Musings from the Oil Patch – March 16, 2010

• The Policy Challenge Of Producing Shale Gas
• From Sea To Sea, Wind Energy Controversy Continues
• Battle Over Future Vehicle Power Source

Musings From the Oil Patch
March 16, 2010

Allen Brooks
Managing Director

Note: Musings from the Oil Patch reflects an eclectic collection of stories and analyses dealing with issues and developments within the energy industry that I feel have potentially significant implications for executives operating oilfield service companies. The newsletter currently anticipates a semi-monthly publishing schedule, but periodically the event and news flow may dictate a more frequent schedule. As always, I welcome your comments and observations. Allen Brooks

A recent column in the Financial Times by John Dizard examines the issue of the cost to produce gas shales in the U.S. and the potential policy mistakes the nation may be making by relying on this resource base. Mr. Dizard began his column with an admonition that it was not wise to get into arguments over other people’s religions. He went on to say that there are times, however, when it becomes imperative to question the religious beliefs of others, and in this case the religion of shale gas. As he put it, “I think it might not be a bad idea to examine the faith-based assumption that the US has a virtually unlimited supply of natural gas from shale formations that can be extracted at a low price for the indefinite future.” As we know, the mantra is that the nation possesses 100-years of gas supply giving it the cushion to base its future energy policy on natural gas – even to the point that we will become a huge exporter of gas to world markets.

As Mr. Dizard states, “Perhaps the few people who think shale gas will be produced at higher cost, and more slowly, than generally believed should be heard out, rather than be executed or sentenced to work in the salt mines.” He highlights the problem with shale gas: It has become the focus of policy initiatives on all sides of the ideological aisle. For example, environmentalists believe shale gas will displace all our dirty coal-fired power plants. Liberals believe it will be the bridge fuel to a global clean-energy future. For national security conservatives, shale gas is the ticket to a U.S. no longer reliant on Middle East countries that are funding sources for global terrorism. Economic conservatives see shale gas as a way to reduce our current account deficit, which would help drive an economic revival. Political groups concerned with shale gas development include environmentalists, landowners and health advocates who are all concerned about the potential for shale gas to contaminate water supplies. Fortunately, this group is looking more toward regulation than prohibition of the development of shale gas.

One of the issues confronting shale gas is the economics of its development. The successful use of horizontal drilling technology and the application of massive hydraulic fracturing to break the shales and release the trapped gas has excited the E&P industry and convinced it that these formations can yield huge resources at extremely low costs. That is where the question of the viability of an energy strategy based on these “cheap” shale gas resources needs to be examined. Mr. Dizard gets into the issue by examining the balancing item in the Energy Information Administration’s (EIA) measurement of reported natural gas storage volumes and the net demand from production and consumption. That balancing item has grown consistently since the middle of last year reaching about 100 billion cubic feet (Bcf) in its latest report of the Form 914 gas market.

The Form 914 estimates are based on samples from natural gas producers and are likely biased toward larger companies. Those companies have had access to Wall Street capital that has allowed them to fund their gas shale development efforts in the face of extremely low gas prices. These companies are also the ones with the greatest ability to hedge their future gas production at higher than current low spot market prices, providing additional capital for the producers. At the same time, the EIA’s sampling probably misses many of the smaller gas producers who have been limited in their ability to raise capital to fund drilling and development projects, thus experiencing falling gas production. This sampling bias may lead people to assume that we have plenty of cheap gas when in effect we are facing a sharp fall in gas production in the future. That eventuality could lead to sharply higher gas prices at some point down the road – the question mark is how far in the future that scenario begins to play out.

