It may be the ultimate gas-processing challenge: Take methane, purify it, then chill it to -260º F. That creates a super-cooled odorless, colorless, clear liquid that occupies 1/600 the volume of the same amount of methane as a vapor.

The next challenge: Keep that super-cold, liquefied natural gas (LNG) in a liquid state, move it half-way around the world, then turn it back into a vapor for ready use. There are lots of moving parts and technology required to make it work—but it is working on a big scale. Statistics show in 2000, 5% of world gas consumption was via LNG. It’s now 10%—and climbing.

The Paris-based International Group of Liquefied Natural Gas Importers reports that worldwide, gas customers purchased 236.3 million tons (11.95 trillion cubic feet) of LNG in 2012, a slight, and unusual, decline from the prior year caused by plant maintenance and unscheduled shutdowns.

The organization’s 2012 report says, “the outlook for LNG demand remains strong, particularly in Asia and in the new markets of Latin America and the Middle East.”

And Access to Energy, the 2013 report of the International Gas Union, observed that “if 2012 was about Australia in the LNG finance market, 2013 is about North America…”

Tight market

A tight global LNG market is expected to see supply growth next year, a recent Barclays report projected. However, Japan and South Korea are expected to absorb much of the gain leaving other importers with limited LNG supplies, Barclays forecasted.

“Even without any rise in South Korean and Japanese consumption, we see Asian demand growth matching global supply increases next year,” Barclays said. “This would leave European consumers with no incremental LNG imports versus this year. In fact, risks to South Korean and Japanese demand now lie to the downside.”

Overall, Barclays projects worldwide LNG supply to barely meet anticipated demand this year. Data show that the demand for LNG has steadily increased, going from 29.4 billion cubic feet (Bcf) per day in 2010 to an estimated 32.3 Bcf per day next year. Growth has been the greatest in Asia.

So there appears to be a waiting—and big—market for North American LNG.

Large-scale U.S. LNG exports could be a reality by 2015 when Cheniere Energy expects to start shipments of as much as 2.2 billion cubic feet (Bcf) per day from its two-train liquefaction plant now under construction at its Sabine Pass terminal in Cameron Parish, Louisiana. Several other U.S. and Canadian export operations could be on stream by 2020.

“The U.S. is now on the cusp of becoming a shale globalizer,” Deloitte Global Services Ltd. observed in a recent report, Oil and Gas Reality Check 2013. The report added, “with low prices and surging production, U.S. gas producers want to tap global markets to increase their price realizations for natural gas.”

It’s all happening due to North America’s exploding supply of gas flowing out of multiple shale plays. Nowhere is the change wrought by those unconventional shale plays more visible than in the flip-flop in the domestic LNG business—from costly import to profitable export.

Investing billions

Building these huge liquefaction plants and storage tanks, docks and insulated tankers to move the product to market will take investments measured in billions of dollars. So far, investors seem to be ready to take the gamble.

It’s remarkable that gas from the shale plays has become so abundant that prices have sagged well below $4 per thousand cubic feet (Mcf) despite strong domestic demand. What’s impressive is the already-approved LNG export operations could be accounting for 1/10 of gas demand within a few years.

The federal Energy Information Administration’s statistics show the U.S. used an average of 69.9 Bcf per day in 2012 with a modest 1% compound annual growth rate in gas demand, by Deloitte’s estimates. The U.S. Department of Energy has received more than 30 LNG export permits to date. If all are approved— which most industry observers doubt will happen—those plants would require 27 Bcf per day of production, or around 40% of total domestic supply. That would make the U.S. the world’s largest LNG exporter by far. Qatar is the largest LNG exporter at 11.8 Bcf per day.

“The U.S. is not constrained from an export decision by its reserves per capita or domestic demand as it moves toward globalization of its shale gas,” the Deloitte report adds. That gives upstream producers and midstream operators running room, regardless of how many export terminals will be built.

That LNG flip-flop creates a profound business opening Frank Curzio, an analyst for Stansberry & Associates Investment Research, tells Midstream Business.

“It’s a massive, massive opportunity,” Curzio says. “You can see why so many people are involved in this. The biggest hurdle was getting these things approved, and now they’re getting approved so quickly. To me, personally, I think this is one of the biggest trends in energy that we’re going to see over the next 20 years.”

Is the gas there?

Curzio adds that first, he had to answer in his own mind the most fundamental of questions about gas: Are there the proved reserves and production capacity available to support what could become a major new market?

