Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-K, Received: 02/27/2014 16:15:05)

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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, 2013

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.)

4675 MacArthur Court, Suite 800, Newport Beach, CA 92660
(Address of principal executive offices, including zip code)

(949) 437-1000
(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  ý   Accelerated filer  o   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, 2013, the last business day of the registrant's second fiscal quarter, was approximately $852,439,909 (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 February 19, 2014, the number of outstanding shares of the registrant's common stock was 89,856,716.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's proxy statement for the 2014 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 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). 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 that we make in this annual report on Form 10-K 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" section of this annual report on Form 10-K. As a result of these and other potential risk factors, the forward-looking statements in this annual report on Form 10-K may not

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prove to be accurate. All forward-looking statements in this annual report on Form 10-K are made only as of the date of this document and, 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.

        Unless the context indicates otherwise, all references to "Clean Energy," the "Company," "we," "us," or "our" in this annual report on Form 10-K refer to Clean Energy Fuels Corp., together with its majority and wholly owned subsidiaries.

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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 ("GGEs") of compressed natural gas ("CNG") and liquefied natural gas ("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 other equipment used in CNG stations and LNG stations, provide operation and maintenance services ("O&M") to customers, offer solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, produce renewable natural gas ("RNG"), which can be used as vehicle fuel or be sold for renewable power generation, and sell tradable credits we generate by selling natural gas and RNG as a vehicle fuel, including credits we generate under the California Low Carbon Fuel Standard ("LCFS Credits") and Renewable Identification Numbers ("RIN Credits" or "RINs") we generate under the federal Renewable Fuel Standard ("RFS") Phase 2. In addition, we help our customers acquire and finance natural gas vehicles and obtain local, state and federal grants and incentives.

        We previously owned BAF Technologies, Inc. and its wholly owned subsidiary, ServoTech Engineering, Inc. (BAF Technologies, Inc. and ServoTech Engineering Inc. are collectively referred to as "BAF"). BAF converted light and medium duty vehicles to run on natural gas and provided design and engineering services for natural gas engine systems. On June 28, 2013, we sold BAF to Westport Innovations (U.S.) Holdings Inc. ("Westport Holdings"), a wholly owned subsidiary of Westport Innovations Inc. ("Westport Innovations" and together with its affiliates, "Westport")

        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 ("EIA"), the amount of natural gas consumed in the U.S. for vehicle use more than doubled between 2000 and 2013. We believe we are positioned to capture a substantial share of the anticipated future 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 forms of CNG, LNG and RNG. 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 ("LCNG"), at locations where no gas pipeline service exists or gas pipeline pressures are inadequate. 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 88 tanker trailers. At the stations, LNG is stored in above ground tanks until dispensed into vehicles in liquid form. RNG is produced from waste streams such as landfills, animal waste digesters and waste water treatment plants. RNG production plants are connected to natural gas pipelines, which allow RNG to be transported to vehicle fueling stations, where it can be compressed and dispensed as CNG, and to LNG liquefaction facilities, where it is converted to LNG.

        CNG is used in passenger vehicles, light to medium-duty vehicles, refuse trucks, transit buses and heavy-duty vehicles, and LNG is used in trucks and other medium to heavy-duty vehicles. Some of our heavy-duty customers have decided to fuel their trucks with LNG because they can carry greater load volumes, their routes are longer and they have found that they can fill their trucks more quickly with LNG. Other heavy-duty customers have chosen CNG because it is generally less expensive than LNG

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(LNG must be liquefied and transported, and the federal government imposes higher fuel taxes on LNG) and more accessible.

        We serve fleet vehicle operators in a variety of markets, including heavy-duty trucks, airports, taxis, refuse hauling, fleet services, ready mix and public transit. We believe these fleet markets will continue to present a high growth opportunity for natural gas vehicle fuels for the foreseeable future. At December 31, 2013, we served approximately 779 fleet customers operating approximately 35,240 natural gas vehicles, and we owned, operated or supplied 471 natural gas fueling stations in 39 states, and in British Columbia and Ontario within Canada.

2013 Business Developments

        We experienced the following key business developments in 2013:

    We delivered 214.4 million GGEs of CNG, LNG and RNG.

    Significant progress was made towards eliminating the historic barriers that have hampered adoption of natural gas vehicles by the U.S. heavy-duty truck industry. We believe the major factors that contributed to this progress include (i) commercial introduction of the 400HP Cummins Westport ISX 12G natural gas engine, (ii) our initiative with the Transportation Finance business of General Electric Capital Corporation ("GE") that makes available to truck operators loans and leases, including fair market value leases, to acquire natural gas heavy-duty trucks at a cost consistent with the cost of a diesel truck, and (iii) our continued build-out of "America's Natural Gas Highway," a nationwide network of natural gas truck fueling stations constructed on the interstate highway system and near distribution centers, intermodal transportation facilities and manufacturing locations, which is designed to enable natural gas fueled freight trucking coast to coast and border to border along key transportation corridors (we also refer to America's Natural Gas Highway as "ANGH"). Our ANGH stations have primarily been initially built to provide LNG. However, we believe operators will adopt heavy-duty trucks that run on both LNG and CNG, so to meet the needs of our customers, we have designed the ANGH stations to be capable of dispensing both fuels.

    We entered a partnership with Mansfield Energy Corp. ("Mansfield"), the largest behind-the-gate (private) fuel provider in the U.S., pursuant to which (i) Mansfield will offer our natural gas fueling station construction and operational services to current and potential customers, and (ii) we acquired Mansfield's CNG construction and service and operations business, operated by Mansfield Gas Equipment Systems Corporation ("MGES"), to complement and enhance our CNG business.

    We entered a consortium, named Eagle LNG Partners, with Ferus Natural Gas Fuels ("Ferus"), GE Ventures and GE Energy Financial Services, that plans to develop regional LNG projects to meet the growing demand for LNG in industries such as heavy-duty trucking, rail, mining, marine, and oil and gas services. Eagle LNG Partners is currently considering projects in Florida, Colorado, North Dakota, Ohio and Texas. These projects may also build upon existing Clean Energy and Ferus plants and operations, as well as the planned GE Plants (as defined and described below) in the Northeast and Midwest.

    We completed the sale of BAF to Westport Holdings for $27.2 million payable in Westport Innovations' common stock. We also entered a joint marketing and sales program with Westport, pursuant to which Westport agreed to pay us $5.0 million in cash and we agreed to work with Westport to encourage sales of natural gas vehicles and conversions and generally increase the natural gas vehicle market.

    We became the first company to commercially distribute a RNG vehicle fuel, which we call "Redeem." Redeem is up to 88% cleaner than diesel and is 100% renewable.

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The Market for Vehicle Fuels

        According to the EIA's Annual Energy Outlook 2014 Early Release (December 16, 2013), the U.S. consumed an estimated 168 billion gasoline gallon equivalents of gasoline and diesel in 2013. 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 approximately 3% of consumption, according to the EIA. The Annual Energy Outlook 2014 Early Release projects that natural gas use in the heavy-duty transportation sector will grow to 1.7 trillion cubic feet, or over 12 billion diesel equivalent gallons, by 2040.

        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. In contrast, natural gas prices have touched historic lows during such period. 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 support natural gas fueling options. In addition, the desire for fuel diversity among fleet operators further enhances the market opportunity for natural gas fuels. Internationally, natural gas as an alternative fuel has been widely used for many years. According to Natural Gas Vehicles of America ("NGV America"), there are about 135,000 natural gas vehicles in the United States, compared to more than 15.2 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 plentiful, domestic, cheaper and cleaner than gasoline or diesel. According to the EIA, in 2012, there were approximately 240 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. NGV America estimates that there are approximately 1,300 natural gas fueling stations in the United States.

Benefits of Natural Gas Fuel

        Domestic and plentiful supply.     In recent years, technological advances in natural gas drilling and production, including the widespread deployment of horizontal drilling techniques, the use of hydraulic fracturing (also known as "fracking") and multi-pad drilling (where wells are drilled at close proximity to each other on the surface before branching out underground), have unlocked vast natural gas reserves. As a result, according to the EIA, global proved natural gas reserves grew by 92% between 1988 and 2011, to over 180 trillion cubic meters. Further, the natural gas reserve potential has become particularly favorable in the U.S. Both the Potential Gas Committee and Navigant Consulting have recently projected that the U.S. has recoverable natural gas resources of over 2,300 trillion cubic feet, which equates to more than 100 years of supply at current consumption levels. The EIA also projects that U.S. natural gas production will grow from 22.5 million cubic feet in 2011 to 37.5 million cubic feet by 2040, an increase of approximately 67%. We believe estimates of available natural gas reserves in the U.S. could continue to grow and we believe continued advances in drilling and production techniques could increase the accessibility of these reserves at reasonable costs, provided that there have been recent efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing which, if implemented, could make it more expensive or unprofitable to produce natural gas through hydraulic fracturing and could lead to reduced natural gas supply and increased natural gas prices.

        Less Expensive.     Due to the abundance of natural gas, the cost of natural gas in the U.S. is significantly less than the cost of crude oil, on an energy equivalent basis. For example, at the end of

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2013, oil was approximately five times more expensive than natural gas on an energy equivalent basis. This means that a GGE of natural gas is significantly less expensive than a gallon of diesel and gasoline. Based on projections from the EIA, we believe that natural gas will remain substantially cheaper than gasoline and diesel for the foreseeable future. In addition, because the price of the natural gas commodity makes up a smaller portion of the cost of a GGE of CNG or LNG, relative to the diesel or gasoline commodity portion of the cost of a gallon of diesel or gasoline, the price of a GGE of CNG or LNG is less sensitive to increases in the underlying commodity cost.

        The low price of natural gas allows us to sell CNG and LNG at a price that is often a $1.00 or $1.50 less per gallon than diesel or gasoline, depending upon local market conditions. For example the average retail CNG price we charged in California, our most significant market, was $1.04 less per gasoline gallon equivalent than the average California regular unleaded gasoline price of $3.89 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 Department of Energy 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 2013 averaged $4.13 per diesel gallon, compared to our LNG diesel gallon equivalent price of $2.93.

        The chart below shows our average pump prices in California for CNG and LNG 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,  
 
  2011   2012   2013  

California retail gasoline(2)

  $ 3.82   $ 4.03   $ 3.89  

California retail diesel(2)(3)

  $ 3.67   $ 3.80   $ 3.71  

California CNG—Clean Energy

  $ 2.70   $ 2.85   $ 2.85  

CNG discount to gasoline

  $ (1.12 ) $ (1.18 ) $ (1.04 )

CNG discount to diesel

  $ (0.97 ) $ (0.96 ) $ (0.86 )

California LNG—Clean Energy

  $ 2.33   $ 2.62   $ 2.63  

LNG discount to diesel

  $ (1.34 ) $ (1.19 ) $ (1.08 )

(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 BTUs and 139,000 BTUs per gallon of gasoline and diesel, respectively.

        The following chart shows the estimated annual fuel cost savings that may be achieved by a natural gas vehicle.

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Representative Annual per Vehicle Fuel Cost Savings
by Fleet Market for California
Based on Average Fuel Prices During 2013

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   $ 2.85 (4) vs.   $ 3.89 (4) $ 5,200  

Shuttle van

  CNG or Gasoline     7,500   $ 2.85 (4) vs.   $ 3.89 (4) $ 7,800  

Municipal transit bus (CNG)

  CNG or Diesel     16,680   $ 1.53 (5) vs.   $ 3.06 (6) $ 25,520  

Refuse truck (CNG)

  CNG or Diesel     11,120   $ 1.47 (5)(7) vs.   $ 3.71 (6) $ 24,909  

Municipal transit Bus (LNG)

  LNG or Diesel     16,680   $ 1.46 (5) vs.   $ 3.06 (6) $ 26,688  

Refuse truck (LNG)

  LNG or Diesel     11,120   $ 1.81 (5)(7) vs.   $ 3.71 (6) $ 21,128  

Heavy-duty truck (LNG)

  LNG or Diesel     22,240   $ 2.63 (8) vs.   $ 3.71 (6) $ 24,019  

(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. Diesel prices were also converted to the energy equivalent of 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 2013. Gasoline retail pricing is based on California average retail gasoline prices during 2013 as reported by EIA.

(5)
CNG and LNG prices based on average prices paid by representative Clean Energy California fleet customers in 2013.

(6)
Diesel price based on EIA reported average diesel price in California in 2013.

(7)
Excludes California imposed fuel 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)
LNG retail price is based on average Clean Energy retail station pricing at the Port of Long Beach station in 2013.

        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 28% of total U.S. greenhouse-gas emissions, and over 13% of global greenhouse gas emissions. Under the LCFS, the California Air Resources Board ("CARB") recognizes that the use of natural gas as a vehicle fuel can provide 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.

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        Increased RNG use could also help reduce greenhouse gas emissions. CARB's full lifecycle analysis of RNG has determined that use of RNG generated from landfills as a vehicle fuel can reduce greenhouse gas emissions by up to 88% as compared to gasoline. Further, the RFS creates tradable RIN Credits 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 RFS. RNG can also be used to generate renewable power in gas-fired power generation units.

        We sell RNG we produce for use as a vehicle fuel through our extensive natural gas fueling infrastructure. In addition, we sell the RINs and LCFS Credits that we generate through these transactions. We plan to escalate our activities in this area by using our fueling infrastructure to sell increasing amounts of RNG, as well as by entering into additional transactions to sell the LCFS Credits and RINs we generate. We have also agreed to market and sell RNG produced by third parties and retain a portion of the RIN and LCFS Credit values generated from those transactions.

        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. Additionally, CNG and LNG are stored in above ground tanks and therefore cannot contaminate soil or groundwater.

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 sealed 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 higher cost of the storage systems that hold the CNG or LNG.

        Any car, truck, bus or other vehicle is capable of being manufactured or modified to run on natural gas. Outside the U.S., numerous makes and models of vehicles are factory produced to run on natural gas as bi-fuel vehicles (bi-fuel vehicles can run on either natural gas or gasoline and have tanks for each fuel), or in some cases, as dedicated natural gas vehicles (dedicated vehicles use only natural gas fuel). 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 by most, if not all, original equipment manufacturers ("OEMs"). 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.

        Vehicle OEMs also offer natural gas school buses, shuttles, transit buses and street sweepers.

        Prior to 2013, there were two natural gas engines available for the U.S. heavy-duty truck market:

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

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      trucking to date. Most major truck OEMs, including Freightliner, AutoCar, Navistar, International, Kenworth, Peterbilt, Mack and Volvo, offer natural gas trucks using this engine.

    15 liter high pressure direct injection engine with 400-450 horsepower and 1,800 lb-ft torque produced by Westport Innovations, which requires the use of a diesel particulate filter and selective catalytic reduction with urea injection to reduce emissions in compliance with EPA 2010 standards. This engine found 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. Westport Innovations, however, announced in 2013 that it plans to cease production of this engine.

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

        Based on our experience, the two natural gas engines available prior to 2013 were not well-suited to serve the U.S. heavy-duty truck market. Of these two engines, the 8.9 liter engine delivers 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 (during 2013, Westport announced that it would cease production of the 15 liter engine). We believe the preferred engine for this market is a 12 to 13 liter engine that delivers 400 horsepower or more and 1,400 to 1,500 lb-ft torque, and the historical 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.

        In 2013, Cummins Westport made its ISX 12G engine commercially available. This 12 liter engine has 400HP and delivers 1,450 lb-ft torque, and can run on either CNG or LNG. We see this engine as a "game changer" that meets the needs of the heavy-duty truck market, as well as other heavy-duty vocational trucking applications, and we believe the engine has been well received by truck operators. Major truck OEMs, including Freightliner, International, Navistar, Kenworth, Peterbilt, Mack, and Volvo, now offer natural gas trucks using this engine. In addition, Volvo is developing a 13 liter engine that may become available in 2014.

        We anticipate the commercial roll-out of these and other natural gas engines that are well-suited for the U.S. heavy-duty truck 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 truck industry. We estimate that there are approximately three million heavy-duty trucks on the road in the U.S., and that such trucks collectively consume approximately 25 billion gallons of fuel each year. As a result, we believe this market has the potential to become our largest.

