The massive expansion of liquefied natural gas (LNG) export capacity along the Gulf Coast from a proposed second wave of projects could create volatility for prices without additional pipeline buildout to capture production from major supply sources like the Permian and Appalachian basins, and $5 gas is “not out of the question” during periods of high demand, according to analysts.
More than 40 Bcf/d of so-called second wave LNG projects have been announced, with Venture Global LNG Ltd. sanctioning Calcasieu Pass LNG last month and Cheniere Energy Inc. moving forward with a sixth production unit at its Sabine Pass terminal in Louisiana. Additional final investment decisions are expected before the end of the year.
However, most of the projects are concentrated along the Texas and Louisiana coasts and removed from many of the major supply regions of the United States.
“If you look at the availability of pipeline capacity today, it’s pretty thin,” said BTU Analytics’ Tony Scott, managing director of analytics. “That creates bottlenecks to serve LNG exports.”
To be sure, the Energy Information Administration (EIA) in its most recent Drilling Productivity Report said gas production is expected to increase in September in five of the seven most prolific unconventional plays. The Appalachian Basin is expected to lead the way with a projected 32.61 Bcf/d versus 32.24 Bcf/d in August. The Bakken Shale is set to grow to 2.95 Bcf/d from 2.94 Bcf/d, the Haynesville Shale to 11.32 Bcf/d from 11.19 Bcf/d, the Denver-Julesburg/Niobrara formation to 5.62 Bcf/d from 5.57 Bcf/d and the Permian Basin to 14.86 Bcf/d from 14.62 Bcf/d.
Meanwhile, the Eagle Ford Shale’s gas output is expected to decrease slightly, to 6.73 Bcf/d from 6.75 Bcf/d, and the Anadarko Basin is set to decline to 7.51 Bcf/d from 7.56 Bcf/d, EIA said.
However, the availability of firm pipeline capacity to move those molecules to an expanding fleet of LNG export terminals along the Gulf Coast is becoming “harder and more expensive” to secure, according to BTU. As more terminals are sanctioned, there will be a continued need to aggregate supply from farther supply basins.
To The Max
One of the key constraints that has developed in the last couple of years is in getting incremental supply from northern Louisiana to the Gulf Coast. Production growth from the Haynesville and strong demand pull from existing LNG facilities has left existing pipelines running almost to the max, according to BTU.
“This corridor has just under 9 Bcf/d of capacity and through the summer, we’ve been sending over 8 Bcf/d between the two regions,” Scott said.
Prices have already begun to reflect the bottlenecks, with Columbia Gulf Mainline basis weakening over the last two years. Columbia Gulf averaged 10 cents below Henry Hub in 2017, but a year later, that discount blew out to 14 cents, NGI historical price data show. So far in 2019, Columbia Gulf has averaged 17 cents below the benchmark.
While the Haynesville may not grab the headlines that other onshore basins do, the play continues to surprise analysts, including Goldman Sachs, since rig counts have remained “robust” despite gas prices below $2.75.
RBN Energy attributed the ongoing growth in the play to enhanced drilling techniques and a focus on the region’s “sweet spots”, with volumes climbing to more than 11 Bcf/d from less than 6 Bcf/d in late 2016.
“The play has attracted renewed interest and focus from a new slate of players who have steadily improved drilling efficiencies and economics there,” RBN analyst Jason Ferguson said.
Nevertheless, Chesapeake Energy Corp. has already reduced activity in the play, and Comstock Resources Inc., the Haynesville’s No. 1 operator, plans to release one or two rigs in the near term to ensure it can hit its free cash flow target in 2020.
The looming downturn in Haynesville activity can be risky for proposed pipelines connecting northern Louisiana to the Gulf Coast. Tellurian Inc. is seeking to build the 200-mile, 42-inch diameter Haynesville Global Access gas pipeline that would feed its proposed Driftwood LNG terminal.
“We are concerned about the potential runway in the Haynesville,” Scott said.
But RBN COO David Braziel said the Haynesville may continue to surprise as it has in recent months. “The Haynesville is an elastic basin because it doesn’t have the liquids content. To the extent there was a sustained gas price rally, it could ramp up rather quickly.”
Haynesville production in January 2017 was at only 5.4 Bcf/d, according to RBN. By mid-2019, production had risen around 4.5 Bcf/d. “The Haynesville has a tremendous capacity to add production in a short amount of time,” Braziel said.
Farther east, stranded associated gas volumes from the Permian Basin, which have led to an unprecedented plunge to minus $5.75 at the Waha hub, have slowly begun making their way to the Gulf Coast.
