additional models through various outlets will become available in 2012. Modifications for dedicated natural gas vehicles involve removing the gasoline fuel system and replacing it with a compressed natural gas fuel storage system and reflashing the engine's computer controlled fuel management system.

        Currently, there are three natural gas engines available for the trucking market:

    7.6 liter spark-ignited engine with 300 horsepower and 860 lb-ft torque produced by Emission Solutions, Inc. for Navistar International Corp., or Navistar. This engine is used for local trucking such as food and beverage delivery.

    8.9 liter spark-ignited engine with 250-320 horsepower and 660-1,000 lb-ft torque produced by Cummins Westport, Inc., or CWI, a joint venture of Cummins, Inc. and Westport Innovations, Inc. This engine is used in commercial trucks, refuse trucks and buses, and has been the backbone for natural gas trucking to date.

    15 liter high pressure direct injection engine with 400-450 horsepower and 1,800 lb-ft torque produced by Westport Innovations, Inc., which requires the use of a diesel particulate filter and

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      selective catalytic reduction with urea injection to reduce emissions in compliance with U.S. Environmental Protection Agency, or EPA, 2010 standards. This engine is finding use in applications that require high horsepower, such as transporting loads in excess of the 80,000 pound U.S. federal highway standard and up steep inclines.

        Every major truck Original Equipment Manufacturer, or OEM, including Freightliner, Navistar, International, Kenworth, Peterbilt and Volvo, offers natural gas trucks using the engines described above. Further, other OEMs offer natural gas school buses, shuttles, transit buses and street sweepers.

New Heavy Duty Truck Engines and Building America's Natural Gas Highway

        Based on our experience, the natural gas engines available for the trucking market are not ideally suited to serve the U.S. heavy-duty trucking market. We believe the ideal engine for this market is an approximately 12 to 13 liter engine that delivers approximately 400 horsepower and 1,400 to 1,500 lb-ft torque. In contrast, the 7.6 liter and 8.9 liter engines deliver inadequate horsepower and torque, and the 15 liter engine is too large and expensive to efficiently transport the loads typically hauled by U.S. carriers, and has the added complication of requiring three fuels—LNG, diesel and urea. We believe the lack of an engine that is well-suited for the U.S. heavy-duty truck market has hampered the adoption of natural gas fuel by this market.

        During the past twelve months, engine manufacturers have announced plans to offer natural gas truck engines that we believe will be ideally suited for the U.S. heavy-duty trucking market. CWI has developed and is field testing a spark-ignited 11.9 liter engine that delivers 400 horsepower and 1,400 lb-ft torque. We believe this engine will be commercially available within the next twelve months. In addition, Navistar and its partners are developing a 12.9 liter dual-fuel engine that is expected to be available in mid-2013. Major truck OEMs, including Freightliner, International, Navistar, Kenworth, Peterbilt, Autocar and Volvo, plan to offer natural gas trucks using these engines.

        We anticipate the commercial roll-out of these and other natural gas engines that are well-suited for the U.S. heavy-duty trucking market, together with the economic and environmental benefits of natural gas fuel, will result in increased adoption of natural gas fueled trucks by the U.S. heavy-duty trucking industry. Heavy duty trucks are generally high volume users of vehicle fuel. We believe many use 20,000 gallons or more per year. We therefore anticipate that operators of natural gas heavy-duty trucks could become significant customers. As these engines are adopted and increasing numbers of heavy-duty natural gas trucks are deployed in the U.S., natural gas fueling infrastructure must be available to serve the needs of truck operators. To meet these needs, we are building America's Natural Gas Highway, a nationwide network of LNG truck fueling stations on the interstate highway system and in major metropolitan areas. We expect the first ANGH phase to include approximately 150 fueling stations, with approximately 70 stations anticipated to be open in 33 states by the end of 2012, and the balance in 2013. We anticipate that many ANGH stations will be co-located at Pilot Flying J Travel Centers, pursuant to an agreement we entered with Pilot in October 2010. Pilot is the largest truck-fueling operator in the U.S., with approximately 500 truck travel centers in 43 states. We believe our relationship with Pilot positions us to build ANGH stations at some of the best locations in the U.S.

        In an effort to accelerate the adoption of natural gas engines that are well-suited for the U.S. heavy-duty trucking market, in January 2012, we entered a strategic joint marketing and fueling agreement with Navistar. Pursuant to this agreement, the companies will offer operators a truck lease and fueling package that is structured to eliminate the incremental cost of a natural gas truck, in exchange for the operators entering a long-term minimum-commitment fueling contract with our company.

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Products and Services

        We sell CNG and LNG and provide operating and maintenance, or O&M, services to our customers. For the year ended December 31, 2011, CNG and RNG (together) represented 70% and LNG represented 30% of our natural gas sales (on a gasoline gallon equivalent basis). We design and construct CNG, LNG and LCNG fueling stations and sell or lease some of those stations to our customers. We also sell RNG produced by our subsidiary Dallas Clean Energy LLC, or DCE, sell natural gas vehicles produced by our subsidiary BAF, and sell advanced natural gas fueling compressors and related equipment and maintenance services through our subsidiary Clean Energy Compression Corp, also known as I.M.W. Industries Ltd. (we refer to this entity as "IMW" in this report). In addition, we help our customers acquire and finance natural gas vehicles.

        CNG Sales.     We sell CNG through fueling stations located on our customers' properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers' vehicles. Our CNG sales are made primarily through contracts with our customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. Our 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 Production and Sales.     We obtain LNG from our own plants as well as through relationships with suppliers. We own and operate LNG liquefaction plants near Houston, Texas and Boron, California, which we call the Pickens Plant and California LNG Plant, respectively. The Pickens Plant has the capacity to produce 35 million gallons of LNG per year and also includes tanker trailer loading facilities and a 1.0 million gallon storage tank that can hold up to 840,000 usable gallons. Additionally, our California LNG Plant is capable of producing 60 million gallons of LNG per year, and we plan to expand this plant to increase its production capacity to 90 million gallons of LNG per year. This plant has tanker trailer loading facilities similar to the Pickens Plant and a 1.8 million gallon storage tank that can hold up to 1.5 million usable gallons.

        We sell LNG to fleet customers, who typically own and operate their fueling stations. Increasingly, we also sell LNG to fleet and other customers at our public-access LNG stations and for non-vehicle use, such as power generation. During 2011, we procured 43% of our LNG from third-party producers, and we produced the remainder of the LNG at the Pickens Plant and the California LNG Plant. For LNG that we purchase from third parties, we have entered into, and we may enter into additional, "take or pay" contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. 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. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied. We also sell LNG 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.

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        We expect that we will need to secure additional sources of LNG for America's Natural Gas Highway. We plan to expand the production capability of our California LNG Plant and we are investigating other potential sources of LNG. We also anticipate that we will need to purchase or lease additional tanker trailers to transport LNG to ANGH stations, and that we will need to increase the number of third parties who provide us contract carrier services. We may also pursue other alternatives to meet our future LNG transportation demands.

        Operation and Maintenance.     We perform O&M services for CNG stations, which are either owned by us or our customers. In addition, we perform O&M services for LNG stations we own, and we perform O&M services for a small number of LNG stations owned 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 them efficiently. As of December 31, 2011, we had an operations team of 102 employees, including 65 full-time employees dedicated to performing preventative maintenance and available to respond to service requests in 23 states and in Canada. In addition, we have 75 full-time employees dedicated to performing preventative maintenance on IMW's foreign installations in Bangladesh, Colombia, Peru and China.

        Our Station Network.     As of December 31, 2011, we owned, operated or supplied 273 fueling stations for our customers in 23 states and Canada. We owned 153 of the stations, and our customers owned the other 120 stations. The breakdown of the services we perform for these stations is set forth below.

 
  As of December 31, 2011  
 
  CNG fueling
stations
  LNG fueling
stations
  Total
stations
 

Operated, maintained and supplied by Clean Energy

    127     9     136  

Supplied by Clean Energy, operated and maintained by customer

        31     31  

Operated and maintained by Clean Energy, supplied by customer

    95     11     106  
               

Total

    222     51     273  
               

        Station Construction and Engineering.     Since 2008, we have built 165 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 build 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 tanks (which hold a relatively small buffer amount of compressed natural gas). Equipment for an LNG station typically consists of storage tanks that hold 5,000 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 up to six gasoline gallon equivalents per minute, which is comparable to a traditional gasoline fueling dispenser. Our LNG dispensers are designed to fuel up to 20 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.

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        To enhance our station construction capabilities, in December 2010, we acquired Wyoming Northstar Incorporated, or Northstar, a leading provider of LNG and LCNG station design, construction operations and maintenance services. Northstar is also a leader in LNG and LCNG fueling system technologies, including manufacturing one of only two weights-and-measures certified LNG dispensers. Northstar is a key component of our plan to roll-out America's Natural Gas Highway. In addition, to further support our station construction activities, in 2011, we purchased Weaver Electric Inc. ("Weaver"), a Southern California-based construction and engineering firm that specializes in natural gas fueling stations.

        RNG.     In August of 2008, we acquired 70% of the outstanding membership interests of DCE, which owns 100% of Dallas Clean Energy McCommas Bluff, LLC, or DCEMB. DCEMB owns a facility that collects, processes and sells renewable, pipeline-quality natural gas at the McCommas Bluff landfill located in Dallas, Texas. DCEMB sells RNG produced at the facility to Shell Energy North America under a Gas Sale Agreement entered into in April 2009. Depending upon RNG production volumes, DCEMB also has the ability to sell RNG as a vehicle fuel. In November 2010, we entered into an agreement with Republic Services Group to develop a second RNG project at their landfill in Canton, Michigan. The project is scheduled to commence operations in the summer of 2012, and we have entered into a ten-year fixed-price sale contract for the majority of the RNG that we expect the project to produce. In addition, we are seeking to expand our RNG business by pursuing additional projects.

        Vehicle conversions.     In October 2009, we completed our acquisition of BAF, a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support, and research and development for natural gas vehicles. BAF is headquartered in Dallas, Texas and is a Ford Qualified Vehicle Modifier for all Ford natural gas products. To further enhance the capabilities of BAF, in February 2011, we purchased a 19.9% interest in ServoTech Engineering, a company that provides design and engineering services for natural gas fueling systems.

        Natural gas fueling compressors.     In September 2010, we acquired the advanced, non-lubricated natural gas fueling compressor and related equipment manufacturing and servicing business of IMW. IMW is headquartered near Vancouver, British Columbia, has additional manufacturing facilities near Shanghai, China, and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States. Our acquisition of IMW was driven by four goals. First, we wanted to eliminate a potential competitor. Second, we wanted to make sure we could satisfy our internal compressor needs, since compressors are the most important piece of equipment for a CNG station. As the adoption of natural gas vehicles has increased, our CNG station construction backlog has increased and our compressor requirements have increased. We believe our compressor needs will continue to grow in the future. By acquiring IMW, we believe we are assured of having compressors readily available to deploy at our stations. The third goal was to be able to provide certain customers with a "factory direct" offering. Since some customers do not want our full suite of services and simply want a station that they can own and operate, we can now offer them a high quality and low cost "equipment only" solution. The fourth driver was our goal to participate in the global growth of natural gas vehicle fueling. IMW has a strong reputation in the global market, and we believe IMW will benefit and participate in such growth.

        Vehicle Acquisition and Finance.     We offer 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 certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from

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our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated.

        VETC.     From October 1, 2006 through December 31, 2011, we received a federal fuel tax credit, or VETC, of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sold as vehicle fuel. Based on the service relationship with our customers, either we or our customers were able to claim the credit. The program providing for the VETC expired on December 31, 2011.

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, Atlanta, New Jersey, Pennsylvania, Seattle, New Mexico, Chicago, Georgia, Florida, Virginia, Minnesota, Kentucky, Indiana, New Hampshire, Indiana and Missouri in the U.S., in Toronto and Vancouver, Canada and in Bangladesh, Colombia, Peru and China. At December 31, 2011, we had 82 employees in sales and marketing, including seven employees of BAF and 14 employees of IMW. 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 opportunities in targeted metropolitan areas and in locations where we have existing fueling infrastructure. 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.

Key Markets and Customers

        At December 31, 2011, we had 530 fleet customers operating approximately 25,000 vehicles, including approximately 6,000 transit buses, 2,400 taxis, 1,700 shuttles and 3,300 refuse trucks. We target customers in a variety of markets, such as trucking, airports, taxis, refuse, public transit and government fleets. During 2009, 2010 and 2011, approximately 59%, 42% and 33% of our revenues, respectively, were derived from contracts with governmental entities such as municipal transit fleets. We do not depend on a single customer or a few customers, the loss of which would have a material adverse effect on us.

    Trucking —Many shippers, manufacturers, retailers and other truck fleet operators have begun adopting natural gas fueled trucks. Some of our customers in this market currently include: the Houston distribution centers of Sysco Food Services, a wholesale distributor of food products, United Parcel Service, the Houston distribution center of H.E. Butt Grocery Company, Trimac USA of Houston, Renewable Dairy Fuels of Fair Oaks, Indiana, Saddle Creek, a third-party logistics company in Lakeland Florida and Pepsi Bottling Group. We anticipate that the commercial roll-out of natural gas engines that are well-suited for the U.S. heavy-duty trucking market, in connection with the economic and environmental benefits of natural gas fuel, will result in increased adoption of natural gas fueled trucks by the U.S. trucking industry. Heavy-duty trucks in the U.S. are generally high volume users of vehicle fuel. We believe many use 20,000 gallons or more per year. We therefore believe that this market has the potential to become, in the coming years, our largest market. As a result, we have made a significant commitment of capital and other resources to construct America's Natural Gas Highway, which is intended to primarily serve the needs of operators of heavy-duty natural gas trucks that are moving goods around the U.S.

    Airports —Many U.S. airports face emissions challenges 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

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      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 Albuquerque, Atlanta Hartsfield-Jackson International, Austin-Bergstrom International, Baltimore-Washington International, Burbank, Dallas-Ft. Worth International, Hartford, Las Vegas, Love Field (Dallas), Long Beach, Denver International, LaGuardia (New York), Los Angeles International, New Orleans, Newark International, Oakland International, Ontario, Palm Springs, Phoenix Sky Harbor International, San Francisco International, Santa Ana/John Wayne, San Diego International, SeaTac International (Seattle), Tucson International and Will Rogers (Oklahoma City). At these airports, our representative customers include taxi and van fleets, as well as parking and car rental shuttles. We believe these are well-suited customers because they use a relatively high volume of vehicle fuel and can be served by centralized fueling infrastructure.

    Taxis —According to the Taxi, Limousine, and Paratransit Association, there were approximately 6,300 companies operating 171,000 taxicabs in the United States in 2010. We believe that less than 2% of these vehicles are natural gas vehicles. Because taxi fleets travel many miles, use a relatively high volume of vehicle fuel and can refuel at a central location, we believe they are excellent candidates to use CNG. Natural gas vehicles provide taxi fleets a convenient way to reduce operating costs and provide a clean environment for their drivers and customers. We serve approximately 2,300 taxis in Southern California, the San Francisco Bay Area, Dallas, Houston, Las Vegas, New York City, Phoenix, Tucson and Seattle. We have also seen a significant interest in new policy initiatives at major airports across the country this past year, including the Philadelphia, Cincinnati, and Newark Airports.

    Refuse Haulers —According to INFORM, there are nearly 200,000 refuse trucks in the United States, consuming approximately two billion gallons of fuel per year, that collect and haul refuse and recyclables from collection points to landfills and recycling facilities. Due to the desire to recognize operating savings, and to address their customers' demands to reduce emissions, refuse haulers are increasingly adopting trucks that run on CNG. We estimate that out of the approximately 8,000 new refuse collection trucks ordered during 2011, over 2,000 were powered by CNG fuel. Waste Management has made public its commitment that 90% of its new vehicle orders in 2012 will be natural gas vehicles. Further, Republic Services has committed that 65% of its new purchases in 2012 will be natural gas vehicles and 40% of their fleet will be CNG within five years. We serve numerous Waste Management and Republic Services sites now, and hope to expand this number in the future. In addition to Waste Management and Republic Services, we have a national account with Waste Connections, and we also have contracts with private waste haulers such as CleanScapes (Seattle), Choice Waste (FL), Recology (Formerly Norcal Waste), South San Francisco Scavenger, Burrtec (CA), Central Jersey Waste, Garofalo V & Sons (NY) and Waste Pro (FL) among others. We also provide vehicle fueling services to municipal refuse fleets including fleets in Los Angeles, Fresno, Sacramento, Burbank, Dallas, San Antonio, and on Long Island, New York among other locations. We believe refuse companies are ideal customers because they can be served by centralized fueling infrastructure and they use a relatively high volume of fuel.

    Transit agencies —According to the American Public Transportation Association, there are over 64,800 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. Transit agencies have been early adopters of natural gas vehicles, with almost 34% of all buses in the United States operating on LNG or CNG, according to the American Public Transportation Agency 2011 Public Transportation Factbook. Our representative public transit

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      customers include Dallas Area Rapid Transit, City of Laredo Transit (Texas), City of Elk Grove (California), Santa Monica Big Blue Bus, Los Angeles Metropolitan Transit Authority, Boston Metropolitan Transit Development Agency, Phoenix Transit, Tempe Transit, Foothill Transit (California), Santa Cruz Metropolitan, Orange County Transit Authority, Regional Transit Commission of Nevada and Regional Transit Authority (Ohio). Transit agencies typically fuel at a central location and they use high volumes of fuel.

    Government fleets —According to the Federal Highway Administration, or FHA, in 2009, there were over 4.6 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 637,000 and 494,000 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 California Department of Transportation (Los Angeles and Orange County), State of New York, City of Denver, City and County of Los Angeles, City of San Antonio, Town of Smithtown (NY), City and County of San Francisco, City and County of Dallas and City of Phoenix.

Acquisitions

        In April 2008, we opened our first compressed natural gas station in Lima, Peru through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interests of DCE, which owns 100% of DCEMB. DCEMB owns a facility that collects, processes and sells RNG collected from a landfill in Dallas, Texas. On October 1, 2009, we completed our acquisition of BAF, a company that is a Ford approved Qualified Vehicle Modifier for all Ford natural gas products. BAF provides natural gas alternative fuel systems, application engineering, service and warranty support and research and development for a wide line of Ford natural gas products. On September 7, 2010, we acquired the advanced, non-lubricated natural gas fueling compressor and related equipment manufacturing and servicing business of IMW. On December 15, 2010, we acquired Northstar, which is a leading provider of design, engineering, construction and maintenance services for LNG and LCNG fueling stations. During 2011, we acquired Weaver and a 19.9% interest in ServoTech Engineering. In the future, we anticipate we will continue to pursue acquisitions and partnerships as we become aware of opportunities where we believe we can increase our competitive advantages or enhance our market position.

Tax Incentives

        Historically, U.S. federal and state government tax incentives and grant programs were available to reduce the cost of acquiring and operating a natural gas vehicle fleet. Incentives were typically available to offset the cost of acquiring natural gas vehicles or converting vehicles to use natural gas, constructing natural gas fueling stations and selling CNG or LNG. As of December 31, 2011, however, all federal government tax incentives had expired. In 2011, legislation was introduced in Congress to extend or reinstate certain federal tax incentives. However, the legislative process is inherently uncertain and we do not know if or when any of the legislation providing for reinstatement, extension or new incentives for natural gas fuel or vehicles may be passed.

Grant programs

        We apply for and help our fleet customers apply for federal, state and regional grant programs in states where we operate including California, Connecticut, Georgia, Idaho, Indiana, Nevada, New

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Jersey, New York, Ohio, Pennsylvania, and Texas. These programs provide funding for natural gas vehicle purchases and station construction.

Competition

        The market for vehicular fuels is highly competitive. The biggest competition for CNG and LNG 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.

        A significant number of established businesses, including oil and gas companies, retail fuel providers, vehicle OEMs, refuse collectors, natural gas utilities, industrial gas companies and other organizations have entered or are planning to enter the market for natural gas vehicle fuels. Many of these current and potential competitors have substantially greater financial, marketing, research and other resources than we have. We also compete with suppliers of other alternative vehicle fuels, including ethanol, biodiesel and hydrogen fuels, as well as providers of hybrid and electric vehicles. Some of our current principal competitors in the market for natural gas vehicle fuels include:

    Intergrys, a provider of CNG fuel infrastructure and fueling services through its subsidiaries Trillium USA and Pinnacle CNG, which it acquired in 2011;

    Pacific Gas and Electric, a utility that operates public access CNG stations in Northern California;

    Gas producers Encana, Chesapeake and Apache, who are investing in fueling infrastructure;

    Mansfield Oil, a diesel fuel provider to fleets that recently acquired a California-based fuel infrastructure company;

    Vocational Energy, a fueling infrastructure company focused on the refuse market; and

    Applied LNG Technology and Prometheus Energy, each of which distributes LNG in the western United States.

