The long-term outlook for natural gas is mostly bright, but two shale plays in Texas and Louisiana have two very different tales to tell when it comes to investing in infrastructure to support a possible upturn while commodity prices remain low.
In the Eagle Ford of South Texas, there is excess capacity in the system, but Gulf Coast projects at Corpus Christi, Texas, primarily designed to handle Permian Basin oil production, will also carry Eagle Ford volumes.
The Haynesville in the Ark-La-Tex Basin of East Texas and western Louisiana, however, is weathering the low prices with more expansions of gathering systems, transportation pipelines and processing facilities to handle future production as 100 drilling rigs work the land.
Eagle Ford tiers
The take on the Eagle Ford from analysts at Wells Fargo Securities is that the play has excess capacity for crude at least through 2025. What’s more, breakeven prices by efficiency are in tiers there, with $61 a barrel (bbl) in Eagle Ford West, $50/bbl in the central segment, and about $39/bbl in Eagle Ford East.
“The potential for a global economic slowdown, the U.S.-China trade war and geopolitical instability could keep oil and natural gas prices rangebound, muting the near-term outlook for U.S. hydrocarbon export growth,” Wells Fargo analysts predicted in a recent report. “Given this backdrop, we expect U.S. crude, natural gas and NGL production growth to moderate. While increased volumes and higher cash flows for midstream companies positioned in growth basins should still materialize, the overall growth trajectory is more muted.”
Analysts at investment banking company Stifel Financial said that even though natural gas prices have been well below past years’ $3 per million Btu (MMBtu), gas rigs operating in the combined Marcellus and Haynesville shales have been steady at 100 or more in 2019.
The Eagle Ford had only nine natural gas rigs throughout the year and 58 oil rigs, Stifel reported. By comparison, more than 440 oil rigs operate in the Permian.
“Volumes aren’t growing. They’re pulling their reins in because of the commodity price,” said Joel Moxley, a longtime midstream executive, who recently joined the GPA Midstream Association as president and CEO. “Midstream’s health relies on upstream’s health.” (See interview with Moxley in this issue.)
Moxley said flat volumes in the Eagle Ford mean things have been slowing down for midstream, and any new infrastructure projects that might have been planned are on hold. What’s more, operators are taking Eagle Ford revenue and pumping it into the Permian and other hot areas.
A different story
“The Haynesville is very much a different story. Volumes are growing,” Moxley said. Volumes from the Haynesville are at a new all-time high, surpassing a previous high from about five years ago that necessitated a buildup of midstream assets to get it to market, he said.
As of September, Haynesville natural gas production was 11 billion cubic feet per day (Bcf/d) and is forecast to hit 14 Bcf/d by 2025.
He said that Haynesville producers may be so active, even at $2.35/MMBtu and less, because the cost of drilling is lower than before, much of the infrastructure is already in place, and the play’s mostly dry gas decreases processing costs. The Haynesville also is closer to markets than the Eagle Ford, which lowers costs even more, he said.
However, “The Eagle Ford is already connected to all this export capacity,” so it is positioned to move significant volumes if strong natural gas prices make a return, he said. “Capacity usually comes on in large chunks, but demand takes some time to come up.”
Forecasts from Enverus (formerly Drillinginfo) put Eagle Ford oil production up to 1.49 million barrels per day (MMbbl/d) in 2020, compared to 1.43 MMbbl/d in the third quarter of 2019. Natural gas production from the play is expected to dip in 2020 to 6.82 Bcf/d from 6.87 Bcf/d in the third quarter this year.
Many existing pipelines and processing facilities in the Eagle Ford (and Austin Chalk) and Haynesville are nearing the end of their dedication contracts with producers, which could mean a reduction in revenue off the assets, unless the gap between excess capacity and supply narrows, Moxley said. The legacy agreements, however, will have paid for the infrastructure by the time they expire, and midstream services could go cheaply to keep the pipeline full, he added.
