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Rosenblatt Energy Research April, 2013

Macro Energy, Transportation, and Infrastructure

Alternative Natural Gas Demand: It’s Not Just Trucking Anymore

Jeffrey Campbell, Managing Director, Senior Analyst, Energy, Rosenblatt Securities Dr. Walter Kemmsies, Chief Economist, Rosenblatt Securities; Chief Economist, Moffat & Nichol

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Table of Contents

Research Report Conclusions ....................................................................................................................... 2

Glossary of Acronyms Used in This Report ................................................................................................. 5

Dissecting the Low-Case: U.S. NG Supply, Demand and Pricing Effects .................................................. 6

Fleshing Out the Mid-Case Adoption Scenario .......................................................................................... 17

Big E&P’s: Early Adopters ......................................................................................................................... 18

CNG/LNG Takes on Oil-Based Fuels in Transportation ............................................................................ 22

Light Duty Vehicles .................................................................................................................................... 26

Fleet Focus: Buses and Refuse Trucks, Earliest Adopters of NGT ........................................................... 31

Fleet Focus: Class 8 Combo Trucks, an LNG Opportunity ....................................................................... 33

Railroad Locomotives ................................................................................................................................. 38

Marine Engine Applications ....................................................................................................................... 43

The High Case: A Step-Change Storage Breakthrough ............................................................................. 49

Consensus Forecasts and Historical Valuation Data of Companies in This Report ................................... 54

Major Research Sources ............................................................................................................................. 56

A Final Point About Our Approach to Macro Research ............................................................................. 56

Focus Companies ........................................................................................................................................ 57

Rosenblatt Energy Research Analysts ........................................................................................................ 59

3 Rosenblatt Securities Contact: Jeffrey Campbell (212) 607-3177; [email protected]

Research Report Conclusions

Alternative Natural Gas Consumption Will Accelerate

Our work suggests that adoption of natural gas (NG) as a fuel alternative to diesel will accelerate. This alternative NG adoption is wide-reaching and driven by the following five forces:

• The wide and durable price spread between natural gas and oil-based fuels

• “Sweet spot” natural gas truck engines have arrived in 2013

• Freight transportation modalities are interconnected

• Ports are the locus of freight interconnectedness

• Environmental strictures must be met if ports are to grow

Throughout the report--which identifies 50 companies in 16 sectors levered to alternative NG consumption trends--we look at barriers and impediments as critically as we do positive drivers to arrive at forecasts which we believe are both feasible and potentially conservative.

Our Low-Case NG Adoption Forecast to 2020 of 1.9 Bcf/d assumes a durable $0.50 price spread between NG and oil-based fuels. The research closely examines possible reasons why current NG/crude oil price spreads could narrow: growing NG use in power plants; potential U.S. Liquefied Natural Gas (LNG) export; horizontal drilling and hydraulic fracturing with environmental issues around same; Estimated Ultimate Recovery (EUR) and the fecundity of shale gas; growing consumption of ultra-low sulphur diesel.

Our Mid-Case NG Adoption Forecast to 2020 of 3.1 Bcf/d (our base case) assumes a durable $1.00 price spread between NG and oil-based fuels. The Mid-Case research details potentially large NG consumption in stationary engines in the E&P industry, confirms the composition of light-duty and heavy-duty truck fleets, looks at the economics of switching to NG, and explains and models their replacement cycle dynamics as the basis for future vehicle adoption. Evolutionary NG storage solutions and growing refueling options for NG vehicles are scrutinized. LNG as railroad locomotive fuel is explored and modeled, and an important new trend in rail haul is examined. Stricter emission standards being enforced at ports—a major structural catalyst of NG fuel adoption—is investigated and modeled.

Sectors favored by our Mid-Case adoption scenario include the following businesses and companies: ship builders General Dynamics (GD); package delivery United Parcel Service (UPS); truck leasers Ryder System, Inc. (R); truck transporters Swift Transportation (SWFT); refuse handlers Waste

mailto:[email protected];%[email protected]


Management (WA), Republic Services, Inc. (RSG); railroads Kansas City Southern (KSU), Canadian National Railway Company (CNI); on-shore fuel producers and providers Apache Energy (APA), Clean Energy (CLNE), Encana (ECA), Royal Dutch Shell Plc (RDS-A); TravelCenters of America (TA), Susser Holdings (SUSS); waterbourne LNG producers Cheniere Energy, Inc. (LNG), Sempra Energy (SRE), RD; producers of NG engines and NG conversion components General Electric Company (GE), Caterpillar (CAT), Cummins (CMI), Westport Innovations (WPRT); vehicle NG storage providers 3M (MMM), Quantum Technologies (QTWW), WPRT; light duty and heavy duty Original Equipment Manufacturer (OEM)s Ford (F), General Motors (GM), Paccar (PCAR) Volvo Corporation (VOLVY); E&P companies with extensive low-cost U.S. NG operations APA, Anadarko Petroleum (APC), Cabot Oil and Gas (COG) Devon Energy (DVN), ECA, EOG Resources (EOG), Noble Energy (NBL), Range Resources (RRC), Southwestern Energy (SWN) and oil services companies Halliburton (HAL), Baker-Hughes (BHI), Schlumberger (SLB). We provide a High-Case Adoption Forecast to 2020 of 3.1 Bcf/d. The High Case explores cutting edge NG storage and home fueling solutions, both of which will be required for NG adoption and gasoline displacement in consumer vehicles. As we do not expect meaningful commercialization before 2020-30 timeframe our Mid-Case model is not impacted.



Glossary of Some Acronyms Used in This Report Billion Cubic Feet per Day (Bcf/d) CNG pressure vessel (CNGPV) Coal-to-Gas Fuel Switching (CTG) Compressed Natural Gas (CNG) Compressed Natural Gas Pressure Vessel Emission Control Area (ECA) Environmental Defense Fund (EDF) Environmental Protection Agency (EPA) Estimated Ultimate Recovery (EUR) European Union (EU) Federal Motor Carrier Safety Act (FMCSA) Heavy-Duty vehicle (HDV) Henry Hub (HH) High Pressure Direct Injection (HPDI) Horsepower (hp) Internal Combustion Engine (ICE) Light Duty Vehicle (LDV) Liquefied Natural Gas (LNG) Louisiana Light Sweet (LLS) Marine Gas Oil (MGO) Metal Organic Framework (MOF) Natural Gas (NG) Natural Gas Liquids (NGL) Natural Gas Vehicle (NGV) Natural Gas Transportation (NGT) Naturally Occurring Radioactive Materials (NORM) Original Equipment Manufacturer (OEM) Powder River Basin (PRB) Pressure Pumping (pp) Qualified Vehicle Modifiers (QVM) Ultra-Low Sulphur Diesel (ULSD)



Dissecting the Low-Case: U.S. NG Supply, Demand and Pricing Effects NG Needs New Demand Sources to Break Free of Coal-to-Gas (CTG) Fuel Switching During the period of natural gas oversupply in the U.S. since 2009 there has been only one source of demand able to step up and balance the market: utility fuel switching from coal to NG. Our previous work has suggested the magnitude of this fuel switching primarily surrounds Powder River Basin (PRB) coal and NG price spreads. When NG prices were lowest in the 2012 spring shoulder season, CTG switching reached approximately 9 Bcf/d and averaged 7 Bcf/d during the following summer. This dynamic creates the natural gas price floor. The flip side is that as NG prices rise, the economic reward for CTG switching declines until there is no longer an incentive to do so. Currently, weather-related demand effects aside the cessation PRB/NG fuel switching creates the natural gas price ceiling. For gas prices to escape from the CTG fuel switching trading band, other forms of natural gas demand are required. New-Build Gas-Fired Power Plants Will Increase NG Demand

By 2016 the Southeastern U.S. will have 23 new gas-fired power generation units representing 60% of overall new-build capacity. Pipeline build-out indicates these units will be sourced from the Marcellus Shale with some 4.5 bcf/d of new gas supply potential by 2015. As these units come online dispatch variability will become less price sensitive and more aligned to weather effects. CTG switching will still be meaningful but the price floor will rise as structural gas demand increases with the new unit build-out and fuel switching will become more episodic. At the same time we expect dry gas production growth to peak in 2014-15. From that point on, NG production growth will be highly sensitive to price.



Increased NG Consumption in Manufacturing is a Reasonable Expectation Formosa Plastics is building a $2Bn styrene plant in Houston to shift to NG from oil-based naphtha and take advantage lower U.S. NG prices. Sasol (SSL) has proposed a Gas-To-Liquids conversion plant to produce synthetic diesel from NG in LA, Nucor (NUE) will build a Direct-Reduced Iron plant in LA plant that has a long-term NG supply deal with ECA, and other DRI projects are proposed for Ohio and Minnesota. These ventures demonstrate the expectation of both manufacturers and NG producers that U.S. NG prices will remain favorable compared to both oil and NG prices in the rest of the world for years to come. While a detailed analysis of U.S. NG and its influence upon manufacturing awaits another report, here we can summarize that along with new power generation, growth in NG demand from U.S manufacturing as well as increased natural gas transportation (NGT) raises the probability that structural demand for NG will replace the low price band in which CTG fuel switching currently functions with a higher price band. We expect to see these effects becoming more tangible in 2015-16, really not that far away. Liquefaction and Export of U.S. NG Creates a New Global Source of Demand U.S. export of liquefied domestic NG could become a reality in 2015 and tie U.S NG production to global LNG demand. Cheniere commissioned Deloitte to provide a detailed study of the effects of 6 Bcf/d of U.S. LNG exports under various marketing scenarios within the framework of Deloitte’s World Gas Model. Deloitte concluded U.S. gas prices would rise very little, while U.S. exports into either Asia or the European Union (EU) would reduce gas prices in both markets.



Working backward, we believe that in any market where U.S. LNG is less expensive than current supply of flexible demand, price reduction is a given. Any notion that foreign gas prices could resist such an effect recalls the REX pipeline that was built to export U.S. Rockies NG to U.S. mid-continent markets. Constructed with the idea that Rockies NG pricing would improve, instead the flood of cheaper Rockies gas reduced NG pricing in the mid-continent. In a world of flexible demand and multiple supplies gas-on-gas competition is usually swift and brutal with the lowest marginal cost source of supply the winner. U.S. LNG Exports May Push Future Global Pricing to NG Benchmarks At minimum, if the bulk of U.S. LNG exports arrive in one market, they should hasten the creation of spot LNG prices linked to gas price benchmarks. With time, this approach could spread elsewhere as displaced LNG will move to other markets and compete on price. Whether the take-or-pay portion of long-term contracts will price to gas benchmarks as Cheniere has done is beyond the scope of our work in this report, however, we note the U.S.’s second export and Japan’s first Henry Hub (HH)-based import deal has been secured by Tepco for 800K tons per annum of LNG from the SRE Cameron Project. U.S. LNG Exports Should Support Higher NG Prices Regarding U.S. LNG export effects on domestic NG prices, the short answer is that it is unlikely to reduce them. Regarding driving U.S. gas prices higher, Deloitte expects U.S. gas prices to be largely unaffected by LNG exports due to “vast shale gas resources that are now economically viable due to technological advancements in recent years”. Bearing in mind the host of recent U.S. E&P non-cash write-downs—the result of testing the economic viability of developing proved reserves using trailing year annualized average NG prices--these resources appear to require higher NG prices than those in 2012. Our thesis is that once demand has obviated the need for CTG switching as a market balancing device, NG prices will gradually rise to attract more production. Higher Prices Do Not Mean High Prices We do not expect normalized NG prices to threaten the viability of NGT. While current write-downs indicate a good chunk of the “vast resource” cannot attract investment at $3/mcf, producers with core acreage in prolific basins like the Marcellus Shale and Haynesville Shale can make acceptable returns at even lower prices. In discussing APC’s Marcellus operations former CEO Jim Hackett remarked, “Each well costs between $3 million and $4 million dollars, which means we can realize a 10-percent rate of return at $2.50 NYMEX natural gas prices.” Other E&P’s such as COG and RRC have demonstrated Marcellus economics remain attractive within a $2.50-$3.50/mcf pricing band based on capital investment that was not motivated to hold acreage. On its most recent quarterly call ECA announced a return of capital spending in the Haynesville Shale. ECA expects to drill 7,500 ft. laterals averaging 18 bcf Estimated Ultimate Recovery (EUR) and make acceptable economic returns at an average $2.50/mcf in their core acreage using their Resource Play Hub pad drilling development concept. It would not surprise us if Cheniere seeks bilaterally negotiated supply agreements with major producers in basins such as the Haynesville and Eagle Ford Shale, both of which are in close proximity to Cheniere’s liquefaction facilities. Such agreements would represent a hedge for



Cheniere’s discretionary liquefaction capability since its take-or-pay production is linked to HH plus 15% of the given HH price. Durable $1 Per Gallon Equivalent Spreads Are Feasible Happily for NGT, neither today’s ultra low NG prices, nor very high oil prices are required to create durable $1.00 price spreads between Compressed Natural Gas (CNG)/LNG and gasoline/diesel which is the assumption we use in our Mid-Case scenario. Our modeling indicates that at an average 12-1 oil price to NG price ratio acceptable fuel price spreads remain intact. This does not assume a fuel subsidy such as the $0.50/g fuel tax credit which has been extended for 2013. Another way to think about the price spread is that NG is about 29% of the realized cost of CNG/LNG whereas crude oil is about 60% of the cost of gasoline and diesel. This means CNG/LNG prices are intrinsically less sensitive to NG price swings than gasoline and diesel are to crude oil. Overall, as we progress toward 2020 we expect normalized gas prices to settle in a $4.50-$5.50 price band. This price range will provide sufficient incentive for E&P’s to produce enough NG to support moderate NG fuel costs for transportation even with some LNG exporting. What if NG Fuel Adoption is Slower Than we Expect? Stricter emissions requirements are not going away. There are basically three ways to achieve the standards:

• Burn dirtier fuel and install some kind of pollutant capturing technology

• Burn Ultra-Low Sulphur Diesel (ULSD)

• Burn NG Going forward U.S. new trucks moving into and out of ports must meet the 2007 Environmental Protection Agency (EPA) standard. Dirty fuel is not an option for these trucks. Their current options are to burn ULSD or NG. In shipping, if we assume NG will not receive high adoption then the fuel burden falls to dirty fuel with pollutant capture or ULSD. In this case dirty fuel is bunker fuel and scrubbing technology. It is easier to produce ULSD in large quantities than bunker fuel and shipping studies suggest dirty fuel will be insufficient to supply eventual needs. In fact, global refiners are asking that a fuel availability review slated for 2018 be brought forward so that the issue can be settled and investment in more ULSD production made secure. Global economic collapse aside, this does not sound like a loose ULSD market either now or in the future. The economics of fuel choice are based on fuel prices, not commodity prices. It is possible that global oil prices could be lower than today without much movement in ULSD prices if supply and demand of this fuel remains tight.



