Post-Apocalyptic archaeologists in some future era will sift through the remains of Sabine Pass, marvel at the sheer size and complexity of its structures and conclude that this monumental undertaking must have been terribly important for our civilization and a clear sign of immense success.

We’ll find out soon enough.

U.S. exports join the global battle for LNG market share next year, and Cheniere Energy Inc.’s massive facility on the shores of the Gulf of Mexico constitutes North America’s tip of the spear. Conventional wisdom declares this effort to be a windfall waiting to happen: a global game changer that is good for U.S. trade balance, good for the U.S. energy industry, good for overseas buyers seeking cleaner-burning fuel to replace coal and good for countries seeking some semblance of energy security in difficult times.

But conventional wisdom also was quite certain about the need for U.S. LNG imports just a few years ago—before that notion was trumped by the unconventional wisdom that shale development would completely remake the market. Knowledgeable industry observers perceive vast potential for this endeavor but admit that it’s not a sure thing. Success hinges on a number of factors with one common variable: price.

Demand from Asia

Liquefying natural gas so that it can be transported is not new. The first liquefaction plant, CAMEL, was completed in Arzew, Algeria, in September 1964, and the first LNG carrier, the Methane Princess, delivered the first shipment from that plant to the Canvey Island regasification facility in the U.K. in October of that year. Today, a fleet of 431 specially built LNG tankers traverse 400 global routes to support an aggregate volume that represents 30% of the international natural gas trade.

What is new is the convergence of a slew of new export sources and booming Asian economies.

For Thomas Moore, Houston-based partner with Mayer Brown LLP, the most significant trend that will transform the LNG field is demand in Asia. It is the endless stream of data concerning China, India, Japan and South Korea that bedazzles analysts and influences export ambitions.

“The first [issue] is how fast demand for natural gas as a fuel as opposed to any alternatives grows in the Far East,” Moore told Midstream Business. “Clearly, because of the problems with nuclear in Japan, Japan is going to continue to be a major importer. Korea is going to be a major importer and China is beginning to be a major importer, but each of those markets is affected by local forces that are very hard to anticipate. For example, how fast will China’s economy grow? And at what point will this increased environmental awareness push China away from its current reliance on coal? So it’s hard, at least for me, to predict long term what the Chinese market will be.”

“The Chinese market is huge,” agreed Tom Campbell, director for Stratas Advisors, a Hart Energy company. “Japan and Korea, in terms of import capacity, are the big players, and that’s not going to change,” he told Midstream Business.

In Japan, the aftermath of the Fukushima Daichii nuclear disaster, following the March 2011 tsunami, has encouraged that country to move away from nuclear toward alternative sources, with gas-fired generation considered by Moore to be the only really viable replacement, at least in the short term.

However, a recent Goldman Sachs report, while reinforcing the view of a continued robust LNG demand outlook for Asia, expressed concern over the uncertainty of Japan’s nuclear future. Recently, Japan’s Nuclear Regulatory Authority cleared the way for Kyushu Electric Power Co. to restart two reactors at its Sendai plant in southern Japan. Other obstacles make a restart unlikely to happen in 2014, but restart plans have clouded forecasts and dampened Goldman’s outlook for Asian LNG demand.

Even if Japan does move aggressively toward LNG, Moore questioned how big its market will grow, citing recent occurrences in Korea as an example.

“Although South Korea is a large LNG importer, the Korean government has, in the last year and a half, become much more resistant to increased imports of LNG and is looking again at alternative fuels, including coal,” he said. “So the question is: Will the natural gas market in the Far East continue to grow the demand for natural gas—and therefore LNG—in that market irrespective of the price of alternative fuels?”

Demand from Europe

“A related question is, will Europe—because of the problems in the Ukraine—really spend the money necessary to develop an alternative natural gas supply source for which LNG is probably, at least in the short term, the only alternative?” Moore asked. “And that is going to depend a lot on how long the Ukrainian crisis takes to be resolved and the willingness of Europe to move away from cheaper alternative energy sources such as coal, at least in power generation.”

Cameron Gingrich, Calgary-based director of gas services for Ziff Energy, is also watching closely to see which direction the Europeans choose.