        In addition, natural gas utilities in California, Michigan, Illinois, New Jersey, North Carolina and Georgia have recently made efforts to invest in the market for natural gas vehicle fuels.

        With our acquisition of IMW in September 2010, we began selling CNG fueling equipment. The market for CNG fueling equipment is highly competitive with several competitors selling in multiple countries. We believe our largest competitors for CNG fueling equipment are Aspro, GNC Galileo, SAFE, ANGI Energy Systems, Inc., and Atlas Copco. Numerous other equipment or compressor manufacturing companies may also enter the market in the future.

        We own, operate or supply 273 CNG and LNG fueling stations. We operate 222 CNG fueling stations, which we estimate is approximately four times the number of CNG fueling stations operated by our next largest competitor. We believe we are the only company in the U. S. 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. In addition, we believe that IMW is the leading global supplier of CNG equipment for vehicle fueling. We expect, however, competition to intensify in the near term as the use of natural gas vehicles and the demand for natural gas vehicle fuel and related equipment increases. Increased competition will lead to amplified pricing pressure, reduced operating margins and fewer expansion opportunities.

Background on Clean Air Regulation

        Federal Clean Air Act —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

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programs regulating vehicles and stationary sources have their basis in Title I or Title II of the Federal Clean Air Act.

        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 stationary source emissions, vehicle pollution or mobile sources of pollution are developed as part of a state implementation plan. For mobile sources, two criteria pollutants in particular are of concern: ozone and particulate matter. 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 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.

        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 apply to new diesel engines. Specifically, new particulate matter standards took effect in the model year 2007 and new NOx standards were 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, required refiners to begin producing ultra low sulfur diesel fuels on June 1, 2006.

        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.

        Although the federal government has not adopted any laws that comprehensively regulate greenhouse gas emissions, the EPA is developing regulations that would regulate these pollutants under the Clean Air Act.

        California's AB 32—In September 2006, California Governor Arnold Schwarzenegger signed AB 32—the Global Warming Solutions Act of 2006—into law, which calls for a cap on greenhouse-gas emissions throughout California and a statewide reduction to 1990 levels by the year 2020, and an additional 80% reduction below 1990 levels by 2050. To achieve the state's greenhouse gas reductions for mobile sources, CARB, in 2009, approved the LCFS that requires a 10% carbon reduction in gasoline and diesel fuels sold in the State of California by 2020, and therefore encourages other low carbon transportation fuels to enter the marketplace by allowing them to generate carbon credits that can be sold to noncompliant regulated parties. Under this regulation, CNG, LNG and RNG are identified as "compliant fuels" through 2020 as their carbon benefits have been verified to far exceed

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the regulation's 2020 goal of a 10% reduction. Although a Federal District Court in California recently ruled that the LCFS violates the U.S. Constitution's commerce clause, that decision is under appeal to the 9 th  Circuit Court of Appeals and we anticipate that CARB will continue to press to regulate the carbon intensity of vehicle fuels sold in California.

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 and 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 with the California Department of Corporations.

    Vehicle conversion —Vehicles that are converted to run on natural gas and sold by BAF are subject to EPA emission requirements and certifications, federal vehicle safety regulations and, in some cases, such as California, state emission requirements and certifications.

    Natural gas fueling compressors —CNG fueling equipment is manufactured to meet the electrical and mechanical design standards of the country where the equipment will be installed. Our manufacturing facility in Canada is registered with the British Columbia Safety Authority and the Society of Mechanical Engineers for manufacturing and operating pressure vessels.

    RNG —Our RNG production facility in Texas, and the RNG facility we are building in Michigan, are required to comply with Title V air permits as well as EPA regulations covering the collection of landfill gas. In addition, our RNG projects must produce RNG that meets the gas quality specifications of the local utilities that accept the gas. These specifications are approved by the relevant state utilities commission. In California, the gas utilities pipeline specifications prohibit the injection of landfill gas. If the gas utilities that we rely upon to accept and ship our RNG product adopt new gas specifications or otherwise refuse to accept our RNG product, we will be unable to sell the product and generate revenues.

        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 and regulations of greenhouse gas emissions from our LNG plants or stations. 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, 2011, we employed 1,036 people, of whom 82 were in sales and marketing, 844 were in operations, engineering, and vehicle and compressor production, and 110 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 our revenues from external customers, operating income (loss) and long-lived assets broken down by geographic area, see note 14 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 of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. The reference to our website is intended to be an inactive textual reference and the contents of our website are not intended to be incorporated into this report.

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Item 1A.—Risk Factors

         An investment in our Company involves a high degree of risk of loss. You should carefully consider the risk factors discussed below and all of the other information included in this annual report on Form 10-K before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.

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

        In 2009, 2010 and 2011, we incurred pre-tax losses of $33.4 million, $4.2 million, and $48.2 million, respectively. Our loss for 2009 includes $17.4 million of derivative losses related to marking to market the value of our Series I warrants; our loss for 2010 was decreased by a derivative gain of $10.3 million on our Series I warrants; and our loss for 2011 includes a $2.7 million derivative gain. During 2009, 2010 and 2011, our losses were substantially decreased by our receipt of approximately $15.5 million, $16.0 million, and $17.9 million of revenue from federal fuel tax credits, respectively. The program under which we received such credits expired on December 31, 2011. To build our business and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers compelling natural gas fuel prices. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits, our business will suffer and the price of our common stock may drop. In addition, if the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants.

A material portion of our historical revenues are associated with a federal fuel excise tax credit that expired on December 31, 2011.

        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, expired December 31, 2011 and may not be reinstated. In 2009, 2010, and 2011 we recorded approximately $15.5 million, $16.0 million and $17.9 million of revenue, respectively, related to fuel tax credits, representing approximately 11.8%, 7.6% and 6.1%, respectively, of our total revenue during the periods. In addition, on July 15, 2010, the IRS sent us a letter disallowing approximately $5.1 million related to certain excise tax credit claims that we made from October 1, 2006 to June 30, 2008. We are appealing the IRS disallowance, and if we are unsuccessful, we may be required to refund some or all of the $5.1 million in contested claims.

The failure of our initiative to build America's Natural Gas Highway would materially and adversely affect our financial results and business.

        Our business plan calls for us to construct America's Natural Gas Highway, a network of LNG truck fueling stations on interstate highways and in major metropolitan areas that we expect to initially consist of approximately 150 stations. Building America's Natural Gas Highway requires a significant commitment of capital and other resources, and our ability to successfully execute our plan faces substantial risks, including:

    Natural gas truck engines that are well-suited for the U.S. heavy-duty truck market may be adopted by fleet operators at a rate that is slower than our expectations due to, among other things, failure by manufacturers to develop and produce engines, performance issues relating to engines and the cost of engines;

    We may not be able to identify and obtain sufficient rights to use suitable locations for ANGH stations;

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    Development of the ANGH will require substantial amounts of capital, which may not be available on terms favorable to us or at all;

    We may experience delays in building stations, including delays in obtaining necessary permits and approvals;

    We will need to construct significantly more fueling stations in 2012 and 2013 than we have constructed in any fiscal year since we commenced operations, and we may not be able to hire and retain the necessary qualified personnel and our operational infrastructure and systems may be inadequate;

    We may be required to redirect resources from other areas of our business, including our refuse, transit, taxi and airport businesses;

    We may complete ANGH stations before there are sufficient numbers of customers who are capable of fueling at the stations, which would result in us having substantial investments in assets that do not produce revenues and may cause us to lose money on LNG fuel that is supplied to the ANGH stations but is not purchased;

    We may not be able to acquire and transport sufficient volumes of LNG to meet the needs of customers fueling at ANGH stations;

    LNG may not be an attractive alternative to diesel fuel in the future; and

    Building the ANGH will impose significant added responsibilities on our management team and will divert their attention from other areas of our business.

        We must effectively manage these risks and any other risks that may arise in connection with the ANGH build-out to successfully execute our business plan. Failure to successfully execute our ANGH initiative will materially and adversely affect our financial results, operations and business.

We will need to raise debt or equity capital to continue to fund the growth of our business.

        We will be required to raise debt or equity capital to fund the growth of our business. At December 31, 2011, we had total cash and cash equivalents of $238.1 million and short-term investments of $33.3 million, and we expect to receive an additional $50.0 million in June 2012 pursuant to the terms of our Loan Agreement with Chesapeake NG Ventures Corporation. Our business plan for 2012 calls for approximately $239.5 million in capital expenditures. We may also require capital for unanticipated expenses, mergers and acquisitions and strategic investments. In addition, we have committed to significant future payments that we will be required to make in connection with our acquisitions of IMW and Northstar. At December 31, 2011, our future payments for IMW and Northstar totaled $32.5 million and $6.8 million, respectively. We are also obligated to pay up to $40.0 million as additional consideration related to our IMW acquisition if certain performance measurements of IMW are met.

        Equity or debt financing options may not be available on terms favorable to us or at all. Additional sales of our common stock or securities convertible into our common stock will dilute existing stockholders and may result in a decline in our stock price. We may also pursue debt financing options including, but not limited to, equipment financing, the sale of convertible promissory notes or commercial bank financing. Recent economic turmoil and severe lack of liquidity in the debt capital markets and volatility in the equity capital markets have adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which would harm our business, results of operations, and future prospects.

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We are required to make substantial future payments to the holders of our debt securities.

        During July and August, 2011, we issued $200.0 million of debt securities and agreed to issue an additional $50.0 million of debt securities in each of June 2012 and June 2013. Such debt securities bear interest at the rate of 7.5% per annum. The entire principal balance of the debt securities issued in July 2011 is due and payable in July 2018, and the entire principal balance of the debt securities we issued in August 2011 is due and payable in August 2016. We may repay the debt securities in common stock or cash. We expect our interest payment obligations under the debt securities to be approximately $16.9 million for the year ending December 31, 2012 (such amount includes the interest that will be due on an additional $50 million of debt securities we anticipate issuing in June 2012). In future periods, we may not have sufficient capital resources to enable us to fulfill our payment obligations to the holders of our debt securities. If we are unable to make scheduled payments or comply with the other provisions of the documents relating to the debt securities, the holders of such debt securities may be permitted under certain circumstances to accelerate the maturity of the debt securities and exercise other remedies provided for in the securities and under applicable law. An acceleration of the maturity of the debt securities that is not rescinded would have a material adverse effect on our company.

Our growth is influenced by tax and related government incentives for clean burning fuels and alternative fuel vehicles. A reduction in these incentives or the failure to pass new legislation with new incentive programs will increase the cost of natural gas fuel and vehicles for our customers and may reduce our revenue.

        Our business is influenced by 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 income tax credit that was available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles expired on December 31, 2010. The continued absence of these vehicle tax credits could have a detrimental effect on the natural gas vehicle and fueling industry, including sales at our wholly owned subsidiary, BAF, and adversely affect our results of operations and financial performance. If federal incentives are not reinstated or extended and if new incentives are not passed, fewer natural gas vehicles may be sold and used and our revenue and financial performance may be adversely affected. Furthermore, the failure of certain federal, state or local government incentives which promote the use of natural gas as a vehicle fuel to pass into law could result in a negative perception by the market generally and a decline in the market price of our common stock. In addition, if grant funds are no longer available under existing government programs for the purchase and construction of natural gas vehicles and stations, the purchase of natural gas vehicles and station construction could slow and our business and results of operations may be adversely affected. Continued reduction in tax revenues associated with high unemployment rates, economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction, which could impair our ability to grow our business.

Challenges we may encounter managing our growth may divert resources and limit our ability to successfully expand our operations.

        We have been and continue to be engaged in a period of rapid and substantial growth, which places a strain on our operational infrastructure and imposes significant added responsibilities on members of our management. Our ability to manage our operations and growth effectively requires us to continue to hire, train and integrate necessary personnel to further develop our operational, financial and management controls, expand and improve our financial reporting and legal compliance systems and manage our natural gas station construction, maintenance and operations projects. If we are not able to effectively manage our business growth in a cost-effective manner, our operating results, sales and revenues may be negatively impacted.

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We depend on key personnel to operate our business, and if we are unable to retain our current personnel or hire additional personnel, our ability to develop and successfully market our business would be harmed.

        We believe that our future success is highly dependent on the contributions of our executive officers, as well as our ability to attract and retain highly skilled managerial, sales, technical and finance personnel. Qualified individuals are in high demand, and we may incur significant costs to attract them. All of our executive officers and other U.S. employees may terminate their employment relationship with us at any time, and their knowledge of our business and industry would be extremely difficult to replace. If we are unable to attract and retain our executive officers and key employees, our business, operating results and financial condition will be harmed. In addition, our management team has a long history of working together, and we believe that our key executives have developed highly successful and effective working relationships. If one or more of these individuals leave, we may not be able to fully integrate new executives or replicate the current dynamic, which may cause our operations to suffer.

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

        Limited availability of natural gas vehicles and engine sizes restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers produce a small number of natural gas engines and vehicles in the U.S. and Canadian markets, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. The technology used in some of the heavy duty vehicles that run on LNG is also relatively new and has not been previously deployed or used in large numbers of vehicles. As a result, these vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers and are operated under strenuous conditions. If heavy duty LNG truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for LNG engines, or LNG engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and LNG fueling business may be significantly impaired, which would adversely affect our financial performance. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales may be restricted, even if there is demand.

If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline and diesel, potential customers will have less incentive to purchase natural gas vehicles, which would decrease demand for CNG and LNG and reduce 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, 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. Our ability to offer CNG and LNG fuel to our customers at lower prices than gasoline and diesel depends in part on natural gas prices remaining lower, on an energy equivalent basis, than oil prices. If the price of oil, gasoline and diesel declines, it will make it more difficult for us to offer our customers discounted prices for CNG and LNG as compared to gasoline and diesel prices and maintain an acceptable margin on our sales. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. In addition, any new regulations imposed on natural gas extraction in the United States, particularly on extraction of natural gas from shale formations, could increase the costs of domestic gas production or make it more costly to produce natural gas in the United States, which could lead to substantial increases in the price of natural gas. Reduced prices for gasoline and diesel fuel, combined with higher costs for natural gas and natural gas vehicles, may cause potential customers to delay or

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reject converting their fleets to run on natural gas. In that event, our sales of natural gas fuel and vehicles would be slowed and our business would suffer.

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

        In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through December 31, 2011, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At December 31, 2011, the NYMEX index price for natural gas was $3.36 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 an effective futures contract in place that fully mitigates the price risk or where we otherwise cannot pass the increased costs on to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel and consequently our business. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant amount of our customer agreements, the commodity cost is passed through to the customer. 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, negative publicity surrounding drilling techniques, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. In particular, there have been recent legislative efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic fracturing of shale gas reservoirs has resulted in a substantial increase in the proven natural gas reserves in the United States, and any changes in regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to increased natural gas prices.

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. 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. Further, economic difficulties may result in the delay, amendment or waiver of environmental regulations due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a challenging economy. Further, the delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles could also have a detrimental effect on the United States natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

Delays in the implementation of California's Global Warming Solutions Act of 2006 and the Low Carbon Fuel Standard would adversely affect our business.

        In response to the enactment of California's Global Warming Solutions Act of 2006, or AB 32, which is intended to reduce greenhouse gas emissions, the California Air Resources Board, or CARB, was charged with the development and implementation of various regulations, including its low carbon fuel standard, or LCFS. Pursuant to the California LCFS regulations, we have been generating LCFS credits, with the objective of generating revenues by selling the LCFS credits to entities, including

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sellers of gasoline and diesel fuel, that need the credits to offset their carbon footprint in the State of California. Subsequent to the adoption of the LCFS, several parties filed suits challenging the constitutionality of the LCFS. In addition, in 2010 opponents of AB 32 sponsored a ballot initiative aimed at repealing the legislation. On December 29, 2011, the United States District Court for the Eastern District of California issued an injunction preventing CARB from enforcing the LCFS. If the injunction is not lifted, our business will be adversely affected because we will not be able to generate revenues by selling our LCFS credits. Further, if the implementation of AB 32 and its related regulations is otherwise delayed, or if AB 32 is repealed, the appeal of LNG, CNG and RNG vehicle fuel, which all produce lower greenhouse gas emissions than gasoline or diesel fuel, could be diminished, which would slow our growth and adversely affect our business.

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 customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We may not 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, our ability to supply CNG and LNG at competitive prices and acceptance of our technology, fuel systems and services. A decline in oil, diesel fuel and gasoline prices may result in decreased interest in alternative fuels like CNG and LNG. Further, potential customers may not find our technology, fuel systems or services acceptable.

We face increasing competition from oil and gas companies, retail fuel providers, refuse companies, industrial gas companies, natural gas utilities, and other organizations that have far greater resources and brand awareness than we have.

        A significant number of established businesses, including oil and gas companies, refuse collectors, natural gas utilities, industrial gas companies, station owners and other organizations have entered or are planning to enter the natural gas fuels market. Many of these current and potential competitors have substantially greater financial, marketing, research and other resources than we have. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. Utilities in Michigan, Illinois, New Jersey, North Carolina and Georgia have also recently made efforts to invest in the natural gas vehicle fuel space. We expect competition to intensify in the near term in the market for natural gas vehicle fuel as the use of natural gas vehicles and the demand for natural gas vehicle fuel increases. Increased competition will lead to amplified pricing pressure, reduced operating margins and fewer expansion opportunities. To compete effectively in this environment, we must continually develop and market new and enhanced product offerings at competitive prices and must have the resources available to invest in the further development of our business. Our failure to compete successfully would adversely affect our business and financial results.

Our global operations expose us to additional risk and uncertainties.

        We have operations in a number of countries, including the United States, Canada, China, Colombia, Bangladesh and Peru. In addition to the other risks described herein, our global operations may be subject to risks and uncertainties that may limit our ability to operate our business. Our natural gas compression equipment is primarily manufactured in Canada and sold globally, which exposes us to a number of risks that can arise from international trade transactions, local business practices and cultural considerations, including:

    political unrest, terrorism and economic and financial instability;

    compliance with the U.S. Foreign Corrupt Practices Act;

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    unexpected changes in regulatory requirements and uncertainty related to developing legal and regulatory systems governing economic and business activities, real property ownership and application of contract rights;

    import-export regulations;

    difficulties in enforcing agreements and collecting receivables;

    difficulties in ensuring compliance with the laws and regulations of multiple jurisdictions;

    difficulties in ensuring that health, safety, environmental and other working conditions are properly implemented and/or maintained by the local office;

    changes in labor practices, including wage inflation, labor unrest and unionization policies;

    limited intellectual property protection;

    longer payment cycles by international customers;

    currency exchange fluctuations;

    inadequate local infrastructure and disruptions of service from utilities or telecommunications providers, including electricity shortages;

    potentially adverse tax consequences; and

    differing employment practices and labor issues.

        We also face risks associated with currency exchange and convertibility, inflation and repatriation of earnings as a result of our foreign operations. In some countries, economic, monetary and regulatory factors could affect our ability to convert funds to U.S. dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the U.S. dollar. We do not engage in currency hedging activities to limit the risks of currency fluctuations.

We may not be successful in managing or integrating IMW into our business, which could prevent us from realizing the expected benefits of the acquisition and could adversely affect our future results.

        The integration of IMW into our business presents significant challenges and risks to our business, including (i) the distraction of management from other business concerns, (ii) the retention of customers of IMW, (iii) expansion into foreign markets, (iv) the introduction of IMW's compressor and related equipment manufacturing and servicing business, which is a new product line for us, (v) achievement of appropriate internal controls over financial reporting and (vi) the monitoring of compliance with all laws and regulations. IMW derives significant revenue from sales in emerging markets, and prior to the acquisition, IMW was not required to comply with the U.S. Foreign Corruption Practices Act or any of the requirements of Sarbanes-Oxley. If we do not successfully integrate IMW into our business and maintain regulatory compliance, we may not realize the benefits expected from the acquisition and our results of operations could be materially adversely affected. If the revenue of IMW declines or grows more slowly than we anticipate, or if its operating expenses are higher than we expect, we may not be able to achieve, sustain or increase the growth of our business, in which case our financial condition will suffer and our stock price could decline.

A significant portion of the purchase price of IMW was allocated to goodwill and a write-off of all or part of this goodwill could adversely affect our operating results.

        Under business combination accounting standards, we allocated the total purchase price of IMW to its net tangible assets and liabilities and intangible assets based on their fair values as of the date of the acquisition and recorded the excess of the purchase price over those values as goodwill. Our estimates of the fair value of the assets and liabilities of IMW were based upon certain assumptions, including assumptions about and anticipated attainment of new business, believed to be reasonable, but

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which are inherently uncertain. Pursuant to the applicable accounting standards, we initially allocated $45.0 million of the purchase price for IMW to goodwill. Our goodwill could be impaired if developments affecting the acquired compressor manufacturing operations or the markets in which IMW produces and/or sells compressors lead us to conclude that the cash flows we expect to derive from its manufacturing operations will be substantially reduced. An impairment of all or part of our goodwill could adversely affect our results of operations.

