Riding the ever-growing shale boom, U.S. LNG export project developers have been quick to trumpet proposals. High arbitrage opportunities, bolstered by what has been until now relatively inexpensively produced gas, provide an enticing incentive to ship LNG to Asian, European and South American markets.

Even as major liquefaction facilities in Australia, Russia, the East Coast of Africa and, potentially, Canada, are racing toward production making long-term bets on an increasing worldwide appetite, U.S. project developers are strapping up their boots and donning hard hats. They would like to think their bold entrance to the world stage would make foreign projects nervous, and perhaps they do. However, with U.S. projects off to the races, persistent questions remain: How many projects will produce, how much will they produce, and when?

Gulf projects

The majority of U.S. projects are sited for the Gulf of Mexico. According to a recent Hart Energy survey, 21 projects are proposed for the Gulf, representing about 248 million tonnes, or about 35.43 billion cubic feet per day (Bcf/d), of capacity. They average about 11 million tonnes per annum (mtpa), or 1.57 Bcf/d, in size, although questions abound regarding whether all will be built. (Canada has proposed an additional 322 million tonnes, or 46 Bcf/d, mostly in British Columbia.)

Nearly all Gulf projects have been approved by the U.S. Department of Energy (DOE) for export to nations that have free trade agreements (FTAs) with the U.S., but few have garnered non-FTA approval. And that is not the only regulatory hurdle left to vault. Many have been waiting for the Federal Energy Regulatory Commission’s (FERC’s) approval for more than a year, or have not applied.

Of all the U.S. LNG export projects proposed, few have all three major federal approvals needed. Many have been waiting in the FERC or DOE non-FTA queues for over a year.

Non-Gulf projects

Only seven projects have been proposed for states outside of the Gulf Coast. Altogether, they have proposed a little over 46 mtpa (6.57 Bcf/d), only about 15% of overall proposed U.S. exports. Exempting the massive Alaskan Nikiski project, they are much smaller than their Gulf brethren, weighing on average about 4.4 mtpa (0.63 Bcf/d).

Cove Point in Maryland and the two Oregon projects, Oregon LNG and Jordan Cove, are perhaps the highlights of the group at a more advanced stage. Cove Point, Dominion’s regasification terminal seeking to become bi-directional, has DOE approvals and just received approval from FERC at the end of September. The Oregon projects have DOE approvals, applied to FERC in June last year, and even have approval from the National Energy Board of Canada, whose pipelines they intend to link with and source some of their feed gas.

While they tout shorter, more direct shipping routes—the two Oregon projects and one Alaskan are closer to Asian buyers, and Downeast looks to Europe—they have their own challenges. Both Oregon projects have faced much residential resistance, either from environmentalists or landowners who are uneasy about pipelines crossing their land.

FERC approval has virtually assured Cove Point of moving forward, although it remains unclear if a circuit court judge’s opinion about the legality of a municipal land ordinance may delay the project.

Nikiski LNG recently said it entered into a memorandum of understanding with the Japanese government in order to encourage Japanese investors in the project. But while it has acquired 95% of the land it would need for a massive 800-mile pipeline extending from extreme northern Alaska to the southern Nikiski region, it has only acquired about 38% of the land required for the site.

The front-runners

Three Gulf projects are the most advanced: Sabine Pass LNG, Freeport LNG and Cameron LNG. Sabine Pass, owned by Houston-based Cheniere Energy, is located in Cameron Parish, Louisiana. A former import facility, it is currently converting into a bi-directional plant. Its five LNG tanks can store about 17 Bcf altogether, and its first four liquefaction trains were approved by FERC in April 2012. The DOE approved exports to FTA and non-FTA countries in September 2010 and in May 2011, respectively.

Upon completion, its four initial trains will each be capable of liquefying 4.5 mtpa (0.64 Bcf/d), for a total of 18 mtpa (2.57 Bcf/d). There are plans for two more, which are awaiting approval.