“Of course we have been tracking natural gas,” he says. “I took my research team, in the past nine months, to every single major shale area. I interviewed everybody from real estate agents to executives; we saw these fields. We’ve been to North Dakota and the Bakken shale, the Permian basin and the Eagle Ford in Texas, and also the Marcellus shale in Pennsylvania.”

And what was his conclusion after all that travel?

“We have massive amounts of natural gas,” Curzio says. “That’s the first thing we wanted to see. How much natural gas do we actually have?” He mentions G. Steven Farris, board chairman and chief executive of Apache Corp., said at a recent industry conference that there may be a 300-year supply of gas. “Now, I don’t know if it’s a 300-year supply, but based on the government numbers, it’s at least a 92-year supply,” Curzio says.

So even conservative reserve estimates are very optimistic. Financing all those plants will take a lot of money, Curzio points out, but he quickly adds there are plenty of investors who want in on the action. Consider Cheniere, he says.

“I see no problem raising the money, especially when a small company like Cheniere Energy can raise $3.4 billion [in 2012] when its market cap was $3.4 billion, because there are massive commitments. These international state-run companies, whether it’s China, Japan, India, are willing to sign 10- year contracts with us. You’re going to see this happen. I haven’t seen anything that suggests funding is going to be a problem.”

In September, Cheniere announced that it planned to take the general partner of its master limited partnership (MLP), Cheniere Energy Partners, public, filing with the Securities and Exchange Commission to form Cheniere Energy Partners LP Holdings as a corporation. Cheniere ultimately will receive net proceeds from an initial public offering of common shares. Cheniere announced it intends to use cash from the offering for the development of its existing assets, future projects and general corporate purposes. Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are joint book runners.

Six LNG import terminals, including Sabine Pass, went up during the years when domestic gas production was in slow-but-steady decline, and the conventional wisdom was the U.S. must start to import gas.

They enjoy a major advantage now, Dale Nijoka, global oil and gas sector leader for Ernst & Young’s Global Oil & Gas Center, tells Midstream Business. They are what he calls “brownfield facilities” with existing tankage, docks, pipeline connections, etc., in place. All that must be added is an actual liquefaction plant, he adds.

“The view is that while it’s relatively easy to shift the flow on those things, there’s still a huge capital cost that has to be incurred to make sure that they’ll be able to run those plants and be able to get the gas to them and enough to do the export.”

What’s next?

The next plant to receive approval, Nijoka speculates, will be a greenfield project, built from scratch. The Jordan Cove project in Coos Bay, Oregon, will be different in another respect as it will handle primarily Canadian-produced gas.

LNG exports constitute some big financial risks but offer the prospect of big rewards. It’s all about price differentials. North America has the cheapest gas prices in the world and the prospect of significant profitability. But those LNG exports could do more than add supply to the global market. They very well could alter the way the world prices LNG—and that could hurt other exporters that have substantially higher costs.

LNG has traditionally been benchmarked against crude oil, yielding a sales price premium for exporters. On a Btu-equivalent basis, oil at $100 per barrel (bbl.) yields a gas price of around $16.70 per million Btu (MMBtu), or about what many LNG importers pay right now. Japan and some other Asian importers were paying as much as $18 per MMBtu last year at the same time the Henry, Louisiana, gas hub priced gas at a modern low of $1.95 per MMBtu, creating an astounding price spread. Domestic gas prices have since perked up to the $4 range, but the gap remains very wide.

There’s a reason for that apples-to-oranges oil benchmark, Nijoka says. “If you remember back 20 or 30 years when they first started signing some of those contracts, the reason oil was used was because there wasn’t any other method to price them. They didn’t have an international gas market. Some of us would argue we still do not have a global gas market, that it’s still very spotty, but it’s evolving into a global market like oil.”

But it appears at least some U.S. exports will be based on the Henry hub price.

The Deloitte report found strong interest, particularly among Asian LNG customers, in adopting Henry hub gas prices as a standard. That could lower LNG prices paid by Asian customers by a quarter and seriously hurt the economics of some LNG projects, particularly in Australia, Deloitte said, with hybrid indexes somewhere between the two likely to emerge.

Cheniere commissioned a separate study by Deloitte MarketPoint to determine the potential price impact on the world LNG market as U.S. exports comes onstream. The study projected two scenarios, a “business-as-usual” approach in which world markets will have a prolonged period of oil price indexation, and “competitive response,” which assumes the increased competition from newer supply sources coming on-line during the next decade will alter the market. The study assumed U.S. LNG exports of 6 Bcf per day.