We may not be successful in managing or integrating Northstar with our existing operations.

        On December 15, 2010 we acquired Northstar, a leading provider of design, engineering, construction and maintenance services for LNG and LCNG fueling stations. Our ability to realize benefits from the acquisition depends on the growth of the LNG fueling market and our ability to successfully integrate Northstar's business with our existing operations. The LNG fueling market may not grow and we may not successfully manage the integration of Northstar's business with our existing operations.

DCEMB's failure to comply with the terms of its bond financing agreements would impair our rights in DCEMB.

        In connection with the issuance of the Revenue Bonds, DCEMB entered into, among other documents, the Loan Agreement, the Note, the Deed of Trust and the Security Agreement, which are defined elsewhere in this report (collectively the "Bond Agreements"). Pursuant to the Bond Agreements, DCEMB is subject to certain covenants, including a requirement to make loan repayments on the Revenue Bonds. This repayment obligation is secured by a security interest in all of the Collateral (as defined in the Security Agreement), which includes, but is not limited to, DCEMB's rights, title and interest in any gas sale agreements and the funds and accounts held under an indenture. If DCEMB defaults on its obligation to make loan repayments on the Revenue Bonds, the Issuer or the Trustee may, among other things, take whatever action at law or in equity as may be necessary or desirable to ensure loan repayments are made on the Revenue Bonds. If the Issuer or the Trustee take any such actions, or if DCEMB otherwise fails to comply with its covenants and other obligations under the Bond Agreements, our rights in DCEMB would be impaired, and our business and results of operations may be adversely affected.

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.

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

        We have existing, and will continue to seek, long-term CNG and LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 59%, 42% and 33% of our annual revenues in 2009, 2010 and 2011, respectively. 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

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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.

        Further, government contracts are frequently awarded only after competitive bidding processes, which have been and may continue to be protracted. In many cases, unsuccessful bidders for government agency contracts are provided the opportunity to formally protest certain contract awards through various agency, administrative and judicial channels. The protest process may substantially delay a successful bidder's contract performance, result in cancellation of the contract award entirely and distract management. We may not be awarded contracts for which we bid, and substantial delays or cancellation of purchases may even follow our successful bids as a result of such protests.

The budget deficits being experienced by many governmental entities may reduce the available funding for certain natural gas programs and services and the purchase of CNG or LNG fuel, which could reduce our revenue and impair our financial performance.

        Many governmental entities are experiencing significant budget deficits as a result of the economic recession, which has and may continue to reduce or curtail their ability to fund natural gas fuel programs, purchase natural gas vehicles or provide public transportation and services, which would harm our business. Furthermore, in response to budget deficits, such governmental entities have and may continue to request or demand that we lower our price for CNG or LNG fuel.

Conversion of vehicles to run on natural gas is time-consuming and expensive and may limit the growth of our sales.

        Conversion of vehicle engines from gasoline or diesel to natural gas is performed by only a small number of vehicle conversion suppliers (including our wholly owned subsidiary, BAF) that must meet stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. In addition, conversion of vehicle engines from gasoline or diesel to natural gas may result in vehicle performance issues or increased maintenance costs that could discourage our potential customers from purchasing converted vehicles that run on natural gas and impair the financial performance of BAF. Without an increase in vehicle conversion options, reduced vehicle conversion costs and improved vehicle conversion performance, our sales of natural gas vehicle fuel and converted natural gas vehicles, through BAF, may be restricted and our revenue will be reduced both by less demand for natural gas vehicle fuel and less demand for converted natural gas vehicles.

A majority of BAF's sales of CNG vehicles in recent years has been to one customer. If this customer does not continue to purchase CNG vehicles, and BAF is unable to sell CNG vehicles to other customers, BAF's revenue will decline.

        During 2009 and 2010, BAF derived approximately 63% and 66%, respectively, of its revenue from AT&T. In 2011, AT&T significantly reduced its purchases from BAF, resulting in a substantial decline in BAF's revenue. If AT&T does not increase its purchases, in the absence of additional sales to other customers, BAF will experience materially reduced revenues and may require additional cash to continue its operations, which could adversely affect our capital resources and financial results.

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,

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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 fuel, may slow the need to diversify fuels and affect the growth of the natural gas vehicle market. Use of electric heavy duty trucks or the perception that electric heavy duty trucks may soon be widely available and provide satisfactory performance in heavy duty applications may reduce demand for heavy duty LNG trucks. In addition, 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 our ability to compete with other alternative fuels and alternative fuel vehicles.

Our ability to obtain LNG is restricted by limited and disjointed production of LNG.

        Production of LNG in the United States is fragmented and limited. It may be difficult for us to obtain LNG without interruption and near our current or target markets at competitive prices or at all. If LNG liquefaction plants we own, or if any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged downtime, or if new LNG liquefaction plants are not built, our LNG supply will be restricted. One of the suppliers from whom we obtain LNG has experienced unscheduled plant shut downs and has been unable to maintain minimum production levels on a consistent basis, which has caused us to incur additional costs to obtain LNG from other sources. If we are unable to supply enough of our own LNG or purchase it from third parties to meet customer demand, we may be liable to our customers for penalties. In addition, the execution of our business plan will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to increase the market for LNG fuel, including supplying LNG fuel to heavy duty truck customers, and will adversely affect our investments in America's Natural Gas Highway. If we experience an LNG supply interruption or LNG demand that exceeds available supply, or if we have difficulty entering or maintaining relationships with contract carriers to deliver LNG on our behalf, our ability to expand LNG sales to new customers will be limited, our relationships with existing customers may be disrupted, and our results of operations may be adversely affected. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations and cannot pass these costs through to our customers, our operating margins will decrease on those sales due to our increased transportation costs.

LNG supply purchase commitments may exceed demand causing our costs to increase.

        We are a party to two LNG supply agreements that have a take-or-pay commitment, and we may enter into additional take-or-pay commitments, particularly in connection with our development of America's Natural Gas Highway. Take-or-pay commitments require us to pay for the LNG that we have agreed to purchase irrespective of whether we can sell the LNG. Should the market demand for LNG decline, if we lose significant LNG customers, if demand under any existing or any future LNG supply contract does not maintain its volume levels or grow, or if future demand for LNG does not meet our expectations, our operating and supply costs may increase as a percentage of revenue and negatively impact our margins.

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

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the availability of natural gas or possibly create a supply imbalance that increases natural gas prices. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, insufficient pipeline capacity, equipment failure on liquefaction production or delivery delays, we may experience supply stoppages that 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.

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

        From 2005 to 2008, we sold and delivered approximately 30% 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. Effective January 1, 2007, we no longer offer contracts with a price cap to our customers, though, from time to time we still enter into contracts with various customers to sell CNG or LNG at fixed prices. At any given time, 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 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, our policy has been to purchase futures contracts to hedge our exposure to natural gas price variability related to our fixed price contracts. Such contracts, however, may not be available or we may not have sufficient financial resources to secure such contracts. 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 effectively 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, 2011, we were economically hedged with respect to our fixed price contracts with our customers.

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 customer contracts when determining the volumes included in the futures contracts we purchase, or we elect to purchase a futures contract in connection with a bid proposal and ultimately we are not awarded the entire contract or our customer does not fully perform its obligations under the awarded contract. We also could incur significant losses if a counterparty does not perform its obligations under the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot be assured that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

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

        We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our

31


futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. As of December 31, 2011, we had $3.6 million on deposit related to our futures contracts.

If our futures contracts do not qualify for hedge accounting, our net income (loss) 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 the relevant derivative accounting guidance, which requires us to value our futures contracts at fair market value in our financial statements. Prior to June 2008, our futures contracts did not qualify 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. At December 31, 2011, all of our futures contracts qualified for hedge accounting. 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 (loss) and stockholders' equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. We had no derivative gains or losses related to our natural gas futures contracts for the years ended December 31, 2010 and 2011. 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.

Compliance with potential greenhouse gas regulations affecting our LNG plants or fueling stations may prove costly and negatively affect our financial performance.

        California has adopted legislation, AB 32, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020 and an additional 80% reduction below 1990 levels by 2050. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas or our CNG and LNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or CNG and LNG stations, and these unknown costs are not contemplated by our customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.

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

        Natural gas fueling operations and vehicle conversions entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the EPA or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained, may rupture and the contents of the tank may rapidly decompress and result in death or 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. If CNG or LNG vehicles are perceived to be unsafe, it will harm our growth and negatively affect BAF's ability to sell converted CNG vehicles, which would impair our financial performance.

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

        We loan to certain qualifying customers a portion of, and occasionally 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: the equipment financed consists mostly of vehicles that 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. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. As of December 31, 2011, we had $6.3 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

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 foreign business practices, the environment, health and safety, labor and employment and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities. In addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities.

        In connection with our LNG liquefaction and landfill gas processing operations, we need or may 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 and may distract our officers, directors and employees from the operation of our business.

We may not be successful in developing or expanding our RNG business.

        In November 2010, we announced that we entered into an agreement to develop a pipeline quality RNG project at a Republic Services owned landfill outside of Detroit, Michigan. We are also in the process of expanding operations at our RNG production facility at the McCommas Bluff landfill outside of Dallas, Texas. In addition, we are seeking to expand our RNG business by pursuing additional projects. RNG production represents a new area of investment and operations for us, and we may not be successful in developing these projects and generating a financial return from our investment. Historically, projects that produce pipeline quality RNG have often failed due to the volatile prices of conventional natural gas, unpredictable RNG production levels and technological difficulties and costs associated with operating the production facilities. Our ability to succeed in expanding our McCommas Bluff project and developing our project in Michigan and other projects we may secure in the future depends on our ability to obtain necessary financing, successfully manage the construction and operation of RNG production facilities and our ability to sell and market the RNG at substantial premiums to recent conventional natural gas prices. If we are unsuccessful in obtaining necessary financing or managing the construction and operation of our RNG production facilities, or if we are unable to sell and market RNG at a substantial premium to conventional natural gas prices, our

33


business and financial results may be materially and adversely affected. In addition, the California Energy Commission is considering revising existing rules that allow California utilities to classify as a bundled renewable energy credit any in-state electricity generation using RNG produced outside the state. If we cannot sell RNG produced outside of the state of California into California for use as an RPS compliant fuel, it would likely impair our ability to obtain premium prices for RNG. In the absence of state and federal programs that support premium prices for RNG, we will be unable to generate profit and financial return from these investments, and our financial results could be materially and adversely affected.

Operational issues, permitting and other factors at DCEMB's landfill gas processing facility may adversely affect both DCEMB's ability to supply RNG and our operating results.

        In August 2008, we acquired our 70% interest in DCE, which owns 100% of DCEMB. DCEMB is a party to a 15-year gas sale agreement with Shell Energy North America (US) L.P., or Shell, for the sale to Shell of specified levels of RNG produced by DCEMB's landfill gas processing facility. DCEMB may not be able to produce or sell up to the maximum volumes called for under the agreement or produce RNG that meets the relevant pipeline specification. DCEMB's ability to produce such volumes of RNG depends on a number of factors beyond DCEMB's control, including, but not limited to, the availability and composition of the landfill gas that is collected, successful permitting, the operation of the landfill by the City of Dallas, the reliability of the processing facility's critical equipment and weather conditions. The DCEMB facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. For example, as part of an operational upgrade in March 2009, the facility was shut down for approximately one month. Also, on June 12, 2009, the facility was taken offline for repairs that were completed on July 2, 2009, and the facility was taken offline for upgrades from September 20, 2010 until September 25, 2010. Severe winter weather in Texas resulted in power outages and broken equipment in February 2011, resulting in a week of down time and an extended period during which the plant operated at half capacity. Further, production has been negatively affected by the recent severe drought and high temperature conditions in Texas. Future operational upgrades, including planned expansion of the plant, or other complications in the operations of the facility could require shutdowns, and accordingly, DCEMB's revenues may fluctuate from quarter to quarter.

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 (income) were approximately $6.5 million, $6.4 million, $18.5 million, $1.9 million, $24.4 million, $(9.9) million, $1.8 million, $(13.8) million, $9.8 million, $5.6 million, $11.4 million, and $(20.9) million for the three months ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011, September 30, 2011, and December 31, 2011, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. In particular, if our stock price increases or decreases in future periods during which our Series I warrants are outstanding, we will be required to recognize corresponding losses or gains related to the valuation of the Series I warrants that could materially impact our results of operations. 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 may be due to a number of 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, downtime at our facilities (including any shutdowns of DCEMB's landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, our debt service obligations, changes in the

34


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, fluctuation in the value of our natural gas futures contracts, 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.

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

        As of December 31, 2011, there were 85,433,258 shares of our common stock outstanding, 10,683,303 shares underlying outstanding options, 2,130,682 shares underlying outstanding warrants (all of which were sold in our registered direct offering that closed in November 2008) and 13,164,557 shares underlying the convertible notes we issued in July and August 2011. All of our outstanding shares are eligible for sale in the public market, subject in certain cases to the requirements of Rule 144 of the Securities Act. Also, shares subject to outstanding options, warrants and convertible notes are eligible for sale in the public market to the extent permitted by the provisions of various option, warrant and convertible note agreements and Rule 144, or if such shares have been registered for resale under the Securities Act (8,999,999 shares underlying convertible notes we issued in August 2011 have been registered for resale under the Securities Act). If these shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our common stock could decline.

        Further, as of December 31, 2011, 16,539,720 shares of our stock held by our co-founder and board member T. Boone Pickens are subject to pledge agreements with banks. Should one or more of the banks be forced to sell the shares subject to the pledge, the trading price of our stock could also decline. In addition, a number of our directors and executive officers have entered into Rule 10b5-1 Sales Plans with a broker to sell shares of our common stock that they hold or that may be acquired upon the exercise of stock options. Sales under these plans will occur automatically without further action by the director or officer once the price and/or date parameters of the particular selling plan are achieved. As of December 31, 2011, 1,060,318 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. All sales of common stock under the plans will be reported through appropriate filings with the SEC.

A significant portion 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, 2011, T. Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate approximately 24.5% of our outstanding shares of common stock. 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 have interests that differ from yours and may vote in a way with which you disagree and that 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.

Item 1B.    Unresolved Staff Comments.

        None.

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Item 2.    Properties.

        Our corporate headquarters are located at 3020 Old Ranch Parkway, Suite 400, Seal Beach, California 90740, where we occupy approximately 40,200 square feet. Our office lease expires on March 31, 2018. We believe our headquarter facilities are adequate for our current and near term operating needs.

        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 own an LNG liquefaction plant in Boron, California, approximately 125 miles from Los Angeles. In November 2006, we entered into a ground lease for the 36 acres on which this plant is situated. The lease is for an initial term of 30 years, beginning on the date that the plant commences full operations, and requires annual base rent payments of $230,000 per year, plus up to $130,000 per year for each 30,000,000 gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We began paying rent on December 1, 2008. For 2011, we recorded rent expense of approximately $1.3 million, which included royalty payments to the landlord for each gallon of LNG produced at the facility as well as for certain other services that the landlord provided.

        We lease the space upon which we operate our DCE plant at the McCommas Bluff landfill in Dallas, Texas.

        We lease or license 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, and in some cases, LNG stations. The ground leases or licenses 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.

        We lease a manufacturing facility in Chilliwack, British Columbia where we occupy approximately 57,000 square feet. The facility lease expires in January 2018. We also lease two warehouse locations in Chilliwack, British Columbia totaling approximately 61,800 square feet that both expire on August 31, 2012.

Item 3.    Legal Proceedings.

        We are party to various legal actions that have arisen 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 have and may continue to 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 effect on our consolidated financial position, results of operations, or liquidity.

Item 4.    Mine Safety Disclosures.

        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 2010

             

First Quarter 2010

  $ 23.70   $ 15.15  

Second Quarter 2010

  $ 23.65   $ 13.48  

Third Quarter 2010

  $ 19.36   $ 13.95  

Fourth Quarter 2010

  $ 15.80   $ 13.14  

Fiscal Year 2011

             

First Quarter 2011

  $ 16.95   $ 11.75  

Second Quarter 2011

  $ 17.85   $ 12.13  

Third Quarter 2011

  $ 17.21   $ 10.75  

Fourth Quarter 2011

  $ 13.99   $ 9.02  

Holders

        There were approximately 78 stockholders of record as of March 7, 2012. We believe there are approximately 69,941 stockholders of our common stock held by brokerage firms on behalf of stockholders.

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. Further, the SLG Agreements (as defined and described in note 9 to our consolidated financial statements), restrict our ability to pay cash dividends on our common stock. We anticipate that all future earnings will be retained to finance future growth.

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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, 2011 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 and the associated equipment and services necessary to use 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, 2009, 2010, and 2011 and the consolidated balance sheet data at December 31, 2010, and 2011, 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, 2007 and 2008, and the consolidated balance sheet data at December 31, 2007, 2008, and 2009 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.


(In thousands, except share data)

 
  Year Ended December 31,  
 
  2007   2008   2009   2010   2011  

Statement of Operations Data:

                               

Total Revenues(1)

  $ 117,716   $ 125,867   $ 131,503   $ 211,834   $ 292,717  

Operating expenses:

                               

Costs of sales

    85,660     98,768     82,921     141,889     216,684  

Derivative (gains) losses:

                               

Futures contracts

        611              

Series I warrant valuation

            17,367     (10,278 )   (2,655 )

Selling, general and administrative(2)

    35,934     62,416     47,509     63,258     86,850  

Depreciation and amortization

    7,108     9,624     16,992     22,487     30,406  
                       

Total operating expenses:

    128,702     171,419     164,789     217,356     331,285  
                       

Operating loss

    (10,986 )   (45,552 )   (33,286 )   (5,522 )   (38,568 )

Interest income (expense), net

    3,506     1,630     (32 )   (1,194 )   (9,616 )

Other income (expense), net

    (192 )   (168 )   (310 )   2,080     (611 )

Income (loss) from equity method investments

        (188 )   244     427     637  
                       

Loss before income taxes

    (7,672 )   (44,278 )   (33,384 )   (4,209 )   (48,158 )

Income tax (expense) benefit

    (1,222 )   (290 )   (304 )   1,436     703  
                       

Net loss

    (8,894 )   (44,568 )   (33,688 )   (2,773 )   (47,455 )

Loss (income) of noncontrolling interest

        105     439     257     (178 )
                       

Net loss attributable to Clean Energy Fuels Corp

  $ (8,894 ) $ (44,463 ) $ (33,249 ) $ (2,516 ) $ (47,633 )
                       

Basic and diluted loss per share

  $ (0.22 ) $ (0.98 ) $ (0.60 ) $ (0.04 ) $ (0.68 )
                       

Weighted average common share outstanding:

                               

Basic and diluted

    40,258,440     45,367,991     55,021,961     62,549,311     70,415,431  
                       

(1)
Revenues include the following amounts:

 
  Year Ended December 31,  
 
  2007   2008   2009   2010   2011  

Fuel tax credits (VETC)

  $ 17,046   $ 17,197   $ 15,535   $ 16,042   $ 17,889  
                       

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(2)
2008 amount includes $18.6 million of expenses to support Proposition 10 on the California ballot in November 2008 that was not adopted. 2010 amount includes $2.2 million of impairment charges.

 
  December 31,  
 
  2007   2008   2009   2010   2011  

Balance Sheet Data:

                               

Cash and cash equivalents

  $ 67,938   $ 36,284   $ 67,087   $ 55,194   $ 238,125  

Restricted cash

        2,500     2,500     2,500     4,792  

Short-term investments

    12,480                 33,329  

Working capital

    119,481     47,338     78,799     65,070     292,501  

Total assets

    249,025     290,374     355,799     583,499     942,707  

Long-term debt, inclusive of current portion

    225     25,084     12,221     64,416     289,422  

Stockholders' equity

    230,932     233,777     277,189     413,287     540,883  

 

 
  Year Ended December 31,  
 
  2009   2010   2011  

Key Operating Data:

                   

Gasoline gallon equivalents delivered (in millions):

                   

CNG

    67.9     81.4     101.8  

RNG

    6.4     7.4     6.7  

LNG

    26.7     33.9     47.1  
               

Total

    101.0     122.7     155.6  
               

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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 annual report on Form 10-K for a discussion of some of these risks and uncertainties. This discussion should be read with our financial statements and related notes included elsewhere in this report.

        We provide natural gas solutions for vehicle fleets primarily in the U.S. and Canada. Our primary business activity is selling CNG and LNG vehicle fuel to our customers. We also manufacture and service advanced natural gas fueling compressors and related equipment, build, operate and maintain fueling stations, sell or lease fueling stations to our customers, process and sell RNG, and provide natural gas vehicle conversions. Our customers include fleet operators in a variety of markets, such as trucking, airports, taxis, refuse hauling and public transit. In April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interests of DCE. DCE owns a facility that collects, processes and sells RNG at the McCommas Bluff landfill in Dallas, Texas. On October 1, 2009, we completed our acquisition of BAF, a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles. On September 7, 2010, we completed the purchase of IMW, a company that manufactures and services advanced, non-lubricated natural gas fueling compressor and related equipment. On December 15, 2010, we acquired Northstar, a provider of design, engineering, construction and maintenance services for LNG and LCNG fueling stations.