At the present time, we are witnessing the larger, independent E&P companies who have been leaders in developing the gas shale plays across this country pouring money into their drilling efforts. They are being forced to drill if they want to hold onto the acreage they have already leased. Since the companies cannot fund their entire drilling programs from their current income stream, they are resorting to raising money on Wall Street, selling non-core, non-gas shale assets, entering into joint ventures with large international oil and gas companies with substantial cash balances or even selling out to this type of competitor. Devon Energy (DVN-NYSE) has elected to sell its offshore and international oil and gas assets and redeploy the funds into developing its shale gas assets. XTO Energy Inc. (XTO-NYSE) reached an agreement to sell the company to Exxon Mobil Corp. (XOM-NYSE) as a way to capitalize on its gas shale and tight gas reserves and expertise.

In recent weeks we have seen various E&P companies elect to raise money on Wall Street. The latest to announce an offering is EQT Corp. (EQT-NYSE) which is planning to sell 12.5 million shares of stock in an underwritten offering. The company is planning to use the additional funds to speed up the development of its Marcellus Shale and Huron/Berea plays. With the announcement of the planned equity offering, EQT also announced plans to boost its capital spending this year from $850 million to $1.2 billion. As Murray Gerber, chairman and chief executive officer of EQT stated in the press release announcing the offering, "We are extremely confident in our capability to profitably develop our extensive Marcellus and Huron / Berea asset positions, and therefore we believe it is time to accelerate that development."

Chesapeake Energy (CHK-NYSE), besides being the leading company in exploiting the hunger of international oil and gas companies wishing to gain access to the U.S. gas shale plays through negotiated joint ventures where these companies fund the drilling and development efforts, has also resorted to the use of new equity to fund its cash needs. In this case, Chesapeake has used stock to buy more leases. The company issued 25 million shares, raising $429 million. The offering said the shares were sold with the intent to create financial flexibility and that the proceeds may be used to resolve disputed lease deals in the Haynesville Shale play. When the company first proposed selling stock to fund lease purchases, it wanted to sell 50 million shares with a goal of raising $1 billion. Unhappy investors irked by the potential dilution from the equity raise, drove the share price down sharply. That plan was revised to the one being executed now. The company, whose share price has underperformed relative to its peer group over the past year, put a positive, if not hopeful, spin on the offering. Jeff Mobley, Chesapeake’s head of investor relations, said this was a “unique situation where equity was used to bridge a valuation proposition in purchasing acreage.” He went on to call the assets acquired for investors “actually accretive.”

At the end of the day, the question becomes whether these gas shale plays yield as much production as the producers forecast. If not, then the economic argument that gas shales can yield huge flows, albeit for a short time period and at low costs, may prove elusive. The gas shale faithful believe that full cycle economics for gas shales will be profitable at $3.50 – $4.50 per thousand cubic feet (Mcf). The skeptics think the return criteria will require $7.50 – $8.00 per Mcf prices. After 18 months of low and falling oilfield service costs, prices for rigs and other drilling, completion and production services are beginning to rise. Without a surge in natural gas spot prices, profit margins will be squeezed significantly in the near term. Just how long can producers fund non-profitable drilling programs? As one of our prior bosses put it, “Wishing and hoping is not a strategy.”

A number of high profile wind energy projects are moving through regulatory approval stages toward either final approval or rejection. These projects extend from coast to coast – from Massachusetts and Rhode Island offshore wind farms to Oregon’s Antelope Ridge project and numerous places in between. These projects are all generating challenges either based on their location or their economics. The irony in the controversies is that both opponents and proponents of wind energy claim the high moral ground of saving the planet – clean energy versus unspoiled landscapes.

In Massachusetts, the latest development is that a Fall River based Indian tribe announced its support of the controversial Cape Wind project to be constructed in Nantucket Sound. At the moment the project is being challenged by two local Indian tribes, the Mashpee Wampanoag and the Wampanoag Tribe of Gay Head (Aquinnah), claiming that the wind turbines will spoil the Indians’ views of the horizon that form an integral part of their daily ritual in welcoming the sun. The tribe supporting Cape Wind is the Pocasset Wampanoag, but it is not federally recognized so its comments have to go into the category of general public comments on the project rather than the special category reserved for comments from participants actively involved in the approval process. Presumably the latter category’s comments carry greater weight. In a letter to the commission soliciting public comments, Pocasset Wampanoag Chairman George Spring Buffalo stated, “We have asked our elders and they do not know of and have never witnessed a daily ceremony on the waters of Nantucket.”