“They’ll basically pay a higher price for LNG, but they’ll diversify some of that security-of-supply issue,” he told Midstream Business. “Whether they go all in on LNG is yet to be seen, but certainly Russian gas—a lot of those contracts are linked to oil as well for those European folks. They pay a higher cost of gas already there, so the incremental LNG is a lot smaller delta than it would be for North America to start bringing that LNG. Certainly there are opportunities in Europe. [The supply of LNG doesn’t] have to be low cost because there’s value in diversity because of the security-of-supply issues for a lot of these buyers and utilities in Europe. But will LNG supply take all the Russian gas? I can’t see that happening.”

And Europe is not an energy monolith, either, which presents another type of diversity.

“I think you’re going to see Europe staying an interesting market in some ways,” Campbell added, “particularly in the development of smaller to mid-scale import terminals for countries like Finland and Sweden. They look at this as an opportunity to diversify their gas supply as well as use this gas for inland markets for fuel solutions and as a marine fuel.”

Moore sees limits to government policies, especially when it comes to cost. He cites the market distortion driven by German Chancellor Angela Merkel’s Energiewende, or energy revolution, which mandates purchase of renewable sources of energy at fixed prices before distributors can purchase alternative sources such as coal.

Shale gas denial

Germany also imposed a moratorium on hydraulic fracturing, denying the country access to its 17 trillion cubic feet (Tcf) of technically recoverable shale gas, as estimated by the U.S. Energy Information Administration (EIA). The phase-out of nuclear power in Germany was accelerated after Japan’s Fukushima Daichii incident, so to balance the high cost of renewable energy, power companies turned to a lower-cost but less environmentally friendly option: coal.

“At some price point, even if you put a dollar value on the environmental costs of using coal, for example, people may go back to coal,” Moore said. “This is a very interesting and sort of odd impact of the development of renewables in Europe, particularly Germany. Renewables are not reliable—you have to have secondary capacity because the sun doesn’t always shine, for example. Renewable energy is also still expensive. Although it is counterintuitive, the great environmental initiative for subsidized renewables has led Germany to return to coal for backup generation capacity.”

“So again, at some gas-price level, people will return to coal even if they monetize the environmental costs of coal, because, frankly, it will be cheaper,” he said.

Market price

Hence, the $120 billion question—the amount companies are investing in North American LNG export projects, according to Lux Research: What is the optimum price point for natural gas? The Henry Hub, La., price, which is the U.S. benchmark, must be high enough to sustain profit margins for domestic producers, but not so high as to undercut the competitiveness of LNG exports on the Asian market.

Gingrich doesn’t worry about price.

“Our cost curve foresees for the next 500 Tcf of supply in that $4 to $5 [per MMBtu] range or less than that $4 to $5 range on a full-cycle basis, so that includes [finding and development], op costs, overhead, royalties and return on 15% for producers before tax,” he said. “In our view, with the North American market in that 25 Tcf to 30 Tcf per-year demand, and you think about 500 Tcf of supply in that low-cost range, we should have a market in North America where we will have reasonably priced gas with little price risk going forward. That’s Ziff Energy’s view.”

Moore isn’t so sure. He cites the boom-and-bust cycles of the U.S. LNG market over the last half-century and wonders how the sparkling new export facilities will fare.

“I don’t have a crystal ball,” he said, “but some people who are smarter than I am in this area are really concerned about whether or not U.S. gas prices will remain, over a 20-year period, low enough so that exports from the U.S. are attractive in either the European or Asian markets. And frankly, LNG from other sources may have the same problem. In Africa and Australia, it’s not the cost of the natural gas, but it’s being able to keep the capital costs of the liquefaction facilities under control.

“The market for LNG is subject to a large number of variables, and people are making very large capital investments on the hope that things will turn out OK,” he continued, “but there’s certainly no guarantee.”

Campbell’s research reaches similar conclusions.

“Nobody’s talking about a serious jump in the price of natural gas,” he said. “I think the concern, really, is not that gas is not going to stay cheap, it’s that the capital costs are going to be brutal for anyone trying to build these things, and it’s that the import markets that were, a couple of years ago, so white hot, have come down a lot.”