        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 natural gas truck fueling stations on the interstate highway system and near distribution centers, intermodal transportation facilities and manufacturing locations. Our objective in building America's Natural Gas Highway is to enable natural gas fueled freight trucking coast to coast and border to border along key transportation corridors. 85 ANGH stations have been completed at the end of 2013, and of this number, 22 were open and selling natural gas fuel, and the remainder are planned to open as natural gas trucks are deployed in the geographic areas where the stations are located. We also had an additional 28 ANGH stations under development at the end of 2013. Many ANGH stations are located at Pilot Flying J Travel Centers, one of the largest truck fueling operators in the U.S., with approximately 500 truck travel centers in 43 states. Our ANGH stations have primarily been initially built to provide LNG. However, we believe operators will adopt heavy-duty trucks that run on both LNG and CNG, so to meet the needs of our customers, we have designed the ANGH stations to be capable of dispensing both fuels. We will need to invest additional capital in our ANGH stations to the

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extent more CNG than LNG heavy-duty trucks are deployed and we decide to add CNG or LCNG fueling equipment to our stations.

        To help accelerate the conversion of heavy-duty truck fleets to natural gas, in 2013, we entered a strategic alliance with GE's Transportation Finance business. Fleet operators are eligible for loans and leases, including fair market value leases, from GE to acquire natural gas trucks from OEMs. In exchange for committing to purchase natural gas fuel from our stations, we then help offset the monthly cost of the vehicles to make it consistent with the cost of a diesel truck. Our goal is to work with fleet operators to achieve a one to two year payback on the incremental cost of natural gas heavy-duty trucks, and our alliance with GE is a tool in achieving this goal.

Products and Services

        We sell CNG, LNG and RNG and provide O&M, services to our customers. For the year ended December 31, 2013, CNG and RNG (together) represented 72% and LNG represented 28% of our natural gas sales (on a gasoline gallon equivalent basis). We design and construct CNG, LNG and LCNG fueling stations, as well as offer solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, and sell or lease some of those stations to our customers. We also sell RNG produced by our subsidiary Clean Energy Renewable Fuels, LLC ("CERF"), and sell non-lubricated 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. ("IMW"). In addition, we help our customers acquire and finance natural gas vehicles. We also generate and sell RIN Credits and LCFS Credits. We also previously provided natural gas vehicle conversions and design and engineering services for natural gas engine systems through our BAF subsidiary, which we sold to Westport on June 28, 2013 (see note 2 to our consolidated financial statements).

        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 principally determined 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. 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 public access stations based on prevailing market conditions.

        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 the Boron Plant, respectively. The Pickens Plant has the capacity to produce 35 million gallons of LNG per year and includes tanker trailer loading facilities and a 1.0 million gallon storage tank that can hold up to 840,000 usable gallons. The Boron Plant is capable of producing 60 million gallons of LNG per year and 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 expect that we will need to secure additional sources of LNG for America's Natural Gas Highway. Therefore, we plan to expand the Boron Plant to increase its production capacity to 90 million gallons of LNG per year. Further, we plan to use financing, which we expect to be provided by GE and us, to purchase two LNG plants (the "GE Plants") from GE Oil & Gas, Inc., an affiliate of GE that will also be responsible for all engineering, procurement and construction relating to the GE Plants. We expect that the GE Plants, when complete, will each be initially capable of producing up to 90 million gallons of LNG per year, and they will each be designed to expand their production

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capability to up to 365 million gallons of LNG per year. We also believe additional LNG production plants will need to be built by our company or third parties. To that end, we have entered the Eagle LNG Partners consortium, pursuant to which we anticipate that we and other consortium members will develop additional regional LNG projects to meet the anticipated demand for LNG.

        We sell LNG on a bulk basis to fleet customers, who often own and operate their fueling stations, and we also sell LNG to fleet and other customers at our public-access LNG stations. During 2013, we procured 33% of our LNG from third-party producers, and we produced the remainder of the LNG at the Pickens and Boron Plants. We expect to enter into additional purchase contracts with third-party LNG producers in the future. 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 88 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 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. For LNG customers who own and operate their fueling stations, we sell LNG through supply contracts that are priced on an 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. 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 public-access stations based on prevailing market conditions. LNG generally costs more than CNG, as LNG must be liquefied and transported, and the federal government imposes higher fuel taxes on LNG.

        Operation and Maintenance.     We perform O&M services for CNG stations that are either owned by us or our customers. In addition, we perform O&M services for LNG stations we own and 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, 2013, we had an operations team of 164 employees, including 127 full-time employees dedicated to performing preventative maintenance and available to respond to service requests in 39 states and in Canada. In addition, we have 90 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, 2013, we owned, operated or supplied 471 fueling stations for our customers in 39 states and Canada. We owned 229 of the stations, including 12 co-owned stations, and our customers owned the other 242 stations.

        Station Construction and Engineering.     Since 2008, we have built 305 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 (we often use compressors manufactured by IMW), dispensers and storage tanks (which hold a relatively small buffer

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amount of CNG). Equipment for a LNG station typically consists of storage tanks that hold 5,000 to 25,000 gallons of LNG, plus related dispensing equipment. We also offer solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, which can include the construction and sale of facility modifications.

        A number of our fueling stations have separate public access areas for retail customers, which have the look, feel and dispensing 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 clothing (gloves and safety glasses) because of the extreme low temperatures of LNG.

        To enhance our station construction capabilities, in 2010, we acquired Wyoming Northstar Incorporated, ("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.

        In addition, in May 2013, we purchased MGES for approximately $20.6 million. MGES is primarily engaged in the business of providing CNG station design and construction and CNG equipment repair and maintenance services.

        RNG.     We own a 70% interest in a RNG production facility at the McCommas Bluff landfill located in Dallas, Texas. We sell RNG produced at the facility to Shell Energy North America under a gas sale agreement and, depending upon RNG production volumes, we have the ability to sell RNG produced by the facility as a vehicle fuel. We own a second RNG production facility located at a Republic Services landfill in Canton, Michigan. This facility was completed in December 2012, and we have entered into a ten-year fixed-price sale contract for the majority of the RNG that we expect the facility to produce. We are building a third RNG facility at a Republic Services landfill in North Shelby, Tennessee, and we expect the facility to be operational during the first or second quarter of 2014. We are seeking to expand our RNG business by pursuing additional RNG production projects. We sell some of the RNG we currently produce, and expect to sell a significant amount of the RNG we produce at the facilities we are building and plan to build, through our natural gas fueling infrastructure for use as a vehicle fuel. In addition, we purchase RNG from third party producers, and sell that RNG for vehicle use through our fueling infrastructure. The RNG we distribute for vehicle use is distributed under the name "Redeem."

        Vehicle Conversions.     Prior to its sale on June 28, 2013, we owned BAF, a provider of natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support, and research and development for natural gas vehicles. BAF's vehicle conversions included taxis, vans, pick-up trucks and shuttle buses. BAF owned ServoTech Engineering, Inc. ("ServoTech"), which provided, among other services, design and engineering services for natural gas engine systems.

        Natural Gas Fueling Compressors.     Our IMW subsidiary manufactures and services non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. 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. We believe IMW gives us several strategic advantages. First, it enables us to 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 and our compressor requirements have increased. We believe our compressor needs will continue to grow in the future. Second, IMW enables us 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 themselves, our compressor manufacturing business allows us to

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offer them a high quality and low cost "equipment only" solution. Third, IMW allows us 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. 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 natural gas vehicles to certain of our customers 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. In addition, we have partnered with GE's Transportation Finance business to make loans and leases, including fair market value leases, available to truck operators to acquire natural gas heavy-duty trucks from OEMs.

        VETC.     From October 1, 2006 to December 31, 2013, 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 claimed the credit. The program providing for the VETC expired on December 31, 2013.

        Sales of RINs and LCFS Credits.     We generate LCFS Credits when we sell RNG and conventional natural gas for use as a vehicle fuel in California, and we generate RIN Credits when we sell RNG for use as a vehicle fuel. We can sell these RIN Credits and LCFS Credits to third parties who need the RIN Credits and the LCFS Credits to comply with federal and state requirements. In 2013, we realized $8.6 million in revenue through the sale of LCFS and RIN Credits. We anticipate that we will generate and sell increasing numbers of RIN Credits and LCFS Credits as we grow our business and sell increasing amounts of CNG, LNG and RNG for use as a vehicle fuel. The market for RIN Credits and LCFS Credits is volatile, and the prices for such credits may be subject to significant fluctuations. Further, the value of RIN Credits and LCFS Credits will be adversely affected by any changes to the state and federal programs under which such credits are generated and sold.

Sales and Marketing

        We have sales representatives in all of our major operating territories, including Alabama, Arizona, California, Colorado, Florida, Georgia, Illinois, Indiana, Kentucky, Massachusetts, Minnesota, Missouri, New Hampshire, New Jersey, New Mexico, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Texas, Virginia, and Washington in the U.S., in Toronto and Vancouver in Canada and in Bangladesh, Colombia, Peru and China. At December 31, 2013, we had 117 employees in sales and marketing, including 19 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 provide education on the value of natural gas as a vehicle fuel and to keep abreast of proposed and newly adopted regulations that affect our industry.

Key Markets and Customers

        At December 31, 2013, we had 779 fleet customers operating approximately 35,240 vehicles, including approximately 7,300 transit buses, 2,230 taxis, 3,020 shuttles, 6,720 refuse trucks and 1,680 heavy-duty trucks. We target customers in a variety of markets, such as trucking, airports, taxis, refuse, public transit and government fleets. During 2011, 2012 and 2013, approximately 21%, 33% and 19% of

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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 to move their freight. Some of the national fleets piloting heavy-duty tractors with natural gas are among the largest fleets in the world including Con-way, FedEx, Frito-Lay, NFI/Lowes, Raven, Ruan, Ryder, Schneider, Swift, UPS, Werner and YRC Worldwide. Interest by shippers increased in 2013, as several Fortune 100 companies engaged in discussions with their carrier base about the use, or expansion of use, of natural gas trucks in their fleets. We believe this increased interest is due in part to the commercial introduction of the Cummins Westport ISX 12G engine, and we anticipate that the continued commercial roll-out of heavy-duty natural gas engines that are well-suited for the U.S. truck market will result in increased adoption of natural gas fueled trucks by the U.S. trucking industry.

    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 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, Cleveland Hopkins International, Dallas-Ft. Worth International, Denver International, Dulles International Airport, George Bush International (Houston), Hartford, Las Vegas, Love Field (Dallas), Logan International Airport (Boston), Long Beach, LaGuardia (New York), Los Angeles International, New Orleans, Newark International, Oakland International, Ontario, Palm Springs, Philadelphia International, Phoenix Sky Harbor International, Ronald Reagan Washington National, San Francisco International, Santa Ana/John Wayne, San Diego International, SeaTac International (Seattle), Tampa International, 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. We believe that vehicles serving airports in the U.S., including shuttles and taxis, consume an aggregate of approximately two billion gallons of fuel per year.

    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 2,230 taxis in Southern California, the San Francisco Bay Area, Dallas, Houston, Las Vegas, New York City, Ohio, Phoenix, Tucson, Chicago, Boston, Newark, Connecticut and Seattle.

    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, transfer stations, waste-to-energy facilities, and material recovery 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 approximately 60% of the new refuse collection trucks

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      ordered during 2013 were powered by CNG fuel. Waste Management has made public that it anticipates 85% of its new vehicle orders in 2014 will be natural gas vehicles. We serve numerous Waste Management sites now, as well as Republic Services and other sites, and hope to expand these numbers in the future. In addition to Waste Management and Republic Services, we also have contracts with private waste haulers such as Atlas Disposal (CA), Blue Diamond Disposal (NJ), Burrtec (CA), Central Jersey Waste, Choice Waste (FL), CleanScapes (Seattle), Garofalo V & Sons (NY), Homewood Disposal (IL), Mission Trail (CA), Livermore Sanitation (CA), USA Recycling (CT), Peoria Disposal (IL), Progressive Waste (LA and TX), Recology (Formerly Norcal Waste), South San Francisco Scavenger, Tidewater Chesapeake (VA), Waste Connection Vancouver and Waste Pro (FL), among others. We also provide vehicle fueling services to municipal refuse fleets including fleets in Burbank, Dallas, Fresno, Los Angeles, Sacramento, 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. We currently serve over 140 hauling companies.

    Transit Agencies —According to the American Public Transportation Association ("APTA"), there are over 67,250 municipal transit buses operating in the U.S. In many areas increasingly stringent emissions standards have limited the fueling options available to public transit operators. Also, transit agencies typically fuel at a central location and use high volumes of fuel. We estimate that the transit agencies in the U.S. consume an aggregate of approximately 1.5 billion gallons of fuel per year. Transit agencies were early adopters of natural gas vehicles, and more than one third of agencies nationwide are operating part or all of their fleet on LNG or CNG, according to APTA. Our U.S. public transit customers include the following: in California, Los Angeles Metropolitan Transit Authority, Foothill Transit, Long Beach Transit, Orange County Transit Authority, Santa Cruz Metropolitan, Santa Monica Big Blue Bus, OmniTrans San Bernardino and six other agencies. In the Southwest, Dallas Area Rapid Transit, Sun Metro (El Paso), El Metro (Laredo, Texas), Phoenix Transit, Tempe Transit, and the public agencies in Albuquerque and Santa Fe, New Mexico. In the Midwest, the public agencies in Kansas City (Missouri) and Akron and Canton, Ohio; and on the East Coast, Hillsborough Area Regional Transit (Tampa, Florida) and NICE Bus (Long Island, New York). We also serve public transit customers in British Columbia.

    Government Fleets —According to the Federal Highway Administration ("FHA"), in 2011, there were over 3.9 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 432,000 and 371,000 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, County of Maricopa (CA), City of San Antonio, Town of Smithtown (NY), City and County of San Francisco, City of Oakland, City and County of Dallas and the City of Phoenix.

Corporate Information; Acquisitions and Divestitures

        We were incorporated under the laws of the State of Delaware in April 2001. In August 2008, we acquired a 70% interest in 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, and on September 7, 2010, we acquired the advanced, non-lubricated natural gas fueling compressor and related equipment

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manufacturing and servicing business of IMW. On December 15, 2010, we acquired Northstar, and in 2011 and 2012, we acquired the natural gas fueling infrastructure construction business of Weaver Electric, Inc., and the natural gas engine system design company ServoTech, respectively. In March 2013, we completed the sale of our interest in Clean Energy del Peru. On May 6, 2013, we acquired MGES, a provider of CNG station design and construction and CNG equipment repair and maintenance services. On June 28, 2013, we sold all of the outstanding capital stock of BAF, including BAF's 100% ownership interest of ServoTech. In the future, we anticipate pursuing acquisitions and partnerships as we become aware of opportunities where we believe we can increase our competitive advantages, expand our product offerings, or enhance our market position.

Tax Incentives

        The program providing for the VETC federal fuel tax credit expired on December 31, 2013. However, U.S. federal and state government tax incentives and grant programs continue to be available to reduce the cost of acquiring and operating a natural gas vehicle fleet. Incentives may include funds to offset the cost of acquiring natural gas vehicles or converting vehicles to use natural gas, constructing natural gas fueling stations or selling CNG or LNG.

Grant programs

        We apply for and help our fleet customers apply for federal, state and regional grant programs in states where we operate including Alabama, Arkansas, California, Colorado, Connecticut, Florida, Georgia, Idaho, Indiana, Louisiana, Maryland, Missouri, Nevada, New Jersey, New Hampshire, New York, North Carolina, Ohio, Oregon, Pennsylvania, Texas, Utah, and Washington. 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, as the vast majority of vehicles in the U.S. and Canada are powered by gasoline and diesel. Many of the producers and sellers of gasoline and diesel fuels are large entities that have significantly greater 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. In addition, in the heavy-duty truck market we compete with market participants who only provide CNG and are advocating that operators adopt that fuel in lieu of LNG.