There have been other questions concerning the tribal objections that were not raised until well into the approval process for Cape Wind. Because the two Indian tribes requested that all of Nantucket Sound be listed on the Historical Registry, a review was conducted by the Massachusetts historical agency after the request was turned down by the federal government. Once the Massachusetts historical officer approved the tribe’s request, a mediation process began. So far the various parties have not been able to reach an agreement allowing the project to go forward.

At the end of February, a media article reported that Cape Wind had offered a million dollars to each of the two tribes, but that the offers had been rejected. The proposals were for $50,000 annual payments to the tribes for the next 20 years. According to Bettina Washington, the Aquinnah tribe’s historical officer, “We would not consider selling our cultural landscape.” The tribes have suggested that an alternative location south of Tuckernuck Island, off Nantucket, proposed by the Town of Barnstable and the Alliance to Protect Nantucket Sound be utilized. This location was previously analyzed and rejected by Cape Wind as being more environmentally damaging and less capable of generating power due to lower performing winds.

In early April, Jeffrey Madison, a former council member of the Aquinnah tribe, sent a letter to Secretary of the Interior Ken Salazar who must now resolve the dispute between the tribes and the wind farm developer, stating that the contention of the tribe that the wind turbines would disrupt tribal rituals was unfounded. He attached to his letter a petition signed by eight other members of the tribe. There were claims that because Mr. Madison was a lawyer with a firm employed by Cape Wind, the motive behind his letter was questionable. Of course, the fact that the two objecting tribes are trying to secure land for a casino was also highlighted. Reports are that the Pocasset Wampanoag’s are also battling to secure land for a casino and that this might have played a role in their support. With gambling doing so poorly at the Connecticut Indian-sponsored casinos, one would wonder why the heightened interest in Indian tribes building more casinos in Massachusetts. But then again this has been one of the preferred ways for Indian tribes to boost their economic well-being in the past.

Exhibit 1. Antelope Ridge Offers Picturesque Views

Source: The Oregonian

Across the country in Oregon near the tiny city of Union located at the south edge of the Grande Rhonde Valley, Horizon Wind Energy, a Houston-based subsidiary of EDP Renovᾴveis of Portugal, one of the largest wind farm developers in the world, a $600 million project has been proposed. The wind farm was initially projected to include 182 wind turbines with some located within 1 ½ miles of town, covering 47,000 acres on mountain ridges on two sides of town. Just recently the project was reduced to only 164 wind turbines. The wind turbines are projected to stand 520 feet above the ground.

Hereto, the debate is between two objectives near and dear to the hearts of residents of Oregon – clean energy and the desire to maintain unspoiled views and protect the habitat for local wildlife. As a spokeswoman for the Oregon Department of Energy put it, “We are about to have a clash of two things very important to the state of Oregon.” In contrast, a Union resident and retired U.S Forest Service employee said, “It reminds me of the old timber wars of the 1970s.”

Oregon has embraced wind power for its clean energy benefits. The state has about 1,200 wind turbines installed producing about 1,758 megawatts of power, ranking the state sixth in the nation behind Texas, Iowa, California, Washington and Minnesota. The growth has been supported by tens of millions of dollars in tax breaks designed to attract wind farm developers since 1998. As a result of its efforts, there are a number of new wind farm projects being proposed for Oregon. But in recent years there has developed a growing opposition to wind farm developments. The opposition has been successful in getting one large developer to withdraw its 40-turbine project that would have obstructed views of the Columbia River Gorge.