Low Prices Require That Current Field Practices Continue Unabated All of the analysis above relies upon one fundamental expectation: the continuance of hydraulic fracturing as a production method. If we are going to consider variables that might push natural gas prices noticeably higher and stunt adoption of alternative uses for NG, we must touch upon four which have received media as well as investor attention: water issues as a cost center, environmental opposition to hydraulic fracturing as a threat to drinking water, EUR of unconventional NG wells, and methane leakage throughout the NG complex. We will not attempt to be exhaustive but rather give a sense of the issues involved and our opinions as to their potential influence on NG prices. Hydraulic Fracturing, the Source of Oilfield Water Consumption

Horizontal drilling has become the method of choice in unconventional continuous formations and the basis for U.S. NG supply growth over the last five years. These formations are usually composed of shale or tight sandstones and tend to be thick wide-ranging relatively well-defined depositional layers highly suitable for long horizontal wellbores.

Most shale formations tend to occur at depths between 4,000 ft.-11,000 ft. Shale is often the source rock for shallower conventional fields which have been in production long before the contemporary effort to produce from the shale itself. As a general construct the deeper the shale the more expensive the well. It takes longer to drill the well and as more horsepower (hp) is required of both the drilling rig and pressure pumping spread.

Source: Total S.A. Company Report



The Five Stages in Unconventional Well Creation

A producing horizontal well is usually created in five steps. First, a lower hp less expensive rig drills the vertical portion of the well. Second, a higher hp more expensive rig drills the lateral portion of the well. Third, an oil services company installs fracturing (“frack”) stages at varying intervals within the lateral wellbore and sets off explosions that fracture rock lying above the wellbore. Fourth, water, surfactants, biocides, and proppant (a material that keeps rock pores open helping hydrocarbons to flow to the well) is injected into each of the frack stages at high pressure. Proppant is usually made of sand or tiny pieces of ceramic material. Finally, the water within the well bore is allowed to flow back out of the well.

Water Management Following Well Construction

How much of the 8-10 million gallons of water pumped into a frack that returns to the surface is highly variable, between 10%-70% with industry figures indicating an average recovery of 45%. This water will not only contain flowback of water that was injected to instigate hydraulic fracturing, but will also contain produced water--ancient water contemporary with the organisms that became oil and NG--and which is often highly salty, mineralized, can contain heavy metals, and sometimes large amounts of Naturally Occurring Radioactive Materials (NORM), although produced water content varies markedly from field to field. Many available water treatment plants are not equipped to handle NORM. Trucking waste water to distant approved treatment centers is not a cost-effective solution.

As a result, the E&P industry in concert with state regulators has come up with several alternative approaches.

a) Inject the water into the ground in disposal wells. There are about 500,000 injection wells across the United States, and according to EPA, approximately 144,000 “Class II” wastewater injection sites in operation. Class II, one of six classes in total recognized by EPA, covers wastewater from oil and natural gas development. Some fields like the Mississippi Lime in OK and KS allow injection well development in concert with oil and gas development. Pipe and electrical systems are constructed so that very little trucking is involved. SD’s project is a good illustration of this approach. SD has stated that its injection program adds about $200k to the cost of each well.

However, not all states will allow injection of waste water so it is not a comprehensive solution. Further, this approach is most viable when a field is in development mode and acreage is contiguous.

b) Water can be evaporated and remaining well site solid wastes can go to designated lined

landfills. As one example, RSG operates nearly 200 state and federally approved landfills of this type. Environmentalists protest about air and potential groundwater pollution from this approach but it should be pointed out that this is a highly regulated method and stories of accidents are rare. The primary drawback here is that water—which is itself a cost center and precious resource—is being wasted.


http://water.epa.gov/type/groundwater/uic/class2/index.cfm


c) Water can be treated and recycled. As fresh water procurement is becoming more expensive, and in drought-prone areas like the Eagle Ford Shale water is scarce, recycling is becoming a more common practice in development fields. From RRC: “By October 2009, Range was successfully recycling 100% of its flowback water in our core operating area in southwestern Pennsylvania. It saves approximately $200,000 per well as it eliminates the cost of trucking and treating water. It reduces fresh water demand and eliminates the need to dispose of the water. It also greatly reduces truck traffic to and from our sites and therefore reduces road damage and any associated noise. It is currently estimated that 60% of Marcellus operators are recycling portions of the water used to complete their wells, and that percentage is expected to rise in the future.” Overall, the degree of recycling is a calculus of produced water quality, costs to recycle, availability of other options, and state regulations. 100% recycling in all fields is likely impossible, but it is clear that the industry has moved to a “recycle first, inject second” process over the past several years.

To summarize, current water management practices are cost items. These costs do not appear to be discouraging the fracking of unconventional resources in pursuit of oil and natural gas liquids (NGL). It is our opinion that NG prices will rise over time, either through enough reduction in NG supply to tighten markets and support higher prices or through greater demand for NG which will accomplish the same thing. We do not consider water management as currently practiced to be a catalyst for NG prices outside the price range previously expressed.

The Environmentalist Challenge: Hydraulic Fracturing Damages Drinking Water

In May 2011, EPA administrator Lisa Jackson told the U.S. Senate that she wasn’t aware “of any proven case where the fracking process itself affected water.” The EPA continues to conduct an exhaustive “scientific study” of fracturing and groundwater contamination which is expected to result in a definitive opinion and best practices recommendation. The results of this study which were to have been presented by the end of 2012 are currently delayed. The Environmental Defense Fund (EDF) has gone on record that fracking is a safe practice provided wells are properly constructed.

Our opinion, and it is precisely that (our opinion), is that it is impossible for hydraulic fracturing to contaminate ground water.

• Fracturing zones are very deep and too far away from aquifers;

• There is impermeable rock between the fracturing zones and aquifers that contain fracking fluids (this is why there is a conventional oil or gas field above the shale);

• Water is heavy and being acted upon by gravity tends to flow downward not upward. This is why we find ancient water miles below the surface.



If there is contamination of groundwater as the result of oil and gas drilling it is likely the result of faulty well construction as the well is drilled and cased through the aquifer. It is more statistically likely as the result of faulty water well construction. Either way human error can occur but is not an indictment of hydraulic fracturing.

The Anti-Fracking Environmental Lobby Will Not Disappear

There is no question that a determined environmental lobby continues to keep up the pressure on E&P’s through the media and their membership focusing on water issues. This lobby, which strongly advocates the use of renewable energy sources, recognizes that low NG prices are an impediment to greater renewable energy adoption due to its much higher production cost per energy unit. E&P’s will not eliminate this pressure until non-toxic fracking fluids are developed that are as cost-effective as current practice or non-toxic fracking fluids are forced upon E&P’s by regulators. Were the industry to adopt non-toxic fracking fluids using currently available solutions, we estimate this would add about $1.00 to our $4.50-$5.50 normalized NG price expectation into 2020. We do not believe this increase is sufficient to hamper adoption of NG into the alternative uses the report details.

What is EUR and How Does It Matter?

EUR is a mathematical exercise that seeks to predict the total future production of an oil or NG well. This has become associated with unconventional resource production because of the much higher decline rates of these wells as compared to conventional formations. At the outset it should be stressed that decline curve analysis is not grounded in fundamental theory but is based on empirical observations. Until enough fracked wells have produced for 20-25 years it will not be possible to construct statistical models based upon facts. In the interim, decline curve analysis represents an “educated guess”. Producers make these guesses as part of the decision process to make or avoid investment in producing their unconventional resources. They also promote their EUR predictions to investors as a basis for determining the relative value of their acreage versus competitors. Decline rates are observed for a certain time period and projected out into the distant future. EUR controversies center on whether production should be modeled hyperbolically or exponentially.



Source: Fekete Associates

This is not the place to dig deeply into math so we will briefly conceptualize the arguments. Hyperbolic declines seek to express decline rates that are not constant over time. This changes the exponential equation formula which assumes decline is constant. The exponential equation will eventually result in a full decline and arrive at zero production. EUR hawks complain that in using hyperbolic declines E&P companies are using math that never gets to zero with the implication that the EUR potential of unconventional resources are being overstated.

In our opinion, the importance of this argument depends on your point of view. If you are at 50K ft. and predicting that the U.S. has 100 years of cheap NG ahead of it, you might be concerned if you felt your prediction was based on faulty mathematical assumptions and could actually be lower.

We prefer a view closer to the ground and make the following observations:

a) In every shale play, five year wells produce at a small fraction of their original production rate.

b) Time value of money says a given well 20 years out it isn’t worth much anyway.

c) Therefore, the five year decline rate is what really counts. This decline rate can increasingly be based on facts rather than speculation. Hyperbolic versus exponential does not matter.

d) The Barnett Shale is the one example we have of a shale play long on production. For the past two years DVN has managed to keep production flat by drilling predominately liquids-rich wells and few dry gas wells. The liquids-rich wells likely have more associated gas production than the dedicated dry gas wells but far fewer of them are being drilled. The Barnett is DVN’s largest producing asset. It seems unlikely that production could remain steady in the face of the program shift if the older dry gas wells were not producing predictably out to five years and likely beyond.



Therefore, we remain fairly unconcerned about EUR from the standpoint of the 50K view. Whether 70, 80 or 100 years, the U.S. has a large unconventional NG resource to tap based on presently identified well locations projecting 5 year declines. For individual company reserves analysis EUR can be meaningful, but we prefer cash flow over probable/possible (2P/3P) Net Asset Value (NAV) reserve estimates as the basis for valuation for this reason and believe the market does as well. As the ceiling tests we mentioned earlier show, E&P executives can incorrectly estimate the future economic value of their reserves. Those write-downs also tell us that higher NG prices are ahead. However, the size of the resource and the industry’s notable skill in cutting costs suggests these increases are more likely to be of moderate than great magnitude.

The EDF Methane Study

EDF is conducting two studies over two years to generate data on methane leakage “from well to wheels”. Going into the study, based on a paper in the Proceedings of the National Academy of Sciences co-authored by EDF scientists Ramon Alvarez and Steve Hamburg, the EDF asserts that at current methane leakage estimates “converting a fleet of heavy duty diesel vehicles to natural gas would result in nearly 300 years of climate damage before any benefits were achieved”. The first study seeks to estimate methane emission from natural gas production with direct measurements at sample sites. It brings together EDF, University of Texas at Austin, and nine natural gas producers: APC, BG Group (BRGYY), Chevron (CVX), ECA, Pioneer Natural Resources (PXD), RD, SWN, Talisman Energy (TLM), and XTO Energy, an ExxonMobil (XOM) subsidiary. For the second major study, EDF is partnered with the Center for Alternative Fuels, Engines and Emissions at West Virginia University and eight industry organizations to understand methane leakage from the use of natural gas as a fuel in natural gas vehicles. EDF aims to complete the entire two-year effort by December 2013. Findings from this collective research could help guide how companies, states and the federal government measure, monitor and manage methane emissions. Our View of the EDF Effort EDF’s stated goal is to advocate “for leak reduction in order to maximize natural gas' potential carbon benefit”. EDF is not tying themselves to gas wells or fuel pumps. They are conducting relevant scientific studies which should result in more and better data. There is nothing but good to gain by reducing methane emissions wherever it is economically feasible to do so. At the same time, it is disingenuous to use NGT as a melodramatic hook when the Energy Information Administration (EIA) data upon which EDF presently relies indicates 64% of all methane emissions occur in oil and gas production. The wellhead is the low hanging fruit which EDF admits elsewhere. Further, the EPA identifies methane emissions as 3.8% of U.S. greenhouse gas emissions in 2011. This is a rather small base from which to call for 300 years of unquantified climate damage from Class 8 NGT. Hopefully, the rhetoric will subside when the data comes in.


http://www.engr.utexas.edu/news/7416-allenemissionsstudy

http://wvutoday.wvu.edu/n/2013/03/04/scemr-release

http://wvutoday.wvu.edu/n/2013/03/04/scemr-release

http://blogs.edf.org/energyexchange/2012/04/10/what-will-it-take-to-get-sustained-benefits-from-natural-gas/

http://blogs.edf.org/energyexchange/2012/04/10/what-will-it-take-to-get-sustained-benefits-from-natural-gas/


Effects on NG Prices

The EPA Gas Star program demonstrates a variety of ways to cut methane emissions cost-effectively. Currently voluntary, in the future this may transform into a more typical program where companies throughout the NG value chain are required to cut their methane emissions a certain percentage per year and left to figure out for themselves how to do so. As long as the scale-up is not too rapid, many of the emissions investments will pay for themselves with greater methane retained for sale. We do not expect NGT utilization to increase so quickly that this could not be rationally handled. If however, the results of the studies demand rapid implementation of costly emission controls this could increase NG prices by raising the threshold for E&P investment into NG production. We believe the price outcome is unpredictable until the EDF study results are at hand and any regulatory pathway better defined.