Overview

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

        Sources of revenue.     We generate the vast majority of our revenue from selling CNG and LNG, and commencing on September 7, 2010, also from selling advanced natural gas fueling compressors and related equipment and maintenance services through our subsidiary, IMW. A significant portion of our revenue is also earned by designing and constructing and selling natural gas fueling stations, selling natural gas vehicle conversions through our wholly owned subsidiary, BAF, providing fueling station operations and maintenance services to our customers, and selling pipeline quality RNG produced by our DCE joint venture. We also generate limited revenue by providing the financing for 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 (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide O&M services, but do not sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of RNG produced and sold as pipeline quality natural gas by DCE), (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss) attributable to us. The following table, which you should read in conjunction with our consolidated financial statements and notes contained

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elsewhere in this Form 10-K, presents our key operating data for the years ended December 31, 2009, 2010, and 2011:

Gasoline gallon equivalents delivered

 
  Year Ended December 31,  
(in millions)
  2009   2010   2011  

CNG

    67.9     81.4     101.8  

RNG

    6.4     7.4     6.7  

LNG

    26.7     33.9     47.1  
               

Total

    101.0     122.7     155.6  
               

Operating data

                   

Gross margin

  $ 48,582   $ 69,945   $ 76,033  

Net loss

    (33,249 )   (2,516 )   (47,633 )

        Key trends in 2009, 2010 and 2011.     According to the EIA, demand for natural gas fuels in the United States increased by approximately 26% during the period January 1, 2009 through December 31, 2011. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets.

        The number of fueling stations we served grew during the past three years from 176 at December 31, 2008 to 273 at December 31, 2011 (a 55.1% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG and LNG gasoline gallon equivalents we delivered from 2009 to 2011 increased by 54%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2009, 2010 and 2011. In addition, in 2011, we also benefitted from increased revenues from compressor sales and fueling station installations as a result of our acquisitions of IMW and Northstar, which occurred during the fourth quarter of 2010.

        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 in 2009 and 2010. In 2011, the cost of sales related to compressors sold through IMW and fueling station installations performed by Northstar also contributed to the increase.

        Since the last half of 2009, we have experienced reduced margins in certain markets, particularly in the municipal transit and refuse sector. The reduction in margins is primarily a result of increased competition and sales agreements with larger entities that have greater pricing leverage. Also, in many cases, our agreements with our customers, including governmental agencies, are subject to a competitive bidding process and we have been required to reduce our prices to maintain our contracts as they come up for bid. In addition, in May and June of 2009, we acquired four compressed natural gas operations and maintenance services contracts with municipal transit agencies, and in 2010 and 2011, we won several contracts with a transit agency in California that have significant volume but smaller margins than we typically generate on our fuel sales. As a result of all of these factors, the overall average margin on our fuel sales across our business decreased sequentially in 2010 and 2011.

        We believe that our margins on fuel sales will improve in the future to the extent we are successful in increasing our retail CNG and LNG fueling operations, which is where we earn our highest margins. If our retail CNG and LNG fueling operations do not grow, we may experience further reduced margins. We may also lose contracts with governmental customers if we are unwilling or unable to reduce our prices or lose in the competitive bidding process, which would reduce our volumes. We will need to increase our business with non-government entities to replace volumes lost in competitive bid procurements when we are not successful in retaining the contracts.

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        During 2011, prices for oil, gasoline, and diesel fuel generally increased, while the price for natural gas generally decreased. Oil hit a high of $113.93 in April 2011 and settled at $98.83 per barrel on December 31, 2011. In California, average retail prices for gasoline have increased from $3.36 per gallon in January 2011 to $3.62 per gallon at December 31, 2011, and average retail prices for diesel fuel have increased from $3.51 per diesel gallon in January 2011 to $4.04 per diesel gallon at December 31, 2011. Higher gasoline and diesel prices improve our margins on fuel sales to the extent we price our fuel at a discount to gasoline or diesel and natural gas prices do not increase by a corresponding amount. During this time period, the price for natural gas generally declined. The NYMEX price for natural gas ranged from $4.22 per MMbtu in January 2011 to $3.36 per MMbtu in December 2011. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.60 for the month of January 2011 to $2.75 for the month of December 2011. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.50 during January 2011 to $2.55 for the month of December 2011.

        Recent developments.     In December 2006, we issued to Mr. Boone Pickens, one of our founders and a member of our board of directors, a warrant to purchase 15,000,000 shares of our common stock. The warrant had an exercise price per share of $10.00 and expired at 5:00 p.m. Pacific time on December 28, 2011, or the Expiration time. The warrant was issued to Mr. Pickens prior to our initial public offering in exchange for the cancellation of all amounts we owed to him under a revolving line of credit entered into in 2006, which we used for margin deposits related to futures contracts. Also, in exchange for issuance of the warrant, Mr. Pickens assumed all of our then-outstanding liabilities related to certain futures contracts. The warrant was transferrable with our consent. Prior to the Expiration time on December 28, 2011:

    Mr. Pickens notified us that he was exercising a portion of the warrant to purchase 1,500,000 shares;

    Mr. Pickens transferred his right, title and interest in the warrant with respect to the remaining 13,500,000 shares to certain third-party investors, and we consented to such transfers;

    In consideration of the warrant transfers, the third-party investors granted Mr. Pickens options to repurchase an aggregate of 6,750,000 shares for $22.00 per share through December 28, 2012 for 5,500,000 shares and December 28, 2013 for 1,250,000 shares;

    The third-party investors notified us that they were exercising the transferred portions of the warrant to purchase an aggregate of 13,500,000 shares;

    Mr. Pickens and the third-party investors delivered to us an aggregate of $150,000,000, which was the total exercise price for the warrant; and

    We issued an aggregate of 15,000,000 shares to Mr. Pickens and the third-party investors.

        By May, 2012, we intend to exercise our option to acquire the remaining 81.1% of Servo-tech Engineering, Inc. ("ServoTech"), a company that provides design and engineering services for natural gas fueling systems among other services, for $2.8 million, under an option issued to us when we acquired the initial 19.9% interest in ServoTech for $1.2 million on February 25, 2011.

        Anticipated future trends.     We anticipate that, over the long term, the prices for gasoline and diesel will continue to be signifcantly higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in large part on the growth in U.S. natural gas production.

        The 2012 Annual Outlook early release from the EIA states that total marketed production of natural gas grew by an estimated 4.5 Bcf/d (7.4 percent) in 2011, the largest year-over-year volumetric

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increase in history. This strong growth was driven in large part by increases in shale gas production. EIA expects production to grow by 1.4 Bcf/d (2.2 percent) in 2012 and 0.7 Bcf/d (1.0 percent) in 2013 as low natural gas prices reduce new drilling plans and consumption is estimated to grow at a moderate pace. In the face of continued low spot and future prices, as well as record high storage levels for this time of year, drillers appear to have begun cutting back on new production plans for 2012. According to Baker Hughes, the natural gas rig count has fallen to 809 as of December 29, 2011, from a 2011 high of 936 in mid-October. However, high initial production rates from new wells, associated natural gas production from oil drilling, and a backlog of uncompleted or unconnected wells contribute to the forecast of further production increases in 2012 and 2013, albeit at lower rates than 2011.

        The preliminary 2012 Annual Energy Outlook report from the EIA estimates that shale gas could represent 49% (13.6 tcf) of U.S. natural gas production by the year 2035, up from the 14% and 23% (5 tcf) of domestic natural gas produced in 2009 and 2010, respectively. The EIA estimates that based upon 2010 consumption levels, that there is enough available shale gas to satisfy demand for the next 100 years. The primary reason for the availability of additional natural gas is the increased successful use of recent shale drilling technology and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher energy value than dry natural gas.

        Hydraulic fracturing (commonly called "fracking" or "hydrofracking") is a technique in which water, sand and a small amount of chemicals and sand are pumped into the well to unlock the hydrocarbons trapped in shale formations by opening cracks (fractures) in the rock and allowing natural gas to flow from the shale into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas producers to extract shale gas at reasonable cost. Horizontal drilling is an enhanced oil recovery ("EOR") or gas recovery method. A horizontal well is commonly defined as any well in which the lower part of the well bore parallels the oil zone. The benefits of horizontal wells include the avoidance of drawdown-related problems such as water/gas coning, and extension of wells by means of multiple drain holes. Without these techniques, natural gas does not flow to the well rapidly, and commercial quantities cannot be produced from shale because the natural gas would not flow from the formation at high enough rates to justify the cost of drilling.

        Based on analyst reports, we believe that there is a significant worldwide supply of natural gas relative to crude oil. According to the 2010 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2009 natural gas production was 37% greater than the ratio of proven crude oil reserves to 2009 crude oil production. This analysis suggests significantly greater long term availability of natural gas than crude oil based on current consumption.

        We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. With our recent acquisitions of IMW and Northstar, we are now a fully integrated provider of advanced compression technology, station-building and fueling. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including trucking, refuse hauling, airports, taxis and public transit. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network or LNG production capacity, as well as the logistics of delivering more CNG and LNG to our customers. We also anticipate that we will continue to seek to acquire assets and/or businesses that are in the natural gas fueling infrastructure or RNG production business that may require us to raise additional capital. Additionally, we have and will continue to increase our sales and marketing team and other necessary personnel as we seek to expand our existing markets and enter new markets, which will also result in increased costs.

        We anticipate the commercial roll-out of natural gas engines that are well-suited for the U.S. heavy-duty trucking market, together with the economic and environmental benefits of natural gas fuel, will result in increased adoption of natural gas fueled trucks by the U.S. trucking industry. Heavy-duty

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trucks in the U.S. are generally high-volume consumers of vehicle fuel. We believe many use 20,000 gallons or more per year. We therefore believe that this market may become our largest market. As a result, we have made a significant commitment of capital and other resources to build a nationwide network of LNG truck fueling stations, which we refer to as America's Natural Gas Highway, or ANGH, on the interstate highway system and in major metropolitan areas that will enable natural gas fueled freight trucking coast to coast and border to border within the 48 continental states. We expect the first phase of America's Natural Gas Highway to include approximately 150 fueling stations, with approximately 70 stations anticipated to be open in 33 states by the end of 2012, and the balance in 2013. We expect that many ANGH stations will be co-located at Pilot-Flying J Travel Centers already serving goods movement trucking.

        Many governmental entities, which represented approximately 44% of our revenues from 2007 through 2011, are experiencing significant budget deficits as a result of the economic recession and have been, and may continue to be, unable to invest in new natural gas vehicles for their transit or refuse fleets. They may also be compelled to reduce public transportation and services, or the prices they pay for these services, which would negatively affect our business.

        Sources of liquidity and anticipated capital expenditures.     Liquidity is the ability to meet present and future financial obligations either through operating cash flows, the sale or maturity of existing assets, or by the acquisition of additional funds through capital management. Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities.

        Our business plan calls for approximately $239.5 million in capital expenditures in 2012, primarily related to construction of new fueling stations, including America's Natural Gas Highway stations, expanding our LNG plant, expanding and building landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction and potential merger or acquisition activity. For more information, see "Liquidity and Capital Resources" below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce our ability to grow our business and generate increased revenues.

        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.

Operations

        We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the year ended December 31, 2011, CNG and RNG (together) represented 70% and LNG represented 30% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate significant revenues through sales of RNG produced by our joint venture subsidiary DCE, sales of natural gas vehicles by our wholly owned subsidiary BAF, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW, and sales of LNG and LCNG fueling station design, construction and O&M services through Northstar. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations typically tend to operate and maintain their own stations. Substantially all of our station sale and leasing revenues have been generated from CNG stations.

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CNG Sales

        We sell CNG through fueling stations located on our customers' properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers' vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. We will continue to offer fixed price contracts, as appropriate, and consistent with our natural gas hedging policy. 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 LNG to fleet customers, who typically own and operate their fueling stations. Increasingly, we also sell LNG to fleet and other customers at our public-access LNG stations and for non-vehicle use, such as power generation. During 2011, we procured 43% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third parties, we may 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 58 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. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy adopted in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied. We also sell LNG 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.

Government Incentives

        From October 1, 2006 through December 31, 2011, we received a federal fuel tax credit ("VETC") of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sold as vehicle fuel. Based on the service relationship with our customers, either we or our customers were able to claim the credit. We recorded these tax credits as revenues in our consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be received. As such, the credits are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them. The program providing for the VETC expired on December 31, 2011.

Operation and Maintenance

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

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Station Construction

        We generate a 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.

        On December 15, 2010, we completed the purchase of Northstar, an entity that provides design, engineering, construction and maintenance services for LNG and LCNG fueling stations. During 2011, Northstar contributed approximately $10.5 million to our revenue.

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 certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. Through December 31, 2011, we have not generated significant revenue from vehicle financing activities.

Landfill Gas

        In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million, including transaction costs. DCE owns a facility that collects, processes and sells RNG from the McCommas Bluff landfill located in Dallas, Texas. For the years ended December 31, 2009, 2010, and 2011, DCE generated approximately $7.9 million, $11.3 million, and $12.0 million, respectively, in revenue from sales of RNG, all of which is included in our consolidated statements of operations.

        On April 3, 2009, DCE entered into a fifteen-year gas sale agreement with Shell Energy North America (US), L.P., or Shell, for the sale by DCE to Shell of RNG produced by DCE's landfill gas processing facility.

        DCE retains the right to reserve from the gas sale agreement up to 500 MMBtus per day of RNG for sale as a vehicle fuel. To the extent that DCE produces volumes of RNG in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. DCE may not produce or be able to sell up to the maximum volumes called for under the agreement. DCE's ability to produce RNG is dependent on a number of factors beyond DCE's control including, but not limited to, the availability and composition of the landfill gas that is collected, the operation of the landfill by the City of Dallas and the reliability of the processing plant's critical equipment. The processing equipment is currently being expanded and upgraded, which may result in significant down time to complete the work, which consequently may reduce DCE's sales of RNG during the expansion and upgrade period. The expansion and upgrade work is anticipated to continue through the first half of 2012.

        The sale price for the gas under the agreement with Shell is fixed. The sale price for the gas represents a substantial premium to the current prevailing prices for natural gas at March 12, 2012.

        The gas sale agreement is terminable by either party on thirty days' written notice if the California Energy Commission makes a written determination or adopts a ruling or regulation after the date of the agreement that the RNG sold under the agreement will, from the date of such ruling or regulation,

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no longer qualify as a California Renewable Portfolio Standard eligible fuel. In addition, Shell has the right to terminate the agreement upon thirty days' written notice if the volumes of RNG produced and delivered, calculated monthly on a rolling two-year average, are less than an annual average of 630,720 MMBtu per year (or 2,083 MMBtu per day).

        In November 2010, our subsidiary Canton Renewables, LLC ("Canton Renewables"), signed a Gas Sale and Purchase Agreement that grants Canton Renewables the right to produce RNG at a landfill owned and operated by Republic Services in Canton, Michigan. The landfill gas facility is under construction and is expected to be completed and operational in the summer of 2012. Canton Renewables has executed an agreement with an affiliate of the local gas utility that will enable Canton Renewables to inject the RNG produced into the local gas transmission system and transport it to the interstate pipeline, where it may be distributed for use in power generation or as a low-carbon, renewable vehicle fuel. We have entered into a ten-year fixed-price sale contract for the majority of the RNG we expect this landfill gas facility to produce.

Vehicle Conversions

        On October 1, 2009, we completed our acquisition of BAF. Founded in 1992, BAF provides natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF's vehicle conversions include taxis, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF. The majority of BAF's revenue during 2010 and 2011 was derived from sales of converted natural gas service vans to AT&T. For the years ended December 31, 2010 and 2011, BAF contributed approximately $42.3 million, and $23.6 million, respectively, to our revenue.

Natural Gas Fueling Compressors

        On September 7, 2010, we completed our purchase of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has other manufacturing facilities near Shanghai, China, and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States. During 2011, IMW contributed approximately $69.1 million to our revenue.

Volatility of Earnings and Cash Flows

        During 2009, 2010, and 2011, our futures contracts qualified for hedge accounting, so we had no derivative gains or losses recognized in our consolidated statements of operations for the years ended December 31, 2009, 2010, and 2011. In accordance with our natural gas hedging policy, we plan to structure all futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See "Risk Management Activities" below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

        Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At December 31, 2011, we had $3.6 million of

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margin deposits, which are included in prepaid expenses and other current assets and notes receivable and other long-term assets on our consolidated balance sheet.

        The decrease in the value of our futures positions and any corresponding margin deposits required thereon could significantly impact our financial position in the future.

Volatility of Earnings Related to Series I Warrants

        Beginning January 1, 2009, under Financial Accounting Standards Board ("FASB") authoritative guidance, we are required to record the change in the fair market value of our Series I warrants in our consolidated financial statements. We have recognized a gain of $10.3 million and $2.7 million related to recording the estimated fair market value changes of our Series I warrants in the years ended December 31, 2010 and December 31, 2011, respectively. See note 18 to our consolidated financial statements contained elsewhere herein. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of valuing our Series I warrants. On November 10, 2010, 1,183,712 of the Series I warrants were exercised and thus, were not outstanding during 2011.

Volatility of Earnings Related to Contingent Consideration

        Under recent business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisitions of both BAF and IMW in our financial statements through the contingency period, which expired December 31, 2011 for BAF and expires on March 31, 2014 for IMW.

        If the anticipated results of IMW increase or decrease during future periods, we may be required to recognize material losses or gains based on the valuation of the increased or decreased consideration due to the former IMW shareholder. During 2011, we recognized a gain of $2.8 million related to the estimated change in value of the BAF and IMW contingent consideration, of which $0.9 million related to BAF. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of changes in the estimated fair value of the contingent consideration amount.

Debt Compliance

        In connection with our acquisition of IMW, we entered into a credit agreement with HSBC that requires IMW to comply with certain financial covenants. Among those financial covenants are that IMW shall not permit (i) its ratio of debt to tangible net worth to be greater than 3.25 to 1.0 until December 31, 2010 and greater than 3.00 to 1.0 on and after January 1, 2011, (ii) its tangible net worth to, at anytime, be below CAD$3.0 million and (iii) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until December 31, 2010 and less than 1.25 to 1.0 on and after January 1, 2011. Should IMW's operating results not materialize as planned, we could violate these covenants. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement would be due and payable. IMW was in compliance with these covenants as of December 31, 2011.

        The Indenture and the Loan Agreement DCEMB entered into as part of issuing its Revenue Bonds, as defined and disclosed in note 9 to our consolidated financial statements, have certain non-financial debt covenants with which DCEMB must comply. As of December 31, 2011, DCEMB was in compliance with its debt covenants.

        The Loan Agreement we entered into as part of issuing the CHK Notes, as defined and discussed in note 9 to our consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of December 31, 2011, we were in compliance with these debt covenants.

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        The Convertible Note Purchase Agreements we entered into as part of issuing the SLG Notes, as defined and discussed in note 9 to our consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of December 31, 2011, we were in compliance with these covenants.

        Some of our natural gas fuel sales contracts require us to sell LNG or CNG to our customers at a fixed price. 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.

        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, we operate under a natural gas hedging policy pursuant to which we only purchase futures contracts to hedge our exposure to variability in expected future cash flows related to a particular fixed price contract or bid. Subject to the conditions set forth in the policy, we purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to cash flow variability related to such fixed price sales contracts entered into after the date of the policy. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and enter into fixed price sales contracts only in accordance with the natural gas hedging policy, a complete copy of which, as amended effective May 29, 2008, was filed as Exhibit 99.1 to our Form 8-K filed with the SEC on June 20, 2008. The summary of the policy described above does not purport to be complete and is qualified in its entirety by reference to the copy of the policy previously filed.

        Due to the restrictions of our revised hedging policy, we expect to offer 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 estimated cash requirements over the duration of the underlying futures contracts. The amount of this price component will vary based on the anticipated volume and the natural gas price component to be covered under the fixed price sales contracts.

Critical Accounting Policies

        Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles ("US GAAP"). 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, asset realization, accounts receivable reserves, notes receivable reserves, warranty reserves, derivative values, income taxes, and the fair 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 consolidated financial statements.