Exhibit 2. Oregon Has Many Wind Farms Developments

Source: The Oregonian

The objections to the Antelope Ridge Wind Power Project were based on its noise that residents believe will hurt their health, its impact on tourism and the habitat of elk, deer and the sage grouse. Also, the residents see the project as an intrusion of outsiders into the 1,900-person town, which they fear will hurt the community’s development. Lastly, they are opposed to the state’s tax breaks for wind farm developers. On the other hand, the developer points out that the project will be built on privately-owned land and will create 165 construction jobs for a nine to twelve-month time. Once the project is operating, it will employ 20 full-time maintenance workers and roughly 32 related jobs.

Exhibit 3. The Number Of Turbines Overwhelms Area

Source: The Oregonian

All wind farm projects of 105 megawatts of greater are regulated by the state-level Energy Facility Sitting Council. A council member said she is listening to the objections from people wanting to restrict the placement of wind turbines on mountains, but she also said she knows people who are in need of the lease income that would come from these wind farm developments. One situation that might change as a result of this growing opposition is a modification of the state’s wind farm sitting standards. At the present time, only designated scenic areas get special consideration for damage to their views.

While the battles over clean energy and unspoiled views are waged across the country, on Block Island, off the Rhode Island coast, the economic benefits of wind power are confronting the landscape issue. It appears the economic benefits of wind will win this battle, however. The Deepwater Wind demonstration wind energy project is in final stages of approval. Based on the current schedule, on March 30 the state’s Public Utility Commission is to decide whether to approve or deny the electric power contract recently negotiated between Deepwater Wind and the state’s utility company – National Grid (NGG-NYSE). The written order by the commission is to be published on April 2nd. By the end of August Rhode Island is to release its ocean zoning plan that will include the exact location of the eight-turbine wind farm.

The eight turbines will tower 450 feet above the ocean and will be visible from the Block Island shore. The wind turbines are planned to be arrayed in a curve following the south shore of the island. At night the towers will have blinking red lights atop them that bothers some of the residents. Deepwater Wind is proposing that it will have the red lights only come on when a plane flies overhead. It also says that the red lights at the base of the towers to warn fisherman will not be seen from the shore. So while there is opposition, much of it comes from part-time, wealthy residents. At the same time many of the locals are more concerned about the economic benefits from the power rather than the view.

In examining the opposition to the Block Island wind farm, there have been comparisons made to the hostility surrounding the Cape Wind project that is hurting its approval pace. The Block Island project is smaller than Cape Wind and it will provide power to the residents at a lower cost than they are paying now. At the present time, Block Island residents get their power from the local power company, BIPco, which is generating electricity from diesel generators on the island. The diesels are old and inefficient and subject to interruptions in service causing island-wide blackouts periodically. Once the wind turbines are in operation, hopefully by 2013, the generators will be retired.

Truckloads of diesel fuel arrive by ferry, once a week in the winter and sometimes as often as three times a week during the summer season when the number of people on Block Island grows to 15,000 from 1,000 and electricity usage quadruples. BIPco’s electricity rate is tied to the price of diesel and the premium to transport it to the island. Last January, the rate for electricity was 29.29¢ per kilowatt-hour (kWh). That rate compared to 14.8¢/kWh on the mainland. With taxes thrown in, the monthly cost for a family on Block Island is nearly twice that for a family onshore. Given the seasonality of oil prices, Block Island’s electricity costs often move sharply higher in the summer when energy demand is the greatest. In the summer of 2008 when crude oil hit nearly $147 a barrel on the futures market, the rate for electricity on the island was 62¢/kWh, four times the rate on the mainland and the highest retail electricity rate in the nation at that time. The monthly bill for the typical family doubled compared to last January’s cost of $168.

Businesses are particularly hard hit by rising diesel prices in the summer since it is difficult to pass on the cost impact through adjusted retail and tourist prices. For example, a local grocery store on Block Island highlighted in various media stories, is running a $20,000 per month electric bill to provide heat, lights and cold storage for its food. During the summer of 2008, this same store’s electricity bill was $40,000 a month. There is little room for the grocery store owner to raise prices for cans of corn or boxes of corn flakes to recover this extra $20,000 expense. Hotel and bed-and-breakfast operations are also hard pressed to adjust their room rates to accommodate this magnitude of electric power cost jumps.