Fleshing Out the Mid-Case Adoption Scenario

CNG is the Shorter Distance NG Fuel Form.

CNG currently does not provide more than approximately 250 miles driving per fill-up on average. However, for trucks and vans which can sacrifice the space for an extra tank, range can be increased, or bi-fuel options can add some additional range on gasoline or diesel. CNG is the fuel of choice for a hub-and-spoke transportation model which does not generally require vehicles to drive more than 300 mile round-trips and returns them to the same location at the end of each workday. In particular, fleet vehicles can take advantage of slow-fill CNG refueling which is less expensive than fast-fill pumps that are increasingly demanded by individual consumers. Utility fleet cars, delivery step-vans, garbage trucks, airport shuttles and buses are all good examples of successful implementation of this model. Of current U.S. transportation served by natural gas, the vast majority run on CNG in fleet vehicles. Displacement of oil-based fuels in Light Duty Vehicles (LDV) usage primarily means gasoline, whereas fuel replacement in heavy-duty vehicles (HDV) driving means diesel.

LNG is Better Suited for Longer Driving Distances and HDV Use.

LNG is produced by purifying NG and super-cooling it to -162°C to turn it into a liquid. Because it must be kept at cold temperatures, LNG is stored in double-walled, vacuum-insulated pressure vessels. LNG is good for trucks needing a longer driving range because liquid LNG stores more energy than gassy CNG in the same amount of volume. Large trucks can also dedicate more space to fuel without real penalty. LNG also refuels faster than CNG although it requires safety equipment when fueling takes place. A person fueling with LNG must wear a protective face mask and thick work gloves with large gauntlets, both of which protect the skin from possible contact with the super-cold LNG. However, fueling with LNG is not difficult, and truck drivers are expected to refuel their own vehicles at refueling stations. LNG is not a suitable fuel for vehicles which frequently idle or go days without driving due to the evaporative cooling which keeps LNG temperature constant. This is why LNG will never be a suitable fuel for passenger cars. LNG is typically used in medium and HDV which drive frequently and are used daily.



Big E&P’s: Early Adopters

Switching From Diesel to NG on Drilling Rigs and Fracturing Spreads

Hor. Rigs

Rig Days

Total Days

Wells at 15 Days

Daily Per Rig

Diesel(g) Consumed

Total Rig Diesel(g)

Consumed (000)

Frack Days @4 Per Well

Daily Frack

Diesel(g) Consumed

Total Frack

Diesel(g) Consumed

(000)

Subtotal Diesel

Gallons (000)

800 325 260,000 17,333 1,500 390,000 69,333 9,000 624,000 1,014,000

Diesel Gallons

Displaced @100%

Gas (000)

Diesel Gallons

Displaced @70%

Gas (000)

Diesel Gallons

Displaced @50%

Gas (000)

Diesel Gallons

Displaced @30%

Gas (000)

1,014 710 507 304

NG/ Diesel Spread $-(000) $-(000) $-(000) $-(000)

$1.00 $1,268 $887 $634 $380

$1.50 $1,901 $1,331 $951 $570

$2.00 $2,535 $1,775 $1,268 $761

Source: Rosenblatt Energy Research

The model above examines two components involved with drilling these wells: a high h.p. drilling rig which bores the horizontal leg of the well, and the pressure-pumping spreads that inject the water and proppant into the well. Both rig and pp consume large amounts of diesel fuel and are ripe for replacement with NG.

The model contains certain assumptions which we consider reasonable but not absolute. We model 800 horizontal rigs (both gas and oil), which is derived from recent drilling activity and can increase or decrease depending on commodity price trends. Although fit-for-purpose high horsepower rigs run constantly in development projects they still require movement from pad to pad, plus not all horizontal drilling is done on pad. Therefore, we model 325 days service on average per rig although anything between 300-330 days is reasonable. 15 days for an average horizontal leg could vary, but our sense is that with the present concentration on oil and NGL targets, plus the Marcellus Shale, this is feasible for scenario modeling. The same can be said for assuming 4 days to complete the average fracture stimulation. Our diesel consumption per daily frack numbers are low-end of averages provided by various industry players from their field experience. Finally, we add 25% to the dollar amounts in the spreads table on the assumption that Canadian oil services practices will eventually shift to NG. NG



consumed in Canada is NG that will not be exported to the U.S. so we believe it belongs in the model. Overall, our opinion is that the model is not overly aggressive.

The upshot of the model is that if 100% NG consumption could be attained in the stationary engines in these two components of horizontal well drilling it would be roughly equivalent to 84,000 18 wheelers traveling 67K miles/year on NG and would consume at least 250MMcf/d of natural gas. Intuitively, if vertical drilling rigs and all the trucks involved in transporting drilling and servicing material, fracking equipment, sand, water, and personnel to well locations were running on NG the diesel displacement would be much higher. In what follows we explore what is taking place in the field right now and how it is constructing a pathway to the future.

Modern high hp rigs fit for drilling long horizontal laterals run on electricity. A stationary generation set (gen set) supplies the needed electricity for the rig. Until recently diesel was the only fuel consumed to generate this electricity. However, NG can to some degree be substituted in the same engines and can come in the form of LNG, CNG, or field gas. Whatever the source, ultimately it is dry gas being burned within an Internal Combustion Engine (ICE). ECA and NBL have referenced the use of a CAT 3516 Nat Gas-Elect Gen Set for 100% diesel displacement with LNG. NBL cited annual fuel savings of $750,000 per rig in Wattenburg drilling (which is 35% more savings than our model above would have predicted) with this method. Ensign Drilling runs 11 of its 15 rigs on GE Jenbacher gas engines running entirely on LNG and is the first driller to operate on LNG in the Marcellus Shale.

NBL is now conducting tests of “less capital intensive” LNG/diesel dual-fuel gen-sets using externally mounted Altronic-GTI conversion kits on CAT 3512 engines. CAT also offers its own conversion kit, Dynamic Gas Blending, that by allows use of LNG, CNG, or suitable field gas by automatically adjusting to the variable quantities of methane that exists in different field locations. These CAT engines run on up to 70% LNG, however both ECA and APA told us that real world diesel displacement of 25%-50% is the current norm.

Switching From Diesel to NG on Fracturing Spreads

Source: Company Report. Cummins Fracturing Engines to Be Converted to Dual-Fuel


http://hhpinsight.com/epoperations/2013/02/cummins-for-pge-universal-fracking/attachment/universalwellservices4-1111/


As our model indicates, on a daily basis hydraulic fracturing consumes at least 6 times more diesel than rig drilling. This is an area of oilfield services that is getting an immediate push to convert to NG. APA is conducting dual-fuel field tests with Linde-supplied LNG and diesel with HAL and a CNG/diesel spread with SLB in Wheeler County. Cummins also has conversion kits to run QSK50 engines on NG in frack spreads that are currently being field-tested. Universal Well Services, a unit of Patterson-UTI Energy (PTEN) plans to convert 100% of its fracturing fleet to dual-fuel field gas/diesel for its work with Pennsylvania General Energy. UWS estimates it will consume 750,000 gallons less diesel per year. It should be noted that a fuel mix of at least 30% diesel is required in all these engines to ignite the NG using compression. This informs our displacement decisions in the model above.

Another approach to oil field power generation is using a gas turbine. Private Green Field Energy Services collaborated with APA in demonstrating that their turbine fracturing technology could run on 100% field gas. Mike Bahorich, Chief Technology Officer of Apache, called the test "A major initiative for Apache." Aside from the convenience and potential cost savings of using field gas, GFES turbines can run on 100% NG unlike the duel fuel diesel conversions. GFES is also collaborating with GE in two pilot programs, one with Sandridge (SD) and the other with APA. In the SD pilot GFES will provide electric power for artificial lift in an OK Mississippian well powered entirely by field gas. SD has indicated a desire to both reduce operational costs and improve its environmental impact if the pilot is successful. The APA pilot will drive a 1500 horsepower electric land drilling rig in the Granite Wash using 4 GE 1-megawatt turbine engines running entirely on field gas. According to APA, the attractiveness of the gas turbine is its simplicity and lack of fussiness. Aside from water removal, the turbine is flexible regarding the btu amount within the gas. On the other hand turbines are very inefficient engines that require lots of fuel. These two traits position the turbine to be a consumer of field gas and nothing else.

Use of Field Gas is Likely to Increase Wherever Possible

Although CNG and LNG are continuing to be tested in field operations, the movement toward field gas consumption is compelling where feasible. In drilling aimed at liquids targets NG does not figure strongly in the economics. In such instances, drilling and fracturing with field gas is essentially consuming free gas. That said, all sources of NG possess economic costs. CNG must be compressed and transported. LNG must be liquefied and transported. Field gas must be dewatered and cleaned before use, and must be available in sufficient quantities to perform the task at hand. Field gas with any significant NGL content would not be used as the NGLs have greater intrinsic value than dry gas, and stripping out NGLs in the field would be cost prohibitive. APA drilling engineer Sam Goswick told RER that the gas turbine and field gas are made for each other “Because the turbine is a simple engine that will accept a wide range of heat values (British Thermal Unit content within the gas) making it really convenient. It is also a very inefficient engine so field gas is the only fuel inexpensive enough to make the turbines economical.” In the end we believe all three solutions will find fans depending on the availability of CNG and LNG, and the quality of the field gas at hand. The overriding concept is to find a source of gas that creates better field economics than 50% displacement of diesel in dual-fuel engines.



Substituting NG for Diesel Presents a Friendlier E&P Industry Environmental Profile.

Gas emits 20-30% less carbon dioxide than oil-based fuels and has negligible emissions of nitrogen oxides, sulfur oxides and particulate matter, all of which are linked to respiratory health problems according to the EPA. The fracturing and methane leakage controversies of the past several years have encouraged the E&P industry to get greener wherever possible.

E&P Investment in NGT is Accelerating Refueling Growth

Large E&P’s like APA, CHK, ECA, and SWN encourage NGT by transferring increasing numbers of fleet vehicles to run on NG. These vehicles require refueling capability. APA has converted 42% of their LDV fleet to NG with an eventual goal of 80% conversion. They also give their employees 50% back on cost to convert their vehicles to NG, plus a $5,000 CNG fuel card. Typically, when an E&P builds private refueling capacity it adds additional capacity to sell CNG (and less often LNG) to the public. As one example, SWN says that nearly 40% of customers at the company-built CNG filling station in Damascus, AK, are local vendors and residents. ECA similarly built a CNG station in Coushatta, LA, for its own use and six months later began selling CNG to regional corporate fleets. APA, which has been involved in grassroots NGT development for 4 years, has constructed 20 CNG fueling stations. 13 are semi-private for their own use and neighboring commercial fleets and 7 are open to the general public.

Burning Diesel to Capture NG is a Losing Proposition

Due to the E&P’s special relationship with NG we believe eventual adoption of NG in both field operations and the various vehicles which support them will be as high as possible. ECA estimates this could result in an additional 1 Bcf/d of NG demand. Some third party estimates are 1.5 Bcf/d. We model ultimate E&P consumption potential of 1 Bcf/d at an 80% adoption rate for a .8 Bcf/d consumption forecast.



CNG/LNG Takes on Oil-Based Fuels in Transportation

Potential NG Consumption in Transportation

Source: Encana Company Report

Consumer Cars are Unlikely a Large NGV Opportunity

Below are some payback scenarios for Natural Gas Vehicle (NGV). To keep it simple (because we are leery that consumers would factor it into their buying decision) we left out any presumption of maintenance savings for NGV versus gasoline counterparts. Scenario #1 uses price premiums which are typical of OEM and OEM-approved NGV offerings. We use miles driven per year and life of vehicle assumptions derived from government sources for family cars, and the assumptions we model for fleet vehicles which are detailed below. It also assumes a durable $1 per gallon positive spread between CNG and gasoline. None of the vehicles modeled have positive total savings based on these criteria. Scenario #2 uses all the same inputs with a 50% reduction in upfront purchase costs. We believe this is eventually achievable because (as we will detail later) OEM commitment to produce NGV will drop costs significantly simply because of scale efficiencies and a tighter supply chain. Adding incremental improvements to storage costs makes this scenario believable. Only vans make a profit in this scenario, but losses are marginal enough that moderate changes to other variables such as positive fuel spreads or length of ownership period in the case of fleet usage could provide positive investment returns. Plus, in fleets lower maintenance costs are a definite component of buying decisions.



Scenario #3 uses all the same inputs with a 75% reduction in upfront purchase costs. In this case every vehicle is an unambiguous winner, and with the input variability mentioned in Scenario #2 there could be large savings in certain circumstances. At this point we believe revolutionary storage changes will be required to get to this level of vehicle pricing premiums. It should also be observed that widening the price spread to $1.50 per gallon drove every category to positive returns in Scenario #2. CLNE and Honda recently added a $3,000 fuel card credit at CLNE stations as an inducement to purchase the NG. Competition between fuel providers can also lower fuel costs. Oklahoma currently has 63 public CNG filling stations, the most per-capita of any U.S. state, and averages $1.35/GGE, well below the national average of about $2 per GGE. Many of these stations are E&P-sponsored and may not represent realistic market prices.