‘Complex market dynamics’

The study for Cheniere found “complex market dynamics, but under close examination, clear economic impacts with potential geopolitical implications become evident.” It determined :

• U.S. LNG exports could hasten a transition away from oil-price indexation.

• Prices are projected to decrease fairly significantly in regions importing U.S. LNG while domestic gas prices would rise marginally. “The projected increase of average U.S. prices from 2016 to 2030 is about 15 cents per MMBtu, while the corresponding price decrease in importing countries could be several times higher.”

• U.S. LNG exports are projected to narrow the price difference between the U.S. and export markets and hence, the market will likely limit the volume of economically viable U.S. exports.

• U.S. exports are projected to provide economic benefits to gas-importing countries. While the price impact within the U.S. is projected to be fairly minimal because of the large size of the North American resource base and responsiveness of the domestic gas market to price signals, the global impact could be more than what the relative size of 6 Bcf per day of exports might indicate.

• Other gas exporters could suffer a decline in trade revenues due to price erosion and/or customer displacement. “Entry of new supply clearly benefits consumers, but negatively impacts suppliers through price reductions and/or direct displacement of their export volumes. Even if gas supply in a region is not directly displaced by U.S. LNG exports, its producers might suffer decline in revenues due to lower prices affecting the region.”

• U.S. LNG could displace some current oil consumption through increased gasfired electric power generation, perhaps as much as 5 million bbl. per day.

A Deloitte study concluded there may be some benchmark in between. “Rather than signaling a complete switch from oil to gas-hub indexation for longterm LNG contracts in Asia Pacific, these recent developments reflect a transition toward a pricing spectrum where oil indexation is one of several pricing mechanism used,” it said.

The gas reserves may be there, the money may be there, but the biggest hurdle of all in large-scale LNG exports often gets overlooked, Nijoka says.

“The biggest thing that I see that companies are going to struggle with is just the construction itself. How do we get these plants constructed? Do we have the right people to do it? What’s the timeline for it? And are our pockets deep enough that we’re going be able to pay for this?” he says.

A world-class gas liquefaction plant is big. Construction requires trained and experienced technicians and all sorts of specialized metal alloys, pumps, cooling systems, insulation and other things. They’re not off-the-shelf. Big players with deep pockets—he mentions Shell, BP and BG Group as examples—can probably pull it off. “But the smaller companies are going to struggle,” he adds.

“I think that’s part of the reason why Cheniere looks like they’re just going to be a merchant and process the gas. They are trying to protect themselves from risk. They don’t want to buy a bunch of gas at $3 and then sell LNG for $12, when suddenly the gas prices spike or the LNG prices drop. They want to make sure they lock in a margin between the natural gas for their facility and the actual LNG,” he adds.

Nijoka cites Australia’s challenges to rapidly grow its LNG business as an example.

“Australia is having a bit of a struggle because of the workforce and the strengthening of the Australian dollar. Do they have enough qualified people? Let’s say I’m a welder, I’m a really good welder. One company hires me today at $100 an hour and tomorrow the company down the street calls and tells me they will give me $150 an hour. There’s this huge wage inflation that they’re battling against.

“I don't think we will see that in the U.S., I think there’s enough construction infrastructure to have these projects done. It’s just time and money, it’s going to take several years to develop and build them,” Nijoka says.

Alaska’s prospects

Any discussion of North American LNG exports eventually comes around to Alaska. The state had the first, commercial-scale LNG export operation at Nikiski, outside Kenai, to liquefy gas produced from Cook Inlet fields for shipment to Japanese utilities. ConocoPhillips operated the plant for 40 years but dropped its export license and closed things down in 2012. The plant had a comparatively modest capacity of 240 million cubic feet (MMcf) per day.

The state recently asked ConocoPhillips to apply for a new license and reopen the mothballed site, providing an incentive for new Cook Inlet drilling. Oddly, Nikiski may figure into plans for a long-discussed, 800-mile pipeline that would move abundant, North Slope gas to a liquefaction plant on tidewater. The current gas pipeline plan, strongly supported by the state government, announced in October it chose Nikiski for its terminal, rather than Valdez.

