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By Alan Kovski
Plans for exports of U.S. liquefied natural gas have multiplied as a global supply glut has developed, raising the prospect that some exporters may lose money for several years.
Analysts say the LNG surplus also increases the likelihood that some contracts could be renegotiated, some projects may be delayed long enough to get past the oversupply period, and some plans may never come to fruition at all.
Fast growth in worldwide LNG demand should eliminate the surplus in five or six years, so there can be good reason to delay projects and become part of a “second wave,” analysts told Bloomberg BNA. But until then, markets—rather than lawmakers, regulators or activists—will pose obstacles to profitable exports.
“There are certainly going to be regrets,” said Kenneth Grant, executive vice president of Compass Lexecon, a subsidiary of FTI Consulting Inc. “Margins are going to be squeezed for years.”
Companies in the competition for LNG exports range from Exxon Mobil Corp. and Royal Dutch Shell Plc to relatively small outfits founded over the last decade with private equity backing.
About 70 percent of global LNG is consumed in Asia, where contract prices typically are indexed to spot crude oil prices. Currently that indexing produces Asian spot LNG prices of about $5.50 per million British thermal units (MMBtu). LNG from the U.S. for sale in Asia costs an estimated $8 to $9 per MMBtu, taking into account the costs of the gas, liquefaction, and transportation.
“Buying LNG at these prices is a guarantee of losing money,” Fereidun Fesharaki, chairman of consulting company FGE, said while speaking recently at the Center for Strategic and International Studies, a think tank in Washington.
U.S. LNG is being exported only from the Sabine Pass facility of Cheniere Energy Inc. in Louisiana. The buyers and sellers using the plant are struggling with global prices well below their estimated costs. GAIL (India) Ltd., one of the buyers, reportedly has been seeking to renegotiate its contract, although neither GAIL nor Cheniere has confirmed the reports.
GAIL, whose majority owner is the government of India, is not a small fish, but so far, Cheniere has indicated it has no intention of renegotiating anything.
The pressure for renegotiations may grow substantially, however, as top LNG traders like Shell see the growing risk of losses within their contract portfolios.
Fesharaki suggested some buyers, especially the national oil companies of some LNG-consuming countries, may walk away from contracts and trigger legal wrangling if they cannot renegotiate terms.
Cheniere, which started exporting in 2016, may be able to pass off most of its market risks to customers, but it has had its own financial strains, losing money in 2016. It turned a profit of $172 million in the first quarter of 2017, but its long-term debt amounted to $24 billion, a high level for such a specialized company with such a short track record in LNG.
Cheniere’s contractual customers include GAIL, Shell, Korea Gas Corp., Total S.A., Spanish company Gas Natural Fenosa, and British utility Centrica Plc. Typically the companies will buy the gas and market the LNG themselves, although Cheniere also is willing to sell LNG overseas through its own marketing affiliate, giving it at least some of the market risk that its six big contractual customers take.
Most companies planning to build U.S. LNG export plants need customers to sign 20-year contracts to give banks enough assurance of revenues to justify the loans for the projects. Projects currently under construction are proceeding because of 20-year contracts typically signed when LNG prices were much higher than they are now, before the slump in gas and oil prices that started in 2014.
The U.S. projects under construction are “tolling” arrangements, where the owner of the liquefaction plant provides the service but does not try to take an ownership stake in the LNG. Customers take the market risk.
Now, the challenge is to find customers willing to sign such contracts when everyone can see spot prices are not fully covering U.S. LNG costs. Big customers in Japan, South Korea, China and India have been the special prizes.
President Donald Trump has been talking of LNG sales as a way to improve the U.S. trade balances with China and South Korea and a way to provide Europeans with less reliance on Russian-pipelined natural gas. His remarks do not square with the market conditions, however.
Chinese companies are over-contracted, and Asian demand is so oversubscribed that the surplus has been going to Europe, Fesharaki said. LNG spot prices in Europe are lower than Asian prices, again raising the prospect of sales at a loss for the near term.