CNG LDV Vehicle Payback Scenarios Model

Vehicle

premium ($)

mpg md/y gallons

NG Price

Spread ($)

savings ($)

payback years

vehicle life

total savings

($)

Family Car 10,000 30 12,000 400 1 400 25 10 -6,000 Fleet Car 10,000 30 25,000 833 1 833 12 5 -5,833 Pick-up 15,000 18 30,000 1,667 1 1,667 9 4 -8,333 Van 15,000 14 30,000 2,143 1 2,143 7 4 -6,429

50% Reduction

Vehicle premium

($) mpg md/y gallons

NG Price

Spread ($)

savings ($)

payback years

vehicle life

total savings

($)

Family Car 5,000 30 12,000 400 1 400 12.5 10 -1,000 Fleet Car 5,000 30 25,000 833 1 833 6 5 -833 Pick-up 7,500 18 30,000 1,667 1 1,667 4.5 4 -833 Van 7,500 14 30,000 2,143 1 2,143 3.5 4 1,071

75% Reduction

Vehicle premium

($) mpg md/y gallons

NG Price

Spread ($)

savings ($)

payback years

vehicle life

total savings

($)

Family Car 2,500 30 12,000 400 1 400 6.3 10 1,500 Fleet Car 2,500 30 25,000 833 1 833 3 5 1,667 Pick-up 3,750 18 30,000 1,667 1 1,667 2.25 4 2,917 Van 3,750 14 30,000 2,143 1 2,143 1.75 4 4,821 Source: Rosenblatt Energy Research



Current Evolutionary Storage Development

While the current low number of refueling options is a certainly an adoption impediment, we believe current onboard storage technology is the greater barrier to adoption of CNG in passenger cars and LD trucks. With few exceptions current storage is heavy, bulky and robs interior vehicle space to attain an acceptable driving range. It is also expensive and a primary reason NGV’s cost more to purchase than gasoline or diesel vehicles. Buying a NG car with high up-front costs becomes a call option on a positive NG and oil fuel price spreads, something about which consumers should not be required to be expert. If storage technology can be improved on capacity and especially cost we believe LDV adoption would rise and with it refueling options.

This is not to suggest that active efforts to address these problems are not underway.

On 2/13/13 3M announced NGV2-2007 certification of their first CNG pressure vessel (CNGPV) using improved manufacturing methods and proprietary 3M™ Matrix Resin featuring nanosilica technology. The new CNGPV reduces weight by 30%, and increases capacity 10% while lowering cost. As Rick Maveus, Global Business Manager, 3M Advanced Composites clarified for us, these weight and capacity claims are in comparison with other Type IV tanks (100% composite), not Types 1-3 which all use metal to some degree. Therefore, 30% less weight in the lightest tank category is a notable improvement. 3M identified the 21.5 x 60 inch tank as designed for light- and medium-duty pick-up trucks and corporate fleet vehicles. The successful certification follows the 2012 announcement by 3M and CHK that the two would collaborate in designing, manufacturing and marketing a broad portfolio of CNG tanks for use in all sectors of the U.S. transportation market. 3M expects to announce certification of other geometries in the coming months. CHK is slated to become one of the first users of the new tank.

Source: MMM Company Report

QTWW is a small CA company that has developed the Q-LiteTM Type IV CNGPV which is 70% lighter than steel, is certified to both NGV2-2007 and ISO 11439 specifications, and has a service life of 20 years. The company cites its ultra-light weight CNGPV as winning orders on better fuel economy and driving range.



Source: Quantum Technologies Company Report

In examining descriptions and pictures of either of these improved CNGPV’s we do not see evidence yet of the conformability that could mount the tanks out of sight and return interior space to vehicle users. 3M suggests that as more OEMs become involved with NGV design and build, opportunities to better integrate their pressure vessels will present themselves. Further, while we hear about cost savings generically 3M told us specifically that their newly approved Type IV tank is more expensive than Type 1 steel, but indicated reductions in weight and increases in range were compensating value-adds. It doesn’t appear that the Q-LiteTM Type IV is any different. A QVM Space Breakthrough BAF, a Clean Energy company, has the first Ford F-250/350 pickup truck with an underbody tank package in the industry, giving drivers the use of the full truck bed – something fleets have long desired. The company continues to expand its R&D efforts and is working on adding Lincoln “black car” vehicles to its lineup to better serve limo markets. However, CLNE CEO Andrew Littlefair admitted that it is difficult for a QVM to drive down costs and the BAF F-250 remains an expensive proposition.


http://www.ngvglobal.com/baf-offers-underbody-tanks-for-ford-f-250350-0712

http://www.ngvglobal.com/baf-offers-underbody-tanks-for-ford-f-250350-0712


OEM NGV Production Will Reduce NGV Cost

When considering the current cost premium of a NG vehicle versus its gasoline/diesel counterpart, about 35-55% of the cost is the storage vessel. EPA certification is also another notable expense. Otherwise, in most respects the different components that put NG in a cylinder—injectors, tubing, regulators—are not exotic. Costs can be reduced by greater volumes and assembly line efficiencies. OEMs routinely cite the need for base volumes of 10K-20K vehicles to begin meaningful cost reductions. Recently auto dealerships in 28 states representing the Big Three U.S. manufacturers plus Honda submitted more than 100 bids in response to a joint Request For Proposals by 22 U.S. states which promised vehicle purchases of 10K units per year. The results are premium cuts for five vehicle classes averaging 4 %-16%. One outstanding example was a $6,000 price reduction on the three-quarter ton Dodge Ram CNG. The bi-fuel option on the truck currently lists for $11,000. For a compact sedan, the CNG premium declined about $2,100. As an additional benefit the increased presence of NGVs in state, city and local government fleets will encourage the growth of refueling infrastructure accelerating public acceptance of CNG-powered vehicles. Frank Dankovich, Head of Government Sales for Chrysler Group Fleet division, predicted greater demand will spur more declines in NGV premiums and further investment by the auto industry. “[OEM’s] also want to see investment in infrastructure continue to accelerate thereby providing a viable fueling option to prospective customers,” he said. ECA told us that in instances where they could obtain OEM vehicles they have received prices as much as 40% lower than 3rd party conversions. Currently they drive GM and Chrysler OEM vehicles as well as F QVM trucks from Westport Wing and BAS. LNG Storage is Evolving As Well

Optimized for spark engines, the new WPRT LNG Tank System, available in 120 and 150 gallon capacities, begins shipping by mid-2013. The new 120 gallon or 150 gallon single-tank systems can run for approximately 350 to 450 miles, respectively, on cold (unsaturated) LNG fuel. Previously WPRT spark-injected engines required saturated LNG. Using cold LNG adds about 10% greater driving range. Fleets with a combination of spark-injected and WPRT High Pressure Direct Injection (HPDI) trucks can now rely on the same LNG refueling infrastructure due to the system's fuel-flexible capabilities. Even though the new tank is more expensive a current comparable single LNG storage tank, WPRT asserts the system saves money overall by requiring only one tank. This not only saves the cost of the extra tank but reduces vehicle weight which can contribute to better mpg or extra payload. Compared to existing compressed natural gas (CNG) options, a single 150 gallon Westport LNG Tank System takes the place of three standard CNG tanks, lowering fuel storage expense and reducing overall vehicle weight by approximately 600 lbs. Additionally, LNG has shorter refueling times compared to CNG. Faster refueling is a very important point to the trucking industry as the Federal Motor Carrier Safety Act (FMCSA) restricts continuous work hours of drivers and is exacerbating the preexistent shortage of drivers.


http://energy.aol.com/tag/Honda/

http://energy.aol.com/tag/Frank+Dankovich/

http://energy.aol.com/tag/Chrysler%20/


Light Duty Vehicles

Adoption of NGT is a Replacement Cycle Phenomenon

While it is likely some used vehicles are being converted to NG, adoption in large numbers lies in new vehicle sales, from either OEM’s or designated Qualified Vehicle Modifiers (QVM). When trying to imagine rates of adoption out to 2020 the first step is to try to identify reasonable numbers for existing classes of vehicles more likely to convert to NG. Then estimate the replacement rate of each group to arrive at an annual addressable number.

Fleet Vehicles Are One Potentially Strong Market for NGT

Fleet vehicles generally follow a hub and spoke model driving a fairly well-defined route during a typical business day and returning to the same car yard at the end of the work day. Since this is an ideally efficient refueling model for an alternative fuel it is not surprising that fleets have seen the highest adoption rates of NGV to this point. The better emission profile of NGV’s has also been influential in fleet adoption. NGV are part of taxi fleets, courier and delivery fleets, government and police fleets, community fleets, and trades and commercial fleets. Fleet adoption will continue to increase with more OEM choices like the Chevy Express, and GMC Savana CNG Cargo Van with attendant warranties and evolutionary storage improvements. QVM Ford Transit Connect taxicabs from BAF are finding sales as well. In particular, fleets offer the best opportunity for more NG adoption in passenger cars. Refueling is not an issue with fleet cars. With the exception of taxi and livery fleets, lost trunk space is somewhat unimportant since they are not used to move family members and personal belongings. The environmental benefits of a NGV can be more important to a fleet as there may be government incentives available for lowering fleet emissions. However, vehicle cost and speed of payback remain important to fleets. Evolutionary improvements which lower the initial cost of passenger cars will accelerate their adoption.



Source: Automotive Fleet

Currently, we do not consider rental car fleets good candidates for NG. Their routes are too indeterminate and they often end up in destinations different than their point of origin. However, we think any regional adoption within rental fleets will be tangible evidence that refueling is reaching a tipping point in that area. This reduces our addressable car fleet estimate by 40%.




Overall, we assume an addressable baseline of fleet vehicles at 10,000,000 (rounded down). We also assume the mix within this fleet is 41% cars and 59% trucks. The Vehicle Replacement Cycle is the NGV Purchase Opportunity

Source: Automotive Fleet While there is no universally agreed upon fleet replacement cycle approach, depreciation is the core of every fleet manager’s approach. The depreciation curve above shows that the bulk of the depreciation cost is incurred inside of 60K miles. From that point the mix of declining depreciation cost and increasing maintenance cost creates a fairly flat cost profile out to 120K miles. Against this backdrop, time becomes an important variable. If fleet cars were putting in 20K miles per year and replaced at 60K miles, the fleet would be exposed to high first year depreciation costs every fourth year, or four times in a 12 year cycle. If replacement could be managed to 80K miles that would push the high depreciation to every fifth year or three times in a 12 year cycle. Going out to 100K miles means higher depreciation once every sixth year or three times in a 15 year cycle. Maximizing Resale Lowers Depreciation Overall On paper the longer cycle looks attractive, but there are other important factors to consider. Aside from “soft” variables such as safety, employee morale, company image, there is the quantifiable variable of resale of replaced vehicles. Holding vehicles too long can mean poor resale values which increase depreciation overall.



In one real-world example, a fleet manager who leased had sedans on 50-month leases, with 70,000 to 80,000 miles driven within 20 months. The vehicles were turned in early for a loss because of the early turn-in time. Concurrently, the fleet’s vans and half-ton trucks were on 50-month leases but were turned in at 75,000 miles in an average 32 months. Interestingly, the vans and trucks generated a credit on resale value. Subsequently the manager put the cars on shorter-term leases and extended the vans to 55-month leases to avoid early turn-in penalties on the cars and to take advantage of the value of the vans. Total Cost of Ownership is integral to fleet management. If NGV’s continue to prove more durable than gasoline and diesel vehicles as mounting evidence suggests, it will mean longer replacement cycle times in some fleets and higher resale values through shorter cycle protocols in others.


Longer Vehicle Holding Times are a Structural Trend

There is no question that the Great Recession put pressure on fleet managers to contribute to tighter corporate budgets by keeping older vehicles running longer. But to some extent this trend would have been evident anyway because of improved vehicle quality. It is now fair to say that any reputable vehicle is built to avoid a catastrophic failure for at least 100,000 miles. Stretching out another 20,000 miles with good maintenance practice and driver education on proper driving techniques is feasible.

A final consideration is seasonality in any year that selling vehicles is required. The best time to sell is in the fall and the next best time is in the spring (due to the relationship between selling used cars and the yearly roll-out of new models). This can be a source of vehicle stretching if for budgetary considerations



replacement of vehicles has been pushed into the next year. However, in so doing, sales of legacy vehicles will be lower and depreciation higher as the result.

Our Modeling Assumptions

For our model we assume fleet trucks drive 30,000 miles per year, achieve 120,000 miles, and are replaced after 4 years. We assume fleet cars drive 25,000 miles per year achieve 100,000 miles and are replaced after 5 years. On this basis we model LDV fleet consumption of .14 Bcf/d year-end 2020.

Fleet Focus: Buses and Refuse Trucks, Earliest Adopters of NGT

Source: Waste Management Company Report

While buses and garbage trucks represent a limited market, with only a little more than 68,000 transit buses, 480,000 school buses, and somewhat more than 136,000 refuse trucks operating in the country, they have both seen high early NG penetration. Currently, 30% of transit buses operating and 25% of new buses sold use NG.

• In December, 2012, San Diego Metropolitan Transit System (SDMTS) ordered 350 new 40 ft. and 118 new 60 ft. buses. SDMTS will receive 97 new buses in 2013 and 50 per year for the next four years as replacement cycle purchases of existing CNG buses. All the buses in the SFMTS use Cummins-Westport (CWI) ISL G 8.9 liter engines.



• In January, 2013, LA Metro ordered 550 new CNG buses for 2014-15 with an option for 350

more in 2016. The buses are powered by CWI 8.9 liter engines.