“This is a step forward for the Alaska LNG project and shows continued progress toward building Alaska's energy future,” Steve Butt, senior project manager for the Alaska South Central LNG Project, said. “The Nikiski site also results in a pipeline route that provides an access opportunity to North Slope natural gas by the major population centers in Fairbanks, Mat-Su Valley, Anchorage and the Kenai peninsula.”

If built, the Alaska system would dwarf even the big LNG plants proposed in the Lower 48. Capacity would be 3 Bcf per day and the cost, pipeline and plant combined, could exceed $60 billion. But partners with deep pockets behind it are ExxonMobil, BP and ConocoPhillips— the major North Slope producers—along with TransCanada Pipelines.

Canada and Asia

LNG exports figure prominently in Canada’s booming oil and gas industry, too. Growing U.S. shale gas production has backed out much of Canada’s gas production as new, initial production from western Canadian shale plays comes online.

Nijoka estimates Canadian gas sales to the U.S. peaked at more than 5 Bcf per day “but it’s been reduced somewhat because of the abundance of gas that we have now.” That gas has to go somewhere, and Asia represents an excellent market for western Canada’s abundant gas production.

But how to get it there?

Proposals are in the works for a liquefaction plant and marine terminal at Kitimat, British Columbia. The Kitimat LNG project gained important big-player support in early 2013 when Chevron Corp. purchased stakes in the project previously held by Encana Corp. and EOG Resources Canada.

Chevron then sold 10% of its acquired interests to the remaining original project partner, Apache Canada Ltd., to equalize the firm’s 50/50 stake in the project. The first phase calls for liquefaction of 770 MMcf per day of gas, starting in 2017. Capacity could be doubled in a second phase to start up at a later date. Canada’s National Energy Board (NEB) has approved a 20-year export license.

Although Canada’s regulatory procedures are regarded as more amenable than those of the U.S., the Kitimat plan must jump some high hurdles. British Columbia has a powerful environmental lobby, and the proposal has drawn opposition from native tribes. The project was a major issue in recent provincial elections but the pro-development Liberal Party won and Premier Christy Clark recently announced grants to study the impact of a largescale plant on the remote area.

Getting gas to a liquefaction plant on the British Columbia coast will be pricey, given that pipelines will need to cross some of the most rugged mountains in North America. TransCanada Corp. told attendees at its recent annual shareholder meeting that it is looking at a C$9-billion investment to build two gas pipelines across northern British Columbia.

There’s also a problem of room—or lack of it—on the mountainous British Columbia coast, Nijoka points out.

“But the issue from a Canadian standpoint is probably more about the logistics of building the plant,” he adds. “Where here in the States we would spread a plant across a number of acres, in Canada they talk about the fact that ‘we would have to build up instead of out,’ meaning that they’ve got to build up because there’s not that much space for them to put it on the West Coast in Canada. I’ve seen photos of the potential site and you don’t get far from the beach before you’re walking uphill.” That will raise engineering and construction costs substantially.

But Canadian producers and midstream operators are looking at options.

Canadian gas may cross the 49th Parallel to feed the proposed Jordan Cove project. Operator Veresen Inc. has applied to Canada’s NEB for permission to export 1.55 Bcf per day of Canadian gas. It also has an application before the U.S. Department of Energy (DOE).

To reach Jordan Cove, western Canadian gas would travel via existing pipelines to the Malin, Oregon, pipeline hub. Veresen and The Williams Cos. would build a 232- mile, 36-inch Pacific Connector Pipeline from Malin to the plant.

The liquefaction plants may go up, but they’ll be useless without the shipping capacity to move it to customers. Shipyards are already hard at work building those new LNG tankers, Nijoka says.

“Most of the new ones are going to be built in South Korea,” he adds. “There’s going to be a whole bunch of shipyards in Asia that will be busy from a cost standpoint, a steel standpoint and everything associated with it. I think long-term it has a big impact. Short-term, I think most of them are already being built.”

Looking ahead

The final impact of the new North American LNG capacity won’t be known for years as billions of dollars go into mammoth plants putting the equivalent of perhaps 10 Bcf per day of gas on the market.

“I think it’s all going to have an impact,” Nijoka says. Problem is, the impact will come to some sort of sprawling, still unknown international business.

“But as all of these plants get built in different parts of the world, I do think the business will become much more global, and you’ll be able to trade the gas just like you trade the oil on the high seas and move it from one market to the other.

“I think long term it’ll force some of the Canadian gas and some of the U.S. gas to be more cost-competitive; figure out a way to do it better, cheaper, faster,” he adds.