The glut shifts negotiating leverage to buyers, Grant at Compass Lexecon said. Buyers might ask for such things as shorter contract terms, fixed prices, and unlimited flexibility on shipping destinations, he said.
Looking farther ahead, Grant said LNG trading likely will shift as it matures to more flexibility in contracts and fewer tolling arrangements. “You can see where it’s going,” he said.
Six U.S. LNG export projects are under construction, with in-service target dates spread over 2017-2019, according to Energy Information Administration (EIA) data. The great majority of their capacity already is committed to 20-year contracts, typically take-or-pay contracts where the LNG buyer either takes the amount in the contract or pays an alternative fee to the owner of the liquefaction plant.
Global LNG trade has been running at 34.6 billion cubic feet a day (Bcfd) and growing at about 6 percent a year. The six U.S. projects under construction will add about 9.6 Bcfd of export capacity, said Victoria Zaretskaya, an EIA analyst.
That is a very large capacity addition during a period when Australia also will be expanding its exports, the projects helping to assure an expansion of the global market surplus, Zaretskaya said.
Fesharaki, looking at the global growth, said, “Between 2017 and 2020 we are increasing the global supply by 40 percent. [There is] no way we can increase the demand by 40 percent in three years.”
Qatar, the world’s largest LNG exporter, sent a tremor through the LNG market July 4 when it said it would increase its LNG exports by 30 percent in five to seven years through an expansion of its North Field natural gas production. Qatar Petroleum, with majority stakes in the nation’s LNG export operations, has some big partners in those operations, including Exxon Mobil Corp., Royal Dutch Shell, and Total S.A.
The cost of producing natural gas at Qatar’s North Field and liquefying it is $2 to $2.50 per MMBtu under current market conditions, Zaretskaya said. Such low-price competition means lower utilization rates should be expected for U.S. export facilities once the extra capacity comes online, she said.
“It’s very hard to compete with Qatar.”
Looking at the indexing of Asian LNG prices to crude oil, EIA estimates oil prices would have to climb to the $65-$70 range per barrel for U.S. LNG to be competitive in Asian spot markets, Zaretskaya said. Current prices are below $50 for the benchmark crudes West Texas Intermediate and Brent, though it is commonly expected that they will rise over time.
Five U.S. LNG export projects have been approved by the Energy Department and the Federal Energy Regulatory Commission but are not yet at the construction stage, in part because they do not all have customers locked up. Other projects have been proposed but not yet approved.
The projects that have yet to see construction and win permits would form the second wave for U.S. LNG export facilities.
Magnolia LNG LLC, planned for the Lake Charles, La., area, is one of the projects approved but awaiting customer contracts and construction. It is a subsidiary of Liquefied Natural Gas Ltd.
The target for Magnolia LNG is to complete customer contract negotiations and reach a final investment decision by the end of 2018, Greg Vesey, CEO of the parent company and the subsidiary, told Bloomberg BNA.
Vesey’s timing might allow most of the glut to pass before his LNG export plant goes into operation. It can take four years to build an LNG export plant, he said. If the construction were to start late in 2018, the plant might be completed around the end of 2022. Analysts have been suggesting the glut will fade by about 2023-2024, although their forecasts preceded the Qatar expansion announcement.
Still, there are quite a few developers aiming for a similar window of opportunity.
“I accept that it is tough competition,” Vesey said.
Magnolia LNG, like many of the projects, has private equity as part of its financial backing. Private equity managers have been diving into energy infrastructure projects throughout the U.S. oil and gas sector.
Stonepeak Infrastructure Partners, a private equity firm, is a partner of Magnolia LNG. Such investment managers look to energy infrastructure investments for their relative long-term stability, Vesey said.
Long-term stability is especially valued by pension funds. IFM Investors Pty Ltd., an Australian investment group owned by pension funds, has invested in one of the projects under construction, Freeport LNG, in Texas. Global Infrastructure Partners, a private equity firm, also owns a piece of Freeport LNG.
Cheniere Energy’s institutional investors include BlackRock Inc., The Vanguard Group Inc., The Goldman Sachs Group Inc., Carl Icahn, and hedge fund Baupost Group, among others. And Blackstone Group took a big ownership stake in Cheniere’s Sabine Pass project through a Cheniere affiliate.