Impairment of Goodwill and Long-lived Assets

        Before 2011, we evaluated the carrying value of goodwill during the fourth quarter of each fiscal year and between annual evaluations if events occured or circumstances changed that would more likely than not reduce the fair value of the goodwill below its carrying amount. Beginning in 2011, we performed our evaluation of the carrying value of Goodwill under the amended guidance issued by the FASB in Accounting Standards Update ("ASU") 2011-08, Testing for Goodwill Impairment , issued in September 2011, which we chose to early adopt. Under the amended requirements of ASU 2011-08, an entity is not required to quantitatively determine a reporting unit's fair value if it concludes, based

50


upon a qualitative assessment, that it is not more likely than not that the reporting unit's fair value is less than its carrying amount. The guidance also allows us to proceed directly to a quantitative analysis on an individual reporting unit basis, which we do when there is doubt about whether or not a qualitative assessment is sufficient or when there is an indicator of impairment. Based on our analysis, which we performed as of October 1, 2011, no impairment was identified.

        We test tangible and intangible long-lived assets with definite useful lives for impairment whenever circumstances or events may affect the recoverability of the long-lived assets. The evaluation is primarily dependent on the estimated future cash flows of the assets and the fair value of these items, as determined by management based on a number of estimates, including future cash flow projections, discount rates and terminal values. In determining these estimates, management considers internally generated information and information obtained from discussions with market participants. The determination of fair value requires significant judgment both by management and outside experts engaged to assist in this process.

        The impairment test for long-lived assets is a two step process. The first step is to assess if events or changes in circumstances have affected the recoverability of long-lived assets. If management believes that recoverability has been affected, then step two requires management to calculate the undiscounted future cash flow related to the asset or asset group and to compare the cash flow to the carrying value of the asset or asset group. If the undiscounted future cash flows exceed the carrying value, then there is no impairment.

        During the fourth quarter of 2010, we recorded an impairment charge of $1.5 million related to an operating and maintenance contract we lost in a competitive bid to a competitor. In addition, during the fourth quarter of 2010, our subsidiary, DCE, expensed approximately $0.7 million of costs related to equipment that was replaced as part of its expansion of the McCommas Bluff landfill in Dallas, Texas. We had no impairment charges during 2011.

Warranty Reserves

        Our warranty periods range up to thirty-six months, depending on the product or service. We provide a warranty reserve for estimated product warranty costs at the time the applicable sale is recognized. We continuously monitor and analyze warranty claims and maintain a reserve for the related warranty costs based on historical experience and assumptions. If actual failure rates and the resulting cost of repair vary from our historically based estimates, revisions to the estimated warranty reserve would be required.

Natural Gas Derivative Activities

        FASB authoritative guidance for our derivative instruments, specifically for our natural gas futures contracts, 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. For those contracts that do not qualify for hedge accounting, we record the changes in the fair value of the derivatives directly to our consolidated statements of operations. For those contracts that do qualify for hedge accounting, we record the changes in the fair value in our consolidated balance sheet as a component of stockholders' equity. We determine the fair value of our derivatives at the end of each reporting period based on quoted market prices from the NYMEX discounted to reflect the time value of money for contracts related to future periods.

        The counter-party to our derivative transactions is a high credit quality counterparty, however, we are subject to counterparty credit risk to the extent the counterparty is unable to meet its settlement commitments. We manage this credit risk by minimizing the number and size of our derivative contracts and by actively monitoring the creditworthiness of our counterparties. We record valuation adjustments against the derivative assets to reflect counterparty risk, if necessary. The counterparty is

51


also exposed to credit risk by us, which requires us to provide cash deposits as collateral when our contracts are in a liability position in the aggregate.

Revenue Recognition

        We recognize revenue on our CNG and LNG gas sales and for our O&M services in accordance with US GAAP, 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 our customers' storage facilities. We recognize revenue from O&M agreements as we provide the related services.

        In certain transactions with our customers, we agree to provide multiple products or services, including construction of and sale of a station, providing O&M to the station, and sale of fuel to the customer. We evaluate the separability of revenues based on current FASB authoritative guidance, which provides a framework for establishing whether or not a particular arrangement with a customer has one or more revenue elements. Prior to 2010, to the extent we had adequate objective evidence of the values of the separate elements indentified as part of a contract, we allocated the revenue from the contract on a relative fair value basis at the inception of the arrangement. During 2008 and 2009, we did not have objective evidence for our multi-element arrangements, which generally resulted in the deferral of revenue until the future services are performed. Since 2010, however, we have applied newly issued FASB authoritative guidance that allows us to use a combination of objective and reliable evidence to develop management's best estimate of the fair value of the undelivered element. If the arrangement contains a lease, we use the existing evidence of fair value to separate the lease from the other elements in the arrangement.

        We recognize revenue related to our leasing activities in accordance with current FASB authoritative guidance. 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 O&M service revenues as earned from the customer on a volume-delivered basis.

        We typically recognize revenue on long-term fueling station construction projects where we sell the station to the customer using the completed-contract method. However, for IMW and Northstar, we use the percentage-of-completion method of accounting. In those circumstances, revenue is recognized as work on a contract progresses, based on cost incurred in relation to total estimated costs to be incurred for that project.

        We recognize revenue on RNG sales and vehicle sales when we transfer title of the gas or vehicle to our customer.

Stock-Based Compensation

        We recognize compensation expense related to stock options granted to employees based on the grant date fair value. Our assessment of the estimated fair value of the stock options granted is affected by our stock price as well as assumptions regarding a number of complex and subjective variables and the related tax impact. We use the Black-Scholes model to estimate the fair value of stock options granted.

        The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. This model also requires the input of certain assumptions, including: the expected volatility of our common stock price, expected dividends, if any, expected life of the stock option, and the risk free interest rate appropriate for the expected holding period.

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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.

        We operate within multiple domestic and foreign taxing jurisdictions and are subject to audit in these jurisdictions. These audits can involve complex issues, which may require an extended period of time for resolution. Although we believe that adequate consideration has been given to such issues, it is possible that the ultimate resolution of such issues could be significantly different than originally estimated.

Recently Issued Accounting Pronouncements

        See Note 1 to our consolidated financial statements contained elsewhere herein.

Results of Operations

Fiscal Year Ended December 31, 2011 Compared to Fiscal Year Ended December 31, 2010

        Revenue.     Revenue increased by $80.9 million to $292.7 million in the year ended December 31, 2011, from $211.8 million in the year ended December 31, 2010. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 122.7 million gasoline gallon equivalents to 155.6 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 20.4 million gallons, and an increase in LNG sales of 13.2 million gallons. Our net increase in CNG volume was primarily from eight new stations for an existing refuse customer, six new stations for an existing transit customer, four new refuse customers, two new transit customers and one new airport customer, which together accounted for 14.2 million gallons of the CNG volume increase. We also experienced an increase of 16.9 million gallons in CNG volume between periods from our existing airport, transit and refuse customers, and volume growth from our share of our joint venture in Peru. These CNG volume increases were offset by a 10.2 million gallon decrease related to the loss of two transit customers. We also experienced a net increase of 13.2 million gallons in LNG volume between periods, which was primarily due to a 13.3 million gallon increase from Northstar O&M services in 2011. We experienced a slight decrease in our RNG sales (our 70% share of the RNG sales at DCE) of 0.7 million gallons as a result of adverse weather conditions which included a period of drought (which slows down gas flow) and a lightning strike that damaged some of our processing equipment. We experienced a $24.3 million increase, excluding Northstar, in station construction revenues between periods, primarily due to the completion of 12 new CNG stations for four refuse customers, four new CNG station upgrades for one of our existing transit customers, two new CNG stations for two transit customers, and one new CNG station for a trucking customer. Our acquisition of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $51.4 million and $9.8 million, respectively, to our increased revenue between periods. Revenue attributable to VETC also increased between periods as we recorded $17.9 million of revenue related to fuel tax credits in 2011, compared to $16.0 million in 2010. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon charged was $0.86 for the year ended December 31, 2011, which represents a $0.13 per gallon decrease from $0.99 in the year ended December 31, 2010. The decrease was primarily

53


due to a higher percentage of O&M contracts between periods, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Revenue also decreased by $18.7 million between periods due to decreased sales of natural gas vehicle equipment by BAF.

        Cost of sales.     Cost of sales increased by $74.8 million to $216.7 million in the year ended December 31, 2011, from $141.9 million in the year ended December 31, 2010. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. Our acquisition of IMW on September 7, 2010 and Northstar on December 15 2010 contributed $48.7 million and $6.5 million, respectively, to our increased cost of sales between periods. We also experienced a $22.6 million increase, excluding Northstar, in station construction costs between periods. These increases were offset by the decrease in our effective cost per gallon of $0.08 per gallon, to $0.62 per gallon for 2011. This decrease was primarily the result of a higher percentage of O&M contracts in 2011 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. We also experienced a $13.5 million decrease in costs related to BAF's vehicle equipment sales between periods as BAF's sales of natural gas vehicle equipment decreased between periods.

        Selling, general and administrative.     Selling, general and administrative expenses increased by $23.6 million to $86.9 million in the year ended December 31, 2011, from $63.3 million in the year ended December 31, 2010. The most significant increase was our salaries and benefits amount increasing by $15.6 million between periods as we increased our employee headcount from 710 at December 31, 2010 to 1,036 at December 31, 2011. Stock option expense also increased between periods by $1.6 million. In addition, consulting services increased $1.4 million, rent and occupancy increased $1.3 million, business insurance increased $1.2 million, and travel and entertainment increased $1.2 million between periods due to our business growth. These increases were offset by a $2.8 million gain related to a decrease in the estimated fair value of the BAF and IMW contingent consideration liabilities between periods. Also, 2010 included an impairment charge of $1.5 million related to an intangible asset as one of the contracts we acquired in 2009 was lost through a competitive bidding process, and a write-off of $0.7 million at our DCE subsidiary related to equipment that was replaced as part of the expansion of the McCommas Bluff landfill in Dallas, Texas. There were no impairments or write-offs in 2011.

        Depreciation and amortization.     Depreciation and amortization increased by $7.9 million to $30.4 million in the year ended December 31, 2011, from $22.5 million in the year ended December 31, 2010. This increase was primarily due to additional depreciation expense in 2011 related to increased property and equipment balances between periods, primarily related to our expanded station network. Our 2011 amortization expense also increased as 2011 includes a full year of amortization of the intangible assets we obtained in connection with our acquisition of IMW in the third quarter of 2010 and Northstar in the fourth quarter of 2010.

        Derivative (gain) loss on Series I warrant valuation.     Derivative gains decreased by $7.6 million to a gain of $2.7 million in the year ended December 31, 2011, from a gain of $10.3 million in the year ended December 31, 2010. The amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants during the periods. (See note 18 to our consolidated financial statements contained elsewhere herein.)

        Interest expense, net.     Interest expense, net, increased by $8.4 million to $9.6 million of expense for the year ended December 31, 2011, up from $1.2 million for the year ended December 31, 2010. This increase was primarily the result of an increase in interest expense related to the debt we incurred to acquire IMW in the third quarter of 2010, the $40.2 million bond issuance by our DCE subsidiary completed in March, 2011, and our $200 million of convertible notes we issued in July and August of 2011. (See note 9 to the consolidated financial statements for a full description of our outstanding debt).

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        Other income (expense), net.     Other income (expense), net, decreased by $2.7 million to $0.6 million of expense for the year ended December 31, 2011, compared to income of $2.1 million for the year ended December 31, 2010. This decrease was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes.

        Income (loss) from equity method investment.     During 2011, we recorded $0.6 million of equity in the income of our 49% interest in our Peruvian joint venture, compared to $0.4 million in 2010.

        Loss (income) of noncontrolling interest.     During the year ended December 31, 2011, we recorded $0.2 million for the noncontrolling interest in the net income of DCE, compared to $0.3 million for the noncontrolling interest in the net loss of DCE in the year ended December 31, 2010. The noncontrolling interest represents the 30% interest of our joint venture partner.

Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009

        Revenue.     Revenue increased by $80.3 million to $211.8 million in the year ended December 31, 2010, from $131.5 million in the year ended December 31, 2009. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 101.0 million gasoline gallon equivalents to 122.7 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 13.5 million gallons. The acquisition of four compressed natural gas operations and maintenance services contracts in May and June of 2009, four new refuse customers, two new transit customers, and one trucking customer together accounted for 11.3 million gallons of the CNG volume increase. The volume growth from our existing public, refuse and transit customers, combined with the volume growth from our share of our joint venture in Peru, contributed to the remaining CNG volume increase. We also experienced an increase of 7.2 million gallons in LNG volume between periods, which was primarily due to the volume growth of 2.3 million gallons from our existing transit and refuse customers, combined with a 3.8 million gallon increase from our port trucking customers. We also had a LNG volume increase of 1.0 million gallons from two new refuse customers. We had an increase in biomethane sales (our 70% share of the biomethane sales at DCE) of 1.0 million gallons. Revenue also increased between periods by $35.4 million from sales of natural gas conversion equipment and vehicles by BAF, which we acquired on October 1, 2009. Our acquisitions of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $17.8 million and $0.7 million, respectively, to our increased revenue between periods. We also experienced a $5.6 million increase, excluding Northstar, in station construction revenues between periods. Revenue attributable to VETC also increased between periods as we recorded $16.0 million of revenue related to fuel tax credits in 2010, compared to $15.5 million in 2009. These increases were offset by the decrease in our effective price per gallon charged between periods. Our effective price per gallon was $0.99 for the year ended December 31, 2010, which represents a $0.01 per gallon decrease from $1.00 in the year ended December 31, 2009. This decrease is primarily due to the acquisition of certain O&M agreements in 2009 and 2010 that generate less revenue per gallon than contracts where we supply the natural gas commodity.

        Cost of sales.     Cost of sales increased by $59.0 million to $141.9 million in the year ended December 31, 2010, from $82.9 million in the year ended December 31, 2009. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers together with $25.4 million of increased costs related to BAF's vehicle equipment sales, which we began to recognize on October 1, 2009 when we acquired the company. Our acquisition of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $14.0 million and $0.5 million, respectively, to our increased cost of sales between periods. We also experienced a $4.4 million increase in station construction costs between periods. These increases were offset by the decrease in our effective cost per gallon of $0.01 per gallon, to $0.70 per gallon during 2010. This decrease was primarily the result of certain O&M contracts that we acquired in 2009 and 2010 that are included in

55


our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties.

        Selling, general and administrative.     Selling, general and administrative expenses increased by $15.8 million to $63.3 million in the year ended December 31, 2010, from $47.5 million in the year ended December 31, 2009. A significant portion of this increase was the result of our salaries and benefits amount increasing by $7.2 million between periods as we increased our employee headcount from 229 at December 31, 2009 to 710 (including the addition of 420, 70 and 23 IMW, BAF and Northstar employees, respectively) at December 31, 2010. We also experienced a $3.8 million increase in business insurance, contract labor, software/hardware maintenance, training/seminars and office supplies related to our continued business growth and our acquisitions of IMW and Northstar in 2010. Our travel and entertainment expenses increased $1.9 million between periods, primarily due to the increased travel of our sales team. In addition, our professional fees increased $1.8 million between periods, primarily for legal, audit and consulting services related to the acquisitions of IMW and Northstar. 2009 includes a reversal of a bad debt for $1.3 million that did not recur in 2010. Our marketing expenses increased $1.1 million between periods primarily due to certain advertising we conducted related to the Ports of Los Angeles and Long Beach and the refuse sector. During the fourth quarter of 2010, we recorded an impairment charge of $1.5 million related to an intangible asset as one of the contracts we acquired in 2009 was lost through a competitive bidding process, and $0.7 million at our DCE subsidiary related to equipment that was replaced as part of their expansion of the McCommas Bluff landfill in Dallas, Texas. Offsetting these increases was a decrease of $2.2 million between periods related to our stock-based compensation expense and a decrease of $1.2 million during the fourth quarter of 2010 related to a decrease in the IMW contingent consideration liability.

        Depreciation and amortization.     Depreciation and amortization increased by $5.5 million to $22.5 million in the year ended December 31, 2010, from $17.0 million in the year ended December 31, 2009. This increase was primarily due to additional depreciation expense in the year ended December 31, 2010 related to increased property and equipment balances between periods, primarily related to our expanded station network. Our 2010 amortization expense includes increased amortization of the intangible assets we obtained in connection with our acquisition of the operation and maintenance contracts we acquired during the second quarter of 2009, BAF in the fourth quarter of 2009, IMW in the third quarter of 2010, and Northstar in the fourth quarter of 2010.

        Derivative (gain) loss on Series I warrant valuation.     Derivative (gain) loss decreased by $27.7 million to a gain of $10.3 million in the year ended December 31, 2010, from a loss of $17.4 million in the year ended December 31, 2009. The amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants (see note 9 to our consolidated financial statements contained elsewhere herein) during the periods.

        Interest income (expense), net.     Interest income (expense), net, increased by $1.2 million from $0 to $1.2 million of expense for the year ended December 31, 2010. This increase was primarily the result of an increase in interest expense in the year ended December 31, 2010 related to debt we incurred related to the acquisition of IMW.

        Other income (expense), net.     Other income (expense), net, increased by $2.4 million to $2.1 million of income for the year ended December 31, 2010, from a loss of $0.3 million for the year ended December 31, 2009. This increase was primarily due to the impact of foreign currency exchange gains at IMW.

        Income (loss) from equity method investment.     During 2010, we recorded equity income of $0.4 million related to our 49% interest in our Peruvian joint venture, and in 2009, we recorded a gain of $0.2 million related to our interest.

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        Loss (income) of noncontrolling interest.     During the year ended December 31, 2010, we recorded $0.3 million for the noncontrolling interest in the net loss of DCE, compared to $0.4 million for the noncontrolling interest in the net loss of DCE in the year ended December 31, 2009. The noncontrolling interest represents the 30% interest of our joint venture partner.

Seasonality and Inflation

        To some extent, we experience seasonality in our results of operations. Natural gas vehicle fuel amounts 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, electricity 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 or materially increase our operating costs.

Liquidity and Capital Resources

        Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. In March 2011, we received net proceeds of $40.2 million from the issuance of tax-exempt revenue bonds by our DCEMB subsidiary. We received aggregate net proceeds of $200.0 million from the issuance of convertible notes in July and August 2011, and we have commitments from an investor for an additional $100.0 million in convertible debt securities over the subsequent two years. Also, in December 2011, we received aggregate net proceeds of $150.0 million from the exercise of warrants by Mr. Boone Pickens and certain third party investors. Our $20.0 million line of credit expired August 14, 2011, as we did not elect the one year renewal option. We paid off our Facility B Loan during 2011, which had a balance of $7.8 million at the time of repayment.

        In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, including America's Natural Gas Highway stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in RNG production facilities, mergers and acquisitions, 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, support of legislative initiatives and for working capital for our expansion. We have also acquired and may continue to seek to acquire and invest in companies or assets in the natural gas and RNG fueling infrastructure, services and production industries. On February 25, 2011 (the "Closing Date"), we paid $1.2 million to acquire a 19.9% equity interest in ServoTech Engineering, Inc. ("ServoTech"), a company that provides design and engineering services for natural gas fueling systems among other services. We intend to exercise our option to purchase the remaining 81.1% of ServoTech for $2.8 million by May 2012. We financed our operations in 2011 primarily through cash on hand and cash provided by financing activities.

        At December 31, 2011, we had total cash and cash equivalents of $238.1 million, compared to $55.2 million at December 31, 2010.

        Cash used in operating activities was $11.2 million for 2011, compared to $4.0 million used in 2010. Our operating cash flow, before working capital changes, decreased by $26.5 million between periods, primarily related to increased selling, general and administrative expenses in 2011 as we increased our headcount from 710 at December 31, 2010 to 1,036 at December 31, 2011 and we incurred increased expenses due to our growth during the year. Our working capital changes resulted in an increase in cash flow between periods due to timing differences related to various cash flows

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between periods. The biggest change between periods resulted from our collection of a full year of 2010 VETC revenue ($16.0 million) in 2011 as the legislation for VETC was reinstated in the fourth quarter of 2010 and made retroactive to January 1, 2010, but not filed for and received until 2011.

        Cash used in investing activities was $181.8 million for 2011, compared to $68.7 million for 2010. Our purchases of property and equipment were $85.8 million during 2010, compared to $50.5 million in 2010. In 2011, we increased our capital expenditures on our fueling stations and our RNG landfill facilities. Our investment in unconsolidated affiliates totaled $4.7 million in 2011, and was primarily related to increased investments in The Vehicle Production Group, LLC, a company producing a CNG taxi and paratransit vehicle. We also invested $1.2 million in 2011 to purchase a 19.9% interest in ServoTech Engineering, Inc., a company that provides design and engineering services for natural gas fueling systems. In 2010, we paid $20.5 million related to our acquisitions of IMW and Northstar. In 2011, we paid $1.0 million for our acquisition of Weaver Electric, Inc. In 2011, we transferred $57.1 million to restricted cash accounts related to funds earmarked for station construction along America's Natural Gas Highway and funds designated for the plant expansion at our McCommas Bluff Landfill in Dallas, Texas. We also purchased $33.3 million of short-term investments in 2011 in connection with our cash management policy.