“We’ll figure out a way to manage the transportation cost, to move stuff from the Gulf Coast to the East Coast into the Asian market, or it may actually be that you move gas over into the European market and put it in Rotterdam or somewhere, which opens a whole new can of worms with [Russia’s] Gazprom and its ability to deliver gas into the European markets.”

Deloitte’s research projects a ready response as LNG exports begin.

“The North American gas market is dynamic,” it concluded. “If exports can be anticipated, then producers, midstream players and consumers can act to mitigate the price impact. Producers will bring more supplies online, flows will be adjusted, and consumers will react to price change resulting from LNG exports.”

Think Small: Domestic LNG Growing

By Paul Hart

All those export-focused, world-class liquefaction plants costing billions have a lot of attention right now, but liquefied natural gas (LNG) also has a growing niche at home. Like the exports, it’s the potential to work a price spread— in this case versus diesel fuel—that’s driving things.

The early adopters will be corporations with large truck fleets, Frank Curzio, an analyst for Stansberry & Associates Investment Research, tells Midstream Business.

“They’re switching their engines over to natural gas because it’s cheaper. The upfront cost, of course, is more expensive, but the payback period is two to three years from now, which is nothing for these companies. The amount of fuel savings are between 30% and 40% right now,” he says. “Compared to diesel, they have a huge benefit in terms of the spread in prices.”

Firms as diverse as UPS, Coca-Cola, Wal-Mart, Canadian National Railway and BNSF are testing LNG as a fleet fuel for trucks and locomotives.

But the biggest market may involve gassing up those very LNG tankers weighing anchor at North American ports and their sister ships, Dale Nijoka, global oil and gas sector leader for Ernst & Young’s Global Oil & Gas Center, tells Midstream Business.

“The big prize is probably more in the shipping area. If you were to look at where you get the bang for the buck, it’s not you or me changing our car to run off natural gas. The real bang is when you get into the shipping industry and you see just how much fuel oil they use and what you could take out in fuel oil,” Nijoka says. “But there again, there’s this huge midstream infrastructure that has to be built out so that you could make that conversion.”

The marine classification firm Det Norske Veritas (DNV) did a study recently that projected that by 2018-2020 some 30% of all newbuild shipping will have LNG-powered engines. DNV even coined a new acronym—bungas— for the LNG bunkers business.

Landside, oil-field conversions offer a big market, too. Stabilis Energy, a small-scale liquefaction supplier, recently announced a venture with Flint Hills Resources LLC to build five LNG liquefiers. The first will have a capacity of 100,000 gallons per day and is scheduled to go on stream in January 2015 in George West, Texas.

So is all this small-scale LNG market a case of me-too, fad economics? Curzio doesn’t think it is.

“This trend is as real as it gets, and it’s going to get bigger and bigger based on my research and visiting a lot of these companies and talking to them,” he adds. “I think this trend is definitely for real.”

LNG Projects Get In Line

By Frank Nieto, Editor, MidstreamBusiness.com

Cheniere Energy’s Sabine Pass terminal was the first terminal to receive permission from the Federal Energy Regulatory Commission (FERC) and the U.S. Department of Energy (DOE) to export as much as 803 billion cubic feet (Bcf) per year—2.2 Bcf per day—of domestically produced liquefied natural gas (LNG) to countries both with and without U.S. Free Trade Agreements (FTA). The company stated that it could be ready to export these volumes as early as 2015.

It has since submitted two more applications to export 280 million cubic feet (MMcf) per day and 240 MMcf per day of LNG to both FTA and non-FTA countries. The two licenses for FTA exports were approved in July. The company is seeking approval to export another 860 MMcf per day of LNG to both FTA and non-FTA countries as well.

Twenty other terminals have received DOE approval to export LNG to FTA countries. The majority of these applications are also seeking full licensing to export volumes to non-FTA countries. Selected projects include:

• Freeport LNG, Freeport, Texas, which received approval for two applications in February 2011 and February 2012 to export 1.4 Bcf per day (511 Bcf per year) to FTA countries. In May, the company received approval to export this same capacity to non-FTA countries. The company has a second application to export volumes to non-FTA countries that is still pending. This ConocoPhillips project is expected to take three to four years to complete and could be brought online in early 2017.