• In April, 2013 Dallas Area Rapit Transit (DART) will begin taking delivery of a 459 CNG bus order comprising 31 and 40 ft. buses. All of DART’s buses run on CWI 8.9 liter engines. These buses are replacing both LNG and clean diesel buses in service since 1998. In 2015, when all the buses will be in operation, DART expects to reduce annual fuel costs by nearly two-thirds.

According to Natural Gas Vehicles for America almost 50% of all refuse trucks run on NG. WM, the biggest solid waste hauler in the U.S., recently committed to

• Increase CNG from 80% to 100% of its 18,342 truck fleet removing both diesel and LNG from operations.

• WM noted with use of CNG instead of diesel costs dropped from up to $11 for every driver hour worked to about $3 an hour. This is because CNG trucks refuel overnight from unattended slow-fill pumps eliminating lost worker time filling up at diesel pumps.

• WM allows public access to all of its CNG fuelling facilities

• The company will grow the current 1400 CNG fleet as part of its normal replacement cycle of approximately 1,000 trucks annually.

• The company cited lower cost premiums for CNG trucks. As an example, refuse truck manufacturer New Way now offers factory CNG integration providing quicker turnaround and lower costs.

Similarly, in the city of Phoenix

• By April, 2013, 20% of the AZ solid waste fleet will be CNG vehicles, the largest in the state.

• By the summer of 2014, that percentage will increase to 30 percent, with a goal to increase numbers by 10 to 15 percent every year.

• Once the Phoenix fleet is fully converted to CNG, the city estimates saving almost $2 million annually while bringing improved regional air quality and energy security.

Transit buses and garbage trucks can use 10,000 to 15,000 gallons of fuel per year. Continued growth in this segment remains meaningful for greater NG consumption.



Fleet Focus: Class 8 Combo Trucks, an LNG Opportunity

Source: Ryder Systems Company Report

According to the Federal Highway Administration (FHWA), combination trucks--tractors designed to pull one or more trailers--account for 59% of Class 8 miles travelled and are the largest portion of HDV diesel consumption. FHWA says there were 2.6 million registered combination trucks in the U.S. which drove a total 176 billion miles in 2011, for an average 67,692 miles per truck. Assuming an average historic fuel economy of 5.5 mpg, Class 8 trucks consumed an estimated 24.4 billion gallons of diesel, which is equivalent to 582 million barrels of oil, or 8.9 Bcf/d of NG. In the combo truck sub-set this then suggests 5.2 bcf/d of NG consumption.

Aside from hub and spoke fleets, combo trucks represent the best opportunity to fuel with NG due to their high mileage per vehicle. According to Steve Leffent, UPS Director of Global Sustainability, “The cost of the vehicles is coming down and fuel is becoming more available.”

New Truck Sales are the Basis for Replacement Cycle Assumptions

According to Ward’s Automotive new Class 8 trucks sales were, 217,286 in 2011, and 250,419 in 2012. For comparison, in 2006 284,008 Class 8 trucks were sold. Clearly, the financial crisis in 2008 and subsequent low growth environment weighed on new truck sales, which is not an enormous turnover percentage to begin with. It is tempting to assume that with further economic recovery a return to halcyon numbers is assured but we prefer to be conservative. If anything, a high rate of adoption of NG HDV augers for longer life per vehicle, a structural pressure on new sales numbers apart from exogenous economic effects.

Furthermore, we focus on the replacement cycle because of the bifurcation in the Class 8 category. We estimate roughly 20% of Class 8 owners are big fleets while 80% are fleets of 6 trucks or less. It is the



20% group that may replace diesel trucks with new NG trucks. They have capital programs of regular truck replacement in place. They work with customers that care about environmental footprint and want better emissions numbers in their carriers. The down-market progression of trucks is called cascading. When a large fleet sells a Class 8 truck (on average within 7 years), it is usually to smaller operators who specialize in buying these single owner used trucks. After perhaps 5 more years this group will sell these trucks into the aftermarket. Historically, even very high mileage trucks have continued to see use until federal emissions standards rendered them obsolete for interstate hauling. At that point they are either sold overseas or retain life in intrastate hauling. This is one reason port drayage trucks are amongst the oldest and most polluting trucks in the fleet. The point is that since CNG/LNG combo trucks will likely continue to be emissions compliant indefinitely, their usage and consumption of NG is likely to be durable.

Class 8 Truck Seven Year Replacement Cycle

Year 2013 2014 2015 2016 2017 2018 2019 2020 Installed Base (MM) 2,600,000 2,603,750 2,607,556 2,611,420 2,615,341 2,619,321 2,623,361 2,627,461 Miles Driven (Bn) 176,000 176,254 176,769 177,293 177,825 178,367 178,917 179,476 Per Truck Mileage 67,692 67,692 67,791 67,891 67,993 68,097 68,201 68,308

Rplmnt Sales 250,000 253,750 257,556 261,420 265,341 269,321 273,361 277,461

% of Base 9.6% 9.7% 9.9% 10.0% 10.1% 10.3% 10.4% 10.5%

Yearly Fleet Increase 0.0 3,750 3,806 3,863 3,921 3,980 4,040 4,100 Cmltv Fleet Increase 0.0 3,750 7,556 11,420 15,341 19,321 23,361 27,461 MPG 5.50 5.72 5.95 6.19 6.43 6.69 6.96 7.24 % Rplmnt 1% 5% 10% 14% 18% 22% 26% 30% % Total Fleet 0.10% 0.49% 0.99% 1.40% 1.83% 2.26% 2.71% 3.17% New LNG Trucks 2,500 12,688 25,756 36,599 47,761 59,251 71,074 83,238 Cmltv LNG Trucks 2,500 15,188 40,943 77,542 125,303 184,554 255,628 338,866 DE Gallons (MM) 30.8 180 467 851 1,324 1,878 2,505 3,198 Annual Barrels(MM) 0.73 4.28 11.11 20.26 31.53 44.72 59.65 76.15

Annual Bcf 4.1 24.0 62.2 113.5 176.6 250.4 334.0 426.4

Bcf/d 0.01 0.07 0.17 0.31 0.48 0.69 0.92 1.17 Source: Rosenblatt Energy Research



Class 8 Replacement Cycle Model Conclusions

The model demonstrates a few core ideas:

• MPG will increase in Class 8 over time;

• Trends in extending HDV service life are not likely to contract hence a 7 year replacement model (although a small sub-set of extreme mileage-per-year HDV will be replaced sooner by large fleets);

• a large percentage capture of the replacement cycle opportunity in a given year still represents a small percentage share of the fleet overall;

• Nevertheless, a small percentage share of the total Class 8 fleet still creates a meaningful NG consumption figure.

Adoption Rate Estimates Vary Widely

The model above does not claim to be definitive but is illustrative and feasible over a 7 year time span. SWFT CEO Jerry Moyes, pointing to the higher-powered engines on the horizon said, "We really think that this industry over the next five years could be close to 50% natural gas." We interpret that to mean close to 50% of replacement sales could be NG, a much more aggressive assumption than our model. FedEx Corporation (FDX) CEO Frederick Smith predicted between 5%-30% of U.S. long-distance trucking will be fueled by CNG and LNG over the next ten years, a wide-ranging prediction from a company that has not been an early adopter like UPS. FedEx is currently testing two CNG and two LNG trucks, and looks to buy more if the tests are successful. Smith expects truck cost to decline and refueling choices to improve while adding that the cost of NG tractors is the primary variable that will affect the magnitude of FedEx NG truck adoption. CLNE management says that FedEx Freight has been running LNG trucks up to 1,000 miles per day out of Dallas and are pleased with performance.

Ultra Long-Haul Trucking Rationalization is Positive for LNG Adoption

Long-haul trucking is moving away from one driver/one long haul. Drivers have consistently shown a willingness to receive less pay in return for more hours at home with their families. Furthermore, the FMCSA has imposed limitations on the amount of trucker driving time. Distribution has responded with a reorganized supply chain that allows a driver to be away from home for no more than 2 days at a time. Instead of making loads move from point A to point E with one driver, the route can be broken up with one driver regularly driving between points A and B, another between points B and C, and so forth. In this way loads can be quickly swapped between different tractors, and have the additional advantage of delivering and augmenting loads at several points along the route without huge increases in time driven overall. This is creating a greater number of 300-400 mile per-day loads, and plays well into the LNG trucking sphere. Depending on tank configuration, driving 300-700 miles with LNG can be easily obtained. This is also an area for longer range CNG to have an increasing role as better storage solutions take hold.



Greater Engine Breadth Will Drive Faster Adoption in HDV

Aside from capital costs and refueling options, engine choice has been limiting adoption of NG in HDV. The 8.9-liter engine came first, which was suitable for refuse trucks, buses, and shuttle buses which have seen rapid adoption. Next was the WPRT HPDI 15-liter. However, this truck fuels with both LNG and diesel, and requires urea as part of the emission control technology. In short, the 15 liter engine is a somewhat complex solution that is also too much truck for all but the most demanding hauling situations. The yawning 12-13 liter gap is being filled in 2013 with the introduction of the CWI 11.9-liter engine (full production, August, 2013). In 2014, VOLV will launch a 13-liter engine for the North American market (using WPRT HPDI technology). 12-13 liter diesels are taking over many applications historically served by 15-liter-class engines in Class 8 vehicles to save money, fuel consumption and lower emissions. As one proof, 13-liters recently outsold 15-liters in heavy trucks for the first time ever. With modern combustion technology and advanced electronics, the 13-liter engines can produce high horsepower and torque to many customer specifications. Both CLNE and ECA have told us the CWI 11.9 will be a game changer. In addition to filling a gap it will be utilized by all major U.S. Class 8 OEMs increasing choices and decreasing costs.

Refueling Infrastructure is Broadening Support of HDV NG Adoption

Importantly, installations of CNG/LNG refueling capability are increasingly rapidly. Choice means competition, and truckers need to be able to obtain fuel at competitive prices.

• CLNE is accelerating deployment of highway CNG and LNG locations by installing pumps at select Pilot Flying J locations no more than 250 miles apart. 70 LNG locations were built in 2012 with 70-80 more for 2013. Some of these stations are waiting for demand to become truly operational but at least this half of the “chicken and egg” problem is being solved.

• RD and TA plan to build more than 200 LNG fuel lanes at approximately 100 TA sites and Petro Stopping Centers throughout the country with the first expected to become operational in 2013. TA also plans to train and equip many of TA's 3,000 repair technicians, 1,000 truck service bays and 400 Road Squad emergency roadside repair vehicles to service natural-gas-powered truck engines, an important value-adding investment beyond fuel availability itself. TA is also considering adding CNG at select locations.

• Independently RD announced that it would build two LNG liquefiers, one in Ontario, Canada, and one in Louisiana, which together could liquefy 500,000 tons/y, or 12K boe/d. The plants will be finished within 3 years. Longer range plans are to produce 10 times this amount of LNG in the next decade.

• Class 7 and Class 8 heavy-duty trucks now operate on a 700-mile corridor between Salt Lake City

and Los Angeles with public freeway access to LNG every 200 to 250 miles.

• The “Texas Triangle” is a Texas state government initiative to provide grants for 20 CNG/LNG stations between Dallas-Ft. Worth/San Antonio/Houston as well as rebates for HDV purchase. Each station’s base volumes are supported by a local anchor fleet.



• Expanded government fleets will require more refueling options. Typically, government and municipal facilities (e.g., Columbus, OH; Phoenix, AZ, Los Angeles, CA) overbuild capacity to encourage wider adoption of NGV, primarily to improve air quality.

• 4 CNG stations are being built on Interstate 79 between Charleston, WV, and Mount Morris, PA,

in support WV’s policies to encourage the growth of NGV in the state.

• Kwik Trip, a 385 store chain, has 12 CNG/LNG stations under construction in Minnesota, Wisconsin and Iowa and will have 18 stations fully operational by June, 2013. These stations will enable use of natural gas-powered vehicles within the three-state area.

• Stripes, a division of SUSS, is a convenience store chain with 550 locations in Texas and surrounding states. APA realized their public CNG stations had no extra amenities beyond convenient refueling and thought it would be interesting to get a C-Store involved. They approached Stripes with a proposal to help them get comfortable with CNG. For their part Stripes was looking at projections showing that by 2020 10% of all convenience locations will have NG as product, and they were interested in getting involved. APA engineers helped Stripes put CNG pumps at two locations in Midland, TX, which are also convenient to APA Permian Basin employees. Going forward, further expansion of CNG refueling will be led by Stripes.

Overall, understanding and using replacement cycles is how we model NGV uptake into the various fleets we have examined into 2020. Specific to HDV, while we do not know with certainty the actual replacement cycle percentage LNG trucking will capture in any given year, we do expect it to progressively increase, particularly as the CWI 11.9 liter engine takes hold in 2014. Class 8 OEM’s are fully engaged with NG which both reduces price premiums and increases consumer confidence. The payback period is shorter for HDV than any other vehicle class and the resulting operational savings become very attractive.

We model bus/refuse consumption of .58 Bcf/d year-end 2020. We model Class 8 consumption of .7 Bcf/d year-end 2020.



Railroad Locomotives

Rails Are Pressured By LNG Trucking

In the intermodal traffic world the rails have seen trucking erode their market share in every category. The one area where rails manage to maintain an advantage is 750 miles and longer transport. Broadly, as LNG long-haul trucking grows it will increase trucking competitiveness at longer distances. This threat motivates an accelerated adoption of LNG into locomotives as a result. Put another way, current testing of LNG locomotives confirms the railroads are taking adoption of LNG in HDV seriously. Environmental Strictures Are Coming As Well New EPA air-pollution standards for railroads will likely require railroads to use ULSD or add expensive emissions-control equipment to new diesel locomotives in 2015. Stricter emission requirements in major U.S. ports are another intermodal push on the railroads to clean up locomotive emissions.