        A significant number of established businesses, including oil and gas companies, fuel providers, vehicle OEMs, refuse collectors, natural gas utilities, truck stop and fuel station operators, 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. 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;

    Questar Fueling, an affiliate of the Questar Gas Utility, provides CNG fuel infrastructure and fueling services and is advocating that heavy-duty truck operators adopt CNG over LNG;

    TruStar Energy (formerly Vocational Energy), a fueling infrastructure company;

    Shell Oil Products U.S., which is constructing and plans to operate a network of natural gas fueling stations at TravelCenters of America locations in the U.S.;

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    Love's Travel Stops, a travel-center operator that is adding CNG refueling infrastructure to its network, and is a proponent of heavy-duty truck operators adopting CNG over LNG;

    Blu LNG, a company backed by ENN Group Co Ltd (one of China's largest companies) that is developing a national network of LNG fueling stations;

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

    Kwik Trip, a company that owns CNG fueling stations in Wisconsin, Minnesota and Iowa, and has announced plans to add 10 to 15 new CNG locations and expand into new markets in 2014.

        Several natural gas utilities, including Pacific Gas and Electric, operate public access CNG stations that compete with our stations. In December 2012, the California Public Utilities Commission approved a compression services tariff application by the Southern California Gas Company, allowing the utility to offer natural gas fueling infrastructure construction services that compete with our offerings. In January 2014, Northwest Natural was also granted a similar service tariff by the Oregon Public Utilities Commission. In addition, utilities in several states, including Michigan, Illinois, New Jersey, North Carolina, Missouri, Maryland, Oregon, Washington, Kentucky and Georgia, have made efforts to invest in the market for natural gas vehicle fuels. Utilities have unique competitive advantages, including that they typically have a lower cost of capital, substantial and predictable cash flows, long-standing customer relationships, greater brand awareness and large and well-trained sales and marketing organizations.

        We sell CNG fueling equipment through our IMW subsidiary. The market for CNG fueling equipment is highly competitive with several competitors selling in multiple countries. We believe our competitors for CNG fueling equipment include Aspro, GNC Galileo, GE, SAFE, ANGI Energy Systems, Inc., and Atlas Copco. Numerous other equipment or compressor manufacturing companies may also enter the market in the future. We also compete with many third parties for the rights to develop RNG production facilities, as well as for customers to purchase the RNG we produce.

        We own, operate or supply 471 CNG and LNG fueling stations. Of these, we operate 308 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. 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 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, or NOx, and particulate

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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 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, CARB 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.

        The federal emissions standards under Title II of the Federal Clean Air Act for medium- and heavy-duty trucks are based on a range of factors such as gross vehicle weight rating ("GVWR"), cab type and roof height, and they will phase in from 2014-2018. As for federal fuel efficiency standards, tractor-trailers will be required to achieve about a 20% reduction in fuel consumption by model year 2018. Heavy-duty pickup trucks and vans will be required to improve fuel economy by model year 2018 by 10% for gasoline and by 15% for diesel vehicles. Vocational vehicles (delivery trucks, buses, garbage trucks) will have to improve fuel economy by 10% by model year 2018.

        Federal RFS.     In February 2010, the EPA finalized the RFS (which were established by the Energy Policy Act of 1992/2005), which creates 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 RFS.

         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, in 2009, CARB approved the LCFS, which requires a 10% carbon reduction in gasoline and diesel fuels sold in the State of California by 2020, and therefore encourages other low carbon "compliant" transportation fuels (including CNG, LNG and RNG) to enter the marketplace by allowing them to generate LCFS Credits that can be sold to noncompliant regulated parties.

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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 affect 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.

    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 facilities are required to comply with Title V air permits. 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.

        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 capital expenditures, earnings or competitive position. More stringent environmental laws and regulations may be imposed in the future, such as more rigorous air emissions requirements, proposals to make waste materials subject to more stringent and costly handling, disposal and clean-up requirements or 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, 2013, we employed 1,084 people, of whom 117 were in sales and marketing, 804 were in operations, engineering and compressor production, and 163 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.

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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. We are subject to certain risks attendant to our foreign operations, which are described under the heading "Risk Factors" in this annual report on Form 10-K.

Additional Information

        Our website is located at www.cleanenergyfuels.com. We make available, free of charge on our website, 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 Exchange Act 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.

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 2011, 2012 and 2013, we incurred pre-tax losses of $48.2 million, $99.6 million and $63.2 million, respectively. Our losses for 2011, 2012 and 2013 included derivative gains of $2.7 million, $3.4 million and $0.9 million, respectively, relating to marking to market the value of our Series I warrants. See note 18 of our consolidated financial statements. During 2011 and 2013, our losses were substantially decreased by approximately $17.9 million and $45.4 million of revenue, respectively, from federal fuel tax credits. The program under which we received such credits expired on December 31, 2013. 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 competitively priced natural gas vehicle fuel and other products and services. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits and other government incentive programs, 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.

Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our debt.

        At December 31, 2013, our total consolidated indebtedness was $620.4 million, including an aggregate of $295.0 million principal amount of convertible notes we issued in July 2011, August 2011, July 2012, and June 2013 (the "Series 2011 Notes") and an aggregate of $250.0 million principal amount of convertible notes we issued in September 2013 (the "Series 2013 Notes"). We expect our interest payment obligations under the Series 2011 Notes and the Series 2013 Notes to be approximately $22.4 million and $13.3 million, respectively, for the year ending December 31, 2014. Our ability to make scheduled payments of the principal of, to pay interest on, or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive

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and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms or at the desirable time, which could result in a default on our debt obligations. Additionally, our existing and future indebtedness may contain various restrictive covenants, and any failure by us to comply with any of those covenants could also cause us to be in default under the agreements governing the indebtedness. In the event of any such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder, together with accrued and unpaid interest, to be due and payable, thereby causing all of our available cash flow to be used to pay such indebtedness and/or we could be forced into bankruptcy or liquidation. In addition, the amount of our significant indebtedness, combined with our other financial obligations and contractual commitments, could have important consequences. For example, it could make us more vulnerable to adverse changes in general U.S. and worldwide economic, industry and competitive conditions and adverse changes in government regulation, limit our flexibility and planning for, or reacting to, changes in our business and industry, or place us at a competitive disadvantage compared to our competitors who have less debt and limit our ability to borrow additional amounts.

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 limit our growth.

        Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because the components needed for a vehicle to use natural gas adds to a vehicle's 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. Additionally, reduced prices for gasoline and diesel fuel may cause potential customers to delay or decide not to convert their fleets to run on natural gas. 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 production of natural gas through hydraulic fracturing or horizontal drilling techniques, 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. In that event, our sales of natural gas fuel may decrease 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. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we 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 number of our customer agreements, the commodity cost is passed through to the

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customer. Among the factors that can cause 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 efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic fracturing and horizontal drilling techniques 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 or horizontal drilling could lead to increased natural gas prices.

If Cummins Westport experiences difficulties or other delays in making its ISX 12G natural gas engine widely available, or if the engine is not adopted by truck operators to the extent we anticipate, our results of operations and business prospects will be adversely affected.

        We believe that our entry into the heavy-duty truck market, and the execution of our ANGH initiative, depends upon the successful adoption of the Cummins Westport ISX 12G engine (or a comparable engine that we believe would be well-suited for the U.S. heavy-duty truck market). Although the engine has entered production, commercial availability of this engine has been previously delayed and Cummins Westport may experience further delays in making the engine widely available. Further, the Cummins Westport ISX 12G engine may not be adopted and deployed by heavy-duty truck operators in meaningful numbers. Heavy-duty trucks powered by the engine will cost more, as compared to comparable diesel trucks, and may experience operational or performance issues. If meaningful numbers of the Cummins Westport ISX 12G engine are not deployed, or if a meaningful number of the engines that are deployed are not fueled at our stations, our business and financial results would be harmed.

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

        We are building America's Natural Gas Highway, a network of natural gas truck fueling stations on interstate highways and near distribution centers, intermodal transportation facilities and manufacturing locations. 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:

    Our ANGH stations have primarily been initially built to provide LNG and LNG typically costs more than CNG. If CNG becomes the preferred fuel for truck operators, we would be required to spend significant additional capital to add CNG and/or LCNG to our ANGH stations, and we may not have sufficient capital for that purpose;

    Truck and vehicle operators may not fuel at our stations;

    We have no influence over the development, production or availability of natural gas trucks powered by engines that are well-suited for the United States heavy-duty truck market (including the Cummins Westport ISX 12G engine);

    Operators may not adopt heavy-duty natural gas trucks due to cost, actual or perceived performance issues, or other factors that are outside our control;

    We may not be able to obtain acceptable margins on fuel sales at ANGH stations;

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

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    Development of America's Natural Gas Highway will require substantial additional 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 may not be able to hire and retain the necessary qualified personnel, and our operational infrastructure and systems may be inadequate;

    Many ANGH stations have been completed before there are sufficient numbers of customers who will fuel at the stations, and if such customers do not materialize, we will continue to have substantial investments in assets that do not produce revenues and we may lose money on LNG that is supplied to the ANGH stations but is not purchased by customers;

    We may not be able to acquire and transport sufficient volumes of LNG; and

    Building ANGH imposes 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, and our ability to repay our debt.

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 of CNG, LNG and RNG.

        Limited availability of natural gas vehicles and engine sizes restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers currently produce a small number of natural gas engines and vehicles in the U.S. and Canadian markets, they may not make adequate investments to expand their natural gas engine and vehicle product lines, and/or they may discontinue or curtail their natural gas engine and vehicle product lines. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales will be restricted.

        Natural gas vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers. If heavy-duty natural gas truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for natural gas engines, or natural gas engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and natural gas fueling business may be significantly impaired, which would adversely affect our financial performance.

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

        At December 31, 2013, we had total cash and cash equivalents of $240.0 million and short-term investments of $138.2 million. Our business plan calls for approximately $135.0 million in capital expenditures in 2014, as well as substantial capital expenditures thereafter. We may also require capital for unanticipated expenses, mergers and acquisitions and strategic investments. In addition, we have committed to future payments that we will be required to make in connection with our acquisitions of our subsidiaries IMW and Northstar. At December 31, 2013, our future payments for IMW and Northstar totaled $12.4 million and $2.4 million, respectively.

        Equity or debt financing options may not be available when needed or 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

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options including, but not limited to, equipment financing, the sale of convertible notes, high yield debt, asset based loans, term loans, project finance debt, municipal bond financing or commercial bank financing. Any debt financing we obtain may require us to make significant interest payments and to pledge some or all of our assets as security. 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.

We have the ability to incur substantially more debt.

        Despite our current consolidated debt levels, we and our subsidiaries may be able to incur substantial additional debt in the future, some of which may be secured debt. The agreements governing our Series 2011 Notes and our Series 2013 Notes do not restrict our ability to incur additional indebtedness or require us to maintain financial ratios or specified levels of net worth or liquidity. If we incur substantial additional indebtedness in the future, these higher levels of indebtedness may adversely affect our ability to pay the principal of and interest on our debt, or make other required payments, increase the risks relating to our ability to service our indebtedness described above, and/or adversely affect our creditworthiness generally, which could restrict our flexibility in responding to changing business and economic conditions and negatively impact our business.

Our business is influenced by government incentives and mandates for clean burning fuels and alternative fuel vehicles.

        Our business is influenced by federal, state and local government tax attributes, credits, rebates, grants and similar incentives that promote the use of natural gas and RNG as a vehicle fuel, as well as by laws, rules and regulations that require reductions in carbon emissions. Some government programs and incentives have recently expired, such as the VETC federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which expired December 31, 2013 and may not be reinstated. In 2011 and 2013 we recorded approximately $17.9 million and $45.4 million of revenue, respectively, related to VETC fuel tax credits, representing approximately 6.1% and 12.9%, respectively, of our total revenue during the periods. If expired incentives are not reinstated or extended, or if new incentives are not passed, our revenue and financial performance may be adversely affected. Furthermore, the failure of proposed federal, state or local government incentives that promote the use of natural gas and RNG as a vehicle fuel to pass into law could result in a negative perception of our industry and business by the market generally and a decline in the market price of our common stock. Changes to or the repeal of laws, rules and regulations that mandate reductions in carbon emissions and/or the use of renewable fuels, including the California Low Carbon Fuel Standard and the Federal Renewable Fuel Standard Phase 2, would adversely affect our business and ability to operate a profitable RNG business. In addition, if grant funds are no longer available under government programs for the purchase and construction of natural gas vehicles and stations, those activities could slow and our business and results of operations may be adversely affected.

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 and RNG for vehicles. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we have, invest significant time and money in efforts 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

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perception that they impose increased costs on the transportation industry that cannot be absorbed in a challenging economy. 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.

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 sell increasing amounts of CNG, LNG and RNG, which we may not be able to do. 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 prices that are lower than gasoline and diesel 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. Also, if vehicle operators perceive that greenhouse gas emissions of natural gas vehicles are greater than those of gasoline or diesel vehicles, then such operators may not adopt natural gas vehicles. Further, potential customers may not find our product or service offerings acceptable, may not like the natural gas fueling experience or may encounter operational difficulties with natural gas vehicles or natural gas fueling infrastructure. In addition, users may experience issues with the content of the natural gas supplied to CNG stations we own and/or operate. Such issues may adversely affect the adoption of CNG as a vehicle fuel and may result in claims against us.

We face increasing competition from oil and gas companies, fuel providers, refuse companies, industrial gas companies, natural gas utilities, fuel station and truck stop owners, 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 and their affiliates, industrial gas companies, truck stop and station owners, fuel providers and other organizations have entered or are planning to enter the natural gas fuels market. For example, Shell Oil Products U.S. is constructing and plans to operate a network of natural gas fueling stations at TravelCenters of America locations in the United States. In addition, Love's Travel Stops is adding CNG refueling infrastructure to its travel-center network. Further, ENN Group Co Ltd, one of China's largest private companies, is building a network of natural gas fueling stations for trucks along U.S. highways. Many of these current and potential competitors have substantially greater financial, marketing, research and other resources than we have. Further, new technologies and improvements to existing technologies may give existing competitors and new market entrants competitive advantages. In addition, in the heavy-duty truck market, we compete with market participants who advocate the adoption of CNG over LNG, and operators may prefer the CNG offering provided by such competitors. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. The California Public Utilities Commission has approved a compression services tariff application by the Southern California Gas Company, allowing the utility to compete with us by building and owning natural gas fueling infrastructure on customer property and by providing O&M services to customers. Further, utilities in several other states, including Michigan, Illinois, New Jersey, North Carolina, Oregon, Maryland, Washington, Kentucky and Georgia, either have or are preparing to enter the natural gas vehicle fuel business. Utilities, in particular, have unique competitive advantages, including that they typically have a lower cost of capital, substantial and predictable cash flows, long-standing customer relationships, greater brand awareness and large and well-trained sales and marketing organizations.

        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

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opportunities. Our failure to compete successfully in the markets in which we operate, including the heavy-duty truck market, would adversely affect our business and financial results.

We are subject to risks associated with cost overruns, delays, regulatory compliance and other contingencies in connection with our station construction activities, any of which could have a material adverse effect on our business and results of operations.

        In connection with our station construction and facility modification projects, we act as the general contractor and construction manager and typically rely on licensed subcontractors to perform the construction work. We may be liable for any damage we or our subcontractors cause during the course of our projects. Shortages of skilled subcontractor labor for our projects could significantly delay a project or otherwise increase our costs. Our profit on our projects is based in part on assumptions as to the cost of such projects. Cost overruns, delays or other execution issues may, in the case of projects that we complete and sell to customers, cause us to not achieve our expected margins or cover our costs, and in the case of projects that we build and own, cause us to not achieve an acceptable rate of return.

        In addition, our station construction and facility modification activities are subject to oversight and regulation in accordance with national, state and local laws and ordinances relating to building codes, safety, environmental protection, and related matters. It is difficult and costly to manage the requirements of every individual authority having jurisdiction over our various construction projects and to comply with these varying standards. Any new government regulations pertaining to our station construction and facility modification activities may result in significant additional expenses to us and our customers.

Our warranty reserves may not adequately cover our warranty obligations and increased or unexpected product warranty claims could adversely impact our financial condition and results of operations.