‘Not cheap’

Cheniere’s Sabine Pass plant represents an investment of $18 billion. The Golden Pass LNG import regasification plant nearby requires a commitment of $10 billion from co-owners ExxonMobil Corp. and the Government of Qatar to build a liquefaction facility and allow for exports. A similar investment will be pumped into the Cameron LNG facility that is a joint venture among Sempra LNG, Mitsui & Co. Ltd., Mitsubishi Corp., GDF Suez and NYK Line.

In Campbell’s view, companies like Cheniere that are building onto existing import terminals have a huge capital cost advantage.

“You’re building a gigantic concrete tank with this really expensive, really complicated interior containment system for keeping it so cold, so that’s expensive,” he said. “The cost of just building a big thing—the docking port—all that is expensive. The cryogenic pipelines to run it from the plant to the ship—expensive. The liquefaction system—we’re using dozens of turbines—expensive, expensive turbines. Your electrical costs—very expensive. So it’s not cheap.”

But it could be worse. Your plant could be in Australia.

“What you see with the Australian ones,” Campbell said, “is that labor costs have escalated tremendously.”

There is no mystery here. There simply aren’t a lot of people in the world who happen to have LNG project skills. A non-degree technician working offshore Western Australia will earn as much as $105,000 a year, as reported by the “2014 Hays Salary Guide.” The typical Australian oil and gas worker brings in $163,600 a year. A welder can be paid as much as $250,000.

The high price of labor isn’t the only issue, Moore contends.

Australia’s challenges

“One problem with Australia is that the Australian LNG projects are very expensive and have been beset by many delays, largely because of the expensive labor market in Australia, but also because the gas supplies that are being served are very expensive to develop,” he said. “The question for Australia is: Will Australian LNG, even given its geographical proximity to markets, be economical on a long-term basis especially when compared to U.S. and East African supplies?”

Not everyone frets over cost overruns in Australia.

“A lot of the clients I’m dealing with are still very bullish,” Jonathan Smith, KPMG’s Perth, Australia-based oil and gas sector leader for Australia, told Midstream Business. “I think I’m already seeing some downward pressure on the costs and that’s moving all through the industry. There’s so much focus on that.”

In Campbell’s view, the Australian experience serves as a cautionary tale for the U.S. industry.


An LNG carrier in the fleet of Qatar’s RasGas docks at Golden Pass LNG’s facility in Sabine Pass, Texas. Source: Golden Pass LNG

“I think people are trying to assess that out with LNG in North America and say, ‘Wait, we can’t really build 20 plants in Louisiana and expect our capital costs to not get absolutely terrifying,’” he said. “I think they’re wising up to that in pretty short order.”

An Oxford Institute for Energy Studies research associate, Brian Songhurst, recently published his examination of LNG plant cost escalation. He concluded that soaring Australian project costs (300% in some cases) were unique to that location. In comparison to U.S. projects in general, Australian airports on average cost 90% more to construct, hospitals cost 62% more and shopping centers 43% more.

“The high Australian plant costs are not reflected in the plants currently under construction in the U.S.A., Malaysia and Indonesia,” Songhurst wrote. “The rapid rise in Australian costs has led to future projects being shelved or consideration being given to floating LNG facilities that can be fabricated at a lower cost location such as Korea and China.”

Hope floats

The centerpiece of Australia’s floating LNG aspirations is Shell Global’s Prelude vessel, a seagoing wonder of the world under construction in South Korea that has developed into something of an industry unto itself. Designed to operate in depths of up to 820 feet, the 600,000-ton floating facility will be based 125 miles offshore Western Australia and is expected to produce 3.6 million tonnes per annum (mtpa) of LNG, 1.3 mtpa of condensate and 0.4 mtpa of LPG.

“Shell’s project really is a phenomenal innovation when you consider the size of the floating LNG,” Smith said, adding that the project is intended to lower costs associated with onshore plants. “Certainly Shell wants to push that technology and is looking for further opportunities. That’s probably the biggest game changer that I’m seeing in this region.”

The facility is in such a league of its own that Shell hearkens to sports analogies:

  • Length longer than four soccer fields; and
  • Storage tank capacity greater than 175 Olympic-sized swimming pools.

“Prelude is a different animal, because you’re not worried about capital cost escalation with that,” said Campbell. “What you’re worried about is the theoretical feasibility of the entire endeavor.