Railroads are Ideally Suited for LNG

Of all the methods of transportation, nothing has more route specificity than a railroad. Railroads have unique insight into and control over their logistics, and can plan their LNG support infrastructure for maximum efficiency.

Testing Has Already Begun

Source: Canadian National Railway

CNI, Canada’s largest railroad, is testing two main line diesel-electric locomotives fueled 90% by LNG on 300-mile revenue runs north of Edmonton to Fort McMurray, the rail gateway to the oil sands region of northern Alberta. Fueling and maintenance takes place in Edmonton. CN announced it was exploring LNG to “Look for ways to improve operating efficiency and advance the company’s sustainability



agenda,” the latter point referring to the better emissions profile of LNG. The CN-led group expects to conduct engine laboratory tests in 2013 and roll out prototype main line locomotives for road tests in 2014. For its part of the project, WPRT secured a funding commitment of C$2.3 million from the Canadian government’s Sustainable Development Technology Canada. We do not imagine an oil sands run fueled by LNG was chosen by chance. BNSF Railway Co., the 2nd largest U.S. railroad, is also testing LNG locomotives from GE and CAT this year. Unlike the replacement cycle modeling we did for trucking, BNSF has indicated it will “aggressively retrofit” existing locomotives to consume LNG if the tests are successful. This implies LNG consumption in rails could grow faster than replacement cycle economics. We examine this more closely in our WPRT analysis following this report.

Caterpillar Is Betting On LNG Large Engines Dedicated natural gas and natural gas-diesel dual-fuel options will be available from Caterpillar engines for marine, diesel, rail, mining, construction, E&P operations and remote power. CAT believes the first LNG-powered products are likely to include large Cat 793, 795 and 797 mining trucks. One 797 can consume as much as 500K g/y of fuel, or about one-half that of RER’s annual U.S rig and fracking estimate. Locomotives produced by Electro-Motive Diesel, the unit of Caterpillar’s Progress Rail Services that is supporting the CN and BNSF LNG tests, are also believed to be early adopters for the reasons already mentioned. Caterpillar and EMD have partnered with WPRT to apply HPDI technology to compliment “Caterpillar’s strengths in engine and off-road equipment development and EMD’s locomotive expertise.” CAT expects commercial products within 5 years. That is also a reasonable timeframe within which to expect LNG in long-haul trucking to be more commonplace than at present and more ports to have imposed of stricter emissions requirements. Locomotives Are Long-Lived Assets Train locomotives have average service lives of 30 years and several engine rebuilds over that period. A fairly large percentage of current locomotives are near the end of their service lives. This makes the notion that locomotives could be retrofit to consume LNG far more plausible as the result. Our industry sources tell us that every railroad is looking at LNG closely at the present time. With only 7 Class 1 railroads in the U.S., it is almost inconceivable that if one big rail adopts LNG the others will not follow. Crude Oil Is Rail’s New Best Friend While LNG in trucking is a competitive push for rail LNG adoption and emissions standards are a regulatory requirement there is another motivation as well. For many years there has been one long-haul customer that the rails have had to themselves: coal. However, between an unsympathetic EPA, four years of low gas prices, and a couple of unseasonably warm winters, coal consumption has declined demonstrably and with that rail transport of coal. There may be some recovery in volumes as efforts to export more U.S. coal gains steam but a return to halcyon volumes is unlikely. Needing a replacement customer the rails are leveraging their huge footprint to break bottlenecks in crude oil transport.



Source: EOG Resources Company Report Here we pay particular attention to EOG’s assertion that oil-on-rail has become “competitive with existing and announced pipe expansions”. While we believe it is still more expensive to move oil by rail than pipeline, competition is no longer purely on a per-unit cost basis. The railroads’ ability to respond quickly to rising production in the Bakken Shale, Eagle Ford Shale, Permian Basins and the Rockies has added time value of money to the normal comparative calculus between pipeline and rail. Eventually, running their locomotives on cheaper NG will allow the rails to become even more competitive with pipelines. BNSF Railway announced in September, 2012, that it had reached 1 mmbbl/d hauling capability from the Williston Basin in Montana and North Dakota. BNSF projects it will grow shipments to 700Kbbl/d by yearend 2013. KSU has also increased crude hauling as a way to help compensate for lost coal loads.



The WTI/Brent Price Spread Is the Catalyst

Source: EIA The driver of this build-out has been the wide price disparity between WTI and Brent. Crude priced in Cushing averages $15-$20/bbl less than Brent. As we can see from the EOG slide, all railroads are leading south and east of Cushing with water the final destination. St. James, LA delivery merits a Louisiana Light Sweet (LLS) price, an Atlantic basin waterborne benchmark similar to Brent. With double digits per barrel to be gained by going away from Cushing, paying the rails $5/bbl more than pipeline transport is not a concern. In fact, it has even been economical to truck oil over gaps between pipelines in the Eagle Ford Shale in South Texas, a practice that was unheard of before the advent of wide crude oil price spreads. The cause of the price spread is pure supply and demand. After the introduction of 510Kbbl/d from the Keystone pipeline in 2011, 815,000 bbl/d of new cumulative oil pipeline capacity to Cushing had been added. Over the same period, only 400,000 bbl/d of new pipeline take-away capacity was constructed. Production in CO, TX, ND, and Alberta continues to grow. During the next two years 1,190,000 bbl/d of new pipeline delivery capacity is planned for Cushing, balanced by plans to build 1,150,000 bbl/d of delivery capacity from Cushing to the Gulf Coast. In addition, about 830,000 bbl/d of new pipeline capacity is planned to move crude oil directly from the Permian Basin to the Gulf Coast, avoiding the congested Midwest.



Oil on Rail Offers End-Market Flexibility While these numbers alone do not make it clear that the current oversupply potential of 410Kbbl/d will be solved, there is another potential problem in the plan, namely that all that Cushing oil is going to one place, the GOM refining complex. GOM refining capacity is vast, but nothing is limitless. The flexibility of the railroads is increasingly being seen by E&P’s as a reason to choose them to create portfolio diversity. In their last quarterly call EOG specifically cited the railroad’s attractive ability to move their crude anywhere in the U.S. that had advantaged differentials. From a refinery perspective, the rails are the only alternative to pipelines in satisfying their long supply chains. To this end BNSF plans to deliver crude to refineries in California, Oregon, and Washington, and is in talks with other rail carriers to move crude to the East Coast. This Trend Is the Railroad’s Friend The Association of American Railroads (AAR) reported on 2/27/13 that U.S. Class I railroads originated a record 233,811 carloads of crude oil in 2012, up 256 percent from the 65,751 carloads of crude oil originated in 2011. Crude oil in 2012 represented 0.8 percent of all U.S. Class I rail carloads, up from 0.2 percent in 2011. AAR reports crude-only car-loading data on a quarterly basis, with 4th quarter of 2012 seeing 81,122 carloads. Further Expansion is Upon Us

On 3/5/13 Canadian National announced it will increase shipments of heavy northern Alberta crude oil through LBC Tank Terminals’ expanded Sunshine facility within the Gesimar, LA., industrial complex, starting this month. This is part of CN’s plan to capture LLS pricing. CN is also moving chemicals from the Chicago area to the LBC Tank Terminals facility at Geismar. Sunshine is expanding storage capacity by 160,000 barrels, adding additional rail unloading and steaming spots and increased storage capacity. The expansion at Geismar is expected to be completed by October, 2013, and will eventually result in total storage capacity of nearly 3 million barrels. This could be seen as a hedge against failure to approve Keystone XL. Perhaps more accurately it is a repudiation of sending extra tar sands oil to capture mediocre pricing at Cushing.

Conclusion

It is our opinion that there will be LNG uptake in locomotives as a cost-effective way to compete with HDV using the same fuel and to comply with emissions requirements pushes from U.S. ports. Now that major railroads are directly competing with pipelines hauling accelerating amounts of crude oil, improving their environmental footprint, particularly when transporting Canadian diluted bitumen, is additional motivation to run on LNG. Similar to an E&P, burning NG to move crude oil can make sense for a railroad as well. We model .5 Bcf/d of locomotive demand year-end 2020.


http://www.newswire.ca/en/story/1122001/cn-and-lbc-tank-terminals-team-up-to-increase-heavy-northern-alberta-crude-oil-shipments-through-geismar-la-facility


Marine Engine Applications

Source: Germanischer LLoyd U.S. Coastlines Are an Emission Control Area (ECA) On an absolute basis shipping is not a huge source of global pollution, by most estimates around 3%. But on a per-mile basis, it is by far the most polluting form of transportation because it burns the dirtiest fuel. MARPOL VI has imposed air pollutant emissions regulations requiring the reduction of SOx, NOx to 0.1% in Emission Control Areas (ECA) within 200 nautical miles of designated coastlines and ports and 0.5% for global shipping outside of ECA’s. ECA enforcement in the U.S. began 8/1/12 and will be enforced in the EU by 2015 (Baltic, North Sea, and English Channel). The global requirement is currently slated to be enforced in 2020. A fuel availability review will take place in 2018 for possible extension to 2025. Numerous Studies Indicate MARPOL VI Requires ULSD or LNG

• A large 2009 Finnish Study on the effects of the IMO regulations on bunker fuel noted, “According to an IMO expert study, the use of heavy fuel oils will largely have to be abandoned once the sulphur content limit in fuel decreases to less than 1%. Transfer to low sulphur and thus



cleaner fuels will increase fuel costs considerably, because it is more expensive to produce cleaner fuels than heavy fuels.”

• One analysis published by the maritime clean tech market insight firm MEC Intelligence

estimates more than 5% of the world fleet will adopt LNG propulsion by 2020. The key compliance options available are either adoption of low sulphur fuels such as ultra-low sulphur Marine Gas Oil (MGO) and LNG, or using scrubber technology on the existing heavy fuel oil (HFO). MEC Intelligence estimates the total lifecycle ownership cost for a new build LNG propelled vessel is expected to be up to 40% lower as compared to that of a fuel oil and MGO propelled vessel depending on vessel type and geography.

• A highly detailed study performed by maritime consultancy Germanischer Lloyd and maritime

engine manufacturer MAN Diesel and Turbo SE concluded that for operation predominately within ECA’s investing in LNG was the superior choice. It is expected that low sulphur diesel will be significantly more expensive than LNG, and that LNG on an energy content basis can price close to HFO without the attendant cost to scrub the dirty fuel. The report compared and contrasted different sized vessels with the share of ECA operations to assess the benefits of other technologies, such as Waste Heat Recovery systems (WHR), and evaluate “payback” times. The joint study concludes that, “when standard assumptions are used, LNG systems offer shorter payback times than scrubber systems.”

• A viability study undertaken by Princeton Sovereign Maritime LLC, on the LNG as bunker fuel in U.S coastal and inland waterways marine transport validates the superior cost advantage of LNG used as marine fuel when compared to ultra-low sulphur MGO. MGO was recently mandated by the U.S. EPA to be used in all marine assets operating in U.S ECA’s. The dual realization of fuel savings and regulatory emissions compliance is the catalyst for LNG in the U.S. marine fuel market.

• Another option that has been thoroughly explored in studies such as one presented by Morgan Stanley Commodities in April, 2012, suggests that the best option would be dual-fuel capability to run an engine on either MGO or LNG. This becomes in effect a call option on the price spreads between MGO and LNG and the fuel currently pricing best would be selected to drive the ship.

Scrubbing May Not Be Allowed Longer-Term

In addition to high investments in cleaning technology and an increase in fuel consumption of about 2% due to the higher resistance in the exhaust gas stream, it remains to be seen whether scrubbing will be allowed in the long term: when discharging sulfur oxides into the sea, large quantities of carbon dioxide are released. This is a noteworthy consideration because for long-lived assets like ships, environmental certainty is important. Put another way, an investment in LNG today means no regulatory headaches in the future; much like power utilities are gravitating to NG Combined Cycle Gas Turbine’s (CCGT) to meet regulatory certainty for onshore power generation.



The European Transport Committee Endorses LNG in Marine Use Currently, only Sweden has any meaningful facilities for refueling vessels with LNG and the European Commission proposed that LNG refueling stations be installed in all 139 maritime and inland ports on the Trans European Core Network by 2020 and 2025 respectively. These are not major gas terminals, but either fixed or mobile refueling stations to be available at all major EU ports. The EU Looks to be an LNG Opportunity All in, it is appears that EU LNG consumption in shipping is virtually certain with the only debate being the magnitude of eventual adoption. Will the EU ECA Really Motivate a Change in Shipping? This is a challenging time for ocean carriers. Pushback against costly regulations should be anticipated and delays in rule implementation expected. Nevertheless, because ports are specific locations and shippers know their regular routes between ports, LNG bunkering can be built efficiently. Gaztransport & Technigaz forecasts at least two years elapse from obtaining financing to powering a deep sea ship on LNG. This actually gives ports that intend to impose emissions standards time to begin developing LNG bunkering infrastructure so that the proverbial chicken egg can hatch. Some examples:

• The Port of Gothenburg, Sweden, will invest $155.3 MM in an LNG terminal through Dutch storage firm Vopak and infrastructure firm Swedegas with bunkering to launch by 2015.

• Norway has created a national LNG marine transport fuel storage network.

• Rotterdam and Singapore are to soon announce plans for LNG bunkering facilities.