        We provide product warranties with varying terms and durations for the majority of our products and we establish reserves for the estimated liability associated with our product warranties. Our warranty reserves are based on historical trends as well as our understanding of specifically identified warranty issues. The amounts estimated could differ materially from actual warranty costs that may ultimately be realized. An increase in the rate of warranty claims or the occurrence of unexpected warranty claims could have a material adverse effect on our financial condition or results of operations.

Increased IT security threats and more sophisticated and targeted computer crime could pose a risk to our systems, networks, products, solutions and services.

        Increased global IT security threats and more sophisticated and targeted computer crime pose a risk to the security of our systems and networks and the confidentiality, availability and integrity of our data. Depending on their nature and scope, such threats could potentially lead to the compromising of confidential information, improper use of our systems and networks, manipulation and destruction of data and operational disruptions, which in turn could adversely affect our reputation, competitiveness and results of operations.

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. 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. 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, including:

    compliance with the United States Foreign Corrupt Practices Act;

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    political unrest, terrorism and economic and financial instability;

    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;

    differing employment practices and/or labor issues, including wage inflation, labor unrest and unionization policies;

    limited intellectual property protection;

    longer payment cycles by international customers;

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

    potentially adverse tax consequences.

        In addition to the above, 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 United States dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the United States dollar.

We may encounter challenges managing our growth, which may divert resources and limit our ability to successfully expand our operations.

        We have been and expect to 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 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 improve management of our natural gas station construction, maintenance and operations projects. If we are not able to manage our business growth and operations in a cost-effective manner, our operating results, sales and revenues may be negatively impacted.

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 and retain them. All of our executive officers and other United States employees may terminate their employment relationships 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 could 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

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leave, we may not be able to fully integrate new executives or replicate the current dynamic, which may cause our operations to suffer.

A significant portion of the purchase price of IMW was allocated to intangibles, including goodwill, and a write-off of all or part of these intangibles, including 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 regarding new business, believed to be reasonable, but which are inherently uncertain. Pursuant to the applicable accounting standards, we initially allocated $126.4 million of the purchase price for IMW to intangibles, including goodwill. Our intangibles, including 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 intangibles, including goodwill, could adversely affect our results of operations.

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

        We have, 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 21%, 33% and 19% of our annual revenues in 2011, 2012 and 2013, 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 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 contracts may follow our successful bids as a result of such protests.

We may encounter difficulties building the GE Plants and such facilities may never be completed. If we commence construction of either GE Plant we will need to comply with significant obligations to GE.

        Our ability to commence construction of the GE Plants financed under the credit agreement we entered into with GE in November 2012, will depend on a number of conditions, including the availability of sites upon which to construct the GE Plants and our ability to acquire title to, or leasehold interests in, such sites and the receipt of all governmental approvals necessary to design, develop, own, construct, install, operate and maintain the GE Plants. If we do not satisfy all of the conditions by December 31, 2014, GE's obligation to fund the GE Plants will terminate. This may result in us not being able to satisfy our LNG supply needs, and may adversely affect our business, financial condition and operational results.

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        If we commence construction of either GE Plant, we may not be able to comply with all of our obligations to GE. For example, we may not complete one or both of the GE Plants within the required time period, or we may not make our required equity contributions to the plants. The GE Plants may cost more than we expect, and we may not be able to pay the additional cost. If the GE Plants are completed, they may not generate enough cash flow to pay our obligations to GE because they may experience operational difficulties or inefficiencies or we may not be able to sell enough of the LNG the plants produce. If we do not fulfill our obligations, we may lose some or all of our investments in the GE plants.

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, LNG or RNG have the potential to slow adoption of natural gas vehicles. Advances in gasoline and diesel engine technology, especially hybrids, may offer a cleaner, more cost-effective option and make fleet customers less likely to convert their fleets to natural gas. Technological advances related to ethanol or biodiesel, which are increasingly used as an additive to, or substitute for, gasoline and diesel 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 natural gas 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 constrained by fragmented and limited production and increasing competition for LNG supply.

        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, when needed, 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 down time, or if any such plants cannot produce LNG meeting applicable composition specifications and requirements, or if we or others do not build additional LNG liquefaction plants, our LNG supply will be restricted. In 2013, we entered the Eagle LNG Partners consortium, aimed at developing regional LNG projects to meet growing demand for LNG. However, the efforts of this consortium may be unsuccessful and the LNG supply may remain insufficient to meet demands, and our participation in the consortium may prove to be an ineffective use of our management and other resources. If we are unable to supply enough LNG that satisfies applicable specifications (either from our own plants or by purchasing it from third parties) to meet customer demand, we may be liable to our customers for penalties and damages and may lose customers. Competition for LNG supply is escalating. For example, we increasingly compete to purchase LNG with third parties that use LNG to fuel equipment deployed in oil and gas production activities. 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

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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 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 four LNG supply agreements that have a take-or-pay commitment, and we may enter into additional take-or-pay commitments. 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 sales contract does not maintain its volume levels or grow, or if future demand for LNG does not meet our expectations, these commitments may cause our operating and supply costs to increase and our margins may be negatively impacted.

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 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, if any, and these unknown costs are not contemplated by our current 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.

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

        Our operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the U.S. Environmental Protection Agency or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained or installed, 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.

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

        We directly lend 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. These risks include the following: (i) the equipment financed consists mostly of vehicles that are mobile and easily damaged, lost or stolen, (ii) the borrower may default on payments, enter bankruptcy proceedings and/or liquidate, (iii) we may not be able to bill properly or track payments in adequate fashion to

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sustain growth of this service, and (iv) 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, 2013, we had $7.7 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, construction, land use 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 corrective 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 operations, we often need facility permits or licenses to address, among other things, storm water or wastewater discharges, waste handling, and air emissions. 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.

Our RNG business may not be successful.

        We completed a new RNG production facility in Canton, Michigan in 2012, we are developing a pipeline quality RNG project near Memphis, Tennessee, and we are in the process of completing an expansion of our RNG production facility at the McCommas Bluff landfill outside of Dallas, Texas. We are also seeking to increase our RNG business by pursuing additional projects. We may not be successful in developing and operating 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, technological difficulties and costs associated with operating the production facilities, and the absence of government programs and regulations that support such activities. The success of our RNG business depends on our ability to obtain necessary financing, successfully manage the construction and operation of RNG production facilities and our ability to either sell the RNG at substantial premiums to current conventional natural gas prices or to sell, at favorable prices, credits we may generate under federal or state laws, rules and regulations, including RIN and LCFS Credits. If we are unable to accomplish one or more of these items, our business and financial results may be materially and adversely affected.

        In addition, due to recent regulatory and legislative changes in California, our ability to sell RNG produced by projects outside of California to California power plants for use as a Renewable Portfolio Standard ("RPS") compliant fuel is limited. If we cannot sell RNG we produce to California power plants for use as a RPS compliant fuel, we may not be able to obtain long-term, fixed premium prices for RNG.

        The market for RINs Credits and LCFS Credits is volatile, and the prices for such credits may be subject to significant fluctuations. Further, the value of RINs Credits and LCFS Credits will be

33


adversely affected by any changes to the state and federal programs under which such credits are generated and sold. For example, in November 2013, the EPA lowered the 2014 RFS standards, which negatively affected the value of RIN Credits.

        In the absence of state and federal programs that support premium prices for RNG, or that allow us to generate and sell LCFS and RIN Credits and other credits, or if our customers are not otherwise willing to pay a premium for RNG, we may be unable to generate reasonable profits and financial returns from these investments, and our financial results could be materially and adversely affected.

We may experience difficulties producing RNG.

        We have experienced difficulty producing the expected volumes of RNG at our currently operational RNG plants. The contractor we hired to perform the expansion work at the McCommas Bluff plant was not able to cause the expanded plant to meet the performance standards specified in our design-build agreement. This performance failure has resulted in lower than expected RNG production at the plant. We are working to improve performance of the plant and are pursuing our remedies under our agreements with the contractor. However, these actions may be costly and time consuming, and may not ultimately be successful. In addition, we have experienced problems with key equipment at our Canton, Michigan production facility, and such problems have resulted in lower than expected RNG production at the plant. We may incur significant additional costs to fix equipment at that plant.

        Our financial results and operations will be negatively impacted if we continue to experience difficulties producing RNG. Our ability to produce RNG may be adversely affected by a number of factors beyond our control, including but not limited to, limited availability or unfavorable composition of collected landfill gas, failure to obtain and renew necessary permits, landfill mismanagement, problems with our critical equipment, and adverse or severe weather conditions. In addition, we may seek to upgrade or expand our RNG facilities, which may result in plant shutdowns or cause delays that reduce the amount of RNG we produce.

If certain of our subsidiaries do not comply with their financing agreements, we may lose our interest in our RNG production facilities located in Dallas, Texas and Canton, Michigan.

        Two of our subsidiaries, Dallas Clean Energy McCommas Bluff, LLC ("DCEMB") (in which we indirectly own a 70% interest) and Mavrix, LLC ("Mavrix") have issued revenue bonds and promissory notes, respectively, to third parties. DCEMB and Mavrix own our RNG production facilities located in Dallas, Texas and Canton, Michigan. If DCEMB and Mavrix do not comply with their obligations and covenants under these revenue bonds and promissory notes (including their obligations to pay principal and interest), we may lose our interests in the RNG production projects they own, and our business and results of operations may be adversely affected.

Our strategic relationship with Mansfield could produce less beneficial results than we currently expect.

        On May 6, 2013, in connection with our acquisition of MGES, we entered into a strategic partnership with Mansfield, which is designed to offer customers the most comprehensive natural gas solution in the industry. Pursuant to the partnership arrangement, both our sales team and Mansfield's sales team will offer our natural gas fueling station construction and operational services to current and potential customers. The intent is that our offered services will be supported by Mansfield's large-scale fuel supply capabilities and fuel management systems, in order to provide a comprehensive solution to current and prospective customers. This relationship may not achieve the degree of success we aim to achieve, and could prove to be wholly unsuccessful. If we are not able to capitalize on this partnership, our prospects, competitive position in our industry and operational results could be harmed.

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We may never receive the full value of the consideration for our sale of BAF, and we could be subject to future liability in connection with that transaction.

        In connection with our sale of our former subsidiary BAF, we entered into a stock purchase agreement in which we made customary representations and warranties regarding BAF and various aspects of its business, operations and financial condition. Pursuant to the indemnification provisions in that stock purchase agreement, we are subject to certain obligations to the purchaser of BAF if any of those representations and warranties should prove to be untrue and in certain other circumstances. The stock purchase agreement provides that the purchaser of BAF is entitled to hold back $3.0 million worth of the consideration due to us for a period of one year, and use such held back amount to satisfy any losses it may incur that are covered by our indemnification obligations. As a result, we may never receive the portion of the consideration that has been held back. As of December 31, 2013, we wrote down the value of these shares by $1.4 million. Further, with respect to certain specified representations and warranties in the stock purchase agreement, the purchaser of BAF could pursue amounts from us in addition to the value of the held back consideration, in the event that its losses are greater than the value of the held back consideration. Accordingly, we could be subject to monetary liability as a result of our indemnification obligations. Further, Westport may not pay us the $5.0 million it is obligated to pay us on or before March 1, 2014 under the joint marketing agreement we entered in connection with the sale of BAF, in which case we would need to take steps to collect such funds. Any of those results could distract our management team and/or require us to devote our resources to the matter, and could harm our business and financial condition.

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

        Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were approximately $9.8 million, $5.6 million, $11.4 million, $20.9 million, $31.9 million, $11.3 million, $16.3 million, $41.7 million, $3.9 million, $11.9 million, $18.8 million, and $32.3 million for the three months ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, September 30, 2012, December 31, 2012, March 31, 2013, June 30, 2013, September 30, 2013, and December 31, 2013, 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, receipt of fuel tax credits and other government incentives, construction delays and/or cost overruns, down time at our facilities, 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 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, difficulties producing LNG and/or RNG from our facilities, challenges acquiring LNG and/or RNG from third parties, the costs related to the acquisition of assets or businesses, regulatory changes, increasing competition, geopolitical events such as war, threat of war or terrorist actions, and the occurrence of any of the additional risks discussed in this report. 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.

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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, 2013, there were 89,364,397 shares of our common stock outstanding, 11,526,998 shares underlying outstanding options, 1,590,836 shares underlying restricted stock units, 2,130,682 shares underlying outstanding Series I warrants (all of which were sold in our registered direct offering that closed in November 2008), 5,000,000 shares underlying a warrant we issued in November 2012 to GE, an aggregate of 19,160,338 shares underlying our Series 2011 Notes and an aggregate of 16,025,641 shares underlying our Series 2013 Notes. 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 the applicable option, warrant and convertible note agreements and Rule 144, or if such shares 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.

        As of December 31, 2013, 18,139,720 shares of our common 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, 2013, 403,397 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. Sales of shares under these plans could also cause the trading price of our common stock to fall.

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, 2013, T. Boone Pickens beneficially owned in the aggregate approximately 25.7% of our outstanding shares of common stock (including 18,139,720 shares of common stock, 1,901,800 shares underlying stock options exercisable within 60 days of December 31, 2013, and 4,113,923 shares underlying convertible promissory notes he holds). As a result, Mr. Pickens is 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.

Our stock price may be volatile .

        The market price of our common stock has experienced, and may continue to experience, volatility and could be subject to fluctuations in price in response to various factors, some of which are beyond our control. In addition to the other factors discussed in this Item 1A, factors that may cause volatility in our stock price include:

    our actual or perceived ability to capture a substantial share of the anticipated growth in the market for natural gas as a vehicle fuel;

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    successful implementation of our business plans, including our plan to build America's Natural Gas Highway;

    the development, commercial availability and market adoption of natural gas as a vehicle fuel and engines that operate on natural gas, particularly natural gas engines that are well-suited for the heavy-duty truck market, including the Cummins Westport ISX 12G engine, and the mix of such engines between CNG and LNG;

    production, sourcing and supply of LNG and RNG;

    changes in the worldwide prices for natural gas and for traditional vehicle fuels, such as gasoline and diesel;

    actual or perceived fluctuations in our operating results;

    sales of our common stock by us or our stockholders;

    a decline in demand for our common stock;

    the potential for oil and gas companies, natural gas utilities and others to enter the natural gas fuel market;

    changes in our key personnel;

    competitive developments;

    investor perception of our industry or our prospects; and

    changes in general economic and market conditions.

        In addition, the securities markets have from time to time experienced significant price and volume fluctuations that are unrelated to the operating performance of particular companies, and in such instances, have affected the market prices of those companies' securities. These market fluctuations may also materially and adversely affect the market price of our common stock.

Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

        Our corporate headquarters are located at 4675 MacArthur Court, Suite 800, Newport Beach, CA 92660, where we occupy approximately 68,000 square feet. Our office lease expires on June 30, 2021.

        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 30 year ground lease for the 36 acres on which this plant is situated, pursuant to which we pay 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 lease the space upon which we operate our RNG production facilities in Dallas, Texas and Canton, Michigan, as well as the space in North Shelby, Tennessee, where we are building a third RNG production facility.

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        We lease a manufacturing facility in Chilliwack, British Columbia where we occupy approximately 81,000 square feet. The facility lease expires in January 2018.

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, results of operations or liquidity. 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 the Nasdaq Global Market for our common stock for the periods indicated.

 
  Sales Prices  
 
  High   Low  

Fiscal Year 2012

             

First Quarter 2012

  $ 23.92   $ 12.95  

Second Quarter 2012

  $ 20.74   $ 12.55  

Third Quarter 2012

  $ 16.35   $ 13.06  

Fourth Quarter 2012

  $ 13.87   $ 11.00  

Fiscal Year 2013

             

First Quarter 2013

  $ 14.48   $ 12.03  

Second Quarter 2013

  $ 14.30   $ 12.01  

Third Quarter 2013

  $ 13.46   $ 12.26  

Fourth Quarter 2013

  $ 13.79   $ 11.23  

Holders

        There were approximately 65 stockholders of record as of February 19, 2014. We believe there are approximately 93,552 additional stockholders whose shares of our common stock are held on their behalf by brokerage firms or other agents.