The developers with projects not yet approved will have trouble catching up because they will find that the Federal Energy Regulatory Commission does not hand out approvals easily even when the five-member commission has a quorum for making such decisions, which it does not now, Vesey said. It took almost three years to get Magnolia LNG through FERC.
Most of the U.S. export plans are for Gulf Coast sites, and two are for the East Coast. One prominent plan, still at an early stage of permitting at FERC, is for the West Coast—the Jordan Cove project that would ship to Asia from Coos Bay, Ore.
Jordan Cove Energy Project L.P., a subsidiary of Canadian energy infrastructure company Veresen Inc., would build the liquefaction plant and a 235-mile pipeline across Oregon from a gas pipeline hub. A basic selling point would be lower shipping costs and less time than sailing from the Gulf Coast through the Panama Canal to Asia.
FERC rejected the Jordan Cove plan in 2016 because the commission did not see customers solidly lined up to justify pipeline approval. Now the “pre-filing” stage of the permitting process at FERC has been restarted for the project because 50 percent the liquefaction plant capacity and 66 percent of the pipeline capacity have been contracted.
The biggest buyers for Jordan Cove are JERA Co. Inc. and the Japanese trading giant Itochu Corp. JERA represents two Japanese utilities and is the world’s largest buyer of LNG. Australian financial company Macquarie Group Ltd. also has contracted for part of the pipeline capacity through its Macquarie Energy LLC energy trading unit.
Much farther north is a Pacific Coast LNG export plant sitting idle and up for sale. The Kenai LNG plant at Nikiski, Alaska, was idled in 2015 by owner ConocoPhillips Co. and has not shipped anything since, though it is available to do so. ConocoPhillips halted its operations because of “market conditions,” it said in 2016, after competing sources of LNG from Australia, Indonesia and elsewhere had surged into the Asian market.
Jordan Cove is talking with other potential buyers and intends to have 100 percent of its capacity under contract within a time frame that should make the project acceptable to FERC, company spokesman Michael Hinrichs said.
“We prefer not to have any more curve balls thrown at us,” Hinrichs said, alluding to the company executives’ surprise when FERC rejected their plan in 2016.
Fesharaki, though skeptical about projects that are not in construction, said the Jordan Cove project “maybe is still doable.”
He was more definite about the Golden Pass project in Texas, with partners Exxon Mobil and Qatar Petroleum, a Qatari government-owned company. Golden Pass appears sure to go ahead because its partners have the money and appear determined to make it happen, Fesharaki said.
Grant at Compass Lexicon implied something similar, though he did not single out Golden Pass. He said the best bets would be the proposals that are well-capitalized and can make use of existing infrastructure. That would describe the Exxon Mobil and Qatar venture.
There also has been a spate of proposals for LNG exports from Canada, but they have stalled in the face of the same problem of global oversupply.
LNG projects are not in construction in Canada now, although environmental cleanup as a first step in site preparation has begun at a British Columbia coastal site.
That is the location of the planned Woodfibre LNG project. It is owned by Pacific Oil & Gas Ltd., part of a Singapore-based group of companies. It is fully permitted, as are several other Canadian plans.
Woodfibre apparently would be the first Canadian LNG export project out of the gate, maybe with a startup as early as 2020, said Mark Pinney, manager of natural gas markets and transportation at the Canadian Association of Petroleum Producers. It would be an integrated operation, the gas bought and sold by Woodfibre-affiliated companies, not a tolling arrangement.
The biggest question is how robust LNG demand will be, Pinney said. The underlying demand growth has been tremendous, but there can be slowdowns, as happened in 2016 in Japan and South Korea, he said.
Like other analysts, Pinney agreed the glut should be over by 2024 or 2025. “Demand is going to catch up,” he said.
James Henderson, director of the Natural Gas Program at the Oxford Institute for Energy Studies, put it tartly in an analysis issued in 2016. “The somewhat simplistic assumption that Asian markets would always obligingly provide consistently high LNG demand growth has become questionable,” he said.
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