• Antwerp is chairing a working group on LNG bunkering operations which includes Amsterdam,

Bremerhaven, Hamburg, and LA and Long Beach. EU Consumption of LNG for Shipping Could Mean Demand For U.S. Export LNG This potential for EU LNG demand growth also suggests a potential new home for some of the U.S. LNG export that is likely to begin in 2015. Some EU experts have voiced concern that there will be insufficient supply for the EU since Asia has maintained a growing appetite for LNG. Dr. Walter Kemmsies has repeatedly asserted that the international supply of LNG will be dependent on how much LNG the U.S. chooses to export.

RD seems to agree. The company’s subsidiary Shell US Gas & Power LLC and El Paso Pipeline Partners L.P. (EPB) unit Southern Liquefaction Company LLC, plan to develop liquefaction export


http://shipandbunker.com/news/world/866938-obstacles-remain-to-lng-bunker-uptake


capability at the existing Elba Island LNG import terminal near Savannah, Georgia. The Elba Island terminal has received U.S. approval to export up to 4 million tons per annum (mtpa) of LNG to Free Trade Agreement (FTA) countries, and it is seeking permission to export the same volume to non-FTA countries.

RD is also looking beyond the U.S. to manufacturing LNG in Canada for both onshore and maritime transportation industries. It plans to produce approximately 650 MMcf/d of LNG, half of which is earmarked for Green Corridor highway truck consumption between Alberta and British Columbia, with the other half serving shipping between Canada and the Rotterdam ECA.

Infrastructures Are Connected: Ports Will Push on Trucks, Too Some ports have had to jump into environmental improvement with both feet. In the case of the Ports of Los Angeles and Long Beach, there came the realization that there would be no local support for port growth if it was not accompanied by significant pollution reduction. This meant addressing pollution in trucks as well as ships since port growth would mean even more trucks into and out of the port and on local streets and freeways. In 2006, the San Pedro Bay Ports Clean Air Action Plan (CAAP) was created and all trucks coming into and out of the ports were regulated. Over a 3 year period all trucks entering had to be 2007 or newer (2007 was the EPA standard for clean diesel) or pay an access fee to enter the terminal, which quickly added up and motivated buying cleaner trucks. As the result, 2011 diesel particulate levels dropped 75% in comparison to 2005 levels. In 2007, the Ports of Tacoma, Seattle, and Vancouver jointly adopted the Northwest Ports Clean Air Strategy (NPCAS). Specific to drayage trucks, the NPCAS required that by 2015 80% of trucks entering the container terminals must meet the model year 2007 EPA emissions standard, and that by 2017 100% of trucks entering the terminals must comply with this standard. Similar efforts to clean up trucks working in ports are taking place in Oakland, New York, New Jersey, Houston, Charleston, and Norfolk. Many of the drayage trucks operating around ports are single-owner or mom-and-pop outfits that would struggle to improve their emissions without help. The EPA’s SmartWay Transport Partnership focuses on trucks making short hauls from ports to distribution centers because many of them are older and dirtier than Over-The-Road long-haul trucks. EPA grants plus scrap value are being given to drivers to upgrade to better trucks. Nine states also have programs to help drivers replace old dirty trucks. As more and more ports adopt comprehensive emissions strategies to improve their air quality an increasing number of trucks will need to improve as well. This will create an as yet unquantifiable opportunity for CNG/LNG trucking. We can say that Port of Long Beach currently has 11,000 trucks into the port and 1,000 of them run on LNG. We were told that if more LNG refueling facilities were available it is believed more trucks would convert.



U.S. ECA Enforcement Produces an LNG Response

Source: TOTE Company Report

ECA demands are producing effects in the U.S. 6 months ago Totem Ocean Trailer Express (TOTE) announced plans to have GD NASSCO convert two of TOTE’s diesel-powered roll-on, roll-off ships to burn LNG on service between the Port of Tacoma and Anchorage, Alaska. The company received a waiver from the Coast Guard regarding the 8/1/12 deadline by agreeing to run the ships entirely on LNG by 2016. Because the ships operate exclusively within ECA’s, converting them to LNG means the vessels will exceed regulatory compliance for the rest of their service lives, important since they were manufactured in 2003. The ships will be converted on board as they work. TOTE said LNG bunkering facilities that will be built to support its operations could also help other transportation industries in Puget Sound in converting to LNG. This was apparently a consideration in the Coast Guard granting the waiver. This likely will support an earlier opportunity for LNG trucks to meet the port’s 2017 emission standards as well.

In addition, TOTE is having GD NASSCO design and build two 3,100 twenty-foot equivalent unit (TEU) LNG-powered containerships. When completed the 764-foot-long containerships are expected to be the largest ships of any type in the world primarily powered by LNG. The first ship will be delivered Q415 and the second ship will be delivered Q116. The contract between NASSCO and TOTE includes options for three additional ships. The double-hulled ships will operate between Jacksonville, Fla., and San Juan, P.R.

TOTE Is an Example of the Low Hanging Fruit Approach Since TOTE’s Tacoma to Anchorage and Jacksonville to San Juan runs are within ECA waters it had to meet the highest standard. Further, since its routes are highly consistent TOTE is an obvious candidate for LNG conversion regarding bunkering development required.



Other Ships in ECA’s can be Good Candidates for LNG or Duel-Fuel It follows that if dirty ships cannot enter and pollute an ECA then none of the ships which work within the ECA can pollute either. This means that workboats, tug boats, and ferry boats must all meet the ECA emissions standards. These boats consume large amounts of fuel per year; in the case of tugboats as much as 130,000 g/y. Operational Savings Count On Water, Too While meeting environmental specifications can be a motivation to move to LNG, operational savings on lower fuel prices is definitely the other. An example of action upon this possibility is the New York City Department of Transportation announcement that it will convert an Austen Class Staten Island Ferry to LNG during a routine dry docking sometime in 2013. It is noteworthy that the ferry is currently meeting ECA requirements by using MGO. The conversion received a $2,340,000 federal grant with NYC paying the balance to reach $3 million cost of the conversion. A typical ferry runs constantly, has a 40,000 gallon fuel tank that gets filled once a week. Considering the projected spreads between ULSD and LNG, if the pilot is operationally successful, the conversion to LNG could cut approximately $3 million annually from its fuel costs using LNG paying back its conversion cost in one year. Emissions as a Catalyst to LNG Uptake Will Take Time

Overall, we think it will take 3-4 years for ECA strictures to begin to bite in ports around the U.S. We model marine LNG demand of 350 MMcf/d by 2020. The important point to note is that these emissions adoptions will represent a “second wave” of potential demand for CNG/LNG in trucking, stationary engines, rail locomotives and marine applications apart from the adoption cycles already underway.



The High Case: A Step-Change Storage Breakthrough

DOE ARPA-E is Pushing Storage and Refueling Boundaries

The Advanced Research Projects Agency-Energy (ARPA-E) was created by Congress in 2007 to fund potentially transformational energy technologies. In 2012 ARPA-E created the Methane Opportunities for Vehicular Energy (MOVE) program. The aim of MOVE is to reduce America’s dependence on foreign oil, reduce the U.S. trade deficit, and reduce harmful vehicular emissions by making NG a viable fuel for passenger cars. MOVE has invested $29.3 million in 13 projects. 9 of the projects are aimed at better storage methods and 4 seek to provide home fueling at greatly reduced cost. There are many large companies involved including GE, Ford, GM, REL, United Technologies Corporation (UTX), BASF (BASFY), and Eaton Corporation (ETN). There are a number of prominent universities participating including Northwestern University, University of California at Berkeley, University of Minnesota, and University of Texas at Austin to name a few.

All of the projects look interesting individually but collectively suggest several somewhat common strategies.

Adsorbed Natural Gas (ANG) Storage: Attracting Gas Rather Than Crushing It

Source: NREL



Trying to attract NG molecules to stick onto a surface (adsorption) rather than corralling them with pressure is an approach that will get a thorough exploration.

• Ford received the largest grant of the lot--$5,500,000 or almost 19% of allocated funding—to develop a low-pressure material-based natural gas fuel system. Ford asserts that if they are successful the system will “result in lowering the cost of on-board tanks, station compressors, and fuel” while increasing driving range.

• Texas A&M University is partnering with RTI International, Lawrence Berkeley National Lab and General Motors on a similar effort (e.g., storage of NG with highly adsorbent materials).

• Northwestern University, NuMat Technologies (a NWU start-up) and Gas Technology Institute (GTI) are sharing $1.5 million in funding to design, synthesize, and test high-performance materials that can store clean fuels and be produced on a large scale for industry. Their computer-aided design process allows researchers to rapidly identify high-potential, low-cost alternatives, speeding development.

• SRI International also has a sorbent-based method that promises to eliminate the pressure vessel entirely thereby reducing the cost of both storage and refueling.

Metal Organic Framework (MOF) is actually an area of materials science which can be characterized as well researched. For example, the DOE has supported research into hydrogen storage with MOF which traces program data back to 2002. Based at UCLA’s Department of Chemistry, this program included collaboration with Randall Snurr and Joseph Hupp, both of Northwestern University, who are now participating in the NWU/NuMat/GTI ARPA-E project cited above. The NWU researchers are also collaborating with the Department of Chemical Engineering at University of Surrey in England. Together they claim a breakthrough in MOF-based adsorption that increases available surface area by 40%.

BASF was also a collaborator in the DOE hydrogen storage project and is now working with Ford in their project cited above.

According to the University of Leipzig MOF’s are intriguing storage mechanisms versus other approaches because of their ability to be rationally designed. Hydrogen, methane, and CO2 are all being studied for adsorption by MOF’s and it appears that success with one molecule contributes positive knowledge for the storage of another.

Even the most enthusiastic researchers in this area caution that MOF-base approaches are still years away. However, we believe the long research history in the area by top university labs, now with focused government research funding, combined with the participation of large car OEM’s, chemical companies, and a visible competitive atmosphere suggests the success of MOF storage has never had a better opportunity.



Conformable Modular Storage

• United Technologies Research Center (UTRC) is designing modular natural gas storage units that can be assembled to fit a wide range of undercarriages at a cost of approximately $1,500--considerably less than today’s tanks. UTRC received the second highest funding award at $4.4 million.

• REL is developing a low-cost conformable tank with an internal cellular core.

• Otherlab is developing a tank filling with numerous small radius high-pressure tubes which it says is inspired by the human intestine. It promises low-cost, conformability, and maximum storage capacity.

• Pacific Northwest National Laboratory is using the same friction stir welding used on cruise missile fins to make metal tanks which are conformable. PNNL is aiming for the same $1,500 price point as UTRC. This research is notable because it is taking existing technology and trying to use it to drive down the cost of NG storage.

• Overall, we can view these approaches as more containment of NG approaches rather than attraction. The results from these efforts may not be as dramatic as what Ford and GM are hoping for but attainment might be more likely. A $1,500 tank that robs no interior space could be paid back in less than three years with average annual driving, 25 miles per gallon, and the $1.00/g CNG to gasoline spread we model throughout our forecasts.

Some Novel Home Fueling Ideas

• GE is developing a low-cost, at-home natural gas refueling system that reduces fueling time and eliminates compression stages. GE’s design uses a chiller to cool NG to a temperature below -50°C, which would separate water and other contaminants. According to GE this design has very few moving parts and will be virtually maintenance-free. GE believes their simplified, compressor-free design could allow fast refueling at 10% of the cost of today’s systems. With $5,000 the usual figure quoted for current systems, GE is forecasting at-home refueling for $500. Most sources assert that the cost of at-home gas will be below $1.00/GGE. Assuming this is true, projecting payback on a $2.00/gallon spread is not aggressive. With average driving the GE system could be paid back in around 5 months.

• Oregon State University and Colorado State University are teaming up to produce modifications

that would allow a passenger vehicle to provide its own compression for NG storage. OSU’s design would allow natural gas compression to take place in a single cylinder of the engine itself, allowing the actual car to behave like a natural gas refueling station. Ultimately, the engine would then have the ability both to power the vehicle and to compress natural gas so it can be stored efficiently for future use. The design would cost approximately $400.

• The University of Texas at Austin also has a single piston compression design which promises

less complexity and inefficiency with attendant lower cost, but uses a directly coupled motor that



is separate from the vehicle. This particular project received the third highest funding award at $4.3 million.

Overall, several of these projects do not sound farfetched. NG is already liquefied to -162°C to create LNG. Chilling it to -50°C degrees to separate water and impurities doesn’t seem like a daunting task although doing it for approximately $500 remains another matter. NG adsorbents are a mature chemistry from the standpoint of removing impurities from NG. Using adsorbents to hold and release methane on demand remains a different problem that awaits a solution but has possibilities. California PIER Program It should also be noted that California, through its Public Interest Energy Research (PIER) Program has been financing a University of Missouri research effort to store NG in activated carbon derived from corn cobs for a decade and continues to fund the effort.

MOF’s researchers believe their work will yield better results than carbon adsorption; however the CA effort is mature and continues to hit milestones. Research in this area significantly predates the CA effort. As one example, the Atlanta Gas Light Adsorbent Research Group worked from 1990-99 and ran a Chrysler van and truck on adsorbed gas, however the adsorbent cost was characterized as “prohibitive”. With an additional 13 years of research since then there has been enough time for the incremental improvements required to drive down costs and increase the chances of success.



Our High Case methodology assumes the development of an unobtrusive CNG storage system that holds enough gas to provide 300 miles of driving for passenger cars and 500 miles of driving for LDT. We assume this will cost $1,500 for the cars and $2,500 for the longer-range driving. We further assume some type of home refueling system that is easy to use will be developed at a cost of $500. We assume home refueling creates a $1.00/GEG cost and at least a $2/GEG spread to gasoline. We believe the resulting three year payback period would be acceptable to passenger car buyers. We assume no additional demand in 2020, primarily because we do not think the technology can be commercially viable much before then. If achieved, we would expect greatly accelerated growth in CNG adoption during 2020-2030. We expect payback to be much faster for commercial vehicles due to their higher annual mileage driven. We believe success with adsorbent NG storage would also lower the cost of commercial and home fueling due to its lower compression requirements. Seen in this way, the Ford claim that success with their storage effort will lower costs for NG storage throughout the value chain makes sense.