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.

Performance Graph

        This performance graph shall not be deemed "filed" for purposes of Section 18 of 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 for the five-year period ending December 31, 2013 of the cumulative total return for our common stock, the Nasdaq Global Market Index, and the Russell 2000 Growth Index, in each case assuming $100 was invested on December 31, 2008. 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

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for the Nasdaq Global Market Index and the Russell 2000 Growth Index assumes reinvestment of dividends.

GRAPHIC

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 related notes contained elsewhere in this annual report on Form 10-K.

        The consolidated statements of operations data for the years ended December 31, 2011, 2012, and 2013 and the consolidated balance sheet data at December 31, 2012, and 2013, are derived from our audited consolidated financial statements in this annual report on Form 10-K. The consolidated statements of operations data for the years ended December 31, 2009 and 2010, and the consolidated balance sheet data at December 31, 2009, 2010 and 2011 are derived from our audited consolidated

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financial statements that are not included in this annual report on Form 10-K. The historical results are not necessarily indicative of the results to be expected in any future period.

 
  Year Ended December 31,  
 
  2009   2010   2011   2012   2013  
 
  (In thousands, except share data)
 

Statement of Operations Data:

                               

Total Revenues(1)

  $ 131,503   $ 211,834   $ 292,717   $ 334,008   $ 352,475  

Operating expenses:

                               

Costs of sales (exclusive of depreciation and amortization shown separately below)

    82,921     141,889     216,684     253,684     224,762  

Derivative (gains) losses:

                               

Series I warrant valuation

    17,367     (10,278 )   (2,655 )   (3,391 )   (938 )

Selling, general and administrative

    47,509     63,258     86,850     117,976     138,024  

Depreciation and amortization

    16,992     22,487     30,406     36,261     42,318  
                       

Total operating expenses:

    164,789     217,356     331,285     404,530     404,166  
                       

Operating loss

    (33,286 )   (5,522 )   (38,568 )   (70,522 )   (51,691 )

Interest expense, net

    (32 )   (1,194 )   (9,616 )   (16,069 )   (29,287 )

Other income (expense), net

    (310 )   2,080     (611 )   1,236     (970 )

Impairment of cost method investment

                (14,544 )    

Income (loss) from equity method investments

    244     427     637     331     (76 )

Gain from sale of equity method investment

                    4,705  

Gain from sale of subsidiary

                    14,115  
                       

Loss before income taxes

    (33,384 )   (4,209 )   (48,158 )   (99,568 )   (63,204 )

Income tax (expense) benefit

    (304 )   1,436     703     (1,294 )   (3,715 )
                       

Net loss

    (33,688 )   (2,773 )   (47,455 )   (100,862 )   (66,919 )

Loss (income) of noncontrolling interest

    439     257     (178 )   (393 )   (49 )
                       

Net loss attributable to Clean Energy Fuels Corp

  $ (33,249 ) $ (2,516 ) $ (47,633 ) $ (101,255 ) $ (66,968 )
                       
                       

Basic and diluted loss per share

  $ (0.60 ) $ (0.04 ) $ (0.68 ) $ (1.16 ) $ (0.71 )
                       
                       

Weighted average common share outstanding:

                               

Basic and diluted

    55,021,961     62,549,311     70,415,431     87,455,073     93,958,758  
                       
                       

(1)
Revenues include the following amounts:

 
  Year Ended December 31,  
 
  2009   2010   2011   2012   2013  

Fuel tax credits (VETC)

  $ 15,535   $ 16,042   $ 17,889   $ (2,057) (b) $ 45,439 (a)
                       
                       

(a)
Amount includes $20,800 related to 2012.

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(b)
Represents settlement with the IRS over certain VETC amounts.

 
  December 31,  
 
  2009   2010   2011   2012   2013  

Balance Sheet Data:

                               

Cash and cash equivalents

  $ 67,087   $ 55,194   $ 238,125   $ 108,522   $ 240,033  

Restricted cash, short term

    2,500     2,500     4,792     8,445     8,403  

Short-term investments

            33,329     38,175     138,240  

Working capital

    78,799     65,070     312,372     170,778     400,990  

Total assets

    355,799     583,499     931,061     975,200     1,250,965  

Long-term debt, inclusive of current portion

    12,221     64,416     289,422     331,025     620,418  

Total Clean Energy Fuels Corp. Stockholders' equity

    277,189     413,287     540,884     542,713     514,572  

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 are the leading provider of natural gas as an alternative fuel for vehicle fleets in the United States and Canada, based on the number of stations operated and the amount of gasoline gallon equivalents of compressed natural gas ("CNG") and liquefied natural gas ("LNG") delivered. We 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 other equipment used in CNG stations and LNG stations, provide operation and maintenance services ("O&M") to customers, offer solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, produce renewable natural gas ("RNG"), which can be used as vehicle fuel or sold for renewable power generation, and sell tradable credits we generate by selling natural gas and RNG as a vehicle fuel, including credits we generate under the California Low Carbon Fuel Standard ("LCFS Credits") and Renewable Identification Numbers ("RIN Credits" or "RINs") we generate under the federal Renewable Fuel Standard ("RFS") Phase 2. In addition, we help our customers acquire and finance natural gas vehicles and obtain local, state and federal grants and incentives. We previously owned BAF Technologies, Inc. and its wholly owned subsidiary, ServoTech Engineering, Inc. (BAF Technologies, Inc. and ServoTech Engineering Inc. are collectively referred to as "BAF"). BAF converted light and medium duty vehicles to run on natural gas and provided design and engineering services for natural gas engine systems. On June 28, 2013, we sold BAF to Westport Innovations (U.S.) Holdings Inc., a wholly owned subsidiary of Westport Innovations Inc.

Overview

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

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        Sources of revenue.     We generate revenues by selling CNG and LNG, providing O&M services to our vehicle fleet customers, designing and constructing fueling stations and selling those stations to our customers, selling RNG, selling non-lubricated natural gas fueling compressors and other equipment for CNG and LNG fueling stations, providing maintenance services, offering solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, providing financing for our customers' natural gas vehicle purchases and selling tradable credits, including LCFS Credits and RIN Credits. In addition, until June 28, 2013, we generated revenues, through BAF, by selling converted natural gas vehicles and providing design and engineering services for natural gas engine systems.

        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 (through March 2013 when we sold our interest in the 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 our RNG production facilities, (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 elsewhere in this annual report on Form 10-K, presents our key operating data for the years ended December 31, 2011, 2012, and 2013:

Gasoline gallon equivalents delivered

 
  Year Ended December 31,  
 
  2011   2012   2013  
 
  (in millions)
 

CNG

    101.8     130.5     143.9  

RNG

    6.7     8.9     10.5  

LNG

    47.1     55.5     60.0  
               

Total

    155.6     194.9     214.4  
               
               

Operating data (in thousands)

                   

Gross margin

  $ 76,033   $ 80,324   $ 127,713 (1)

Net loss attributable to Clean Energy Fuels. Corp

    (47,633 )   (101,255 )   (66,968 )(1)

(1)
See discussion under "Operations—Government Incentives" below.

        Key trends in 2011, 2012 and 2013.     According to the U.S. Department of Energy, Energy Information Administration ("EIA"), demand for natural gas fuels in the United States increased by approximately 38% during the period January 1, 2011 through December 31, 2013. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during this period, as well as increasingly stringent environmental regulations affecting vehicle fleets and increased availability of natural gas.

        The number of fueling stations we owned, operated, maintained and/or supplied grew from 224 at January 1, 2011 to 471 at December 31, 2013 (a 110.3% 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, RNG, and LNG gasoline gallon equivalents we delivered from 2011 to 2013 increased by 37.8%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2011, 2012 and 2013. In addition, in 2012, we sold four large transit

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stations for $40.3 million, which contributed to our revenue amount during the year. Also, in 2013, revenues included $20.8 million in federal fuel tax credits ("VETC") related to 2012 due to the reinstatement of such credits in January 2013. This increase was partially offset by a reduction in revenues in 2013 due to our sale of BAF on June 28, 2013. Our revenue can vary between periods due to timing of equipment sales, station construction and natural gas sale activity.

        Our fuel cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG, RNG and LNG to our customers in 2011 through 2013. The increase was partially offset in 2013 by a reduction in cost of sales due to our sale of BAF on June 28, 2013. Our cost of sales can vary between periods due to timing of equipment sales, station construction and natural gas sale activity.

        During 2012 and 2013, prices for oil, gasoline, and diesel fuel were generally substantially higher than the price for natural gas. Oil hit a high of $107.65 per barrel, or $19.39 per one million Btus ("MMbtu"), in August 2013 and was $98.42 per barrel, or $17.73 per MMbtu, on December 31, 2013. In California, the average retail price for gasoline was $3.68 per gallon in January 2012, hit a high of $4.71 per gallon in October 2012, and was $3.70 per gallon at December 31, 2013. Average retail prices for diesel fuel in California were $4.05 per diesel gallon in January 2012, hit a high of $4.50 per diesel gallon in September 2012, and was $4.10 per diesel gallon at December 31, 2013. Higher gasoline and diesel prices improve our margins on fuel sales to the extent we price our fuel at a relatively consistent 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 increased slightly. The NYMEX price for natural gas ranged from $3.08 per MMbtu in January 2012 to $3.82 per MMbtu in December 2013. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.75 per gallon for the month of January 2012 to $2.70 per gallon for the month of December 2013. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.48 per gallon during January 2012 to $2.61 per gallon for the month of December 2013.

        Recent developments.     In January 2013, VETC of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that is sold as vehicle fuel was extended through December 31, 2013 and made retroactive to January 1, 2012. The amount attributed to 2012, $20.8 million, has been recorded by us in the first quarter of 2013, the period in which the law was passed.

        In January and February 2013, an aggregate of $4.0 million of principal and accrued interest under an SLG Note (as defined and discussed in note 9 to our consolidated financial statements) was converted by the holder into 268,664 shares of our common stock.

        In March 2013, we completed the sale of our ownership interest in our joint venture in Peru for approximately $6.1 million after receiving a dividend distribution of approximately $1.1 million (see note 7 to our consolidated financial statements).

        In April 2013, our subsidiary Mavrix, LLC ("Mavrix") issued a secured multi-draw promissory note in the maximum aggregate principal amount of $30.0 million (the "Mavrix Note") and received advances of $5.0 million in each of April 2013, September 2013 and December 2013 under the Mavrix Note (see note 9 to our consolidated financial statements).

        In May 2013, we purchased Mansfield Gas Equipment Systems Corporation ("MGES") for approximately $21.0 million, 50% of which we paid in cash and 50% of which we paid in shares of our common stock (see note 2 to our consolidated financial statements).

        In June 2013, we sold BAF for approximately $27.2 million (see note 2 to our consolidated financial statements).

        In June 2013, Boone Pickens and Green Energy Investment Holdings, LLC, (i) purchased from Chesapeake NG Ventures Corporation ("Chesapeake") the outstanding 7.5% convertible promissory

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notes in the aggregate principal amount of $100 million we had previously issued to Chesapeake, and (ii) delivered to us an aggregate of $50.0 million (in satisfaction of the funding requirement they assumed from Chesapeake in connection with the foregoing purchase) and were issued additional 7.5% convertible promissory notes in the aggregate principal amount of $50.0 million (all such 7.5% convertible notes are referred to as the "7.5% Notes") (see note 9 to our consolidated financial statements).

        In September 2013, we completed a private offering of 5.25% Convertible Senior Notes due 2018 (the "5.25% Notes"). The net proceeds from the sale of the 5.25% Notes, after the payment of certain debt issuance costs of $7.8 million, were $242.2 million (see note 9 to our consolidated financial statements).

        Anticipated future trends.     We anticipate that, over the long term, the prices for gasoline and diesel will continue to be significantly higher than the price of natural gas as a vehicle fuel, which will continue to make natural gas vehicle fuel an attractive alternative to gasoline and diesel. 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 United States natural gas production in recent years.

        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 acquisitions in 2010 of the natural gas compressor development and manufacturing business of IMW Industries, Ltd. ("IMW") and Wyoming Northstar Incorporated ("Northstar"), a leading provider of LNG station design, construction, operation and maintenance services, we are a fully integrated provider of advanced compression technology, CNG and LNG station design and construction, and CNG and LNG fueling. We anticipate expanding our sales of CNG and LNG in each of the markets in which we operate, including trucking, refuse hauling, airports, taxis and public transit, and plan to enter additional markets, including marine and rail. 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 and 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 and expend additional capital. Additionally, we have increased, 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 truck 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. We estimate that there are approximately three million heavy-duty trucks on the road in the U.S., and that such trucks collectively consume approximately 25 billion gallons of fuel each year. As a result, we believe this market has the potential to become our largest. We have made a significant commitment of capital and other resources to build a nationwide network of natural gas truck fueling stations, which we refer to as "America's Natural Gas Highway" or "ANGH," on the interstate highway system and near distribution centers, intermodal transportation facilities and manufacturing locations. Our objective in building America's Natural Gas Highway is to enable natural gas fueled freight trucking coast to coast and border to border along key transportation corridors. As of December 31, 2013, we had completed 85 stations, 22 were open and selling natural gas fuel, and an additional 28 were under development. We plan to continue to open stations and build new stations as natural gas trucks are deployed in the geographic areas where the stations are located. Our ANGH stations have primarily been initially built to provide LNG. However, we believe operators will adopt heavy-duty trucks that run on both LNG and CNG, so to meet the needs of our customers, we have designed the ANGH stations to be capable of dispensing both fuels. We will need to invest additional capital in our ANGH stations to the extent

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more CNG than LNG heavy-duty trucks are deployed and we decide to add CNG or LCNG fueling equipment to our ANGH stations.

        Many ANGH stations are located at Pilot Flying J Travel Centers, one of the largest truck fueling operators in the U.S. Under our agreement with Pilot, we own the ANGH stations we build at Pilot locations and pay rent to Pilot for the use of its property. In addition, we are entitled to recoup all of our investments in ANGH stations we build at Pilot locations plus a defined return, after which we share a portion of the station profits with Pilot.

        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 source of liquidity has consisted of cash provided by financing activities.

        Our business plan calls for approximately $135.0 million in capital expenditures in 2014, primarily related to construction of fueling stations, including stations along ANGH, expansion of our California LNG plant, development of two new LNG production facilities, 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, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. 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" and "Capital Expenditures" below. We may not be able to raise capital, when needed, on terms that are favorable to us or 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 of this report.

Operations

        We generate revenues principally by selling CNG, LNG and RNG, and providing O&M services to our vehicle fleet customers. For the year ended December 31, 2013, CNG and RNG (together) represented 72% and LNG represented 28% 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 revenues through sales of advanced natural gas fueling compressors and other natural gas fueling station equipment, providing station modification and maintenance services, providing financing for our customers' natural gas vehicle purchases, and selling RIN and LCFS Credits.

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 principally determined 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. Our fleet customers typically are billed monthly based on the volume of CNG sold

46


at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at public access stations based on prevailing market conditions.

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, and we plan to build two new LNG plants in connection with our strategic collaboration with General Electric Capital Corporation ("GE") (see note 9 to our consolidated financial statements). We expect that these additional plants, as well as our planned expansion of our Boron, California plant, and other plants to be built by us or third parties in the future, will be necessary to secure sufficient sources of LNG in the future.

        We sell LNG on a bulk basis to fleet customers, who often own and operate their fueling stations, and we also sell LNG to fleet and other customers at our public-access LNG stations. During 2012 and 2013, we procured 44% and 33%, respectively, of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. We expect to enter additional purchase contracts with third party LNG producers in the future. For LNG that we purchase from third parties, we have entered into, and 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 88 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. For LNG customers who own and operate their fueling stations, we sell LNG through supply contracts that are priced on an 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. 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 public access stations based on prevailing market conditions. LNG generally costs more than CNG as LNG must be liquefied and transported, and the federal government imposes higher fuel taxes on LNG.