Kinder Morgan Inc.’s Gulf Coast Express is set to begin full operations later this month, while NAmerico Energy Holdings LLC’s Pecos Trail pipeline, which would deliver gas into Cheniere’s Corpus Christi LNG Header system, has a scheduled in-service for sometime this year. Kinder’s Permian Highway Pipeline is due online in the second half of 2020, and the midstreamer is considering a third line, Permian Pass, that also would connect to the Gulf Coast.
“Between all the proposed projects, there is so much capacity that would move gas between the Permian and Gulf Coast that we don’t anticipate getting gas out of the Permian will be a problem,” Braziel said.
Appalachia Pitching In
Nevertheless, Cheniere has been securing supply for Sabine Pass and Corpus Christi terminals from as far away as Appalachia. In addition to contracted capacity on traditional long-haul pipelines like Transcontinental Gas Pipe Line, Cheniere began utilizing the Rover Pipeline to bring Marcellus gas to the facility in 2016. The company is also developing the Midship Pipeline, a 1.44 Bcf/d system under construction to bring Oklahoma supplies to the Gulf Coast.
Freeport and Cameron LNG have followed a similar path in securing gas, and Venture Global is applying a similar strategy in securing “the little bit of spare pipeline capacity that’s left,” according to BTU.
As more bottlenecks emerge, there is an increased risk to basis and outright Henry Hub prices, the firm said. If pipeline development were to fail to keep pace with the second wave LNG buildout, “$5 gas is not out of the question,” Scott said.
There are still opportunities to get incremental production between Appalachia and the Perryville Hub in North Louisiana. Natural Gas Pipeline Company of America (NGPL) has some spare capacity, and the pipeline, which in addition to the proposed second phase of its Gulf Coast Southbound project, has proposed a nearly 0.5 Bcf/d expansion to feed Sabine Pass, with Cheniere signing on to capture that available capacity and more diverse sources of supply.
“But that supply and capacity, in particular, is limited. For basins like the Fayetteville and Oklahoma to participate, additional infrastructure projects are needed,” Scott said. “First movers on securing pipeline capacity may be at an advantage than those who take a slower path, one that’s reliant on marketers or producers to bring them supply.”
Meanwhile, the regulatory process itself has become a bottleneck for some proposed pipeline projects. Both designed to move Appalachia gas to Southeast markets, the Atlantic Coast and Mountain Valley pipelines have become the poster children for extreme regulatory setbacks as greenfield infrastructure projects in the Northeast continue to face strong grassroots opposition.
Even for projects like Midship and Cheyenne Connector that have been relatively innocuous from a public perception perspective, there have been delays at the federal level. Cheyenne’s proposed timeline had called for construction to begin this summer, with in-service in October. The pipeline’s developers cited Federal Energy Regulatory Commission inaction as the reason for in-service pushback to early 2020.
“We think as time continues to move on...that environment likely only becomes more and more challenging, so delays and cost overruns may become more of an issue over time,” Scott said.
BTU expects the average pipeline cost/mile to jump to as high as $15 million in 2020-2021 from less than $3 million in 2014.
“You’re seeing cost escalations even in projects that are nearer to home in less arduous terrain,” Scott said. “New pipeline projects will likely cost $7-8 million/mile to build across the marshes of Louisiana and to the extent they are interstate pipelines, there is risk to the timing of those projects versus the timing of the export projects, and certainly in cost over time.”
To be sure, Kinder management has touted its vast Texas network to link growing supply and demand markets in the state. On Permian Pass, which is not yet part of the backlog, CEO Steven Kean said, “We can bridge the two and connect to our premier Texas intrastate pipeline network and stay entirely within the state of Texas, where we have more commercial flexibility.”
As part of its three-pronged Tellurian Pipeline Network, the Driftwood LNG developer is also proposing the Permian Global Access pipeline, which would feed its not-yet-sanctioned terminal in Calcasieu Parish, LA.
“Where those projects land on the Gulf Coast will dictate the winners and losers of second-wave LNG projects and their ability to access that supply,” Scott said.
Meanwhile, with associated gas production from the Permian expected to remain strong, there is plenty of appetite for those pipelines and more, according to BTU.
“The Permian is running chockablock full,” Scott said. “At a minimum, 3.8 Bcf/d of additional pipe capacity from the Permian, beyond Gulf Coast Express, Permian Highway and Whistler, should be built targeting the Texas/Louisiana border of the Gulf Coast.”