Consensus Forecasts and Historical Valuation Data of Companies in This Report

Business Ticker Price

2013 Consensus

EPS

2013 Consensus EV/EBITDA

Multiple

Trailing 3 Years

EV/EBITDA Multiple

Consensus Book

Value ($) Trailing 3 Years Book Value ($) EV/Sales

Trailing 3 Years

EV/Sales

Ship Builder GD $69.89 6.76 6.1 4.7 - 17.8 35.68 32.20 - 40.42 0.8 0.7 - 1.0

Delivery UPS $85.07 5.02 9.0 8.1 - 27.0 6.41 4.88 - 8.55 1.4 1.3 - 1.6

Truck Lease R $59.37 4.77 4.6 3.7 - 5.2 N/A 25.77 - 28.91 1.0 0.9 - 1.1

Truck Carrier SWFT $14.68 1.13 5.9 4.6 - 9.0 2.78 -11.06 - 1.65 0.7 0.7 - 1.3

Refuse WM $37.41 2.17 8.0 6.8 - 8.4 14.15 12.74 - 13.69 1.9 1.8 - 2.1

Refuse RSG $32.05 1.90 7.8 6.7 - 8.2 22.02 19.32 - 21.33 2.2 2.04 - 2.4

Railroad KSU $107.23 4.16 13.8 8.8 - 15.8 37.41 21.46 - 28.06 4.9 3.3 - 4.9

Railroad CNI $97.80 6.18 10.0 N/A 27.82 N/A 4.6 4.3 - 4.7

Fuel Producer APA $74.49 9.46 3.4 3.0 - 6.6 87.42 49.71 - 76.87 2.6 2.4 - 4.5

Fuel Producer CLNE $14.01 -0.51 231.8 53.3 - 352.7 5.92 4.3 - 6.91 4.1 3.1 - 9.5

Fuel Producer ECA $19.58 0.66 6.1 2.51 - 9.3 9.43 7.19 - 23.98 3.7 1.9 - 4.8

Fuel Provider TA $9.18 1.22 5.4 4.2 - 211.7 22.25 10.6 - 16.18 0.1 0 - 0.07

Fuel Provider SUSS $46.58 1.98 8.3 4.41 - 8.05 N/A 11.8 - 18.71 0.2 0.2 - 0.2

Export LNG LNG $24.74 -1.65 121.2 17.3 - 626.2 0.87 -11.86 - 2.67 29.7 10.5 - 29.7

Export LNG SRE $79.06 4.50 9.6 8.4 - 12.1 44.72 36.37 - 42.49 3.1 2.3 - 3.1

NG Engines CAT $87.75 8.03 6.0 4.9 - 15.7 33.37 14.24 - 27.35 1.0 0.9 - 1.6

NG Engines CMI $114.70 8.75 8.0 6.1 - 15.0 41.56 18.9 - 34.79 1.2 0.9 - 1.6

NG Engines GE $23.20 1.68 8.5 6.4 - 10.6 12.46 10.66 - 12.08 1.6 1.1 - 1.7

NG Engines WPRT $30.57 -1.58 N/A N/A 5.40 N/A 4.3 3.7 - 6.4

NG Storage MMM $104.80 6.83 8.9 7.06 - 10.3 28.07 19.02 - 25.58 2.2 1.8 - 2.5

NG Storage QTWW $0.64 N/A N/A N/A N/A 0.41 - 3.39 1.7 0.6 - 14.3

NG Storage WPRT $30.57 -1.58 N/A N/A 5.40 N/A 4.3 3.7 - 6.4

Vehicle OEM F $13.17 1.40 3.7 1.9 - 8.6 5.81 -1.6 - 4.91 0.3 0.2 - 0.5

Vehicle OEM GM $27.99 3.36 2.0 1.03 - 3.9 25.45 15.16 - 46.03 0.3 0.1 - 0.3

Vehicle OEM PCAR $50.06 3.18 8.0 4.2 - 18.8 17.95 13.7 - 16.61 0.8 0.6 - 1.8

Vehicle OEM VOLVY $15.04 5.98 N/A N/A N/A N/A 0.9 0.8 - 1.3



Business Ticker Price

2013 Consensus

EPS

2013 Consensus EV/EBITDA

Multiple

Trailing 3 Years

EV/EBITDA Multiple

Consensus Book

Value ($) Trailing 3 Years Book Value ($) EV/Sales

Trailing 3 Years

EV/Sales

E&P APA $74.49 9.46 3.4 3.07 - 6.6 87.42 49.71 - 76.87 2.6 2.4 - 4.5

E&P APC $83.20 4.01 5.7 5.1 - 13.7 46.16 36.33 - 43.13 3.5 2.7 - 4.8

E&P COG $67.17 1.29 12.9 7.3 - 21.65 13.25 8.87 - 10.17 9.5 4.8 - 9.5

E&P DVN $57.03 3.54 5.0 4.1 - 8.3 56.64 37.95 - 54.88 2.7 2.4 - 4.5

E&P ECA $19.58 0.66 6.1 2.5 - 9.3 9.43 7.19 - 23.98 3.7 1.9 - 4.7

E&P EOG $127.31 5.88 5.9 5.4 - 15.1 56.35 39.86 - 50.93 3.2 2.8 - 5.6

E&P NBL $114.11 6.55 6.2 6.1 - 10.0 51.53 36.34 - 46.13 5.1 4.07 - 5.9

E&P RRC $80.36 1.34 13.9 11.7 - 24.2 15.69 13.61 - 16.11 9.4 9.05 - 12.9

E&P SWN $38.21 1.63 8.2 5.9 - 11.3 11.27 7.35 - 11.89 4.9 4.1 - 6.6

Oil Services BHI $45.24 3.06 6.3 4.8 - 14.9 41.76 17.12 - 38.71 1.0 1.04 - 2.2

Oil Services HAL $39.13 3.02 6.3 4.2 - 11.8 19.33 9.86 - 16.97 1.2 1.04 - 2.4

Oil Services SLB $73.69 4.73 8.4 8.3 - 18.6 28.94 16.28 - 26.17 2.3 2.3 - 4.3

Source: Bloomberg



Major Research Sources “Natural Gas Vehicle Research Roadmap,” California Institute for Energy and the Environment “Exporting the American Renaissance, Global Impacts of LNG Exports From the United States,” Deloitte “Sulphur Content in Ships Bunker Fuel in 2015,” Ministry of Communications and Transport Finland “Heavy Duty Vehicles and Engines Analysis,” National Petroleum Council “Light Duty Vehicles,” National Petroleum Council “Natural Gas: Fuel for Thought ,” www.truckinginfo.com “Transportation Energy Data Book,” Oak Ridge National Laboratory “The Freight Transportation System,” Federal Highway Administration “Rail Time Indicators, A Review of Key Economic Trends Shaping Demand for Rail Transportation,” Association of American Railroads “Costs and Benefits of LNG as Ship Fuel for Container Vessels,” Germanischer Lloyd and MAN “Modeling the Case for Dual Fuel Shipping,” Morgan Stanley Commodities “LNG in the Maritime Industry,” MEC Intelligence “The Future of the LNG Industry in the Context of Global Energy Markets,” NGVA Europe “New Fueling Solutions with New Technologies,” Linde “Rolling Stock: Locomotives and Rail Cars,” United States International Trade Commission

A Final Point Concerning Our Approach to Macro Research We do not create research orphans. This report, and all subsequent reports we create, will be reviewed every quarter as relevant companies report on their business. Whether the trends are static or changing we will write our findings and delineate the how and why. Our reports will continue to have shelf life for as long as the trends under examination in a report remain viable and potentially actionable.


http://www.truckinginfo.com/


Focus Companies With every macro report RER provides analysis of select companies with specific exposure to the major themes explored in the macro research report. Any macro-derived company report includes extensive Q&A with company executives and/or important operational managers. From this report we offer the following:

ECA—“LNG: Been There, Doing That”

• We examine ECA investments in NG refueling, particularly in LNG;

• We discuss ECA as an advantaged low-cost producer in a large strategic U.S. NG shale basin;

• We dive into ECA’s deep skill-set using NG in oilfield services with ECA’s David Hill, Vice President, Operations, Natural Gas Economy. David is a renowned expert in alternative uses of NG.

WPRT—“Coming Forth With Game-Changers”

• How the differences between spark-ignited engines (SIE) versus dual-fuel compression-ignited engines (DFCE) are important;

• How WPRT has both approaches covered in the highly important 12-13-liter category;

• Some analytical approaches concerning the new engines;

• WPRT’s new LNG storage solution;

• The railroad locomotive replacement cycle and WPRT’s significant opportunity;

• WPRT’s potential in the oil patch.



CLNE—“Bringing America’s Natural Gas Highway to Reality”

• We deeply analyze the CNG landscape and disagree with analysts who claim the space is not competitive;

• Our trucking industry sources tell us big-truck fueling—including LNG—must also be off-highway;

• The important way that CNG and LNG differ as businesses;

• Throughout our analysis of CLNE we refer specifically to our detailed conversation with CEO Andrew Littlefair together with IR Tony Kritzer.

These reports are available upon request.



Rosenblatt Energy Research Analysts

Jeffrey Campbell has been a dedicated energy analyst for the past 13 years. His first 11 years were as Energy Analyst at Suffolk Capital Management, a growth and value institutional money manager in Manhattan. At SCM Jeffrey covered a broad spectrum of energy sectors—utilities, integrated oil companies, national oil companies, exploration and production, oil services, refiners, onshore and offshore drillers, equipment manufacturers, and a variety of alternative energy forms—and beat his relevant energy indices every year of service. In addition to equity research, Jeffrey covered oil and gas macro and oil and gas industry forecasting. Subsequent to SCM, Jeffrey was invited to initiate oil and gas macro research and large-cap E&P coverage at Pritchard Capital Partners, a boutique energy investment bank renowned for its fundamental research. Above all, Jeffrey has been prescient at spotting important energy trends: the ultimate lack of success in U.S. power deregulation; rising oil production costs that made unconventional resources economic; the increase in horizontal drilling and hydraulic fracturing which resulted in U.S. oversupply of natural gas; the importance of associated gas in unconventional liquids drilling; how the advent of horizontal pad drilling made traditional rig count analysis obsolete; coal-to-gas switching and natural gas market balance; the movement to deeper water and deeper drilling offshore as a catalyst for new-build drilling rigs; the globalization of natural gas. In addition to his work on Wall Street Jeffrey also provides oil and gas-related consultative analysis within industry. Prior to his career on Wall Street, Jeffrey was for 17 years a globally touring classical concert pianist. His Telarc recording of the Rimsky-Korsakov Piano Concerto (original cadenza by Jeffrey Campbell) during the Royal Philharmonic Orchestra’s 50th anniversary season remains in print since release in 1997. Jeffrey Campbell holds a BM and MM from The Juilliard School.



As Chief Economist at Moffatt & Nichol, one of the world’s leading port and freight infrastructure design companies, Dr. Walter Kemmsies directs market studies, financial analyses, and global trade and economic trend forecasts. He has led projects ranging from strategic development plans for ports in the Americas as well as M&A transactions and terminal-operator expansion decisions. He pioneered the development of infrastructure volume forecasts through the use of freight cost models to estimate regional market reach combined with freight corridor commodity flow data. Walter is also an advisor to executives at various port authorities and major transportation and manufacturing companies. Walter has been a keynote speaker at major industry conferences such as the American Association of Port Authorities, International Association of Ports and Harbors, Terminal Operators Conference, Journal of Commerce Trans-Pacific Maritime, the Rail Industrial Clearance Association, National Retail Federation and the Transportation Research Board. He publishes a regular monthly column in American Shipper. Walter also contributes to the Federal Reserve’s Survey of Professional Forecasters, as well as the Blackrock Global Institute. He is a member of the International Association of Energy Economists, the National Association of Business Economists, and a member of the Center for Advanced Infrastructure and Transportation board at Rutgers University. Prior to joining Moffatt & Nichol, Walter was the Head of European Strategy at JP Morgan, London, following service as Head of Global Industry Strategy at UBS, London. Walter Kemmsies received his PhD in Economics from Texas A&M University. As a registered analyst and its Chief Economist, Walter produces economic outlook reports for Rosenblatt Securities. The RER research process makes extensive use of high-level industry contacts, channel checks, proprietary data sources and their analysis, and the analyst’s diverse research experience. Rosenblatt Securities believes the collaboration of Jeffrey Campbell and Walter Kemmsies results in differentiated research. Copyright 2013 Rosenblatt Securities Inc. All rights reserved. Rosenblatt Securities Inc. seeks to provide and receive remuneration for Agency Brokerage, Market Structure Analysis, Macro, and other Sector Analysis, and Investment Banking Advisory Services. Rosenblatt Securities Inc. may, from time to time, provide these services to companies mentioned in this analysis. This material is not a research report and should not be construed as such and does not contain enough information on which to make an investment decision. Neither the information contained herein, nor any opinion expressed herein, constitutes the recommendation or solicitation of the purchase or sale of any securities or commodities. The information herein was obtained from sources which Rosenblatt Securities Inc. believes reliable, but we do not guarantee its accuracy. No part of this material may be duplicated in any form by any means.


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