“It’s an extraordinary machine,” he continued. “It’s half-a-kilometer long; it’s the biggest floating thing ever built by human hands. There will be challenges.”

GDF Suez and Santos Ltd. backed away from the challenges of the Bonaparte FLNG project, designed to operate 106 miles off Australia’s coast. The companies expressed confidence in the natural gas fields—Petrel, Tern and Frigate—but said they wanted to pursue a different direction than FLNG.

“I think eventually there may be an interesting opportunity for floating LNG plants,” Campbell said. “It’s going to be a while, though. People are going to want to see Prelude in action. They’re going to want to see it work.”


The scale of Cheniere Energy’s massive Sabine Pass project is impressive. The framework for a portion of the first liquefaction train towers above construction workers. Source: Hart Energy

Panama Canal expansion

On a smaller marine scale, the Panama Canal’s expansion project is expected to be completed and its new locks open for business in early 2016. The EIA says that the renovation to accommodate new Panamax tankers up to 1,200 feet long and 161 feet wide will allow the centuryold canal to handle 80% of the world’s LNG tankers and everything short of Suezmax and very large crude carriers.

With uncertainty—in the form of unfinished canal renovations, volatile markets and plants under construction—draped over the LNG industry, it might be reassuring to return to known quantities. Gingrich can list several advantages to operating in North America.

“We have a stable government, rule of law, here in North America,” he said. “You certainly have opportunities to move upstream, like we’ve seen some of these folks do. You have a huge deregulated market in North America, so you don’t need gas to be exported for whatever reason—say, a plant shutdown—you can put that gas to market and continue to receive revenues for it. Whereas, if that happens in Australia, you really have no place for that gas to go; same with East Africa.

“Here is a well-established, deregulated market that is based on gas supply/demand fundamentals, not based on any oil industry,” he continued. “That’s certainly attractive for the buyers and certainly limits some of the risk around the geopolitical issues like you have in East Africa.”

Moore looks at price stability when he assesses whether a proposed project will make it to completion and divides the projects into two categories:

  • Projects that are equity-financed by major oil companies, such as those in Africa; and
  • Projects that are project-financed, like those in the U.S. that operate 60% to 70% on borrowed money.

“In order for project financing to be successful, you have to be able to demonstrate to the lenders that there is long-term price stability for sales to credit-worthy entities,” he said. “So, for example, the U.S. projects that have reached the final investment decision all have long-term offtake contracts from credit-worthy-rated counter parties. If you’re financing a project, what you still need to be successful is sell out your project for a 15- to 20-year period to somebody who has an investmentgrade rating.

“For the equity-financed projects, which would include the East African projects and the Australian projects, although you don’t have the discipline of finance, you really have the same issue. Are the project sponsors sanguine enough about the long-term price that they will receive or do they have longterm sales contracts, which will make the project viable over a 20-year period?” he asks. “To be successful, you obviously have to have enough financial capability to actually develop the project but the real question is: Can you either sell forward on a long-term basis, or are you comfortable enough with the long-term market that you’re willing to invest your own money in something that’s going to cost several billions of dollars?”

A crucial known quantity is the resource.

“Of course, you also have to have a stable gas supply,” he said. ”Because U.S. projects pipeline gas, the question for gas supply is price. In African and Australian projects, you’re taking reserve risk—is the gas actually in the ground?—but that’s what oil companies do on a daily basis.”

Great expectations

By mid-October, the Stratas Advisors LNG database listed 294 liquefaction plants hosting 478 trains worldwide. This includes all plants no matter the status, whether they are operational, proposed, shelved, under construction, decommissioned or unknown. Of these, 139 plants with 317 trains are categorized as world-scale (0.5 mtpa and up).

In the U.S. alone, 26 plants with 58 world-scale trains were listed. Only one was operational (ConocoPhillips’ Kenai LNG plant in Nikiski, Alaska); four were under construction (Cheniere’s Sabine Pass trains); and the other 53 were proposed. If all are built and operate to capacity, output would reach a staggering 222 mtpa.

“Any time there’s a new opportunity, the market kind of goes wild,” said Campbell, explaining the irrational exuberance of the planning phase. “Right now, that’s going on in North America, where you’ve got almost 60 proposed projects, which is crazy. It won’t happen. It won’t even come close to happening. A fraction of that will come about.”