Gas infrastructure projects in the Eagle Ford abounded in 2014 and 2015, with the latest projects completed in 2017, according to data compiled by Hart Energy’s Stratas Advisors. Stratas noted just one processing project associated with the play in 2019: Aspen Midstream LLC’s processing plant and gathering system in Giddings Field.
Dallas-based Aspen expects to complete the project by the end of the year, a company spokeswoman said. The plant, treating facility and 90-mile system of gas gathering 10- to 20-inch mainline in Giddings will take advantage of the stacked plays including the Austin Chalk and Eagle Ford across six counties. The cryogenic processing plant can handle up to 200 MMcf/d. A residue gas pipeline runs to the Katy, Texas, market hub.
“We believe our system’s proximity to premium markets for both NGLs and natural gas takeaway will allow our producers to realize better netbacks and compete economically with other basins,” Aspen CEO James Clarke said when the project was first announced. In all, the system has long-term dedications with several producers across a 150,000- acre area.
While many pipeline and processing projects focus on easing the bottleneck from an influx of Permian crude oil for export, they also are prepping for potential future volumes from the Eagle Ford.
Howard Energy Partners, a San Antonio company with 215 miles of lean-gas gathering line with a capacity of 1 Bcf/d in Webb County, Texas, has entered a joint venture with Juno, Fla.-based NextEra Energy Partners. NextEra has a 150-mile pipeline from LaSalle County, Texas, to the Aqua Dulce gas hub.
Agua Dulce link
Combining its Eagle Ford assets means Howard’s tie into NextEra’s 30-inch and 16-inch transportation lines creates an option to expand capacity on the gathering system, said Howard Energy’s chairman and CEO Mike Howard. The producers get a direct link to Agua Dulce and access to emerging markets in Mexico and the Texas Gulf Coast.
NextEra president Armando Pimentel said the venture gives the company organic growth in the Eagle Ford with a minimal capital investment by increasing the use of its Eagle Ford midstream system. The joint venture is based on future contracts committing to the use of both systems, so it doesn’t have any influence on existing contracts and revenues.
Another Eagle Ford project on the books is the first phase of a water gathering system from EVX Midstream Partners LLC. In September, the company announced it had completed more than 300 miles of large-diameter water gathering systems. EVX CEO Herb Chambers IV said the systems’ rapid expansion has allowed the company to contract with most producers operating in the Eagle Ford.
NuStar Energy LP is building another 600 Mbbl of storage space, bringing capacity at its Corpus Christi terminal to 3.9 MMbbl when completed in December. It is accompanied by the completion of a connection from the Plains Cactus II pipeline to the NuStar terminal to facilitate Permian crude transportation.
Eagle Ford volumes, however, are still very much in the long-range planning for the San Antonio-based company, ranked No. 24 on this publication’s Midstream 50 list of the sector’s largest publicly held companies.
The continued growth of the company’s South Texas crude system “is once again experiencing throughput at near the historically high levels we saw in the Eagle Ford’s heyday in 2015,” said Brad Barron, president and CEO, when the latest projects were announced in September. The export terminal is “handling the leading edge of the impending wave of Permian long-haul crude oil. And we expect continued growth for both Permian and Eagle Ford barrels going forward.”
Corpus Christi LNG
Also in Corpus Christi—with an eye to creating more export capacity— Cheniere Energy commissioned Train 2 at its liquefaction plant. Between Corpus Christi and its Sabine Pass location on the Louisiana Gulf Coast, Cheniere and Bechtel Oil, Gas and Chemicals Inc. had substantially completed a total of seven processing train units for LNG by the end of the third quarter. Deliveries will begin in May 2020 to several countries, including Spain, Indonesia, Australia and France.
This gives Cheniere another 600 MMcf/d of liquefaction capacity. All told, the top LNG producer and exporter will have a capacity of 45 million tonnes per year.