As of June this year, the first two trains were only 38% complete, but Cheniere still intends to begin operations near the end of next year, with capacity reached in 2016. Trains 3 and 4 will come online incrementally in 2016 and 2017. A fifth and sixth train, if approved, would add another 9 mtpa (1.29 Bcf/d) of capacity in subsequent years.

Next is Cameron LNG, located in Hackberry, Louisiana. Its proponents, Sempra, GDF Suez, Mitsubishi Corp. and Mitsui & Co., just took a final investment decision (FID) in August, and construction on the brownfield site has started. Like Sabine Pass, Cameron is a regasification terminal that is becoming bi-directional. It received its DOE FTA permit in January 2012, FERC’s approval in June and most recently, DOE non-FTA final authorization in September. When it is completed in 2018, the export terminal will have three trains capable of producing 12 mtpa (1.71 Bcf/d) in aggregate.

Freeport, the third-most advanced LNG export terminal, is located in Freeport, Texas. Proposed by Freeport LNG LP, it is the latest to receive FERC approval, in July. DOE FTA and non-FTA approvals were earned in February 2011 and May 2013. Once again, it is a brownfield site, and it proposes to have 13.2 mtpa (1.89 Bcf/d) of capacity spread over three trains. Freeport has just finalized its tolling agreements, accounting for all of its capacity.

While it has not yet taken an FID, one is expected in the fourth quarter this year. Construction will start immediately thereafter. Its first train could come into service as soon as 2018, with its other two following in 2019.

The next in line

Beyond those three, it is difficult to say which other plants will move forward in the regulatory, financial and construction sectors.

“The question about how many of those and which ones are going to go is really going to be driven by several factors,” one industry source said. “One is market appetite. Just because you want to develop your project does not mean the market is ready to take it. The LNG market is only 240 million tonnes [34.29 Bcf/d] now, and a lot of companies are investing a lot of dollars in projects around the world. You have massive resources trying to be developed in East Africa, and those sponsors also have great incentives to try to get those volumes sold, and geographically, they have the advantage to Asian markets. So our view is it’s not a question of how many, but it’s a dual question: how many, and when?”

The source also emphasized that the production of U.S. exports will depend heavily on the resource base with regard to labor, equipment and contractors. In fact, because there are so many petrochemical projects in the U.S., the competition for qualified labor might exert significant inflationary pressure on labor costs.

Octávio Simões, senior vice president for Sempra International and president of Sempra LNG, echoed concerns about the limited number of engineers and designers who have experience in constructing LNG plants.

“The competition is worldwide, not just in the U.S.,” he said. “You have projects coming out in Mozambique, Tanzania, Australia, Papua New Guinea; you still have some discussions of projects in Nigeria, and the list goes on. It’s the same combination of EPC contractors, so there are limits on engineers, designers and other talent to do all this.”

He also said that with the extensive financing these projects have to arrange, investors are sensitive that operators of LNG plants are fully qualified.

“You have to go to great extent to prove to the lenders that you have qualified people to do this.”

A spokesman for BG Group commented that brownfield sites are cost advantaged with respect to greenfield sites. Several other experts cited that assessment as a major factor why some projects are more advantageous, and some also pointed out there might be difficulties in sourcing gas.

“Clearly not all or even most of the 45-plus proposed liquefaction terminals in North America will go forward, and the ones that do will be determined by a few key factors,” George Popps, an analyst at Stratas Advisors, a Hart Energy company, said. “The shale revolution has made domestic natural gas a much cheaper and more attractive option, which has increased demand considerably. Coupled with projected increases to Mexico’s pipeline imports, it is possible that there will be a strain on gas supply in five to seven years as some of these terminals come online and U.S. pipeline exports continue to grow.”

The U.S. Energy Information Agency (EIA) has published several scenarios, but its baseline model puts U.S. LNG exports at about 73 mtpa (10.43 Bcf/d) by 2030. Depending on different scenarios with factors such as oil prices and world demand, that number can swing from about 139 mtpa (18.57 Bcf/d) to 16 mtpa (2.29 Bcf/d). The proposed nameplate capacities ambitiously reach beyond these numbers.