What drives this optimism is price, specifically the price of Japanese imports—more specifically, the differential between Japan’s price and the U.S. price.

At year-end 2010, LNG imported into Japan cost $10.75/MMBtu. One year later, with the country’s power generation system crippled by the tsunami, the price had increased by 53% to $16.48. At the close of third-quarter 2014, that price was $17.17. At the close of third-quarter 2014 in the U.S., the Henry Hub price was $4.02.

‘Unsustainable highs’

“When we’re talking about 2011 to 2012, where you’ve got gas prices in Japan at utterly unsustainable highs and gas prices in North America unbelievably low, this is when a lot of this thinking starts happening,” Campbell said. “Everyone gets very excited and everyone starts putting in applications and everyone starts announcing plans. It’s not going to work that way. So already you’re starting to see people, particularly in British Columbia, get worried about that. The infrastructure challenges are tremendous, the capital cost is tremendous. They are not easy things to build. That’s why there aren’t that many of them, all told, in the world.”


A jetty connects the liquefaction and export components of the Pluto LNG project in Western Australia’s northern Carnarvon Basin. The project is operated by Woodside Petroleum Ltd. and is positioned to exploit the 5 trillion cubic feet of gas reserves in the Pluto and Xena fields. Source: Woodside Petroleum Ltd.

At first glance, it might seem that a $13 gap between Henry Hub in Louisiana and the Fukuoka LNG Terminal on the Japanese island of Kyushu would provide plenty of margin for profit. It’s not that simple.

The cost of moving product that distance and changing the state of the element twice (gas to liquid, liquid to gas) adds up. Data from a U.S. Department of Energy study produced by NERA Economic Consulting projects a 2015 price of $13.52/MMBtu. That’s still considerably below what the Japanese are paying.

U.S. companies betray no lack of confidence in their export plans.

“Although construction has only just begun, we already have signed contracts for the entire output capacity,” said Karl R. Neddenien, media relations and community relations manager for Dominion Resources Inc.’s Cove Point LNG terminal offshore Maryland. “All the LNG we produce will be received by GAIL Ltd. of India and Sumitomo Corp. of Japan. Those two companies will provide the natural gas we liquefy for them, and they will receive the LNG. We will not own the gas or the liquid.”

Cheniere told Midstream Business that it is close to completing contracting for Sabine Pass and Corpus Christi, Texas. The company cites recent global LNG demand growth projections that support the ramp-up of 23 mtpa of liquefaction capacity to come online each year.

“Cheniere is currently developing liquefaction facilities along the U.S. Gulf Coast—with ~27 mtpa at Sabine Pass Liquefaction, in Cameron Parish, La., and 13.5 mtpa at Corpus Christi Liquefaction, in Corpus Christi, Texas,” Katie Pipkin, Cheniere’s senior vice president of business development and communications, told Midstream Business. “Cheniere Energy Sabine Pass Liquefaction has the first four LNG trains under construction, with first LNG expected late 2015. Corpus Christi is expected to reach FID [final investment decision] and commence construction in early 2015.”

Too much too soon?

With Sabine Pass almost ready to roll and Australian projects nearing completion, the possibility of a glut, even for the near term, has crossed some minds.

“From 2016 to 2017 onwards, many Australian and U.S. liquefaction projects will indeed come onstream and may ease the current market tightness,” Vincent Demoury, deputy general delegate for the International Group of Liquefied Natural Gas Importers told Midstream Business. “Therefore, there may be a slight oversupply in this period.”

The suburban Paris-based organization acknowledges the need for more capacity in the future, but notes the difficulty in determining how much.

“Post-2020, new projects are required although many uncertainties remain, both on demand, especially how fast Chinese and Indian LNG demand continues to grow, and supply, the speed of emergence of projects in East Africa, Canada and elsewhere,” Demoury said.

Moore agrees.

“I think there’s always a chance of [a glut],” he said. “The question is, if there is a glut, how fast will the market expand? You do have a great deal of interchangeability of fuels. If the market gets out of balance, that should force LNG prices down, which should, if economic theory holds, increase the demand for LNG because LNG is now cheaper than alternative fuels.