        Cash provided by financing activities for 2011 was $377.8 million, compared to $62.6 million for 2010. In 2011 we received $200.0 million from convertible notes we issued, before incurring $3.1 million of debt issuance costs, $150.0 million from certain warrants that were exercised, and $1.5 million related to stock options exercised. Our DCEMB subsidiary also raised $40.2 million in a revenue bond financing during 2011. In 2010, we received net proceeds of $11.5 million related to the exercise of 1,183,712 Series I warrants and net proceeds of $53.6 million from the issuance of common stock and the exercise of stock options. In 2011, we also paid $2.4 million in association with the contingent consideration obligations on our IMW and BAF acquisitions.

        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, our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, RNG plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Capital Expenditures

        Our business plan calls for approximately $239.5 million in capital expenditures in 2012, primarily related to construction of new fueling stations, including stations along ANGH, expanding our California LNG plant, expansion and construction of landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction and potential merger or acquisition activity. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce the ability of our business to grow and generate increased revenues.

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Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of December 31, 2011:

 
  Payments Due by Period  
Contractual Obligations:
  Total   Less than
1 year
  1 - 3 years   3 - 5 years   More than
5 years
 

Long-term debt and capital lease obligations(a)

  $ 392,489   $ 41,279   $ 69,984   $ 187,438   $ 93,788  

Operating lease commitments(b)

    34,392     5,061     8,724     7,483     13,124  

"Take or pay" LNG purchase contracts(c)

    23,078     5,153     9,259     6,117     2,549  

Construction contracts(d)

    35,168     35,168              

DCEMB electricity contract(e)

    6,447     1,651     3,294     1,502      
                       

Total

  $ 491,574   $ 88,312   $ 91,261   $ 202,540   $ 109,461  
                       

(a)
Consists of long-term debt and capital lease obligations to finance acquisitions and equipment purchases, including interest.

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

(c)
The amounts in the table represent our estimates for our fixed LNG purchase commitments under two "take-or-pay" contracts.

(d)
Consists of our obligations to fund various fueling station construction projects, net of amounts funded through December 31, 2011, and excluding contractual commitments related to station sales contracts.

(e)
Consists of our obligations to purchase electricity at our RNG plant at the McCommas Bluff landfill in Dallas, Texas.

Off-Balance Sheet Arrangements

        At December 31, 2011, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition.

    outstanding surety bonds for construction contracts and general corporate purposes totaling $81.4 million,

    two take-or-pay contracts for the purchase of LNG,

    operating leases where we are the lessee,

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

    firm commitments to sell CNG and LNG at fixed prices.

        We provide 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 our surety bonds as we do not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these arrangements for which we will not be reimbursed.

        We have two contracts that require us to purchase minimum volumes of LNG at index based prices. One contract expires in June 2014 and the other contract expires in October 2017.

        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

59


dates through 2018. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we built our California LNG liquefaction plant. The lease is for an initial term of thirty years and requires payments of $230,000 per year, plus up to $130,000 per year for each 30 million gallons of production capacity utilized, 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 a fee for certain other services that the landlord will provide. Commercial operations began December 1, 2008, and the fixed payments for this lease are 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 certain stations and equipment that we own.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk.

        In the ordinary course of business, we are exposed to various market risk factors, including changes in general economic conditions, domestic and foreign competition, commodity price risk and foreign currency exchange rates.

        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 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 30% (or 33% excluding BAF, IMW and Northstar) of our cost of sales for 2010 and 22% (or 32% excluding BAF, IMW and Northstar) for 2011. Prices for natural gas over the twelve-year period from December 31, 1999 through December 31, 2011, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At December 31, 2011, the NYMEX index price of natural gas was $3.36 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 FASB authoritative guidance on derivatives. The accounting under this guidance for changes in the fair value of a derivative depends upon whether it has been specified in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained.

        The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets, which are then discounted to reflect the time value of money for contracts applicable to future periods. The fair value of these futures contracts is continually subject to change due to market conditions. In an effort to mitigate the volatility in our earnings related to futures activities, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and to 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 the FASB guidance, 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 the futures contracts we hold as of December 31, 2011 to hedge the fixed price component of certain

60


supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on December 31, 2011 ($3.36 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $0.2 million.

        Foreign exchange rate risk.     Because we have foreign operations, we are exposed to foreign currency exchange gains and losses. Since the functional currency of our foreign operations is in their local currency, the currency effects of translating the financial statements of those foreign subsidiaries, which operate in local currency environments, are included in the accumulated other comprehensive income (loss) component of consolidated equity and do not impact earnings. However, foreign currency transaction gains and losses not in our subsidiaries' functional currency do impact earnings and resulted in approximately $0.6 million of losses in 2011. During 2011, our primary exposure to foreign currency rates related to our Canadian operations that had certain outstanding notes payable denominated in the U.S. dollar which were not hedged.

        We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our monetary transactions denominated in a foreign currency. If the exchange rate on these assets and liabilities were to fluctuate by 10% from the rate as of December 31, 2011, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $3.9 million.

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, 2011. The information for each quarter is unaudited and the Company has prepared them 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.

61


Quarterly Financial Data (Unaudited)
(In thousands, except share data)

 
  For the Quarter Ended  
 
  March 31,
2010
  June 30,
2010
  September 30,
2010
  December 31,
2010
 

Revenue:

                         

Product revenues

  $ 34,273   $ 39,434   $ 40,975   $ 75,154  

Service revenues

    4,716     4,601     4,679     8,002  
                   

Total revenues

    38,989     44,035     45,654     83,156  

Operating expenses:

                         

Cost of sales:

                         

Product cost of sales

    25,496     28,692     31,190     47,533  

Service cost of sales

    2,063     1,923     2,319     2,673  

Derivative (gains) losses:

                         

Series I warrant valuation

    18,605     (16,615 )   (7,866 )   (4,402 )

Selling, general and administrative

    13,649     14,878     15,855     18,876  

Depreciation and amortization

    4,991     5,070     5,507     6,919  
                   

Total operating expenses

    64,804     33,948     47,005     71,599  
                   

Operating income (loss)

    (25,815 )   10,087     (1,351 )   11,557  

Interest income (expense), net

    109     (22 )   (70 )   (1,211 )

Other income (expense), net

    43     (39 )   (309 )   2,385  

Income from equity method investments

    77     29     96     225  
                   

Income (loss) before income taxes

    (25,586 )   10,055     (1,634 )   12,956  

Income tax (expense) benefit

    1,203     (77 )   (290 )   600  
                   

Net income (loss)

    (24,383 )   9,978     (1,924 )   13,556  

Loss (income) of noncontrolling interest

    16     (83 )   94     230  
                   

Net income (loss) attributable to Clean Energy Fuels Corp. 

  $ (24,367 ) $ 9,895   $ (1,830 ) $ 13,786  
                   

Basic earnings (loss) per share

  $ (0.41 ) $ 0.16   $ (0.03 ) $ 0.21  
                   

Fully diluted earnings (loss) per share

  $ (0.41 ) $ 0.14   $ (0.03 ) $ 0.18  
                   

62



 
  For the Quarter Ended  
 
  March 31,
2011
  June 30,
2011
  September 30,
2011
  December 31,
2011
 

Revenue:

                         

Product revenues

  $ 58,532   $ 61,523   $ 64,237   $ 75,991  

Service revenues

    6,809     7,590     7,845     10,190  
                   

Total revenues

    65,341     69,113     72,082     86,181  

Operating expenses:

                         

Cost of sales:

                         

Product cost of sales

    43,850     46,888     48,853     61,317  

Service cost of sales

    3,154     3,536     3,901     5,185  

Derivative (gains) losses:

                         

Series I warrant valuation

    3,300     (4,835 )   (1,524 )   404  

Selling, general and administrative

    18,030     21,653     20,140     27,027  

Depreciation and amortization

    7,210     7,632     7,554     8,010  
                   

Total operating expenses

    75,544     74,874     78,924     101,943  
                   

Operating loss

    (10,203 )   (5,761 )   (6,842 )   (15,762 )

Interest income (expense), net

    (820 )   (1,506 )   (3,194 )   (4,096 )

Other income (expense), net

    601     187     (2,450 )   1,051  

Income from equity method investments

    211     164     99     163  
                   

Income (loss) before income taxes

    (10,211 )   (6,916 )   (12,387 )   (18,644 )

Income tax (expense) benefit

    735     1,177     960     (2,169 )
                   

Net income (loss)

    (9,476 )   (5,739 )   (11,427 )   (20,813 )

Loss (income) of noncontrolling interest

    (277 )   120     73     (94 )
                   

Net income (loss) attributable to Clean Energy Fuels Corp. 

  $ (9,753 ) $ (5,619 ) $ (11,354 ) $ (20,907 )
                   

Basic earnings (loss) per share

  $ (0.14 ) $ (0.08 ) $ (0.16 ) $ (0.29 )
                   

Fully diluted earnings (loss) per share

  $ (0.14 ) $ (0.08 ) $ (0.16 ) $ (0.29 )
                   

63


Item 8.    Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

 
  Page  

Consolidated Financial Statements

       

Report of Independent Registered Public Accounting Firm

    65  

Consolidated Balance Sheets as of December 31, 2010 and 2011

    67  

Consolidated Statements of Operations for the Years Ended December 31, 2009, 2010, and 2011

    68  

Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) for the Years Ended December 31, 2009, 2010, and 2011

    69  

Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2010, and 2011

    70  

Notes to Consolidated Financial Statements

    71  

Financial Statement Schedule

       

Schedule II—Valuation and Qualifying Accounts

    107  

64


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, 2010 and 2011, 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, 2011. In connection with our audits of the consolidated financial statements, we also have audited the related financial statement schedule. We also have audited the Company's internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these consolidated financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule and an opinion on the Company's internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        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, 2010 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted

65


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. Also, in our opinion, Clean Energy Fuels Corp. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        Effective January 1, 2010, the Company changed its method of accounting for revenue recognition on transactions with multiple deliverables.

/s/ KPMG LLP

Los Angeles, California
March 12, 2012

66



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except share data)

 
  December 31,  
 
  2010   2011  

Assets

 

Current assets:

             

Cash and cash equivalents

  $ 55,194   $ 238,125  

Restricted cash

    2,500     4,792  

Short-term investments

        33,329  

Accounts receivable, net of allowance for doubtful accounts of $702 and $712 as of December 31, 2010 and December 31, 2011, respectively

    45,645     56,455  

Other receivables

    27,280     19,601  

Inventory, net

    20,483     35,287  

Prepaid expenses and other current assets

    10,959     14,027  
           

Total current assets

    162,061     401,616  

Land, property and equipment, net

    211,643     277,334  

Restricted cash

        54,804  

Notes receivable and other long-term assets

    15,059     16,650  

Investments in other entities

    10,748     16,459  

Goodwill

    71,814     73,741  

Intangible assets, net

    112,174     102,103  
           

Total assets

  $ 583,499   $ 942,707  
           

Liabilities and Stockholders' Equity

 

Current liabilities:

             

Current portion of long-term debt and capital lease obligations

  $ 22,712   $ 22,925  

Accounts payable

    28,635     36,668  

Accrued liabilities

    28,137     28,255  

Deferred revenue

    17,507     21,267  
           

Total current liabilities

    96,991     109,115  

Long-term debt and capital lease obligations, less current portion

    41,704     266,497  

Other long-term liabilities

    28,588     22,687  
           

Total liabilities

    167,283     398,299  

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 149,000,000 shares; issued and outstanding 69,610,098 shares and 85,433,258 shares at December 31, 2010 and December 31, 2011, respectively

    7     9  

Additional paid-in capital

    569,202     741,650  

Accumulated deficit

    (151,926 )   (199,559 )

Accumulated other comprehensive loss

    (3,996 )   (1,216 )
           

Total Clean Energy Fuels Corp. stockholders' equity. 

    413,287     540,884  

Noncontrolling interest in subsidiary

    2,929     3,524  
           

Total stockholders' equity

    416,216     544,408  
           

Total liabilities and stockholders' equity

  $ 583,499   $ 942,707  
           

   

See accompanying notes to consolidated financial statements.

67



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except share and per share data)

 
  Years Ended December 31,  
 
  2009   2010   2011  

Revenue:

                   

Product revenues

  $ 116,635   $ 189,836   $ 260,283  

Service revenues

    14,868     21,998     32,434  
               

Total revenue

    131,503     211,834     292,717  

Operating expenses:

                   

Cost of sales:

                   

Product cost of sales

    76,766     132,911     200,908  

Service cost of sales

    6,155     8,978     15,776  

Derivative losses (gains):

                   

Series I warrant valuation

    17,367     (10,278 )   (2,655 )

Selling, general and administrative

    47,509     63,258     86,850  

Depreciation and amortization

    16,992     22,487     30,406  
               

Total operating expenses

    164,789     217,356     331,285  
               

Operating loss

    (33,286 )   (5,522 )   (38,568 )

Interest expense, net

    (32 )   (1,194 )   (9,616 )

Other income (expense), net

    (310 )   2,080     (611 )

Income from equity method investments

    244     427     637  
               

Loss before income taxes

    (33,384 )   (4,209 )   (48,158 )

Income tax (expense) benefit

    (304 )   1,436     703  
               

Net loss

    (33,688 )   (2,773 )   (47,455 )

Loss (income) of noncontrolling interest

    439     257     (178 )
               

Net loss attributable to Clean Energy Fuels Corp. 

  $ (33,249 ) $ (2,516 ) $ (47,633 )
               

Loss per share:

                   

Basic and diluted

  $ (0.60 ) $ (0.04 ) $ (0.68 )
               

Weighted average common shares outstanding:

                   

Basic and diluted

    55,021,961     62,549,311     70,415,431  
               

   

See accompanying notes to consolidated financial statements.

68


Clean Energy Fuels Corp. and Subsidiaries
Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss)
(In thousands, except share data)

 
  Common stock    
   
   
   
   
   
 
 
  Additional Paid-In Capital   Retained Earnings (Accumulated Deficit)   Accumulated Other Comprehensive Income (Loss)   Noncontrolling Interest in Subsidiary   Total Stockholders' Equity   Total Comprehensive Income (Loss)  
 
  Shares   Amount  

Balance, December 31, 2008

    50,238,212     5     346,467     (113,549 )   854     3,625     237,402        

Issuance of common stock upon exercise of options

    171,939         588                 588        

Issuance of common stock, net of offering costs (see note 9)

    9,430,000     1     73,217                 73,218        

Adoption of FASB ASC 815, Series I warrants

            (9,762 )   (2,612 )           (12,374 )      

Stock-based compensation

            14,071                 14,071        

Net loss

                (33,249 )       (439 )   (33,688 )   (33,688 )

Unrealized gain on futures contracts

                    814         814     814  

Foreign currency translation adjustment

                    345         345     345  
                                   

Balance, December 31, 2009

    59,840,151     6     424,581     (149,410 )   2,013     3,186     280,376     (32,529 )
                                                 

Issuance of common stock upon exercise of options

    1,118,827         11,049                 11,049        

Issuance of common stock, net of offering costs (see note 9)

    3,450,000         42,562                 42,562        

Issuance of common stock upon exercise of Series I warrants

    1,183,712         17,152                 17,152        

Issuance of common stock upon business combinations

    4,017,408     1     61,938                 61,939        

Stock-based compensation

            11,920                 11,920        

Net loss

                (2,516 )       (257 )   (2,773 )   (2,773 )

Unrealized loss on futures contracts

                    (4,231 )       (4,231 )   (4,231 )

Foreign currency translation adjustment

                    (1,778 )       (1,778 )   (1,778 )
                                   

Balance, December 31, 2010

    69,610,098     7     569,202     (151,926 )   (3,996 )   2,929     416,216     (8,782 )
                                                 

Issuance of common stock upon exercise of options

    221,234         1,477                 1,477        

Issuance of common stock, net of offering costs (see note 9)

    601,926         7,500                 7,500        

Issuance of common stock upon exercise of Boone Pickens warrants

    15,000,000     2     149,998                 150,000        

Stock-based compensation

            13,473                 13,473        

Non-controlling interest contribution

                        417     417        

Net loss

                (47,633 )       178     (47,455 )   (47,455 )

Unrealized gain on futures contracts

                    2,091         2,091     2,091  

Unrealized loss on short-term investments available for sale

                    (126 )       (126 )   (126 )

Foreign currency translation adjustment

                    815         815     815  
                                   

Balance, December 31, 2011

    85,433,258   $ 9   $ 741,650   $ (199,559 ) $ (1,216 ) $ 3,524   $ 544,408   $ (44,675 )
                                   

See accompanying notes to consolidated financial statements.

69



Clean Energy Fuels Corp. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

 
  Years Ended December 31,  
 
  2009   2010   2011  

Cash flows from operating activities :

                   

Net loss

  $ (33,688 ) $ (2,773 ) $ (47,455 )

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

                   

Depreciation and amortization

    16,992     22,487     30,406  

Asset impairments

        2,248      

Provision for doubtful accounts and notes

    (783 )   264     344  

Loss on disposal of assets

    423     181      

Derivative loss (gain)

    17,367     (10,278 )   (2,655 )

Stock-based compensation expense

    14,071     11,920     13,473  

Amortization of debt issuance cost

            339  

Accretion of notes payable

        1,118     2,731  

Loss (gain) on contingent consideration for acquisitions

        (1,184 )   (2,828 )

Changes in operating assets and liabilities, net of assets and liabilities acquired:

                   

Accounts and other receivables

    (2,656 )   (35,718 )   (3,329 )

Inventory

    109     (4,882 )   (14,782 )

Margin deposits on futures contracts

    (2,118 )   (3,706 )   2,981  

Return (deposits) on LNG trucks

    5,752     285     160  

Prepaid expenses and other assets

    (1,298 )   (860 )   (6,644 )

Accounts payable

    925     999     8,033  

Accrued expenses and other

    (1,826 )   15,863     8,009  
               

Net cash provided by (used in) operating activities

    13,270     (4,036 )   (11,217 )

Cash flows from investing activities:

                   

Purchases of short-term investments

            (33,329 )

Purchases of property and equipment

    (30,499 )   (50,534 )   (85,798 )

Proceeds from sale of property and equipment

    60     282      

Proceeds from sale of loans receivable

    3,026     2,418     109  

Acquisitions, net of cash acquired

    (10,362 )   (20,473 )   (1,000 )

Investments in other entities

    (5,634 )   (427 )   (4,712 )

Restricted cash

            (57,096 )
               

Net cash used in investing activities

    (43,409 )   (68,734 )   (181,826 )

Cash flows from financing activities:

                   

Proceeds from minority interest DCE equity contribution

            417  

Proceeds from exercise of warrants

        11,537     150,000  

Proceeds from issuance of common stock

    73,217     42,562      

Proceeds from the exercise of stock options

    588     11,049     1,477  

Proceeds from capital lease obligations and debt instruments

    7,160     200     244,455  

Proceeds from revolving line of credit

        12,665     53,595  

Repayment of borrowing under revolving line of credit

        (14,348 )   (49,589 )

Repayment of capital lease obligations and debt instruments

    (20,023 )   (1,050 )   (17,079 )

Contingent consideration paid relating to business acquisitions

            (2,394 )

Payment for debt issuance costs

            (3,054 )
               

Net cash provided by financing activities

    60,942     62,615     377,828  

Effect of exchange rates on cash and cash equivalents

        (1,738 )   (1,854 )
               

Net increase (decrease) in cash and cash equivalents

    30,803     (11,893 )   182,931  

Cash and cash equivalents, beginning of year

    36,284     67,087     55,194  
               

Cash and cash equivalents, end of year

  $ 67,087   $ 55,194   $ 238,125  
               

Supplemental disclosure of cash flow information:

                   

Income taxes paid

  $ 334   $ 222   $ 783  
               

Interest paid, net of $539, $434, and $1,352 capitalized, respectively

  $ 1,078   $ 2,251   $ 6,744  
               

   

See accompanying notes to consolidated financial statements.

70



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies

The Company

        Clean Energy Fuels Corp., together with its majority and wholly owned subsidiaries (hereinafter collectively referred to as the "Company"), is engaged in the business of selling natural gas fueling solutions to its customers, primarily in the United States. The Company began selling certain equipment and services internationally in 2010 as a result of its acquisition of I.M.W. Industries, Ltd. ("IMW").

        Clean Energy has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse and public transit. The Company, builds, operates, maintains or supplies approximately 273 natural gas fueling locations in twenty-three states within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance ("O&M") agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, through manufacturing and servicing natural gas fueling compressors and related equipment, providing natural gas vehicle conversions, processing and selling renewable natural gas ("RNG"), and through financing its customers' vehicle purchases.

Basis of Presentation

        The consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company's financial position, results of operations and cash flows in accordance with U.S. generally accepted accounting principles ("US GAAP"). All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

        The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses recorded during the reporting period. Actual results could differ from those estimates. Current economic conditions may require the use of additional estimates and these estimates may be subject to a greater degree of uncertainty as a result of the uncertain economy.

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.