Government Incentives

        From October 1, 2006 through December 31, 2011, we were eligible to receive 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 claimed 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 American Taxpayer Relief Act, signed into law on January 2, 2013, reinstated VETC for calendar year 2013 and also made it retroactive to January 1, 2012. VETC revenues recognized during 2013 were $45.4 million, which includes $20.8 million for CNG and LNG we sold in 2012 that we recognized in January 2013.

Operation and Maintenance

        We generate a portion of our revenue from our performance of O&M for CNG and LNG fueling stations where we do not supply the fuel. 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

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volume of fuel dispensed at the stations at which we provide O&M services in our calculation of aggregate gasoline gallon equivalents delivered.

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. In May 2013, we purchased MGES for approximately $20.6 million. MGES is primarily engaged in the business of providing CNG station design and construction and CNG equipment repair and maintenance services.

Vehicle Acquisition and Finance

        We offer vehicle finance services for some of our customers' purchases of natural gas vehicles. 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 natural gas vehicles to certain of our customers 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. To help accelerate the conversion of heavy-duty truck fleets to natural gas, in 2013, we entered a strategic alliance with GE's Transportation Finance business. Fleet operators are eligible for loans and leases, including fair market value leases, from GE to acquire trucks from OEMs. In exchange for committing to purchase natural gas fuel from our stations, we then help offset the monthly cost of the vehicles to make it consistent with the cost of a diesel truck. Our goal is to work with fleet operators to achieve a one to two-year payback on the incremental cost of natural gas heavy-duty trucks, and our alliance with GE is a tool in achieving this goal. Through December 31, 2013, we have not generated significant income from vehicle financing activities.

RNG

        We own a 70% interest in a RNG production facility at the McCommas Bluff landfill located in Dallas, Texas. We sell specified levels of RNG produced at the facility to Shell Energy North America (US) L.P. under a gas sale agreement and, depending upon RNG production volumes, we have the ability to sell RNG produced by that facility as a vehicle fuel. We own a second RNG production facility located at a Republic Services landfill in Canton, Michigan. This facility was completed in 2012, and we have entered into a ten-year fixed-price sale contract for the majority of the RNG that we expect the facility to produce. We are building a third RNG facility at a Republic Services landfill in North Shelby, Tennessee, and we expect the facility to be operational during the first or second quarter of 2014. We are seeking to expand our RNG business by pursuing additional RNG production projects. We sell some of the RNG we currently produce, and expect to sell a significant amount of the RNG we produce at the facilities we are building and plan to build, through our natural gas fueling infrastructure for use as a vehicle fuel. In addition, we purchase RNG from third party producers, and sell that RNG for vehicle use through our fueling infrastructure. The RNG we sell for vehicle fuel use is distributed under the name Redeem .

Vehicle Conversions

        Prior to June 28, 2013, we owned BAF, a provider of natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF's vehicle conversions included taxis, vans, pick-up trucks and shuttle buses. BAF owned ServoTech Engineering, Inc. ("ServoTech"), which provided, among other services, design and engineering services

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for natural gas engine systems. We generated revenues through the sale of natural gas vehicles that had been converted to run on natural gas by BAF, and design and engineering services for natural gas engine systems by ServoTech. For the years ended December 31, 2012 and 2013, BAF and ServoTech contributed approximately $24.3 million, and $7.0 million, respectively, to our revenue. On June 28, 2013, we sold our ownership interest in BAF and its ServoTech subsidiary for approximately $27.2 million.

Natural Gas Fueling Compressors

        Our subsidiary, IMW, manufactures and services 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 U.S. For the years ended December 31, 2012 and 2013, IMW contributed approximately $64.5 million and $77.5 million, respectively, to our revenue.

Sales of RIN and LCFS Credits

        We generate LCFS Credits when we sell RNG and conventional natural gas for use as a vehicle fuel in California, and we generate RIN Credits when we sell RNG for use as a vehicle fuel. We can sell these credits to third parties who need the RIN and LCFS Credits to comply with federal and state requirements. In 2012, we realized $2.9 million in revenue through the sale of LCFS Credits. In 2013, we realized $4.8 million and $3.8 million in revenue through the sale of LCFS and RIN Credits, respectively. We anticipate that we will generate and sell increasing numbers of RIN and LCFS Credits as we grow our business and sell increasing amounts of CNG, LNG and RNG for use as a vehicle fuel. The market for RINs Credits and LCFS Credits is volatile, and the prices for such credits may be subject to significant fluctuations. Further, the value of RINs Credits and LCFS Credits will be adversely affected by any changes to the state and federal programs under which such credits are generated and sold.

Volatility of Earnings and Cash Flows Related to Derivative Activities

        During 2011, 2012, and 2013, our futures contracts qualified for hedge accounting, so we had no derivative gains or losses recognized in our consolidated statements of operations for these periods. 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 any of our 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, 2013, we had no margin deposits or futures contracts in place.

Volatility of Earnings Related to Series I Warrants

        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 $3.4 million and $0.9 million, respectively, related to

49


recording the estimated fair value changes of our Series I warrants in 2012 and 2013. See note 18 to our consolidated financial statements contained in this report. 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. As of December 31, 2013, 2,130,682 of the Series I warrants remained outstanding.

Volatility of Earnings and Cash Flows Related to Contingent Consideration

        Under business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisition of IMW in our financial statements through the contingency period, which expires on March 31, 2014.

        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 2012 and 2013, we recognized a gain of $4.1 million and $1.1 million, respectively, related to the estimated change in value of the IMW contingent consideration.

Debt Compliance

        In connection with our acquisition of IMW, we entered into a credit agreement with HSBC Bank Canada that requires IMW to comply with certain financial covenants (see note 9 to our consolidated financial statements). 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, 2013.

        The indenture and the loan agreement entered into by Dallas Clean Energy McCommas Bluff, LLC ("DCEMB"), our 70% owned subsidiary, 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, 2013, we were in compliance with these debt covenants.

        The loan agreements relating to the 7.5% Notes, as discussed in note 9 to our consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of December 31, 2013, we were in compliance with these debt covenants.

        The convertible note purchase agreements relating to the SLG Notes, as discussed in note 9 to our consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of December 31, 2013, we were in compliance with these covenants.

        The GE Credit Agreement, as discussed in note 9 to our consolidated financial statements, contains certain covenants with which we must comply. As of December 31, 2013, we were in compliance with these covenants.

        The Mavrix Note, as discussed in note 9 to our consolidated financial statements, contains certain debt covenants with which we must comply. As of December 31, 2013, we were in compliance with these covenants.

        The indenture relating to the 5.25% Notes, as discussed in note 9 to our consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of December 31, 2013, we were in compliance with these debt covenants.

Risk Management Activities

        From time to time, we enter natural gas fuel sales contracts that 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

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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 effectively hedge 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 our 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, if any, 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 assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements, and revenues and expenses recorded during the reporting periods.

        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

        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 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. Beginning on October 1, 2012, we performed our test for indefinite-lived intangible assets impairment under the amended guidance issued by the FASB in ASU 2012-02, Testing Indefinite-Lived Intangible Assets for Impairment , issued in July 2012, which we chose to early adopt, effective October 1, 2012. The amended requirements of ASU 2012-02 provide a similar framework for testing indefinite-lived intangible assets for impairment as ASU 2011-08 does for testing goodwill for impairment. There were no impairment charges for goodwill or indefinite-lived intangible asset resulting from the October 1, 2012 or 2013 impairment testing, and no events have occurred subsequent to October 1, 2013 which indicate impairment may have occurred as of December 31, 2013.

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        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 by both management and outside experts engaged to assist in this process.

        In 2012, we recorded an impairment charge of $14.5 million related to our investment in the Vehicle Production Group LLC ("VPG"), a company that was producing a natural gas vehicle made in the U.S. We had no impairment charges during 2011 or 2013.

Warranty Reserves

        Our warranty periods range up to twelve 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 future assumptions. If actual failure rates and the resulting cost of repair vary from our 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 and forward exchange 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 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, LNG and RNG 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

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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 and 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. The arrangement's consideration that is fixed or determinable is then allocated to each separate unit of accounting based on the estimated relative selling price of each deliverable, which is determined based on the historical data derived from our stand alone projects. The revenue allocated to the construction of the station is recognized using the completed-contract method. The revenue allocated to the O&M and sale of fuel is recognized ratably over the term of 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 fueling station construction projects where we sell the station to the customer using the completed-contract method. The construction contract is considered to be substantially completed at the earlier of customer acceptance of the fueling station or the time when the fuel dispensing activities begin. When applicable, multi-station construction contracts are segmented into phases as negotiated with customers. Gross margin related to each phase is recognized at its substantial completion. 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.

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.

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.

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        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.

Fair Value Estimates

        We have established a framework for measuring fair value in accordance with authoritative guidance. The framework includes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy consists of the following three levels: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2 inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and inputs (other than quoted prices) that are observable for the asset or liability, either directly or indirectly; Level 3 inputs are unobservable inputs for the asset or liability. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

        Our significant uses of fair value measurements include:

    Recorded values of available-for-sale securities,

    Allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed in those acquisitions,

    Assessments of impairment of long-lived assets,

    Assessments of impairment of goodwill,

    Recorded values of derivative instruments,

    Recorded values of contingent consideration obligations, and

    Recorded values of certain warrants to purchase our common stock.

Recently Issued Accounting Pronouncements

        See Note 1 to our consolidated financial statements contained in this report.

Results of Operations

Fiscal Year Ended December 31, 2013 Compared to Fiscal Year Ended December 31, 2012

        Revenue.     Revenue increased by $18.5 million to $352.5 million in the year ended December 31, 2013, from $334.0 million in the year ended December 31, 2012. A portion of this increase was the result of an increase in the number of gallons delivered between periods, from 194.9 million gasoline gallon equivalents to 214.4 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 13.4 million gallons. Our net increase in CNG volume was primarily from 28 new refuse customers, eight new airport customers, five new transit customers, and one new trucking customer, which together accounted for 7.1 million gallons of the CNG volume increase. We also experienced an increase of 14.5 million gallons in CNG volume between periods from our existing airport, refuse and trucking customers. These CNG gallon increases were offset by a decline of

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6.8 million gallons associated with the sale of our 49% interest in our Peruvian joint venture in March 2013 and 1.4 million gallons related to the loss of three CNG O&M stations for one transit customer. Further, we experienced an increase of 4.5 million gallons in LNG volume between periods, which was primarily due to 1.1 million gallons from seven new refuse, transit, trucking and industrial customers, and 4.8 million gallons from existing trucking, refuse, transit and industrial customers. These LNG gallon increases were offset by a decrease of 1.4 million gallons from one existing transit customer that is in the process of transitioning to CNG buses, and who will continue to be our customer. We experienced a 1.6 million gallons increase between periods in our RNG sales, primarily due to increased RNG production at DCEMB's facility and RNG production at our facility in Canton, Michigan that began in December 2012. Revenue attributable to VETC increased by $47.5 million between periods, including $20.8 million related to recording all of the 2012 VETC revenue in the first quarter of 2013 as a result of legislation passed in January 2013 that retroactively reinstated the fuel tax credit to January 1, 2012 and extended such credit to December 31, 2013. We recorded a $2.1 million reduction in VETC revenue in 2012 related to the settlement of our dispute with the IRS over certain VETC claims. Revenue attributable to IMW increased between periods by $13.0 million. Our effective price per gallon charged was $0.89 for the year ended December 31, 2013, which represents a $0.07 per gallon increase from $0.82 in the year ended December 31, 2012. The increase was primarily due to higher natural gas prices in 2013, upon which we base a portion of our pricing to our customers. LCFS and RIN Credit revenues also increased by $1.9 million between periods, primarily due to increased rates for the credits between periods. These increases were offset by a $17.3 million decrease in the sales of natural gas vehicle equipment and emission control services by BAF between periods (we sold BAF in June 2013). We also experienced a $57.7 million decrease in station construction revenue between periods, primarily due to the sale in 2012 of four large CNG stations to an existing transit customer that did not reoccur in 2013.

        Cost of sales.     Cost of sales decreased by $28.9 million to $224.8 million in the year ended December 31, 2013, from $253.7 million in the year ended December 31, 2012. Station construction costs decreased by $56.5 million between periods as station construction sales decreased between periods. Also contributing to the cost of sales decrease was a $11.8 million decrease in costs related to BAF's vehicle equipment sales and emission control services as we sold BAF in June 2013. These decreases were offset by the increased costs related to delivering and servicing more volume to our customers. Also offsetting the cost of sales decreases between periods was the increase in our effective cost per gallon. Our effective cost per gallon increased by $0.06 per gallon, from $0.52 per gallon to $0.58 per gallon for 2013. This increase was primarily the result of higher natural gas and LNG delivery costs between periods. Cost of sales at IMW increased between periods by $15.3 million primarily due to its increased sales between periods.

        Derivative (gain) loss on Series I warrant valuation.     Derivative gains decreased by $2.5 million to $0.9 million in the year ended December 31, 2013, from $3.4 million in the year ended December 31, 2012. These 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 in this report).

        Selling, general and administrative.     Selling, general and administrative expenses increased by $20.0 million to $138.0 million in the year ended December 31, 2013, from $118.0 million in the year ended December 31, 2012. Salaries and employee benefits increased by $4.5 million between periods, primarily due to higher average salaries and benefits per employee in 2013 compared to 2012, as we increased our sales force by 36 and hired more management level positions between periods to help support America's Natural Gas Highway and our continued business expansion. Also related to our expansion, we experienced a $6.9 million increase in consulting, legal, accounting and professional, business insurance, rent and occupancy, and natural gas policy and promotion expenses between periods. Further contributing to the increase between periods was the effect of recording $3.0 million of

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lower gains on the IMW contingent consideration in 2013 and an increase in our stock based compensation expense of $0.9 million in 2013. We also incurred moving expenses related to the move of our corporate headquarters to Newport Beach, California and costs related to vacating the offices we leased in Seal Beach, California, which amounted to $2.9 million. Our travel and entertainment expenses increased by $1.8 million between periods, primarily due to the increased travel of our sales team to develop new customers in the heavy-duty truck market.

        Depreciation and amortization.     Depreciation and amortization increased by $6.0 million to $42.3 million in the year ended December 31, 2013, from $36.3 million in the year ended December 31, 2012. This increase was primarily due to additional depreciation expense in 2013 related to increased property and equipment balances between periods, which primarily resulted from our expanded station network, including our efforts to build-out America's Natural Gas Highway.

        Interest expense, net.     Interest expense, net, increased by $13.2 million to $29.3 million for the year ended December 31, 2013, from $16.1 million for the year ended December 31, 2012. This increase was primarily the result of an increase in interest expense related to the $50.0 million of convertible notes we issued in July 2012, the $50.0 million of convertible notes we issued in June 2013, the aggregate $15.0 million advanced under the Mavrix Note in April, September and December 2013, and the $250.0 million of convertible notes we issued in September 2013 (see note 9 to our consolidated financial statements for a description of our outstanding debt).

        Other income (expense), net.     Other income (expense), net, decreased by $2.2 million to $1.0 million of expense for the year ended December 31, 2013, compared to income of $1.2 million for the year ended December 31, 2012. This decrease was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes (see note 9 to the consolidated financial statements).

        Income (loss) from equity method investment.     During 2013, we recorded $0.1 million of equity in the loss of our 49% interest in our Peruvian joint venture, compared to $0.3 million of equity in the income in 2012. We completed the sale of our interest in our Peruvian joint venture in March 2013.

        Gain from sale of equity method investment.     During 2013, we recorded a $4.7 million gain from the sale of our 49% interest in our Peruvian joint venture.

        Gain from sale of subsidiary.     During 2013, we recorded a $14.1 million gain from the sale of our former subsidiary, BAF.

        Loss (income) of noncontrolling interest.     During the years ended December 31, 2013 and 2012, we recorded $0 million and $0.4 million, respectively, for the noncontrolling interest in the net income of DCEMB. The noncontrolling interest represents the 30% interest of our joint venture partner.

Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

        Revenue.     Revenue increased by $41.3 million to $334.0 million in the year ended December 31, 2012, from $292.7 million in the year ended December 31, 2011. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 155.6 million gasoline gallon equivalents to 194.9 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 28.7 million gallons. Our net increase in CNG volume was primarily from 18 new refuse customers, 12 new airport customers, five new transit customers, one new station added for an existing transit customer, five new trucking customers, and one new public customer, which together accounted for 19.5 million gallons of the CNG volume increase. We also experienced an increase of 9.2 million gallons in CNG volume between periods from our existing airport, transit, refuse and trucking customers, combined with the volume growth from our share of our joint venture in Peru. Further, we experienced an increase of 8.4 million in LNG volume between periods, which was

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primarily due to a combination of 3.6 million gallons from Northstar O&M services and 4.8 million gallons from 12 new trucking, transit, industrial and refuse customers. We experienced an increase in our RNG sales (through our 70% share of the RNG sales at DCEMB) of 2.2 million gallons due to increased RNG production at DCEMB's facility. We experienced a $42.7 million increase, excluding Northstar and IMW, in station construction revenues between periods, primarily due to the completion of seven new CNG stations for new refuse customers, two CNG station upgrades for two existing refuse customers, one new CNG station for an existing refuse customer, five new CNG stations for new trucking customers, one new CNG station for an existing trucking customer, four new CNG stations for an existing transit customer, two new CNG stations for new transit customers, two CNG station upgrades for an existing transit customer, and one new CNG station for a new airport customer. Also contributing to the revenue increase between periods were $2.9 million of LCFS credits that we recognized in 2012 due to the lifting, during the year ended December 31, 2012, of a federal court injunction that had prohibited enforcement of the California Low Carbon Fuel Standard. Revenue also increased by $0.6 million between periods due to increased sales of natural gas vehicle equipment by BAF. 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 $0.81 for the year ended December 31, 2012, which represents a $0.05 per gallon decrease from $0.86 in the year ended December 31, 2011. The decrease was due to a combination of lower natural gas prices in 2012, upon which we base a portion of our pricing to our customers, and 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 attributable to VETC also decreased between periods because the credits were not available in 2012. However, subsequent to the 2012 year end, the credits were reinstated for 2013 and made retroactive to January 1, 2012. We recorded $17.9 million of revenue related to fuel tax credits in 2011, and we will record our 2012 VETC credits in the first quarter of 2013. We also recorded a $2.1 million reduction in revenue in 2012 related to the settlement of our dispute with the IRS over certain VETC claims. Revenue attributable to IMW and Northstar decreased between periods by $4.6 million and $4.3 million, respectively.

        Cost of sales.     Cost of sales increased by $37.0 million to $253.7 million in the year ended December 31, 2012, from $216.7 million in the year ended December 31, 2011. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. We also experienced a $41.4 million increase, excluding Northstar and IMW, in station construction costs between periods. We also experienced a $1.9 million increase in costs related to BAF's vehicle equipment sales between periods as BAF experienced certain production issues during the period. These increases were offset by a decrease in our effective cost per gallon of $0.11 per gallon, to $0.51 per gallon for 2012. This decrease was the result of lower natural gas costs and a higher percentage of O&M contracts in 2012, which generate a lower effective cost per gallon than contracts where we pay for the natural gas consumed at the stations. Costs that IMW and Northstar incurred decreased between periods by $7.4 million and $2.0 million, respectively.

        Derivative (gain) loss on Series I warrant valuation.     Derivative gains increased by $0.7 million to $3.4 million in the year ended December 31, 2012, from $2.7 million in the year ended December 31, 2011. These 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).

        Selling, general and administrative.     Selling, general and administrative expenses increased by $31.1 million to $118.0 million in the year ended December 31, 2012, from $86.9 million in the year ended December 31, 2011. The increase is primarily related to our continued business growth. Salaries and employee benefits increased by $11.1 million between periods, primarily due to a higher average employee headcount throughout 2012 as compared to 2011. During 2011, headcount increased from 710 at January 1, 2011 to 1,036 at December 31, 2011 as we increased our workforce to build the initial

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phase of America's Natural Gas Highway and to prepare for our anticipated business growth. During 2012, our headcount remained fairly constant with 1,038 employees at December 31, 2012. We experienced a $9.5 million increase in consulting, employee recruiting, business insurance, rent and occupancy, research and development, software/hardware maintenance and office supplies expenses between periods. Our travel and entertainment expenses increased by $2.2 million between periods, primarily due to the increased travel of our sales team to support our continued business growth and to develop new customers in the heavy-duty trucking market. Our bad debt expense increased $1.0 million between periods principally related to our vehicle financing activities. Also contributing to the increase between periods was an increase in stock based compensation expense of $8.6 million. These increases were offset by $1.3 million in additional gains in 2012 related to a decrease in the estimated fair value of the IMW contingent consideration liability between periods.

        Depreciation and amortization.     Depreciation and amortization increased by $5.9 million to $36.3 million in the year ended December 31, 2012, from $30.4 million in the year ended December 31, 2011. This increase was primarily due to additional depreciation expense in 2012 related to increased property and equipment balances between periods, primarily related to our expanded station network, including our build-out efforts of America's Natural Gas Highway. In addition, our amortization expense in 2012 includes increased amortization expense related to our ServoTech acquisition that we completed on April 30, 2012.

        Interest expense, net.     Interest expense, net, increased by $6.5 million to $16.1 million for the year ended December 31, 2012, from $9.6 million for the year ended December 31, 2011. This increase was primarily the result of an increase in interest expense due to the $200 million of convertible notes we issued in July and August of 2011 that had a full year of interest expense in 2012, and the additional $50 million convertible note we issued to Chesapeake in July 2012. (see note 9 to the consolidated financial statements for a full description of our outstanding debt).

        Other income (expense), net.     Other income (expense), net, increased by $1.8 million to $1.2 million of income for the year ended December 31, 2012, compared to expense of $0.6 million for the year ended December 31, 2011. This increase was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes (see note 9 to the consolidated financial statements).

        Impairment of cost method investment.     During the fourth quarter of 2012, we determined there was a decrease in value of our cost method investment in The Vehicle Production Group, LLC that was other than temporary and accordingly recognized an impairment charge for the full value of our investment of $14.5 million.

        Income (loss) from equity method investment.     During 2012, we recorded $0.3 million of equity in the income of our 49% interest in our Peruvian joint venture, compared to $0.6 million in 2011.

        Loss (income) of noncontrolling interest.     During the years ended December 31, 2012 and 2011, we recorded $0.4 million and $0.2 million, respectively, for the noncontrolling interest in the net income of DCEMB. 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.

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        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

        We require cash to fund our capital expenditures, operating expenses and working capital requirements, including outlays for the construction of fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in RNG production, 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 and regulatory initiatives and for working capital. Our principal sources of liquidity are cash on hand and cash provided by financing activities.

Liquidity

        Cash used in operating activities was $4.7 million in 2013, compared to $19.8 million in 2012. The increase was primarily due to collecting additional VETC amounts of $39.3 million between periods. See note 1 to our consolidated financial statements contained elsewhere in this report for a discussion of the timing and availability of VETC. Offsetting this cash flow increase were increased selling, general and administrative expenses and interest expense charges during 2013. We also experienced other working capital changes between periods due to timing differences related to various cash flows.

        Cash used in investing activities was $155.0 million in 2013, compared to $163.9 million in 2012. We purchased property and equipment of $86.7 million in 2013, which is a decrease of $106.2 million from $192.9 million paid to purchase property and equipment in 2012. This decrease is primarily related to our slowing the pace of ANGH-related construction activity as we seek to time such construction with commercial adoption of natural gas trucks. During 2013, our restricted cash balances decreased by $13.3 million as we funded the construction of America's Natural Gas Highway and certain RNG projects during the period, and decreased by $37.9 million in 2012 as we funded similar projects during that period. During 2013, we received $6.1 million related to the sale of our Peruvian joint venture, paid $9.0 million related to the purchase of MGES, and transferred BAF's cash balance of $1.2 million to the buyer in connection with the sale of that entity. The loans we made to our customers to assist them in purchasing natural gas vehicles decreased to $4.0 million in 2013, from $10.5 million in 2012. During 2013 and 2012, we also collected on or sold $4.2 million and $8.3 million, respectively, of loans previously made to our customers. Additionally, we purchased a net amount of $77.6 million of short-term investments during 2013, compared to a net purchase of $5.6 million during 2012. Included in the 2013 amount is $23.7 million we received when we sold certain of the shares of common stock of Westport Innovations that we received as consideration for the sale of BAF in June 2013 (see note 2 to our consolidated financial statements contained in this report). During 2012, we made additional investments of $1.4 million in VPG, a company producing a CNG taxi and a paratransit vehicle.

        Cash provided by financing activities in 2013 was $290.7 million, compared to $53.6 million in 2012. In 2013, we received $50.0 million upon the issuance of additional 7.5% Notes, $15.0 million under the Mavrix Note, and $242.2 million upon the issuance of the 5.25% Notes, and paid $9.1 million of issuance costs related to the debt offerings. These increases were offset by a reduction in the proceeds we received from the exercise of employee stock options of $8.3 million between periods.

        Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, the level of any outstanding indebtedness and the

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interest we are obligated to pay on our 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.

Sources of Cash

        Historically, our principal sources of liquidity have consisted of cash provided by financing activities. At December 31, 2013 we had total cash and cash equivalents of $240.0 million, compared to $108.5 million at December 31, 2012.

        On November 7, 2012, we, through two wholly owned subsidiaries (the "Borrowers"), entered into a credit agreement with GE (the "GE Credit Agreement"). Pursuant to that agreement, GE agreed to loan to the Borrowers up to an aggregate of $200.0 million to finance the development, construction and operation of two LNG production facilities, each with an expected production capacity of approximately 250,000 LNG gallons per day. At December 31, 2013, the Borrowers had not drawn any amounts under the agreement.

        On April 25, 2013, Mavrix entered into a note purchase agreement pursuant to which the purchaser thereunder purchased the Mavrix Note in the maximum aggregate principal amount of $30.0 million and, as of December 31, 2013, has drawn $15.0 million under the Mavrix Note.

        On June 14, 2013, Boone Pickens and Green Energy Investment Holdings, LLC delivered $50.0 million to us in satisfaction of a funding requirement they had assumed from Chesapeake.

        In September 2013, we completed a private offering of the 5.25% Notes. The net proceeds from the sale of the 5.25% Notes after the payment of certain debt issuance costs of $7.8 million were approximately $242.2 million, which we intend to use to fund capital expenditures and for general corporate purposes.

Capital Expenditures

        Our business plan calls for approximately $135.0 million in capital expenditures in 2014, primarily related to construction of fueling stations, including stations along ANGH, expansion of our California LNG plant, development of two new LNG production facilities, 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, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. 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 when needed on terms that are favorable to us or 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.

60


Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of December 31, 2013:

 
  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)

  $ 818,774   $ 65,640   $ 228,656   $ 363,447   $ 161,031  

Operating lease commitments(b)

    61,620     8,493     15,161     12,284     25,682  

"Take or pay" LNG purchase contracts(c)

    22,125     6,607     11,625     3,893      

Construction contracts(d)

    35,021     35,021              

DCEMB electricity contract(e)

    3,149     1,647     1,502          
                       

Total

  $ 940,689   $ 117,408   $ 256,944   $ 379,624   $ 186,713  
                       
                       

(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 four "take-or-pay" contracts.

(d)
Consists of our obligations to fund various fueling station construction projects, net of amounts funded through December 31, 2013, 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, 2013, 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 $68.6 million,

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

    operating leases where we are the lessee, and

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

        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 four contracts that require us to purchase minimum volumes of LNG at index based prices. One contract expires in June 2014, two contracts expire in December 2015, and one 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

61


dates through 2021. 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 $0.2 million per year, plus up to $0.1 million 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.

        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 16% (or 21% excluding BAF, IMW and Northstar) of our cost of sales for 2012 and 25% (or 31% excluding BAF, IMW and Northstar) for 2013.

        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.

        In prior years, we have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we held as of the end of our latest fiscal year to hedge the fixed price component of our supply contracts. That sensitivity analysis generally reflects the expected fluctuation in the value of any such contracts if the price of natural gas were to fluctuate (increase or decrease) by a specified percentage from the price quoted on NYMEX as of the end of our latest fiscal year. We did not perform such a sensitivity analysis as of December 31, 2013 because we did not have any futures contract outstanding at December 31, 2013.

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        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 $0.2 million of gains in 2013. During 2013, 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, 2013, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $0.2 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, 2013. The information for each quarter is unaudited and the Company has prepared the information on the same basis as the audited consolidated financial statements appearing elsewhere in this annual report on 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 annual report on Form 10-K. The results of operations for any one quarter are not necessarily indicative of results for any future period.

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

 
  For the Quarter Ended  
 
  March 31,
2012
  June 30,
2012
  September 30,
2012
  December 31,
2012
 

Revenue:

                         

Product revenues

  $ 65,776   $ 57,705   $ 82,720   $ 87,576  

Service revenues

    7,858     12,137     8,739     11,497  
                   

Total revenues

    73,634     69,842     91,459     99,073  

Operating expenses:

                         

Cost of sales (exclusive of depreciation and amortization shown separately below):

                         

Product cost of sales

    51,902     43,691     67,392     73,486  

Service cost of sales

    3,984     4,839     3,839     4,551  

Derivative (gains) losses:

                         

Series I warrant valuation

    13,506     (8,899 )   (5,692 )   (2,306 )

Selling, general and administrative

    24,850     27,916     30,557     34,653  

Depreciation and amortization

    8,144     8,907     9,047     10,163  
                   

Total operating expenses

    102,386     76,454     105,143     120,547  
                   

Operating loss

    (28,752 )   (6,612 )   (13,684 )   (21,474 )

Interest expense, net

    (3,702 )   (3,321 )   (4,314 )   (4,732 )

Other income (expense), net

    841     (1,177 )   1,914     (342 )

Impairment of cost method investment

                (14,544 )

Income from equity method investments

    91     72     152     16  
                   

Loss before income taxes

    (31,522 )   (11,038 )   (15,932 )   (41,076 )

Income tax expense

    (246 )   (172 )   (277 )   (599 )
                   

Net loss

    (31,768 )   (11,210 )   (16,209 )   (41,675 )

Income of noncontrolling interest

    (137 )   (84 )   (112 )   (60 )
                   

Net loss attributable to Clean Energy Fuels Corp. 

  $ (31,905 ) $ (11,294 ) $ (16,321 ) $ (41,735 )
                   
                   

Basic loss per share

  $ (0.37 ) $ (0.13 ) $ (0.19 ) $ (0.46 )
                   
                   

Fully diluted loss per share

  $ (0.37 ) $ (0.13 ) $ (0.19 ) $ (0.46 )
                   
                   

64



 
  For the Quarter Ended  
 
  March 31,
2013
  June 30,
2013
  September 30,
2013
  December 31,
2013
 

Revenue:

                         

Product revenues

  $ 83,483   $ 78,375   $ 75,389   $ 73,566  

Service revenues

    9,560     9,741     10,932     11,429  
                   

Total revenues

    93,043     88,116     86,321     84,995  

Operating expenses:

                         

Cost of sales (exclusive of depreciation and amortization shown separately below):

                         

Product cost of sales

    46,814     58,925     51,941     55,913  

Service cost of sales

    3,927     3,016     2,866     1,360  

Derivative (gains) losses:

                         

Series I warrant valuation

    466     39     (1,366 )   (77 )

Selling, general and administrative

    32,876     35,187     33,511     36,450  

Depreciation and amortization

    10,158     10,777     10,924     10,459  
                   

Total operating expenses

    94,241     107,944     97,876     104,105  
                   

Operating loss

    (1,198 )   (19,828 )   (11,555 )   (19,110 )

Interest expense, net

    (5,071 )   (6,282 )   (7,418 )   (10,516 )

Other income (expense), net

    (390 )   (1,103 )   736     (213 )

Loss from equity method investments

    (76 )            

Gain from sale of equity method investment

    4,705              

Gain (loss) from sale of subsidiary

        15,498         (1,383 )
                   

Loss before income taxes

    (2,030 )   (11,715 )   (18,237 )   (31,222 )

Income tax expense

    (1,805 )   (293 )   (558 )   (1,059 )
                   

Net loss

    (3,835 )   (12,008 )   (18,795 )   (32,281 )

Income (loss) of noncontrolling interest

    (36 )   65     (41 )   (37 )
                   

Net loss attributable to Clean Energy Fuels Corp. 