“The problem for the U.S. LNG export facilities is that the U.S. price for natural gas—and the cost of U.S. LNG—is largely a function of U.S. gas supply and U.S. gas demand, and these may change in ways that make U.S. LNG uneconomic in the world gas markets,” Moore said.

“This may mean that the U.S. LNG plants stop producing well before the African and Australian LNG plants, even though those plants have a much higher fixed cost,” he continued. “Because the African and Australian plants have already paid for the gas they liquefy through the cost of developing their gas fields, they can operate as long as LNG prices allow them to recover their marginal costs of liquefaction and transportation, which may be far less than the marginal costs of production of the U.S. plants which have to pay for feed gas.”

Setting prices

In September, the Japan OTC Exchange added LNG to its trading of petroleum and related commodities. The new exchange, which opened in November 2013, serves as a test market to develop liquidity for futures contracts, Director Kosuke Araki told Hart Energy. The intention is that LNG buyers will be able to fix costs and hedge against price fluctuations. In the future, LNG will likely be listed on the Japan OTC Exchange’s parent, the Tokyo Commodity Exchange Inc.


The size of one of five massive storage tanks at Cheniere’s Sabine Pass, La., LNG plant can be understood in comparison to the truck on the road in front of it. The company gained a cost advantage when it decided to build the liquefaction facility because the tanks had already been completed for the regasification import facility. Source: Hart Energy

This is a new approach for Japan, in particular, and Asia in general. While it bears watching, the global standard for buying and selling LNG is under the terms of confidential, bilateral long-term contracts. In other words, the actual prices, terms and price revision clauses are unknown, though prices are assumed to be indexed to crude oil. This is the system, in place since the 1960s, by which 73% of all LNG trades took place in 2013, according to a research paper recently published by Rice University’s James A. Baker Institute for Public Policy.

Author Mark Agerton of the Baker Institute noted that, in spite of the lack of transparency, an “S-curve” is evident in Japanese contracts that moderates the effect of very high or very low crude oil prices on the cost of LNG.


Multiple cranes poking into the Louisiana sky illustrate the brisk pace of work at Cheniere Energy’s Sabine Pass project. As many as 120 cranes have been at work on the site at a time. Source: Hart Energy

“We should expect that pricing terms may change over the course of a 20-year contract,” Agerton wrote, noting that LNG’s connection to crude oil prices does not preclude “complex and varied” contract terms. These terms apparently kicked in following the 2011 tsunami, when LNG prices did not immediately shoot up. “This suggests that [long-term contracts] function as a form of insurance against shocks,” he wrote.

The rule of thumb in contracts is that LNG’s price constitutes 14.85% of the price of Brent or the Japan Crude Cocktail. The U.S. benchmark for crude, West Texas Intermediate, has historically tracked Brent very closely, Agerton told Midstream Business, although “the majority of LNG importers and exporters will face global oil prices, not interior North American prices.”

This could be changing, though. “Pricing paradigms may be evolving, as evidenced by recent Japanese requests that U.S. LNG exports be priced on a Henry Hub basis and the emergence of a more robust LNG spot trade,” he said.

Agerton also notes that while spot and short-term volumes made up only 27% of global LNG trade in 2013, that figure is significantly above 5% of total trade in 2000.

‘We want to be in it’

As recently as 2008, the average wellhead price of natural gas in the U.S. was $7.97/MMBtu, double what it is today. The shale boom has unleashed a superabundance of gas on the U.S. market, depressing the domestic price but offering an opportunity to penetrate overseas markets and sell to emerging economies where gas is much more expensive.

The endeavor entails risk—big-time, long-term risk, but that is the nature of the business. However it is viewed in years to come, the LNG export model is terribly important today for economic and environmental reasons.

“I think if you’re an Exxon or a Shell or a Cheniere looking to spend billions of dollars that has to be covered over a 25-year time period, the economics has to make sense today,” Gingrich said. “The geopolitical pendulum will swing to and fro—it helps your cause in some years and hurts your cause in other years—but you have to make your decision today based on the economics, whether it is sustainable.

“Certainly we’ve seen a lot of folks invest a lot of money developing these projects,” he said. “A lot of folks have basically voted with their dollars that ‘this is a sustainable business line and we want to be in it.’”