Freeport LNG has launched an expansion at its export terminal in Brazoria County, Texas. A loan of more than $1 billion from Australian private equity firm Westbourne Capital will allow Freeport to build a fourth processing train while Trains 2 and 3 are still under construction. The first three units will have the capacity to produce as much as 15 million metric tons of LNG a year. Trains 2 and 3 are expected to come online in January and May of 2020. Train 4 would add another 5 million metric tons.
Enterprise Products Partners LP, ranked No. 4 on the Midstream 50, has about $6 billion in capital projects in the works. The partnership is gearing up to process another 35 Mbbl/d with a second propane dehydrogenation plant and as many as 1.65 billion pounds a year of polymer grade propylene (PGP) at the Mont Belvieu, Texas, NGL hub, according to the company.
The primary customer of the new plant is plastics, chemicals and refining giant LyondellBasell.
Enterprise also has a second isobutane dehydrogenation, or IBDH, plant in the works. The first plant has been in operation since 1993. An expansion of the refrigeration facilities at its terminal is also in the works, allowing Enterprise to load up to 5 Mbbl/hour of PGP, as well as to load PGP and LPG on the same large gas carrier.
To supply the growing LNG needs for markets in Louisiana, Enterprise is constructing an 80-mile pipeline from outside Cheneyville, La., to other company connections near Gillis, La. The additional capacity from the Gillis Lateral, when it opens in mid-2021, and additional horsepower at its Mansfield compressor station in DeSoto Parish, La., will increase the existing capacity of the Acadian Haynesville Extension by another 300 MMcf/d, to 2.1 Bcf/d.
“The expansion and extension of the Acadian system enhances our capability to link supply to some of the most attractive markets in the U.S.,” said A.J. (Jim) Teague, CEO and general partner, in a statement. The company has a 357-mile gathering system in the Haynesville with a capacity of 1.3 Bcf/d and treatment of as much as 810 MMcf/d of gas.
A Haynesville prop
Haynesville and other Ark-La-Texas Basin plays are propping up the bottom line for some midstream companies, with revenue making up for parts of the business that are drooping.
For example, Enable Midstream Partners management told shareholders in commentary on its second-quarter financial results that its gas processing and gathering revenue segment was down about 8.4% to $587 million, compared to the same quarter last year, because of lower revenues from NGL sales and lower than average gas sales prices.
Company officials said the decreases were partially offset by several factors, including increased natural gas revenues in the Ark-La-Tex and Anadarko basins from higher gas gathering revenue and greater volumes. Processing fee revenue from those basins also was up but tempered by lower prices. Enable ranks No. 17 on the Midstream 50.
Midstream companies walk the tightrope, not just in the Haynesville and Eagle Ford, but in all of the natural gas producing regions because, while low commodity prices don’t encourage shorter term gains from infrastructure projects, the long-term global outlook for natural gas demand is strong. Producers, midstream companies and financiers operating in Texas and Louisiana shale plays have their eyes on China.
In a recent report, energy market intelligence firm McKinsey & Co. said “gas is the only fossil fuel expected to continuously rise in demand through to 2035.” Last year, China became the largest importer of gas and LNG, knocking Japan and South Korea from the top spots. McKinsey’s analysis of the data found that gas demand will rise 0.9% a year globally, with Asian demand growing by 2.1% a year.
An increase in supply of about 22.4 trillion cubic feet (Tcf) by 2035 will largely come from the U.S. The U.S. is expected to provide an additional 11.6 Tcf, with Russia and the combined African countries supplying about 3.9 Tcf each, McKinsey forecasted.
“We’ll look back at this as a milestone year, when China became the world’s biggest LNG importer and we saw the highest volume of liquefaction projects taking FID (final investment decision),” said Rahul Gupta, associate partner at McKinsey Energy Insights. “In many ways, that sets the tone through to 2035: Asian economies in the ascendancy— led by China—with growing energy demand; the U.S. continuing to rank highly for both supply and demand; but on the supply side, Europe and Asia’s second-tier economies falling away. Overall though, this is a growth story for gas and LNG.”
Travis E. Poling is a freelance writer based in San Antonio.
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