  $ (3,871 ) $ (11,943 ) $ (18,836 ) $ (32,318 )
                   
                   

Basic loss per share

  $ (0.04 ) $ (0.13 ) $ (0.20 ) $ (0.34 )
                   
                   

Fully diluted loss per share

  $ (0.04 ) $ (0.13 ) $ (0.20 ) $ (0.34 )
                   
                   

65


Item 8.    Financial Statements and Supplementary Data.

INDEX TO FINANCIAL STATEMENTS

 
  Page

Consolidated Financial Statements

   

Report of Independent Registered Public Accounting Firm

  67

Consolidated Balance Sheets as of December 31, 2012 and 2013

  69

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2012, and 2013

  70

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2012, and 2013

  71

Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2011, 2012, and 2013

  72

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2012, and 2013

  73

Notes to Consolidated Financial Statements

  74

Financial Statement Schedule

   

Schedule II—Valuation and Qualifying Accounts

  121

66


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, 2012 and 2013, and the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, we have also audited the related financial statement schedule. We also have audited the Company's internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these consolidated financial statements, 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, 2012 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted

67


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 aspects, 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, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ KPMG LLP

Irvine, California
February 27, 2014

68



CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 
  December 31,
2012
  December 31,
2013
 

Assets

             

Current assets:

             

Cash and cash equivalents

  $ 108,522   $ 240,033  

Restricted cash

    8,445     8,403  

Short-term investments

    38,175     138,240  

Accounts receivable, net of allowance for doubtful accounts of $905 and $832 as of December 31, 2012 and December 31, 2013, respectively

    57,594     53,473  

Other receivables

    17,808     26,285  

Inventory, net

    38,152     33,822  

Prepaid expenses and other current assets

    16,002     20,840  
           

Total current assets

    284,698     521,096  

Land, property and equipment, net

    428,177     487,854  

Restricted cash

    13,208      

Notes receivable and other long-term assets

    71,389     73,697  

Investments in other entities

    2,581      

Goodwill

    75,865     88,548  

Intangible assets, net

    99,282     79,770  
           

Total assets

  $ 975,200   $ 1,250,965  
           
           

Liabilities and Stockholders' Equity

             

Current liabilities:

             

Current portion of long-term debt and capital lease obligations

  $ 30,389   $ 23,401  

Accounts payable

    39,216     33,541  

Accrued liabilities

    30,794     46,745  

Deferred revenue

    13,521     16,419  
           

Total current liabilities

    113,920     120,106  

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

    300,636     532,017  

Long-term debt, related party

        65,000  

Other long-term liabilities

    14,014     15,304  
           

Total liabilities

    428,570     732,427  

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 87,634,478 shares and 89,364,397 shares at December 31, 2012 and December 31, 2013, respectively

    9     9  

Additional paid-in capital

    837,367     883,045  

Accumulated deficit

    (300,814 )   (367,782 )

Accumulated other comprehensive income (loss)

    6,151     (700 )
           

Total Clean Energy Fuels Corp. stockholders' equity

    542,713     514,572  

Noncontrolling interest in subsidiary

    3,917     3,966  
           

Total stockholders' equity

    546,630     518,538  
           

Total liabilities and stockholders' equity

  $ 975,200   $ 1,250,965  
           
           

   

See accompanying notes to consolidated financial statements.

69



CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share data)

 
  Years Ended December 31,  
 
  2011   2012   2013  

Revenue:

                   

Product revenues

  $ 260,283   $ 293,777   $ 310,813  

Service revenues

    32,434     40,231     41,662  
               

Total revenue

    292,717     334,008     352,475  

Operating expenses:

                   

Cost of sales (exclusive of depreciation and amortization shown separately below):

                   

Product cost of sales

    200,908     236,471     213,593  

Service cost of sales

    15,776     17,213     11,169  

Derivative gains:

                   

Series I warrant valuation

    (2,655 )   (3,391 )   (938 )

Selling, general and administrative

    86,850     117,976     138,024  

Depreciation and amortization

    30,406     36,261     42,318  
               

Total operating expenses

    331,285     404,530     404,166  
               

Operating loss

    (38,568 )   (70,522 )   (51,691 )

Interest expense, net

    (9,616 )   (16,069 )   (29,287 )

Other income (expense), net

    (611 )   1,236     (970 )

Impairment of cost method investment

        (14,544 )    

Income (loss) from equity method investments

    637     331     (76 )

Gain from sale of equity method investment

            4,705  

Gain from sale of subsidiary

            14,115  
               

Loss before income taxes

    (48,158 )   (99,568 )   (63,204 )

Income tax (expense) benefit

    703     (1,294 )   (3,715 )
               

Net loss

    (47,455 )   (100,862 )   (66,919 )

Income of noncontrolling interest

    (178 )   (393 )   (49 )
               

Net loss attributable to Clean Energy Fuels Corp.          

  $ (47,633 ) $ (101,255 ) $ (66,968 )
               
               

Loss per share:

                   

Basic and diluted

  $ (0.68 ) $ (1.16 ) $ (0.71 )
               
               

Weighted average common shares outstanding:

                   

Basic and diluted

    70,415,431     87,455,073     93,958,758  
               
               

   

See accompanying notes to consolidated financial statements.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

 
  Year Ended December 31, 2011   Year Ended December 31, 2012   Year Ended December 31, 2013  
 
  Clean Energy
Fuels Corp
  Noncontrolling
Interest
  Total   Clean Energy
Fuels Corp
  Noncontrolling
Interest
  Total   Clean Energy
Fuels Corp
  Noncontrolling
Interest
  Total  

Net income (loss)

  $ (47,633 ) $ 178   $ (47,455 ) $ (101,255 ) $ 393   $ (100,862 ) $ (66,968 ) $ 49   $ (66,919 )

Other comprehensive income, net of tax:

                                                       

Foreign currency translation adjustments

    2,101         2,101     4,030         4,030     (1,680 )       (1,680 )

Foreign currency adjustments on intra-entity long-term investments

    (1,286 )       (1,286 )   1,218         1,218     (4,834 )       (4,834 )

Unrealized losses on available-for sale securities

    (126 )       (126 )   (32 )       (32 )   (445 )       (445 )

Unrecognized gains on derivatives

    2,091         2,091     2,151         2,151     108         108  
                                       

Total other comprehensive income (loss), net of tax

    2,780         2,780     7,367         7,367     (6,851 )       (6,851 )
                                       

Comprehensive income (loss)

  $ (44,853 ) $ 178   $ (44,675 ) $ (93,888 ) $ 393   $ (93,495 ) $ (73,819 ) $ 49   $ (73,770 )
                                       
                                       

See accompanying notes to consolidated financial statements.

71


CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands, except share data)

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

Balance, December 31, 2010

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

Issuance of common stock upon exercise of options

    221,234         1,477                 1,477  

Issuance of common stock, net of offering costs

    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) income

                (47,633 )       178     (47,455 )

Accumulated other comprehensive income

                    2,780         2,780  
                               

Balance, December 31, 2011

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

Issuance of common stock upon exercise of options

    1,568,480         8,969                 8,969  

Issuance of common stock, net of offering costs

    632,740         8,503                 8,503  

Issuance of warrants in connection with the GE Credit Agreement

            56,158                 56,158  

Stock-based compensation

            22,087                 22,087  

Net (loss) income)

                (101,255 )       393     (100,862 )

Accumulated other comprehensive income

                    7,367         7,367  
                               

Balance, December 31, 2012

    87,634,478     9     837,367     (300,814 )   6,151     3,917     546,630  

Issuance of common stock upon exercise of options

    119,349         677                 677  

Issuance of common stock, net of offering costs

    1,610,570         21,993                 21,993  

Stock-based compensation

            23,008                 23,008  

Net (loss) income

                (66,968 )       49     (66,919 )

Accumulated other comprehensive loss

                    (6,851 )       (6,851 )
                               

Balance, December 31, 2013

    89,364,397   $ 9   $ 883,045   $ (367,782 ) $ (700 )   3,966   $ 518,538  
                               
                               

See accompanying notes to consolidated financial statements.

72



CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
  Years Ended December 31,  
 
  2011   2012   2013  

Cash flows from operating activities :

                   

Net loss

  $ (47,455 ) $ (100,862 ) $ (66,919 )

Adjustments to reconcile net loss to net cash used in operating activities:

                   

Depreciation and amortization

    30,406     36,261     42,318  

Asset impairments

        14,544      

Provision for doubtful accounts and notes

    344     1,358     1,962  

Derivative gain

    (2,655 )   (3,391 )   (938 )

Stock-based compensation expense

    13,473     22,087     23,008  

Amortization of debt issuance cost

    339     551     1,662  

Accretion of notes payable

    2,731     2,016     1,140  

Gain on sale of equity method investment

            (4,705 )

Dividend received on equity method investment

            1,091  

Gain on sale of subsidiary

            (14,115 )

Gain on contingent consideration for acquisitions

    (2,828 )   (4,112 )   (1,132 )

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

                   

Accounts and other receivables

    (137 )   1,832     (441 )

Inventory

    (14,782 )   (1,879 )   (637 )

Margin deposits on futures contracts

    2,981     3,000      

Prepaid expenses and other assets

    (14,709 )   4,201     579  

Accounts payable

    324     (328 )   (6,962 )

Accrued expenses and other

    4,832     4,966     19,395  
               

Net cash used in operating activities

    (27,136 )   (19,756 )   (4,694 )

Cash flows from investing activities:

                   

Purchases of short-term investments

    (33,329 )   (55,062 )   (170,935 )

Maturities and sales of short-term investments

        49,504     93,289  

Purchases of property and equipment

    (66,687 )   (192,894 )   (86,730 )

Loans made to customers

    (5,591 )   (10,521 )   (3,950 )

Payments on and proceeds from sales of loans receivable

    2,508     8,251     4,153  

Restricted cash

    (57,096 )   37,943     13,250  

Acquisitions, net of cash acquired

    (1,000 )   269     (9,000 )

Cash transferred with sale of subsidiary

            (1,178 )

Investments in other entities

    (4,712 )   (1,437 )    

Proceeds from sale of equity method investment

            6,119  
               

Net cash used in investing activities

    (165,907 )   (163,947 )   (154,982 )

Cash flows from financing activities:

                   

Proceeds from minority interest DCE equity contribution

    417          

Proceeds from exercise of warrants

    150,000          

Proceeds from issuance of common stock and exercise of stock options

    1,477     8,969     677  

Proceeds from debt instruments

    244,455     50,612     300,559  

Proceeds from debt, related party

            15,000  

Proceeds from revolving line of credit

    53,595     39,164     31,527  

Repayment of borrowings under revolving line of credit

    (49,589 )   (34,735 )   (37,767 )

Repayment of capital lease obligations and debt instruments

    (17,079 )   (10,040 )   (10,147 )

Contingent consideration paid relating to business acquisitions

    (2,394 )   (350 )    

Payment for debt issuance costs

    (3,054 )       (9,130 )
               

Net cash provided by financing activities

    377,828     53,620     290,719  

Effect of exchange rates on cash and cash equivalents

    (1,854 )   480     468  
               

Net increase (decrease) in cash and cash equivalents

    182,931     (129,603 )   131,511  

Cash and cash equivalents, beginning of year

    55,194     238,125     108,522  
               

Cash and cash equivalents, end of year

  $ 238,125   $ 108,522   $ 240,033  
               
               

Supplemental disclosure of cash flow information:

                   

Income taxes paid

  $ 783   $ 1,160   $ 2,228  
               
               

Interest paid, net of $1,352, $6,304, and $2,517 capitalized, respectively

  $ 6,744   $ 13,994   $ 22,110  
               
               

   

See accompanying notes to consolidated financial statements.

73



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," unless the context of the use of the term indicates or requires otherwise) is engaged in the business of selling natural gas fueling solutions to its customers, primarily in the United States and Canada.

        The Company has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse, and public transit. The Company owns, operates, maintains and/or supplies over 470 natural gas fueling stations within the United States, and in British Columbia and Ontario within Canada. The Company generates revenue through selling compressed natural gas ("CNG") and liquefied natural gas ("LNG"), providing operation and maintenance services ("O&M") to customers, building and selling natural gas fueling stations to customers, manufacturing and servicing natural gas fueling compressors and other equipment for CNG and LNG fueling stations, offering solutions designed to provide operators with code-compliant maintenance facilities to service their natural gas vehicle fleets, processing and selling renewable natural gas ("RNG"), financing customers' vehicle purchases and selling tradable credits the Company generates by selling natural gas and RNG as a vehicle fuel, including credits ("LCFS Credits") under the California low carbon fuel standard and Renewable Identification Numbers ("RIN Credits") under the federal Renewable Fuel Standard Phase 2. In addition, through June 28, 2013, the Company provided natural gas vehicle conversions and design and engineering services for natural gas engine systems (see note 2).

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 periods. 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.

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)

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.

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, 2012 and 2013:

 
  2012   2013  

Raw materials and spare parts

  $ 30,137   $ 30,521  

Work in process

    5,835     3,011  

Finished goods

    2,180     290  
           

Total

  $ 38,152   $ 33,822  
           
           

Property and Equipment

        Property and equipment are recorded at cost. Depreciation and amortization are recognized over the estimated useful lives of the assets using the straight-line method. The estimated useful lives of depreciable assets are 20 years for LNG liquefaction plant assets, 10 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 $3,090, $5,908, and $3,114 for the years ended December 31, 2011, 2012 and 2013, 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.

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. The Company assesses its goodwill and indefinite lived

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)

intangible assets for impairment annually on October 1, or more frequently if a triggering event occurs between impairment testing dates. The Company's impairment assessment begins with a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. The qualitative assessment includes assessing the potential impact on a reporting units fair value of certain events and circumstances, including the Company's market capitalization value, macroeconomic conditions, industry and market considerations, cost factors, and other relevant entity-specific events. If it is determined, based upon the qualitative assessment, that it is more likely than not that the reporting unit's fair value is less than its carrying amount, then a two-step quantitative impairment test is performed. 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.

        Beginning on October 1, 2012, the Company performed its test for indefinite-lived intangible assets impairment under the amended guidance issued by the FASB in ASU 2012-02, Testing Indefinite-Lived Intangible Assets for Impairment , issued in July 2012, which the Company chose to early adopt. The amended requirements of ASU 2012-02 provided a similar framework for testing indefinite-lived intangible assets for impairment as the ASU 2011-08 does for testing goodwill for impairment.

        There were no impairment charges for goodwill or indefinite-lived intangible assets resulting from the October 1, 2011, 2012 or 2013 impairment testing, and no events have occurred subsequent to October 1, 2013 that indicate impairments may have occurred. The Company reduced its goodwill balance by $774 when it sold BAF on June 28, 2013, and added $16,555 of goodwill on May 6, 2013 when it acquired MGES. The goodwill balances on the consolidated balance sheets include foreign currency translation gains (losses) of $2,124 and $(3,098) as of December 31, 2012 and 2013, respectively.

        Intangible assets with finite useful lives are amortized over their respective estimated useful lives using the straight-line method. The estimated useful lives of intangible assets with finite useful lives are two to 20 years for technology, one to 16 years for lease agreements, one to eight years for customer relationships, one to 10 years for acquired contracts, two to 20 years for trademarks and trade names, and three years for non-compete agreements. The intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

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)

        The Company's intangible assets as of December 31, 2012 and 2013 were as follows:

 
  2012   2013  

Technology

  $ 57,595   $ 54,400  

Lease agreements

    21,645     21,045  

Customer relationships

    23,334     12,791  

Acquired contracts

    13,075     13,121  

Trademark and tradenames

    7,400     6,700  

Non-compete agreements

    2,126     2,126  
           

Total intangible assets

    125,175     110,183  

Less accumulated amortization

    (30,632 )   (30,003 )

Foreign currency rate change

    4,739     (410 )
          <