Fair Value of Financial Instruments

        The carrying values of the Company's financial instruments, including cash and cash equivalents, accounts and other receivables, notes receivable, accounts payable, accrued expenses and other current liabilities, capital lease obligations and notes payable approximate fair value.

71



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

Inventories

        Inventories are stated at the lower of cost or market value on a first-in, first out basis. Management's estimate of market value includes a provision for slow-moving or obsolete inventory based upon inventory on hand and forecasted demand.

        Inventories consisted of the following as of December 31, 2010 and 2011:

 
  2010   2011  

Raw materials and spare parts

  $ 17,634   $ 30,177  

Work in process

    1,196     2,310  

Finished goods

    1,653     2,800  
           

Total

  $ 20,483   $ 35,287  
           

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 twenty 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 related 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 $325, $831, and $3,090 for the years ended December 31, 2009, 2010 and 2011, respectively.

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 or asset group. 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.

        During the fourth quarter of 2010, the Company's majority-owned subsidiary, DCE, recorded an impairment charge of $717 related to equipment that was replaced as part of its expansion of the McCommas Bluff landfill in Dallas, Texas.

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 business combination and determined to have an indefinite useful life are not amortized. When Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 350 "Intangibles—Goodwill and Others" (formerly

72



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

SFAS No. 142 "Goodwill and Other Intangible Assets") was issued in 2001, the Company adopted December 31 st of each year as its annual impairment testing date. In 2011, the Company elected to change its annual impairment testing date to October 1 of each year, commencing October 1, 2011. Moving the testing date to October 1 will allow the Company more time to accurately complete its impairment testing process in order to incorporate the results in its annual financial statements and timely file those statements with the Securities and Exchange Commission. There were no impairment charges resulting from the October 1, 2011 impairment testing, and no events have occurred subsequent to that date which indicate impairment may have occurred. Beginning on October 1, 2011, we performed our test for Goodwill impairment under the amended guidance issued by the FASB in Accounting Standards Update ("ASU") 2011-08, Testing for Goodwill Impairment , issued in September 2011, which we chose to early adopt, effective October 1, 2011. Under the amended requirements of ASU 2011-08, an entity is not required to quantitatively determine a reporting unit's fair value, if it concludes, based upon a qualitative assessment, that it is not more likely than not that the reporting unit's fair value is less than its carrying amount. A qualitative assessment is an option available on an individual reporting unit basis and is an unconditional alternative to Step 1 of the goodwill impairment test. A reporting entity can choose to perform either Step 1 or a qualitative assessment in subsequent reporting periods. If the Company does conduct a Step 1 test, the Company looks at its projected future cash flows and its market capitalization for its respective operations. In these instances, to the extent the Company's projected future cash flows do not materialize as planned or its market capitalization decreases, the Company could be forced to take an impairment charge in future periods.

        Intangible assets with finite useful lives are amortized over their respective estimated useful lives and reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

        During the fourth quarter of 2010, as a result of losing a competitive bid to a customer, the Company recorded an impairment charge of $1,531 related to an intangible asset.

        The Company's intangible assets as of December 31, 2010 and 2011 were as follows:

 
  2010   2011  

Technology

  $ 77,071   $ 77,071  

Customer relationships

    21,590     21,590  

Acquired contracts

    13,075     13,075  

Trademark and tradenames

    7,400     7,400  

Non-compete agreements

    2,126     2,126  
           

Total intangible assets

    121,262     121,262  

Less accumulated amortization

    (9,088 )   (19,159 )
           

Net intangible assets

  $ 112,174   $ 102,103  
           

        Amortization expense for intangible assets was $2,247, $5,915, and $10,071 for the years ended December 31, 2009, 2010 and 2011, respectively. Estimated amortization expense for the five years succeeding the year ended December 31, 2011 is approximately $8,903, $8,766, $8,246, $8,246 and $8,168, respectively.

73



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

Warranty Liability

        The Company records warranty liabilities at the time of sale for the estimated costs that may be incurred under its applicable warranty. Changes in the warranty liability are presented in the following table:

 
  December 31,
2010
  December 31,
2011
 

Warranty liability at beginning of year

  $ 1,136   $ 2,338  

Assumed liability through acquisitions

    691      

Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties

    782     3,208  

Service obligations honored

    (271 )   (2,416 )
           

Warranty liability at end of year

  $ 2,338   $ 3,130  
           

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 the asset life or at the end of the 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 balance. Over time, the liability is increased and expense is recognized for the change in the present value of the obligation, and the initial capitalized cost is depreciated over the useful life of the asset.

        The following table summarizes the activity of the asset retirement obligation, of which $939 and $964 is included in other long-term liabilities, with the remaining current portion included in accrued liabilities, as of December 31, 2010 and 2011, respectively:

 
  2010   2011  

Beginning balance

  $ 918   $ 1,128  

Liabilities incurred

    183     8  

Liabilities settled

    (23 )   (3 )

Accretion expense

    50     46  
           

Ending balance

  $ 1,128   $ 1,179  
           

Revenue Recognition

        The Company recognizes revenue on gas sales and O&M services in accordance with US GAAP, which requires that four basic criteria must be met before revenue can be recognized: (i) persuasive evidence of an arrangement exists; (ii) delivery has occurred and title and the risks and rewards of

74



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

ownership have been transferred to the customer or services have been rendered; (iii) the price is fixed or determinable; and (iv) collectability is reasonably assured. Applying these factors, the Company typically recognizes revenue from the sale of natural gas fuel at the time the fuel is dispensed or, in the case of LNG sales agreements, delivered to the customers' storage facilities. The Company recognizes revenue from O&M agreements as the related services are provided.

        In certain transactions with Clean Energy customers, the Company agrees to provide multiple products or services, including construction of a station, providing O&M to the station, and sale of fuel to the customer. The Company evaluates the separability of revenues based on FASB authoritative guidance, which provides a framework for establishing whether or not a particular arrangement with a customer has one or more revenue elements. Prior to 2010, to the extent the Company had objective evidence of the values of the separate elements indentified as part of a contract, the Company allocated the revenue from the contract on a relative fair value basis at the inception of the arrangement. During 2009, the Company did not have sufficient objective evidence for its multiple-element arrangements, which generally resulted in the deferral of revenue until the future services are performed. However, in 2010, the Company elected to apply newly issued FASB authoritative guidance that allows it to use a combination of internal and external objective and reliable evidence to develop management's best estimate of the fair value of the contract elements. If the arrangement contains a lease, the Company uses the existing evidence of fair value to separate the lease from the other elements in the arrangement.

        The Company recognizes revenue related to its leasing activities in accordance with FASB authoritative guidance. The Company's 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 these arrangements, the Company recognizes gas sales and O&M service revenues as earned from the customer on a volume-delivered basis.

        The Company typically recognizes revenue on long-term fueling station construction projects where it sells the station to the customer using the completed-contract method. However, IMW and Wyoming Northstar Incorporated, Southstar, LLC, and M&S Rental LLC (collectively "Northstar") use the percentage-of-completion method of accounting to recognize revenue because their projects are small and they have been able to demonstrate that they can reasonably estimate costs to complete. In these circumstances, revenue is recognized based on costs incurred in relation to total estimated costs to be incurred for a project.

        The Company recognizes revenue on RNG sales and vehicle sales when it transfers title of the gas or vehicle to its customer.

Volumetric Excise Tax Credits ("VETC")

        The Company records its VETC credits as revenue as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the years ended December 31, 2009, 2010 and 2011 were $15,535, $16,042, and $17,889, respectively. During 2010, the legislation providing for VETC was reinstated in the fourth quarter of 2010 and made retroactive to January 1, 2010. The VETC legislation expired on December 31, 2011.

75



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

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.

Advertising Costs

        Advertising costs are expensed as incurred. Advertising costs amounted to $932, $1,260, and $1,559 for the years ended December 31, 2009, 2010 and 2011, respectively.

Stock-based Compensation

        The Company recognizes compensation expense for all stock-based payment arrangements, net of an estimated forfeiture rate, over the requisite service period of the award. For stock options, the Company determines the grant date fair value using the Black-Scholes option-pricing model which requires the input of certain assumptions, including the expected life of the stock-based payment awards, stock price volatility and risk-free interest rates.

Foreign Currency Translation

        In accordance with FASB authoritative guidance, the Company uses 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. Revenue 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.

        Foreign currency transactions occur when there is a transaction denominated in other than the respective entity's functional currency. The Company records the changes in the exchange rate for these transactions in the consolidated statements of operations. For the fiscal years ended December 31, 2009, 2010 and 2011, foreign exchange transaction gains and losses were included in other income (expense) and were gains of $2, $1,902, and a loss of $(596), respectively.

Income Taxes

        Income taxes are computed using the asset and liability method. Under this method, deferred income taxes are recognized by applying enacted statutory tax rates applicable to future years to differences between the tax bases and financial reporting amounts of existing assets and liabilities. Valuation allowances are established when it is more likely than not that such deferred tax assets will not be realized.

        The Company has a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities based on the technical merits of the position. The amount recognized is measured as the largest amount of benefit that has a greater than 50 percent likelihood of being

76



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

realized upon ultimate settlement. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefit in income tax expense.

Net Loss Per Share

        Basic net loss per share is computed by dividing net loss attributable to Clean Energy by the weighted-average number of common shares outstanding during the period. Diluted net loss per share is computed by dividing net loss attributable to Clean Energy by the weighted-average number of common shares outstanding and potentially dilutive securities outstanding during the period. Potentially dilutive securities include stock options and warrants, and in 2011, convertible notes. The dilutive effect of stock options and warrants is computed under the treasury stock method. Potentially dilutive securities are excluded from the computations of diluted net loss per share if their effect would be antidilutive.

        The following potentially dilutive securities have been excluded from the diluted net loss per share calculations because their effect would have been antidilutive:

 
  2009   2010   2011  

Stock options

    10,348,188     10,433,551     10,683,303  

Warrants

    18,314,394     17,130,682     2,130,682  

Convertibles notes

            13,164,557  

Derivative Financial Instruments

        The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed price arrangements. The Company accounts for its derivative instruments in accordance with FASB authoritative guidance for derivative instruments and hedging activities, which 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 futures contracts at December 31, 2011 are being accounted for as cash flow hedges and are being used to mitigate the Company's exposure to changes in the price of natural gas and not for speculative purposes. At December 31, 2011, all of the Company's futures contracts qualified for hedge accounting.

        The counter-party to the Company's derivative transactions is a high credit quality counterparty; however, the Company is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. The Company manages this credit risk by minimizing the number and size of its derivative contracts. The Company actively monitors the creditworthiness of its counterparties and records valuation adjustments against the derivative assets to reflect counterparty risk, if necessary. The counter-party is also exposed to credit risk of the Company, which requires the Company to provide cash deposits as collateral.

77



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

Comprehensive Income (Loss)

        Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during the period from transactions and other events and circumstances from non-owner sources. The difference between net income and comprehensive income for the years ended December 31, 2009, 2010, and 2011 was primarily comprised of the Company's foreign currency translation adjustment and unrealized gains (losses) on futures contracts.

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. However, certain international customers have historically been slower to pay on trade receivables. Accordingly, 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. In addition, through Export Development Canada, IMW maintains accounts receivable insurance on a substantial portion of its foreign trade receivables, which covers up to 90% of the related outstanding balance. Although 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.

Recently Adopted Accounting Changes and Recently Issued and Adopted Accounting Standards

        On January 1, 2011, the Company adopted changes issued by the FASB to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number). In addition, the changes require a reporting entity to separately disclose the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. These changes were applied to the disclosures in note 18 to the Company's consolidated financial statements contained elsewhere herein.

        On October 1, 2011, the Company adopted changes issued by the FASB to the testing of goodwill for impairment. These changes permit an entity to make a qualitative assessment of whether it is more likely than not that a reporting unit's fair value is less than its carrying amount before applying the two-step goodwill impairment test. If an entity concludes it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, it need not perform the two-step impairment test. The adoption of this pronouncement did not have any impact on the Company's consolidated financial statements.

        On January 1, 2011, the Company adopted changes issued by the FASB to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the

78



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(1) Summary of Significant Accounting Policies (Continued)

beginning of the comparable prior annual reporting period only. Also, the existing requirements for supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The adoption of this pronouncement did not have any impact on the Company's consolidated financial statements.

        In May 2011, the FASB issued changes to conform existing guidance regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio, application of premiums and discounts in a fair value measurement, and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity's use of a nonfinancial asset in a way that differs from the asset's highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. These changes become effective for the Company on January 1, 2012. The Company is currently evaluating the potential impact of these changes on its consolidated financial statements.

        In June 2011, the FASB issued changes to the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The option to present components of other comprehensive income as part of the statement of changes in stockholders' equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. These changes become effective for the Company on January 1, 2012. The Company is currently evaluating these changes to determine which option will be chosen for the presentation of comprehensive income.

(2) Acquisitions

Natural Gas Fueling Compressors

        On September 7, 2010, the Company, acting through certain of its subsidiaries, completed its purchase of the advanced natural gas fueling compressor and related equipment manufacturing and servicing business of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, and has other manufacturing facilities near Shanghai, China and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States.

79



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(2) Acquisitions (Continued)

        In connection with the closing of the Company's acquisition of IMW, a subsidiary of the Company (the "Acquisition Subsidiary") paid an upfront cash payment of $15,034 and issued 4,017,408 shares of the Company's common stock at closing to IMW's shareholder. The issued shares were registered and available for immediate resale by the IMW shareholder. An additional $288 was paid by the Acquisition Subsidiary when the Chinese regulatory authorities subsequently approved the transfer of IMW Compressors (Shanghai) Co. Ltd. to the Acquisition Subsidiary. The Acquisition Subsidiary also issued the following promissory notes to the IMW shareholder (collectively, the "IMW Notes"): (i) a promissory note with a principal amount of $12,500 that was paid on January 31, 2011, (ii) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2012, (iii) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2013, and (iv) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2014. Each payment under the IMW Notes will consist of $5,000 in cash and $7,500 in cash and/or shares of the Company's common stock (the exact combination of cash and/or stock to be determined at the Company's option). In addition, pursuant to a security agreement executed at closing, the IMW Notes are secured by a subordinate security interest in IMW. On January 31, 2011, the Company paid $5,000 in cash and issued 601,926 shares to the IMW shareholder to settle the IMW Note due on that date. On January 31, 2012, the Company paid $5,000 in cash and extended the additional payment due on January 31, 2012 to July 31, 2012.

        IMW's former shareholder may also receive additional contingent consideration based on future gross profits earned by IMW over the four year period following the acquisition. The additional contingent consideration is subject to achieving minimum gross profit targets and will be determined based on a sliding scale that increases at certain gross profit levels. During the four-year period during which these earn-out payments may be made, the former shareholder of IMW will receive between zero and 23% of the gross profit of IMW as additional consideration, up to a maximum of $40,000 in the aggregate (which maximum would be payable if IMW achieves approximately $174,000 in gross profit over the four-year period during which these earn-out payments may be made). The IMW shareholder earned $235 for the first contingent consideration payment.

        The Company accounted for this acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values, as of the date of acquisition. The following table summarizes the allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed:

Current assets

  $ 27,149  

Property, plant and equipment

    2,559  

Identifiable intangible assets

    81,400  

Goodwill

    45,049  
       

Total assets acquired

    156,157  

Liabilities assumed

    (25,986 )
       

Total purchase price

  $ 130,171  
       

80



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(2) Acquisitions (Continued)

        Management allocated approximately $81,400 of the purchase price to the identifiable intangible assets related to technology, customer relationships, non-compete agreements, and trademarks that were acquired with the acquisition. The fair value of the identifiable intangible assets will be amortized on a straight-line basis over their estimated useful lives ranging from three to twenty years. In addition, management allocated $45,049 to goodwill as part of the acquisition and recorded a contingent liability of $9,300 related to the additional contingent consideration described above. Under FASB authoritative guidance, the Company is required to adjust the value of the contingent consideration for this acquisition in the statement of operations as the value of the obligation changes each reporting period. As of December 31, 2011, the fair value of the contingent consideration was approximately $6,000.

        The results of operations of IMW have been included in the Company's consolidated financial statements since September 7, 2010.

        The following table presents the Company's unaudited pro forma results of operations for the year ended December 31, 2010 as if the acquisition had occurred at on January 1, 2010. The pro forma financial data for the period presented includes adjustments for the following: (i) elimination of intercompany transactions (ii) recording the additional amortization expense from the identifiable intangible assets (iii) adjusting the estimated tax provision of the pro forma combined results; (iv) US GAAP conversion adjustments and (v) the issuance of the Company's common stock as part of the acquisition. The Company prepared the pro forma financial information for the combined entities for comparative purposes only, and it is not indicative of what actual results would have been if the acquisition had taken place on January 1, 2010, or of future results.

 
  For the year ended
December 31, 2010
 

Revenue

  $ 249,093  

Net (loss)

    (7,922 )

(Loss) per share:

       

Basic and diluted

  $ (0.12 )

        For the period from September 7, 2010 through December 31, 2010, IMW contributed approximately $17,795 and $319, respectively, to the Company's revenue and net loss.

Liquefied Natural Gas Station Construction

        On December 15, 2010, the Company acquired Northstar, a leading provider of design, engineering, construction and maintenance services for LNG and liquefied to compressed ("LCNG") fueling stations. The purchase price primarily consisted of a closing cash payment in the amount of $7,414. The remaining consideration consists of five annual payments in the amount of $700 each commencing on the first anniversary of the closing date, and up to $4,000 in retention bonuses to certain key employees to be paid in four annual installments commencing on the first anniversary of the closing date.

81



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(2) Acquisitions (Continued)

        The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of December 15, 2010:

Current assets

  $ 4,434  

Property, plant and equipment

    941  

Identifiable intangible assets

    3,350  

Goodwill

    5,228  
       

Total assets acquired

    13,953  

Liabilities assumed

    (3,648 )
       

Total purchase price

  $ 10,305  
       

        Management allocated $2,250 of the purchase price to the identifiable intangible assets related to non-compete agreements, customer relationships, and backlog. The fair value of these identifiable intangibles will be amortized on a straight-line basis over their estimated useful lives ranging from one to ten years. The Company also allocated $1,100 of the purchase price to trademarks, which management believes has an indefinite useful life. In addition, management allocated $5,228 to goodwill as part of the acquisition.

        The results of Northstar's operations have been included in the Company's consolidated financial statements since December 15, 2010. Pro forma financial information has been excluded as Northstar's historical results of operation are immaterial to that of the Company.

Operating and Maintenance Contracts

        In May and June 2009, the Company acquired four compressed natural gas operations and maintenance services contracts for $5,645 in cash. The Company recorded $537 to tangible assets and $5,108 of intangible assets related to customer relationships, which are being amortized over their expected lives of eight years. The results of operations of the acquired contracts are included in the Company's consolidated financial statements from their acquisition dates forward, which are May 2009 for two of the contracts and June 2009 for the remaining two contracts. In addition, as part of the acquisition, the Company became the custodian of certain customer-owned inventories that it is required to replenish when the contracts expire. The customer-owned inventory was valued by the Company's as an asset at $986 with a corresponding balance of $986 recorded as a liability on the acquisition dates of the contracts. During 2010, the Company recorded a charge of $1,531 related to the impairment of an intangible asset originally recorded with this acquisition.

Vehicle Conversion

        On October 1, 2009, the Company purchased all the outstanding shares of BAF Technologies, Inc. ("BAF"), under a stock purchase agreement. The Company paid an aggregate of $8,467 to acquire BAF. Pursuant to the terms of the agreement, the purchase price was reduced by the amount of BAF's outstanding debt, which was repaid in full at closing. Due to the fact that approximately $3,790 of BAF's outstanding debt, including interest, was held by a subsidiary of the Company, the Company paid a net amount of approximately $4,717 in cash to acquire BAF at the closing. BAF shareholders were able to earn additional consideration because BAF had achieved certain gross profit targets in

82



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(2) Acquisitions (Continued)

2010. The additional consideration was determined as a percentage of gross profit based on a sliding scale that increases at certain gross profit levels, subject to achieving a minimum gross profit target and capped by a maximum additional payment amount. For 2010, the shareholders of BAF received $2,159 as additional consideration, and they did not receive any additional consideration for 2011.

        The Company accounted for this acquisition in accordance with authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values, as of that date of acquisition. The following table summarizes the allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed:

Current assets

  $ 4,820  

Property, plant and equipment

    158  

Identifiable intangible assets

    10,660  

Goodwill

    774  
       

Total assets acquired

    16,412  

Current liabilities assumed

    (4,845 )
       

Total purchase price

  $ 11,567  
       

        The Company allocated approximately $10,660 of the purchase price to the identifiable intangible assets related to customer relationships, engine certifications and trademarks that were acquired with the acquisition. The fair value of the identifiable intangible assets will be amortized on a straight-line basis over their estimated useful lives of 1.5 to 8 years. In addition, the Company allocated $774 to goodwill as part of the acquisition and recorded a contingent liability of $3,100 related to the possible consideration owed to BAF shareholders if BAF achieves certain gross profit targets in 2010 and 2011. Under the accounting guidance the Company must follow for this acquisition, the Company is required to adjust the value of the contingent consideration for this acquisition in the statement of operations as the value of the obligation changes each reporting period. At December 31, 2011, the liability for this obligation was $0.