What residents of Block Island are looking forward to is having their grid integrated into the entire Rhode Island power grid. With the laying of a submarine power transmission line to move surplus power generated by the wind turbines to the mainland, the island’s residents gain a stable and lower electricity price. Moreover, when the wind farm is not producing sufficient power, Block Island will be able to receive power from National Grid’s mainland facilities. The net result of this restructuring of the Block Island power market is that the higher cost of the wind power (24.4¢/kWh) will be spread over all 450,000 residential purchasers of power in Rhode Island. So while some residents are upset with the prospect of eight wind turbines whirling on the horizon, the economic impact of reducing electricity costs explains why the vast majority of Block Island residents are in favor of the project. So even though wind power is clearly more expensive than conventional power and it brings visual pollution, the impact on the local power market can be significant – sufficiently powerful to sway public support. The issue of gaining approval for wind power projects highlights how local the issue is.

The Pickens Plan, created by legendary oil man T. Boone Pickens, calls for increased use of natural gas as the preferred way to power the domestic vehicle fleet of the future and to reduce the nation’s consumption of imported oil. This plan has gained increased attention in recent days as a handful of Washington politicians have decided it is time to refocus their efforts on developing a national energy policy. Central to that policy is the increased use of natural gas as a bridge fuel to a clean energy economy that will eventually be powered by wind, solar and nuclear energy.

At the same time the Pickens Plan was revived, the Geneva automobile show raised the profile of small cars and electrically-powered cars as the trend of the future. Several times in the Musings we have examined the question of the future for fully-electric cars versus hybrid vehicles with our conclusion favoring the latter. Now that the debate has become more serious about which fuel will power our future transportation fleet, Europe’s role in the future automobile market has become more important. The greater importance comes from the recent restructuring of the global automobile industry, which involved a number of European players. So which fuel source makes the most sense for the future?

At the Geneva auto show, virtually every exhibitor showcased small cars – either updated models within their existing line-ups or new models. Part of the push for more small cars is the need to have fleets that meet the tougher mileage and emission standards in both Europe and North America. At the same time the auto makers are trying to capitalize on the developing global trends in growing urbanization, aging populations in rich countries, and rising demand from first-time buyers in emerging markets. The challenge for the auto makers is that the least profitable vehicles to sell are small cars. The increased focus on small cars may spell bad news for auto makers struggling to become profitable, and in some cases facing having to repay governments for financial assistance provided during the recent economic collapse.

Different auto manufacturers are trying different strategies with their introduction of new small cars. Audi’s new A1 will have a basic model with an estimated cost of €16,000 ($21,648). But the company really hopes buyers opt for its luxury equipped model that will retail for €25,000 ($33,825). On the other hand, Nissan (NSANY) plans to sell its new Micra in 160 countries, but reap the scale and cost advantages by producing it exclusively at four plants in fast-growing emerging countries – India, Thailand, China and Mexico. BMW (BMW.F) pioneered the idea of packing lots of luxury upgrades into small cars, and now other small car brands such as Ford (F-NYSE), Fiat (FIAT.F) and Hyundai (HYMLF.PK) are offering vehicles with all sorts of optional features such as state-of-the-art telemetrics, custom paint jobs and parking assistance.

Industry forecasts suggest that small “A” and “B” models along with midsize “C” cars will account for more than half the global new car sales market by 2016. Even in the United States, forecasters predict that this market segment will grow from less than a fifth today to about a quarter of the market by then.

