A watershed year for U.S. liquefied natural gas (LNG) export capacity in 2019 could lead to changes in storage behavior in a region where a lack of transparent intrastate pipeline flow data has left market observers without a firm grasp on activity, according to analysts.
Based on planned project completions, export capacity is set to essentially double this year as more than 4 Bcf/d of capacity is expected to begin commercial operation, with the majority on the Gulf Coast.
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“This is the single biggest needle mover on the demand side of the equation in 2019,” Genscape Inc. natural gas analyst Eric Fell said.
The 2019 LNG export boom is off to a running start for leading exporter Cheniere Energy Inc., which completed two projects last year -- earlier than expected. Train 5 at its Sabine Pass LNG facility in Louisiana began producing in late October. Train 1 at its Corpus Christi facility in South Texas began producing in November.
Three trains at Cameron LNG LLC’s export facility in Louisiana, and Freeport LNG Development LP’s project on the upper Texas coast with three trains under construction, are expected to enter service this year.
A lot of the feedgas needed for the new facilities will flow through pipelines in Texas, where data isn’t as readily available and transparent as that of interstate pipelines. The murky data has perplexed some market observers about storage behavior in the U.S. Energy Information Administration’s (EIA) South Central region, which is comprised of nonsalt and salt facilities.
For example, the EIA on Thursday (Jan. 17) reported that overall South Central gas stocks withdrew 4 Bcf, with nonsalt facilities pulling out 6 Bcf and salt facilities injecting 1 Bcf. Many market observers on Enelyst, an energy chat room hosted by The Desk, had pegged a much larger injection for salts.
The previous week’s EIA report (Jan. 10) reflected a far bigger disconnect between salt and nonsalt facilities, with a 19 Bcf withdrawal from nonsalt and a 6 Bcf injection into salt caverns. During a week in December, the market was surprised to see salt facilities inject a much-larger-than expected 8 Bcf into storage.
The disconnect between market expectations and actual storage behavior has occurred as dual peaks in seasonal gas demand are becoming more pronounced as coal retirements and growth in demand from power plants is strong in the same region as salt storage facilities, according to Wood Mackenzie analyst Gabriel Harris.
“This is leading to injections far more often in the winter (and withdrawals in the summer) than in the past,” he said. “When heating degree days are below normal (as they were in recent weeks), we are consistently seeing injection in salt facilities in the winter. A few years ago, injection/withdrawals were more likely to follow a more traditional injection/withdrawal season.”
Additional U.S. LNG exports are expected to boost demand even more. The start up for Sabine Pass Train 5 and Corpus Christi Train 1 helped boost feedgas flows to an average 4.4 Bcf/d in December, after starting the year at close to 2.5 Bcf/d, according to RBN Energy.
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Most of the noise surrounding salt facilities stems from the flexibility they offer the physical gas market, as facilities can inject one day and withdraw the next. Traditional storage facilities have a firm withdrawal and injection season.
“If there was robust demand in the form of exports and marginal industrial power, the facility may still be moving large volumes of gas, but it may not show up in weekly data,” BTU Analytics CEO Andrew Bradford said.
With huge growth of residential/commercial space in the South, heating-related demand is poised to catapult even higher on any sustained cold. That would require more storage to meet both domestic and LNG export demand, according to IAF Advisors consultant Kyle Cooper.
“As long as winters are moderate, there probably is not an issue,” he said. “We have a late 1970s or 2000/01 winter, and we run out of gas unless LNG exports are suspended.”
Overall, the South Central storage picture has improved in recent weeks because of a mild period from mid-December to mid-January. As of Jan. 11, total South Central storage stocks stood at 861 Bcf, in line with year-ago levels and 136 Bcf below the five-year average. Salt inventories were at 303 Bcf, nearly 100 Bcf above year-ago levels and 27 Bcf above the five-year average. Nonsalts sat at 557 Bcf, 94 Bcf below last year and 165 Bcf below the five-year average.
However, the impact of growing exports, coupled with Mexico demand via pipelines, could lead to aggressive draws in the first quarter, Bradford said. “Our view is that by end of winter, we’re back to the five-year average at a national level.”
Still, the case could be made for more storage development, given the expected increase in LNG and Mexican exports. LNG operators using storage “makes perfect sense to me,” said EnerGnostics LLC Managing Director John M. Hopper recently. He long led projects in the Lower 48, and for the past four years or so has been working on storage projects in Mexico. The question is figuring out whether adding it makes economic sense.
Indeed, seasonal spreads following robust unconventional gas development have tightened dramatically, leaving supply area storage largely out of favor. In the Permian Basin, for example, pipelines are being built to accommodate growing supply in the region.
“Once you get Permian Highway in service, we’ll have grown production so much by 2020, that you’ll start to see Permian gas production come off a bit to more meet up with the pipeline capacity it has,” Bradford said. Furthermore, any variance of demand would likely be met by marginal supply from the Permian and marginal pipeline capacity additions, “eroding the necessity for storage development, even with LNG and Mexico exports.”
Indeed, Kinder Morgan Inc. revealed in its 4Q2018 last Wednesday that it is marketing an incremental 100 MMcf/d of capacity on the Permian Highway.