U.S. liquefied natural gas (LNG) terminals are unlikely to shut in significant amounts of the super-chilled fuel this year, but as the export market confronts historically low prices and a global supply glut, it’s not a possibility that can be easily ruled out or even defined.
“It is funny to hear people state that there will or will not be shut-ins with such confidence,” said long-time LNG trader Brad Hitch, a former Cheniere Energy Inc. executive. “The LNG market has not been lifting cargoes from U.S. producers for that many years, and it has very little experience observing how that production can be absorbed by an oversupplied market.”
Poten & Partners’ Jason Feer, head of Business Intelligence, said any estimates on domestic production curtailments would be a guess at best. “Everyone has a book, and you don’t know what their book looks like and how that cargo fits into that book.”
Gas prices in Asia, Europe and the United States, where most supply contracts are tied to Henry Hub, have hit historic lows in recent weeks, weighed down by a warm winter in the Northern Hemisphere, increasing supplies and the coronavirus outbreak, which threatens to destroy even more demand.
If gas prices were to continue spiraling, U.S. terminals could be the first to shut in as the feed gas used from the wholesale market has higher marginal costs than stranded assets from some overseas projects that pull associated gas from oil production, Hitch noted. But what exactly defines a shut-in facility, how long they could last and the impact on U.S. gas prices remains unclear.
“We’re constantly having to adjust how we’re looking at things, especially as there are developments around the coronavirus,” said gas analyst Christin Redmond of Schneider Electric, when asked about the likelihood of U.S. shut-ins.
As long as there’s a positive difference between the U.S. loading price, less variable costs such as shipping, and the foreign sale price of LNG, offtakers will likely move cargoes from the United States, even at just a few cents per MMBtu, said NGI’s Patrick Rau, director of strategy and research.
U.S. LNG producers appear more susceptible to shut-ins as prices have continued to weaken, according to NGI data. The maximum netback for April between the Gulf Coast and both Northwest Europe and Northeast Asia is less than $1.00 above Henry Hub.
Assuming offtakers are paying 115% of Henry Hub prices and including variable costs such as those for shipping and regasification at import terminals, NGI calculations show the rest of the curve looks no better. The spread between the Gulf Coast, Northwest Europe and Northeast Asia is mostly in negative territory through October, putting U.S. LNG out of the money.
“As the current strip stands, we could see some more cargo cancellations this summer,” Rau said. “Of course, there is still time for things to firm up between now and when buyers have to make a firm decision on whether they want to take those latter summer-month cargoes.”
The No. 1 U.S. LNG exporter Cheniere confirmed Tuesday that two April cargoes were canceled by an offtaker at its Sabine Pass and Corpus Christi facilities.
U.S. facilities are underpinned by long-term, take-or-pay contracts that are likely to mitigate any significant shut-ins, according to Enelyst.com managing director Het Shah. The former commodities analyst also noted that these contracts have flexible destination clauses that allow for secondary purchases of the fuel.
“There is a lot of optionality for U.S. LNG to flow at a reasonable rate this summer,” Shah told NGI.
Most U.S. agreements allow buyers to cancel cargoes within a 60-day window for a fee. Even if a deadline were to pass, with enough time before a cargo is lifted, the parties could possibly negotiate different terms.
“Nothing stops a buyer from calling a seller and saying, ”I know I have to lift this cargo under the contract, but it may be economically better for both of us if I don’t,’” Hitch told NGI.
In Cheniere’s case, the gas for the canceled cargoes had yet to reach the terminal and was instead bumped from the loading schedule. CEO Jack Fusco said the canceled cargoes gave the marketing arm “a great option” if it were to elect to sell the physical gas back into the market.
Cheniere has other options to weather the downturn. When heavy fog in the Gulf Coast prevented ships from entering the the Sabine Pass facility in 2019 and earlier this year, the company took out short-term storage capacity for its gas, according to transactional reporting at Pine Prairie Energy Center, a natural gas storage facility in Evangeline Parish, LA.