Joseph Markman can be reached at jmarkman@hartenergy.com or 713-260-5208.

Think Small: Energy Business Likes LNG

By Paul Hart, Editor-In-Chief

Not all of the midstream’s current LNG investment goes to gigantic plants with multibillion dollar price tags, the kind that knock out a tanker-load-a-day of liquefied methane. Multiple, small-scale uses for LNG as a transportation and industrial fuel—given its lower cost compared to diesel fuel or gasoline—have growing interest.

Taken together, they could create a significant market for North America’s surging gas production. A thousand cubic feet of natural gas liquefies as about 12.2 U.S. gallons, which has the energy equivalent of 7.75 gallons of diesel fuel.

The oil and gas business has emerged as a leader in small-scale LNG according to Greg Roche, vice president of sales and marketing at Cosmodyne LLC, which manufactures natural gas liquefiers.

Leading the charge

“The oil and gas business is leading the charge,” he told Midstream Business. “On a macroscopic basis, oil and gas is further along than other industries but the other sectors are taking strides forward as well.”

Linde, a major LNG supplier, also credits oil and gas for a large share of the move to small-scale LNG use. Upstream, a growing number of drilling rig engines and generator sets use LNG while pressurepumping providers can employ LNG to back out more costly diesel for the high-horsepower pumping units that power frack jobs. Field gas often provides a ready supply for liquefaction.

In the energy business—as well as many others—there is growing use of LNG to power truck fleets.

Don Horning, vice president of sales for Clean Energy Fuels Corp., told the recent North American Gas Forum conference in Washington, D.C., his firm now has more than 770 truck fleet customers using either LNG or CNG. Clean Energy Fuels operates 30 LNG refueling stations nationwide and counts such firms as UPS, Procter & Gamble and FedEx among its customers. The firm continues to build a network of LNG and CNG refueling stations along a transcontinental swath from Southern California to the Northeast in partnership with the Pilot Flying J truck stop chain.

Railroads, including such major operators as Canadian National, continue to experiment with LNG as an alternative to railroad diesel. Offshore, there has been growing use of LNG to fuel a variety of short-range ships and barges, including workboats supporting offshore oil and gas operations. Long-range shipping appears to be a new LNG customer.

The LNG market could be huge but there are drawbacks, notes Stratas Advisors, a Hart Energy company.

“One of the obvious drawbacks of LNG is its energy density,” Stratas noted in a recent report on LNG marine applications. “With less energy content than other fuels … LNG requires more product to equal the energy of other fuels. Moreover, LNG must also be stored in bulky cryogenic tanks that cannot be conformed to available space in vessels as conventional fuels can. The result is that many vessels must require serious redesigns in order to accommodate LNG fuel tanks, all while potentially losing out on valuable revenue space.”

Modification costs pose another major issue. Fuel intake systems must be modified and compression-ignition engines cannot use straight natural gas as a fuel. That requires the use of spark ignition or hybrid fuel systems that mix vaporized gas with a distillate fuel suitable for compression ignition.

It costs extra to replace established infrastructure, whether refueling terminals or vehicle fuel systems, but LNG’s lower cost makes it worthwhile, Horning maintained in his presentation. Horning cited figures that show a dual-fuel heavy-duty truck can cost half-again as much as a conventional, diesel fuel unit.

Quick payback

“But the payback is there with 18 months as the goal” for a return on the investment for high-mileage vehicles, he added.

Also “it’s a chicken-or-egg situation,” he said, adding LNG suppliers do not want to add refueling stations unless there are operators who will use them. Fleet operators, likewise, won’t buy LNG-fueled vehicles until there are refueling options available.

One bonus of gas-fueled engines is they are quieter to operate, Horning noted—a plus for bus and delivery truck fleets that typically operate in noisy cities, as well as an emerging preference for drivers.

A lingering issue for LNG used as a motor fuel is how to measure it—by the cubic foot, the pound or the gallon? The informal practice has been to quote a price based on diesel equivalent, much as CNG has been quoted in a gasoline-equivalent price. The National Conference on Weights and Measures, composed of state weights and measures regulators, failed to agree on a standard at its annual meeting held earlier this year in Detroit.

Paul Hart can be reached at pdhart@hartenergy.com or 713-260-6427.