• Lake Charles Exports LLC, Lake Charles, Louisiana, was approved in July 2011 to export 2 Bcf per day of LNG to FTA countries. The terminal was granted approval to export these same volumes to non-FTA countries in August. The company said that construction could start in 2014 with the terminal being functional for exporting by 2018. Participants are BG Group plc, Southern Union Co. and units of Energy Transfer Partners LP.

• Dominion’s Cove Point LNG terminal, Lusby, Maryland, received authorization in October 2011 to export 1 Bcf per day. The company received approval to export 770 MMcf per day of LNG to non-FTA countries in September.

• Jordan Cove Energy Project seeks to build a terminal in Coos County, Oregon, that will export 1.2 Bcf per day of LNG. It received DOE approval to export LNG to FTA countries in December 2011 and is seeking permission to export 800 MMcf per day to non-FTA countries.

• Sempra’s Cameron LNG received permission from the DOE in January 2012 to export 1.7 Bcf per day from Hackberry, Louisiana, to FTA countries. The company stated that it intends to start construction on the project late this year and begin operations in late 2016.

• Gulf Coast LNG Export announced plans to build an export terminal in Brownsville, Texas, that will be capable of exporting up to 2.8 Bcf per day. The company is owned by Freeport LNG’s Chief Executive Michael Smith and is pending approval to export to both FTA and non-FTA countries.

• Gulf LNG Liquefaction Co. received permission from the DOE in June 2012 to export 1.5 Bcf per day of LNG from its terminal in Pascagoula, Mississippi.

• Oregon LNG anticipates completing work on its terminal in Warrenton, Oregon, in 2017. It received DOE approval to export 1.25 Bcf per day to FTA countries.

• Southern LNG Co. received DOE approval in June 2012 to export 500 MMcf per day of LNG from its terminal on Elba Island, Georgia, to FTA countries.

• Golden Pass LNG terminal, Sabine Pass, Texas, owned by Exxon- Mobil, Qatar Petroleum International and ConocoPhillips, received DOE approval in September 2012 to export 2.6 Bcf per day of LNG to FTA countries.

• Cheniere Marketing LLC received approval to export 2.1 Bcf per day of LNG from its proposed Corpus Christi, Texas, terminal to FTA countries in October 2012.

• Main Pass Energy Hub LLC received approval in January to export up to 3.2 Bcf per day of LNG from its proposed deepwater LNG terminal offshore Louisiana to FTA countries. It has not applied to export volumes to non-FTA countries. Freeport-McMoRan Energy received approval in May to export 3.22 Bcf per day of LNG to FTA countries from the terminal and is seeking to export the same volumes to non-FTA countries

Cove Point ‘Unique’ LNG Terminal

By Michelle Thompson, Associate Editor

Dominion Resources Inc. in September became the fourth company to receive a full license to export liquefied natural gas (LNG). Its gas will be shipped from its Cove Point LNG facility on Chesapeake Bay in Lusby, Maryland.

Construction on its facilities, which will cost between $3.4 and $3.8 billion, is expected to be completed in 2017. The proposed liquefaction plant will liquefy about 770 million cubic feet per day of inlet gas.

Though Dominion wasn’t the first company to gain non-FTA export approval, there are elements of Cove Point that make it unique, says Dominion Business Development Manager Bill Allen.

“Our project is a little bit different than Cheniere’s [the first licensed plant], where they are actually selling LNG at the output plant,” Allen told attendees at Platts’ recent Pipeline Development and Expansion Conference in Houston. “Dominion is only offering a tolling service. We are providing a liquefaction service. We don’t have any other commodity; we don’t arrange for upstream supply, we don’t arrange for downstream delivery of LNG. All we provide is a liquefaction service.”

Dominion is also in an advantageous position in the sense that it already has an import terminal, which Allen says will work to the company’s benefit. “I think you’ll find the likelihood of export terminals moving forward in the U.S., the successful projects will be existing LNG import terminals,” he says.

Cove Point was originally built in the mid-1970s as an import terminal. At the time, there were projections for significant amounts of imported LNGs. It was among four such facilities constructed during that time period.

Throughout the years, its capacity has increased to the point that it is now capable of vaporizing 1.8 billion cubic feet per day. Dominion acquired Cove Point in 2002, and the plant had “been mothballed since the early ’80s.” It was reactivated and put back into service in 2003. “There were nearly 40 new import proposals throughout the U.S.,” recalls Allen. “Only about six were built. A big reason for that is the U.S. shale gas revolution.”