        The results of BAF's operations have been included in the Company's consolidated financial statements since October 1, 2009.

(3) Restricted Cash

        At December 31, 2010, the Company's restricted cash balance consisted of cash held in a payment reserve account in connection with the Company's PCB Credit Agreement that was retired on August 14, 2011. At December 31, 2011 the Company's restricted cash consisted of approximately $1,200 supporting outstanding letters of credit and amounts related to certain outstanding debt instruments as described in note 9.

(4) Investments

        Available-for-sale investments are carried at fair value, inclusive of unrealized gains and losses. Net unrealized gains and losses are included in other comprehensive income (loss) net of applicable income

83



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(4) Investments (Continued)

taxes. Gains or losses on sales of available-for-sale investments are recognized on the specific identification basis.

        Available-for-sale securities as of December 31, 2011 are summarized as follows:

 
  Amortized
Cost
  Gross
Unrealized
Loss
  Market
Value
 

Municipal bonds & notes

  $ 19,703   $ (114 ) $ 19,589  

Zero coupon bonds

    712         712  

Corporate bonds

    3,040     (12 )   3,028  
               

Total available-for-sale securities

    23,455     (126 )   23,329  

Certificate of deposits

    10,000         10,000  
               

Total short-term investments

  $ 33,455   $ (126 ) $ 33,329  
               

        The Company had no available-for-sale securities as of December 31, 2010.

(5) Other Receivables

        Other receivables at December 31, 2010 and 2011 consisted of the following:

 
  2010   2011  

Loans to customers to finance vehicle purchases

  $ 1,013   $ 1,789  

Capital lease receivables

    273     310  

Accrued customer billings

    1,976     5,860  

Advances to vehicle manufacturers

    3,603      

Fuel tax credits

    17,577     5,912  

Other

    2,838     5,730  
           

  $ 27,280   $ 19,601  
           

(6) Land, Property and Equipment

        Land, property and equipment at December 31, 2010 and 2011 are summarized as follows:

 
  2010   2011  

Land

  $ 1,198   $ 1,198  

LNG liquefaction plants

    92,856     93,109  

RNG plants

    2,867     21,005  

Station equipment

    91,492     118,613  

LNG trailers

    12,020     13,532  

Other equipment

    21,611     26,508  

Construction in progress

    53,386     86,127  
           

    275,430     360,092  

Less accumulated depreciation

    (63,787 )   (82,758 )
           

  $ 211,643   $ 277,334  
           

84



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(7) Investment in Other Entities

        Through December 31, 2011, the Company has invested approximately $13,106 in The Vehicle Production Group LLC ("VPG"), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPG's operations.

        On February 25, 2011 (the "Closing Date"), the Company paid $1,200 for a 19.9% interest in ServoTech Engineering, Inc. ("ServoTech"), a company that provides design and engineering services for natural gas fueling systems among other services. The Company also has an option to purchase the remaining 81.1% of ServoTech for $2,800 over the 15 month period following the Closing Date. The Company accounts for its interest using the equity method of accounting as the Company has the ability to exercise significant influence over ServoTech's operations.

(8) Accrued Liabilities

        Accrued liabilities at December 31, 2010 and 2011 consisted of the following:

 
  2010   2011  

Salaries and wages

  $ 2,218   $ 5,088  

Accrued gas and equipment purchases

    6,995     4,773  

Derivative liability

    3,060     2,259  

Contingent consideration obligations

    3,493     378  

Accrued property and other taxes

    3,999     3,043  

Accrued professional fees

    670     875  

Accrued employee benefits

    1,659     1,431  

Accrued warranty liability

    2,338     3,130  

Other

    3,705     7,278  
           

  $ 28,137   $ 28,255  
           

(9) Long-term Debt

        In conjunction with the Company's acquisition of its 70% interest in Dallas Clean Energy, LLC ("DCE"), on August 15, 2008, the Company entered into a credit agreement ("Credit Agreement") with PlainsCapital Bank ("PCB"). The Company borrowed $18,000 (the "Facility A Loan") to finance the acquisition of its membership interests in DCE. The Company also obtained a $12,000 line of credit from PCB to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PCB loans (the "Facility B Loan").

        On October 7, 2009, the Facility A Loan was repaid in full and converted into a $20,000 line of credit (the "A Line of Credit") pursuant to an amendment to the Credit Agreement. On August 13, 2010, the Credit Agreement was amended to extend the maturity date of the A Line of Credit to August 14, 2011 and add an unused facility fee. The amendment also provided for a 1-year option to extend the maturity date to August 14, 2012, subject to the Company not being in default on the A Line of Credit. The unused facility fees are to be paid quarterly, in an amount equal to one-tenth of one percent (0.10%) of the unused portion. The Company elected not to renew the A Line of Credit

85



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

on August 14, 2011 and the Line of Credit expired on that date. The principal amount of the Facility B Loan became due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of the aggregate principal amount of the Facility B Loan then outstanding or $2,800. Pursuant to an amendment to the Facility B loan between the Company and PCB dated November 1, 2010, PCB agreed to forgo the scheduled payment due from the Company on August 2010 in the amount of $2,059 until January 31, 2011, which payment was made on such date. On March 31, 2011, the Company paid in full the remaining principal and interest that was due under the Facility B Loan.

        In conjunction with the DCE acquisition mentioned above, the Company also entered into a Loan Agreement with DCE (the "DCE Loan") to provide secured financing of up to $14,000 to DCE for future capital expenditures or other uses as agreed to by the Company, in its sole discretion. On March 31, 2011, the entire amount of unpaid principal and interest due under the DCE Loan was paid to the Company. The interest income related to the DCE Loan has been eliminated in the accompanying consolidated statements of operations.

Revenue Bonds

        On March 25, 2011, the Company's 70% owned subsidiary, Dallas Clean Energy McCommas Bluff, LLC, a Delaware limited liability company ("DCEMB"), arranged for a $40,200 tax-exempt bond issuance (the "Revenue Bonds"). The Revenue Bonds will be repaid from the revenue generated by DCEMB from the sale of RNG. The Revenue Bonds are secured by the revenue and assets of DCEMB and are non-recourse to DCEMB's direct and indirect parent companies, including the Company. The bond repayments are amortized through December 2024 and the average coupon interest rate on the bonds is 6.60%. The bond issuance closed March 31, 2011.

        The bond proceeds will primarily be used to finance further improvements and expansion of the landfill gas processing facility owned by DCEMB at the McCommas Bluff landfill outside of Dallas, Texas. A portion of the proceeds were used to retire the DCE Loan discussed above. The Company, in turn, used the proceeds from the payoff of the DCE Loan to repay approximately $8,000 owed by the Company to PCB under the Facility B Loan on March 31, 2011.

        Pursuant to the Loan Agreement, dated as of January 1, 2011 (the "Loan Agreement"), between DCEMB and the Mission Economic Development Corporation (the "Issuer"), DCEMB has covenanted with the Issuer to make loan repayments equal to the principal and interest coming due on the Revenue Bonds. DCEMB executed a promissory note, dated March 31, 2011 (the "Note"), as evidence of its obligations under the Loan Agreement. Pursuant to the Trust Indenture, dated as of January 1, 2011 (the "Indenture"), the Issuer has pledged and assigned to the Trustee all of the Issuer's right, title and interest in and to the Loan Agreement (with certain specified exceptions) and the Note.

        The obligations of DCEMB under the Loan Agreement are secured by a Leasehold Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing, dated as of January 1, 2011 (the "Deed of Trust"), executed by DCEMB in favor of the deed of trust trustee named therein for the benefit of the Bank of New York Mellon Trust Company, N.A., as Trustee (the "Trustee"). In addition, DCEMB executed a Security Agreement (the "Security Agreement"), as security for its obligations, pursuant to which DCEMB granted to the Trustee a security interest in all right, title and interest of DCEMB to

86



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

the Collateral (as defined in the Security Agreement), which includes, but is not limited to, DCEMB's rights, title and interest in any gas sale agreements, including the gas sale agreement with Shell Energy North America (US), L.P. (the "Shell Gas Sale Agreement"), and the funds and accounts held under the Indenture.

        Pursuant to a Consent and Agreement, by and between Shell Energy, The Bank of New York Mellon Trust Company, N.A., as Depository Bank (the "Depository Bank"), DCEMB and the Trustee, dated as of January 1, 2011 (the "Consent Agreement"), Shell Energy agreed to make all payments due to DCEMB under the Shell Gas Sale Agreement to the Depository Bank. In addition, other revenues generated through the sale of gas produced at the facility will be paid directly to the Depository Bank pursuant to a Depository and Control Agreement, dated as of January 1, 2011 (the "Depository Agreement"), among DCEMB, the Trustee and the Depository Bank.

        All payments received by the Depository Bank will be placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts will be used to service required debt payments, finance further improvements and expansion of the landfill gas processing facility owned by DCEMB, finance the operations and maintenance of DCEMB, finance certain expenses associated with setting up and maintaining the accounts, and other uses as prescribed in the Depository Agreement. The Depository Bank will make payments out of these accounts in accordance with the requirements of the Depository Agreement. At the end of each month after all required account fundings have been fulfilled in accordance with the Depository Agreement, all remaining excess funds will be placed into a Surplus Account. The funds in the Surplus Account will be delivered to DCEMB so long as (i) DCEMB's Debt Service Coverage Ratio (as defined) for the most recent four calendar quarters then ended equals or exceeds 1.25:1, (ii) DCEMB's Debt Service Coverage Ratio (as defined) is reasonably projected to equal or exceed 1.25:1 for the next four calendar quarters, (iii) no events of default have occurred as defined by the Indenture and the Loan Agreement, and (iv) after giving effect to the transfer, DCEMB's Minimum Days Cash on Hand (as defined) shall be, or shall at any time be projected to be, more than the lesser of thirty-five Days Cash on Hand (as defined) or $1,300. Due to these restrictions on this cash, the Company has classified all of this cash as restricted cash on the balance sheet. The Company records the restricted cash that is expected to be received and used within the next 12 months from the Depository Bank for working capital and operating purposes as current in its balance sheet, and presents the remaining balance as non-current in the line item notes receivable and other long term assets. At December 31, 2011, $14,482 was recorded as long term restricted cash and $3,555 was recorded as short term restricted cash in the accompanying consolidated balance sheet.

        Pursuant to a Collateral Assignment and Consent Agreement with Atmos Pipeline—Texas ("Atmos"), DCEMB has collaterally assigned to the Trustee, subject to certain reserved rights and the consent of Atmos, the transportation agreements of the Company with Atmos.

        The Indenture and the Loan Agreement have certain non-financial debt covenants with which DCEMB must comply. As of December 31, 2011, DCEMB was in compliance with all its debt covenants.

87



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

Purchase Notes

        In connection with the closing of the Company's acquisition of IMW, the Company agreed to make future payments consisting of four annual payments in the amount of $12,500. Each payment under the IMW Notes will consist of $5,000 in cash and $7,500 in cash and/or shares of the Company's common stock (the exact combination of cash and/or stock to be determined at the Company's option). In addition, pursuant to a security agreement executed at closing, the IMW Notes are secured by a subordinate security interest in IMW.

        In connection with the closing of the Company's acquisition of Northstar, the Company agreed to make future payments consisting of five annual payments in the amount of $700 each with the first payment due December 15, 2011.

        In connection with the closing of the Company's acquisition of Weaver Electric, Inc. on October 3, 2011, the Company paid $1,000 in cash and agreed to make four additional annual payments in the amount of $250 each with the first payment due October 3, 2012 (the "Weaver Notes").

        The difference between the carrying amount and the face amount of these obligations is being accreted to interest expense over the remaining term of the obligations.

HSBC Lines of Credit

        Also in connection with the closing of the Company's acquisition of IMW, the Company entered into an Assumption Agreement (the "Assumption Agreement") with HSBC Bank Canada ("HSBC") pursuant to which the Company assumed the obligations and liabilities of IMW under the following arrangements with HSBC (collectively, the "IMW Lines of Credit"):

    (i)
    An operating line of credit with a limit of $10,000 in Canadian dollars ("CAD") bearing interest at prime plus 1.25%, to assist in financing the day-to-day working capital needs of IMW.

    (ii)
    A bank guarantee line with a limit of CAD$3,000, which allows IMW to provide guarantees and/or standby letters of credit to overseas suppliers or bid/performance deposits on contracts.

    (iii)
    A forward exchange contract line with a limit of CAD$13,750. The forward exchange contract line allows IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$13,750 (no forward exchange contracts were outstanding at December 31, 2011).

    (iv)
    A MasterCard limit with a maximum amount of CAD$150.

    (v)
    An operating line of credit with a limit of 5,000 Renminbi ("RMB") (CAD$791) bearing interest at the 6 month People's Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.

    (vi)
    A 16,750 Bengali Taka (CAD$197) operating line of credit bearing interest at 14%.

    (vii)
    A 170,000 Columbian Peso (CAD$94) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 12%.

88



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

        The IMW Lines of Credit are secured by a general security agreement providing a first priority security interest in all present and after acquired personal property of IMW, including specific charges on all serial numbered goods, inventory and other assets and assignment of risk insurance (the "Security"). The IMW Lines of Credit contain no fixed repayment terms or mandatory principal payments and are due on demand. Based on the relevant accounting guidance, the Company has classified this debt pursuant to the credit agreement as short-term given that it is due on demand.

        The Assumption Agreement with HSBC also includes certain financial covenants. Among these financial covenants are that IMW shall not permit: 1) its ratio of debt to tangible net worth to be greater than 4.0 to 1.0 until December 31, 2011 and greater than 3.75 to 1.0 from January 1, 2012 through March 31, 2012, and greater than 3.5 to 1.0 from April 1, 2012 through June 30, 2012, and greater than 3.0 to 1.0 on or after July 1, 2012, 2) its tangible net worth at anytime be below CAD$7,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until March 31, 2012 and less than 1.25 to 1.0 on or after April 1, 2012. IMW was in compliance with the financial covenants as of December 31, 2011.

        In addition, the Company and IMW agreed that should the making of any scheduled payment by IMW to the seller of IMW under the IMW Notes result in IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, the Company shall furnish IMW with the funds needed to remain in compliance with the Assumption Agreement, the IMW Lines of Credit and the Security. Further, the Company and IMW agreed that should IMW make any future earn-out payments to the seller of IMW in connection with the acquisition of IMW, and should the making of such earn-out payments result in IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, then the Company shall furnish IMW with the funds needed to make such earn-out payments and remain in compliance with the Assumption Agreement, the IMW Lines of Credit and the Security.

Chesapeake Notes

        On July 11, 2011, the Company entered into a Loan Agreement (the "CHK Agreement") with Chesapeake NG Ventures Corporation ("Chesapeake"), an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from the Company up to $150 million of debt securities for the development, construction and operation of liquefied natural gas stations (the "CHK Financing") pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50 million (each a "CHK Note" and collectively the "CHK Notes"). Chesapeake Energy Corporation guaranteed Chesapeake's commitment to purchase the CHK Notes under the CHK Agreement.

        The first CHK Note was issued on July 11, 2011, and the Company expects to issue the second and third CHK Notes on June 29, 2012 and June 28, 2013, respectively. The CHK Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at Chesapeake's option into shares of the Company's common stock at a conversion price of $15.80 per share (the "CHK Conversion Price"). Subject to certain restrictions, the Company can force conversion of each CHK Note into shares of the Company's common stock if, following the second anniversary of the issuance of a CHK Note, the Company's shares of common stock trade at a 40% premium to the CHK Conversion Price for at least twenty

89



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

trading days in any consecutive thirty trading day period. The entire principal balance of each CHK Note is due and payable seven years following its issuance, and the Company may repay each CHK Note in shares of the Company's common stock or cash. The CHK Agreement restricts the use of the CHK Financing proceeds to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. At December 31, 2011, approximately $40,300 of these funds were included in long term restricted cash as the Company anticipates primarily using the funds to build LNG fueling stations. The CHK Agreement also provides for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the CHK Notes to become, or to be declared, due and payable.

        In connection with the CHK Financing, the Company also entered into a Registration Rights Agreement, dated July 11, 2011, with Chesapeake (the "CHK Registration Rights Agreement") pursuant to which the Company agreed, subject to the terms and conditions of the CHK Registration Rights Agreement, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company's common stock issuable upon conversion of the CHK Notes, and (ii) at the request of Chesapeake, to participate in one or more underwritten offerings of the Company's common stock issuable upon conversion of the CHK Notes. If the Company does not meet certain of its obligations under the CHK Registration Rights Agreement with respect to the registration of the Company's common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the CHK Note represented by the Company's common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met. As of December 31, 2011, the Company met its obligations under the CHK Registration Rights Agreement.

SLG Notes

        On August 24, 2011, the Company entered into Convertible Note Purchase Agreements (each, an "SLG Agreement" and collectively the "SLG Agreements") with each of Springleaf Investments Pte. Ltd., a wholly-owned subsidiary of Temasek Holdings Pte. Ltd., Lionfish Investments Pte. Ltd., an investment vehicle managed by Seatown Holdings International Pte. Ltd., and Greenwich Asset Holding Ltd., a wholly-owned subsidiary of RRJ Capital Master Fund I, L.P. (each, a "Purchaser" and collectively, the "Purchasers"), whereby the Purchasers agreed to purchase from the Company $150 million of 7.5% convertible notes due 2016 (each a "SLG Note" and collectively the "SLG Notes"). The transaction closed and the SLG Notes were issued on August 30, 2011.

        The SLG Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at each Purchaser's option into shares of the Company's common stock at a conversion price of $15.00 per share (the "SLG Conversion Price"). Subject to certain restrictions, the Company can force conversion of each SLG Note into shares of the Company's common stock if, following the second anniversary of the issuance of the SLG Notes, the Company's shares of common stock trade at a 40% premium to the SLG Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each SLG Note is due and payable five years following its issuance, and the Company may repay the principal balance of each SLG Note in shares of the Company's common stock or cash. The SLG Agreements also provide for customary events of default which, if any of them

90



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

occurs, would permit or require the principal of, and accrued interest on, the SLG Notes to become, or to be declared, due and payable.

        In connection with the SLG Agreements, the Company also entered into a Registration Rights Agreement, dated August 30, 2011, with each of the Purchasers (the "SLG Registration Rights Agreements") pursuant to which the Company agreed, subject to the terms and conditions of the SLG Registration Rights Agreements, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company's common stock issuable upon conversion of the SLG Notes, and (ii) at the request of the Purchasers, participate in one or more underwritten offerings of the Company's common stock issuable upon conversion of the SLG Notes. If the Company does not meet certain of its obligations under the SLG Registration Rights Agreements with respect to the registration of the Company's common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the SLG Note represented by the Company's common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met, not to exceed 4% of the aggregate principal amount of the SLG Notes per annum. As of December 31, 2011, the Company met its obligations under the SLG Registration Rights Agreement.

        Long-term debt at December 31, 2010 and 2011 consisted of the following:

 
  December 31,
2010
  December 31,
2011
 

Facility B loan

  $ 9,909   $  

IMW future payment notes

    44,568     34,400  

Northstar future payments

    2,900     2,388  

DCE notes

    435     585  

DCEMB Revenue Bonds (non recourse to the Company)

        39,400  

Chesapeake Notes

        50,000  

SLG Notes

        150,000  

Weaver Notes

        872  

IMW assumed debt

    4,626     6,657  

Capital lease obligations

    1,978     5,120  
           

Total debt and capital lease obligations

    64,416     289,422  

Less amounts due within one year and short-term borrowings

    (22,712 )   (22,925 )
           

Total long-term debt and capital lease obligations

  $ 41,704   $ 266,497  
           

91



Clean Energy Fuels Corp. and Subsidiaries

Notes to Consolidated Financial Statements (Continued)

(In thousands, except share and per share data)

(9) Long-term Debt (Continued)

        The following is a summary of aggregate maturities of long-term debt for each of the years ending December 31:

 
  2012   2013   2014   2015   2016   Thereafter  

IMW future payment notes

  $ 12,336   $ 11,496   $ 10,598   $   $   $  

Northstar future payments

    663     621     576     528          

DCE notes

    585                      

DCEMB Revenue Bonds

    700     2,200     2,415     2,540     2,675     28,870  

Chesapeake Notes

                        50,000  

SLG Notes

                    150,000      

Weaver Notes

    237     225     212     198          

IMW assumed debt

    6,627                      

Capital lease obligations

    1,777     1,890     1,093     360          
                           

Total

  $ 22,925   $ 16,432   $ 14,894   $ 3,626   $ 152,675   $ 78,870