At the end of the day, a question about these optimistic forecasts will be their power sources and how well the public buys into some of the choices being presented. As the media coverage of the Geneva auto show reported, electric-powered cars are moving from prototypes into actual production, whether or not the public is ready to buy them. This is partly being pushed by the embrace of small cars as the way to meet government emission regulations. Yet with the industry not settled on which power source technology to deploy – pure battery power, a combination of batteries and internal combustion engines, or more exotic solutions such as hydrogen – the buying public will be hesitant about making a mistake with their purchase. That hesitancy may delay the growth of the small car market until the auto makers are forced to only offer limited choices.

Where might natural gas powered vehicles fit in this industry turmoil? If, as seems to be the case, the federal government begins to back natural gas powered vehicles, then new regulations and subsidized financing will force consumers to have to buy them. At this point it is not clear that the Obama administration is backing compressed natural gas vehicles. In fact, the government’s decision to provide a $1.4 billion loan to Nissan North America to retool a factory in Smyrna, Tennessee, to produce the Leaf model, a fully-electric car, suggests this is the path it wants car manufacturers to go. The retooled plant will provide 1,300 jobs at a cost of $1.3 million each. The plant will produce 200,000 Leaf models per year that the government says will save 65.4 million gallons of gasoline a year, or 327 gallons a year per car. The problem is that the government also touts the Leaf as a “zero emissions” car, but ignores the fact that it derives its power by plugging into the electric grid that is producing carbon emissions to generate the electricity. Sec. of Energy Chu explained the rationale for the loan, “This is an investment in our clean energy future. It will bring the United States closer to reducing our dependence on foreign oil and help lower carbon pollution.” Nowhere does he talk about auto manufacturers making money by building and selling small electric cars.

Is there a future for CNG vehicles in a world where the current administration seems determined to drive car buyers to electric vehicles? Because of this bias, that may be a reason why the Pickens Plan focuses on over-the-road trucks for conversion to natural gas as an offset to increased consumption of diesel fuel. It recognizes that gaining support for widespread use of natural gas to fuel the automobile fleet will be fruitless. According to the Pickens Plan web site, there are more than 10 million natural gas vehicles on the road worldwide, but only 130,000 in the United States, or 1.3% of our fleet. The Plan targets buses, taxis, utilities and delivery trucks. It believes that trucks that spend a lot of time idling or traveling at walking-speed such as refuse and recycling trucks are ideal candidates for conversion to natural gas.

In November, the American Trucking Associations (ATA) submitted a written statement to the U.S. Senate Energy and Natural Resources Committee on the use of natural gas as a diesel fuel substitute. The comments from this organization, which actually is a federation of motor carriers, state trucking associations and national trucking conferences with the objective of promoting and protecting the interests of the trucking industry, raise serious questions about how far we can progress in converting trucks to natural gas fuel. The ATA’s members include trucking companies and industry suppliers of equipment and services. ATA encompasses over 37,000 companies and every type and class of motor carrier operation.

According to the ATA, the trucking industry consumes 39 billion gallons of diesel fuel each year. That is the equivalent of 928 million barrels per year, or roughly 2.5 million barrels per day. Of course, diesel is only one byproduct of crude oil, therefore if the fuel were to be totally eliminated there would be a greater reduction in the volume of crude oil used. For trucking companies, diesel fuel represents its second largest expense behind labor.

As a transportation fuel, natural gas can be used in either a compressed form (CNG) or liquefied form (LNG). Because of low energy density, CNG is not practical for over-the-road trucks. CNG has been successfully used in shorter range, heavy-duty applications such as refuse trucks and municipal buses. LNG presents a possible alternative for certain trucking applications because it has higher energy content per volume than CNG, although still significantly lower than diesel. The lack of a competitive refueling infrastructure suggests that this alternative is not currently viable for over-the-road applications.

The biggest obstacle for use of natural gas is the cost of natural gas trucks. There are currently two natural gas engine classes available: (1) a spark ignition, 320 horsepower version that sells at a $40,000 premium to its diesel counterpart; and (2) a 450 horsepower, compression ignition version that sells at a $70,000 premium to its diesel counterpart. While there are federal and state tax incentives for purchases of natural gas trucks, the incentives are insufficient to completely offset the price premium.