Proposed capacity for U.S. projects far outstrips analyses of probable exports.

Pavel Molchanov, analyst at Raymond James in Houston, does not expect many of the U.S. projects to materialize.

“The reality is there is not enough gas in North America over a 20-year sustained period of time to enable the North American economy to export that much gas. That is absolutely not going to happen.”

The ratio of domestic demand to gas reserves is too high, he said.

“It’s not realistic for the U.S. and Canada to match Qatar and Australia in their scale of LNG exports, because so much more of the domestic gas has to be utilized for domestic purposes, power generation, heating, petrochemicals and so forth, and of course the U.S. government wants to encourage more natural gas in power generation in place of coal, which means more power plant demand for natural gas in the future. So it strikes me as an absolutely implausible gold rush—or land rush, maybe, would be a better way of putting it—for all of these projects to be popping up.”

He predicts that 10 Bcf/d of production by 2020 would be on the high end of his expectations. Beyond that, he said, it’s difficult to tell.

Simões predicts a similar amount of exports: 12 Bcf/d by 2022 or 2023.

“But it’s going to take some time,” he added. “Probably that number is not even going to be [in] 2022. That number is going to be more like 2025 because it takes a long time. It took a long time for Qatar to come up with 77 million tonnes [per year]. The U.S. is not going to do this overnight.”

Another industry report predicted less than five U.S. projects will proceed to production by 2020, at about 70 mtpa (10 Bcf/d).

“I think the other thing you need to consider is that there may be this misperception that shale gas is cheap,” the industry source said. “And that all shale gas can be produced at $2 to $3, and I think that is a mistake. I think a lot of industry pundits, ourselves included, would say that the stable price for shale is more in the $5 to $6 range [per million British thermal units, or MMBtu] and even then, that depends greatly on the type of shale you’re dealing with.”

Angelina LaRose of the EIA gave similar information on price. Referring to the EIA’s annual energy outlook, she said, “We have gas prices basically until 2030 remaining under $6 [per MMBtu] at Henry Hub, in 2012 dollars.”

Simões believes the price will remain in the $4/MMBtu to $6/MMBtu range for the immediate future.

The source also admits that the Panama Canal expansion, due to be finished either late this year or early next year, will play an interesting role, especially if Gulf projects are bottlenecked on their way to Asia.

“The Panama Canal, after its expansion, will have a maximum capacity. It’s only going to allow or be able to allow a certain number of ships through, and that’s just reality. Not every LNG ship in the world is going to be able to sail through the Panama Canal. There’s a number beyond which, that’s it.”

EIA analyst Michael Yo said that the canal’s expansion will accommodate 80% of all LNG tankers, excluding the Q-Max and Q-Flex tankers, the largest types of carriers, which only sail to and from Qatar. He emphasized that the expansion of the canal will affect regional LNG trade especially.

“There’s a lot of potential for regional trade in the Americas. You also have Trinidad and Tobago using the canal to potentially service Chile, as well as the U.S. There are also several regasification facilities being built in South America, and that’s a potential market for expansion.”

Might there be bottlenecks? Yo said he thought the market would work itself out on its own, through tariffs and appointments to get through it. Simões added that proponents of LNG export projects might see the limited capacity of the canal as a factor that helps decide which projects move forward.

The U.S. LNG export industry, while potentially huge, is still nascent. Multiple industry experts alluded to the difficulty of predicting how it will evolve. Some pointed to the FERC queue as one indicator: With recent changes, the DOE will not consider a non-FTA application before a project has invested millions of dollars into completing its FERC application.

Another factor seems to be sales contracts. Watch for announcements of sale and purchase agreements, many sources said. U.S. projects might make a dramatic entrance eventually, but perhaps not as significant as hoped for.

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