In addition, Cheniere has access to some gas that is cheaper than Henry Hub, with supply deals with Apache Corp. and EOG Resources Inc. for Japan Korea Marker-indexed gas, “which could be cheaper than Henry Hub right now, depending what discount has been applied,” according to Energy Aspects analyst James Waddell.
Instead of cargo cancellations, U.S. LNG players and offtakers could find other solutions, said Kpler LNG analyst Nathalie Leconte.
China National Offshore Oil Corp.’s recent declarations of force majeure were rejected by Total SA and other suppliers, which essentially brought contract negotiations to the forefront, noted Feer. “The initial force majeure declarations convinced everyone they have to start talking and figuring it out.”
Commercially, cancelling even more cargoes would send a bad signal to the market, especially as many developers in the United States are working toward final investment decisions (FID) for projects, according to Leconte. “It would be a bad move to actually shut in some of the trains as they’re trying to construct other terminals.”
Fusco during the quarterly conference call said the low price environment and global supply glut have resulted in less customer appetite to sign long-term contracts. It has made it difficult for Cheniere to “continue to get our fair share of those contracts” and commercialize for now the third stage of the Corpus Christi LNG facility in South Texas. The company had targeted this fall for reaching FID on the roughly 10 million metric ton/year (mmty) expansion project.
Tellurian Inc., which is proposing to build the mammoth 27.6 mmty Driftwood LNG export terminal in southwest Louisiana, was expected to announce a deal with Petronet LNG Ltd., India’s largest LNG buyer, when executives met recently in India. Instead, the parties walked away with a two-month extension of their memorandum of understanding.
Other producers like Cameron LNG use tolling models in which primary offtakers also are shareholders in the liquefaction project, and customers could elect to continue lifting cargoes even in a weak pricing environment, according to Waddell. For example, Cameron sponsor Mitsubishi Corp. last November lifted a cargo that Pavilion Energy Ltd. reportedly canceled from the Hackberry, LA, facility. Pavilion has a long-term, take-or-pay supply deal with Mitsubishi, which essentially controls some liquefaction under its tolling agreement.
Cameron also could cite commissioning, testing and adjustments to production because of safety to downplay the impacts of the downturn, according to Feer. Cameron’s second train began producing in December and is expected to begin operations by the end of March, while the third train has a targeted in-service in the third quarter.
“There are a lot of upward and downward tolerances built into these contracts,” he said.
The market also hasn’t considered how vessel rates impact the supply chain, Feer added. Rates are low as the common duration of contracts has shrunk dramatically. “When things get sloppy and prices start falling, no one wants to be the guy that charters at $60,000/day and then two weeks later, it’s at $37,000/day.” There are a lot of moving parts for someone to make a serious commitment to go in and take ships, he said. “Nobody quite knows how this is going to shake out.”
The key to any positive momentum for the LNG market is Europe. The continent has a large wholesale market and a lot of demand, sparked in part by fuel-switching capabilities in the power sector. It also has ample storage and regasification infrastructure that make it both an attractive market and one of last resort when there’s nowhere else to dump cargoes.
Cheneire management in the year-end earnings call noted that “Europe absorbed almost all incremental supply added in 2019 and reached record quarterly import levels” in the fourth quarter.
The continent has become even more important as the coronavirus outbreak in China, and now other parts of North Asia, has forced ships to divert to other destinations or float with LNG aboard as they wait to unload.
European storage levels are high. While winter is almost over, Hitch said it’s still difficult to gauge how much demand the continent may see in the coming weeks or to predict any supply disruptions from more traditional sources like pipelines. If European storage is brimming as shoulder season gets underway, and it gets fuller faster, the continent’s ability to take in gas later in the summer could be limited, making U.S. gas susceptible, he said.
European gas storage levels were 48% higher than the five-year average for February, according to the U.S. Energy Information Administration. Moreover, from April through November 2019, 55% of U.S. LNG exports went to Europe.
“Last year, storage filled around September, October. We’re looking at August this year,” Feer said.