The trucking industry is highly competitive with over 600,000 companies registered with the U.S. Department of Transportation. More than 96% of them are small businesses operating fleets of less than 20 trucks. With operating expenses often reaching 98% of revenues, these small companies cannot afford to increase their capital spending to purchase more expensive trucks than their competitors are operating.

Another significant problem for truckers is the LNG fuel tanks. They are constructed from ¼” thick stainless steel and add significant weight to the truck. For example, two 119-gallon tanks weighing approximately 1,000 pounds would reduce the payload of a cargo tank truck carrying ethanol, for example, by over 150 gallons. From an industry point of view, embracing LNG trucks would increase the number of trucks required to move the same volume of goods being transported now, adding costs to the economy.

The positive aspect for natural gas trucks is that the fuel sells at a significant discount to diesel fuel on a diesel gallon BTU equivalent basis. Despite fluctuations in diesel and natural gas prices throughout 2009, the spread between LNG and ultra low sulfur diesel fuel was between $0.75 and $1.00 per gallon. Natural gas trucks, however, are less fuel efficient than their diesel counterparts. The spark ignition natural gas engines are about 7% to 10% less efficient, while the compression ignition engines are only about 1% less efficient. Thus, some of the economic benefit of lower cost fuel is given up in the form of reduced efficiency.

An additional challenge facing natural gas trucks is their refueling. Because remote LNG refueling is not an option, if a truck runs out of fuel along the highway it will need to be towed to the nearest refueling station. These stations to be efficient, however, will need to be configured for specific truck designs, etc. Most existing natural gas fueling stations are owned and operated by municipalities and have prior contractual arrangements with truckers. Therefore, any new truck arriving would need to make arrangements before hand, reducing the flexibility of over-the-road truckers. Furthermore, LNG is dispensed at -260°F, meaning that specialized employee training and the provision of personal protective equipment also may be necessary. Establishing one of these specialized refueling stations can cost over $500,000, suggesting that the station owner will be looking at how he can recoup that investment while facing a limited number of natural gas powered trucks – the classic chicken or egg problem. Lastly, truckers worry about the fact there would be so few refueling stations contributing to a lack of price competition that would expose them to high prices at individual retail LNG stations.

Other operational challenges facing natural gas trucks include their operating range. A truck equipped with two 119 gallon tanks has half the operating range of approximately half the typical diesel over-the-road trucks in operation. These gas-powered trucks also surprisingly will require more frequent replacement of injectors than for diesel engines, increasing operating expenses. A positive offset is that natural gas engines require fewer oil changes. The oil change interval for natural gas trucks is roughly three times that of a diesel engine. These operational challenges will put a strain on servicing employment as mechanics will need approximately 60 hours of specialized training. The servicing locations also require greater safety equipment due to the potential for methane exposure. Some operators have reported having to spend over $150,000 in infra-red sensors, modified lighting and electrical systems, and an air evacuation system in order to maintain natural gas powered trucks.

Environmentally, natural gas can reduce CO2 emissions by 15%-23%. Offsetting that benefit, however, is that as LNG in a fuel tank warms up, methane is released to the environment through a pressure relief valve. Depending upon the ambient temperature, an LNG truck could vent most of its fuel over a 7-10 day time period. Thus, the venting of methane in parked trucks over time could actually increase greenhouse gas emissions.

All in all, it seems that natural gas trucks and other specialized vehicles will be limited in use and do not represent the salvation for the nation’s imported crude oil problem. Electric power is also not an option for trucks, but seems to be a favorite for cars among regulators who fail to understand the impact this engine choice has on transportation flexibility and carbon emissions from power plants generating the electricity. So far we have yet to find transportation fuels as cheap and efficient as gasoline and diesel fuel.

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Parks Paton Hoepfl & Brown is an independent investment banking firm providing financial advisory services, including merger and acquisition and capital raising assistance, exclusively to clients in the energy service industry.