In the worst-case scenario, if U.S. cargoes prove uneconomic to lift later this year, don’t expect a doomsday situation. For starters, terminals wouldn’t be mothballed, as it’s technically challenging to shut down trains and just as complex to restart them, Leconte and others said. Furthermore, all the feed gas that’s being used by the facilities, anywhere from 8-9 Bcf/d recently, wouldn’t easily find a near-term home in the U.S. market, which is also awash in supply.
What’s more likely are terminals running at lower utilization rates and periods of prolonged maintenance. Not necessarily an ideal situation as it could push already low U.S. prices even lower. Theoretically, though, that would reopen the arbitrage spread for U.S. exports.
“It’s one of those things where everyone is going to end up learning how flexible their plants are,” Feer said.
Redmond estimated that U.S. exports could be cut by anywhere from 10-15% at some point over the summer, or what she said represents the volume of U.S. LNG capacity that’s not currently under long-term contracts. She added that “you could see aggregate feed gas flows at less than 90% of capacity if say one terminal is undergoing maintenance while others may be sending fewer cargoes due to lack of profitability for spot cargoes.”
Whether those volumes would be enough to push down U.S. prices if they’re forced back into the market is another question. For example, the additional trains scheduled to come online at Cameron and Freeport later this year are secured by long-term contracts that, along with other factors, could keep the U.S. gas market in check and help support prices.
“Even after making those adjustments for maintenance and maybe less spot cargoes going out, that LNG feed gas demand is still around 8 Bcf/d,” Redmond told NGI, adding that gas consumption is also expected to continue growing in the U.S. power sector. “We’re also really keeping an eye on gas production, which we’re pretty much expecting to stay flat for the rest of this year, and maybe even see some declines compared to the highs we saw late last year.”
Shah also is optimistic. U.S. power burn “has been intense” in the low price environment, with the EIA’s recent storage inventory data reflecting that trend. “We see this summer being very tight. To date, winter power burns have been 3 Bcf/d higher year/year,” Shah told NGI. “We’re going to see a rapid depletion of storage this summer.”
Meanwhile, China is expected to begin issuing waivers in March for tariffs placed on U.S. LNG cargoes. While the coronavirus casts doubt over near-term demand, Shah said China’s commitment to buying more U.S. energy will be back loaded to the latter part of 2020. “China will have to start making that up fast, and LNG will be a large part of it.”
The United States shipped 30 LNG cargoes to China in 2017, and another 26 in 2018, but that figure fell to only 3.5 (one was a split cargo) in 2019 because of trade tensions, according to U.S. Department of Energy data.
As the implications of the coronavirus remain unclear, so too does the timing of a price recovery in the LNG market. Analysts appeared to be divided as to whether the market has even reached a bottom, and most see prices being slow to recover.
“We’ll get a pretty good clue in the March, April, May period as to how bad it’s going to be,” Feer said.
As the market gets into the summer months, Shah opined that tightening U.S. natural gas fundamentals may alleviate concerns of U.S. LNG shut-ins. With domestic prices continuing to get whacked — the April contract plunged around 10 cents on Thursday — there is even more pressure for a producer response, he said.
Other factors abroad are less clear. Norway-based Equinor SA deferred production for the second half of 2019 at the Troll natural gas field in the North Sea, but the question is whether it extends the constraints this year, according to Waddell. Meanwhile, Algerian supply to Europe is already around minimum tolerances, so it’s likely difficult to fall much further year/year.
Russia appears willing to keep pipeline gas flowing heavily into a weak European market to maintain market share and for cash flow, Waddell said. “Prices would have to fall further to make it uneconomic for Gazprom to export.”
Outside of Europe, some of the market is “tightening around the edges,” according to the analyst. Thailand is considering reducing production in favor of taking spot LNG cargoes, and Egypt may ask international oil company producers to cut output as the Egyptian Natural Gas Holding Co. cannot make money from selling on the spot market at these low prices. Heavier maintenance at certain facilities may also cut some LNG supply, Waddell said.
Nevertheless, “there is little on the demand side which could substantially drive up LNG prices this year, particularly as we approach the end of the northern hemisphere winter,” Waddell said. “The support is mostly likely to come from European pipelines.”
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