Multiple oil pipelines are preparing to carry more of the Permian Basin’s roaring production to faraway markets, but capacity issues remain for liquids and in particular for natural gas, which could lead to a complete gas blowout by this fall and require flaring or shut ins, according to analysts.
Analysts have been sounding the alarm about Permian takeaway issues for months, as gas and oil price differentials widen. However, to date, there appears to be little pullback by producers in West Texas and southeastern New Mexico.
“There’s no doubt the oil and gas industry has hit its bottom and bounced back with the Permian Basin leading the way,” said Drillinginfo’s Bernadette Johnson, vice president of market intelligence. However, the Austin, TX-based firm also sees “takeaway capacity nearing its limits in the Permian and constraints could have consequences for some. Some will thrive while others will barely survive.”
There is a plethora of oil, natural gas and natural gas liquids (NGL) takeaway solutions on the drawing board.
However, according to Sanford C. Bernstein & Co. LLC, only a handful of oil and NGL projects have been sanctioned in the past six months, including Epic Pipeline Co. LLC’s crude oil and Y-grade liquids lines, as well as Cactus 2 Pipeline, Gray Oak Pipeline LLC and Energy Transfer Partners LP’s NGL conversion plans.
“It now feels crystal clear to investors that neither trucking nor rail represent viable cure-all solutions for Permian oil takeaway bottlenecks, so it seems a question of when (not if) Permian exploration and production activity growth stalls to allow infrastructure to catch up to the cadence of well construction and completion programs in the basin,” said analysts with Tudor, Pickering, Holt & Co. (TPH).
Said East Daley Capital (EDC) analyst Justin Carlson, “Despite Brent crude oil prices recently eclipsing $80/bbl, Midland prices have traded about $15 behind Houston and Houston has traded about $3 behind Brent. Similarly, Midland is trading about $10 behind Cushing. It’s hard to believe Midland was trading at a premium to Cushing in February of this year.”
EDC’s team had warned in March that the “impending wave of production” that is going to hit the market was going to significantly change the takeaway balance.
“A market that has been oversupplied with takeaway capacity for years is now short capacity and midstream companies are scrambling to get Permian production to market with growth projects,” Carlson said.
On the gas side, only Gulf Coast Express, which would move output to the Texas coast, appears to have enough commitments to move forward. However, Enterprise Products Partners LP and Energy Transfer last month formed a joint venture to resume service on the Old Ocean gas pipeline in North Texas, idle for about six years, also to carry more supply to the Gulf Coast from the Permian Basin.
Current oil and gas production forecasts suggest temporarily insufficient capacity “for all the coming production, leading to a bottleneck when getting products to the market and basis blowouts,” said Bernstein analyst Bob Brackett.
The widening differentials for Permian oil and gas likely is indicative of a lack of takeaway options.
“The marginal barrel, with an $11 differential, is likely moving by rail already, a few months earlier than we had expected,” Brackett said.
The inability to solve the Permian gas pipeline takeaway could imperil production post-2020, according to Bernstein analyst Jean Ann Salisbury. Analysts recently determined that Permian associated gas could be strong enough to supply all U.S. demand in the 2020s.
“Our bearish gas outlook is heavily driven by our expectation for Permian production to triple to 2025,” Salisbury said. “We would need six new pipelines (costing $2 billion and 2 Bcf/d each) built by 2025 in addition to Gulf Coast Express to meet our forecast.”
RBN Energy LLC contributor Housley Carr, who has been tracking Permian NGL takeaway, said with liquids output rising and available capacity shrinking, advanced projects by midstream operators could, if built on their current schedules, roughly double the 1.2 million b/d of effective takeaway capacity in place today within the next 18 months or so.
“Much of the planned capacity is backed by long-term commitments from Permian producers anticipating continued growth in production of crude and NGL-rich associated gas, especially in the play’s Delaware Basin,” Carr said.
NGL Output Up 25% In Eight Months
Permian NGL production, including ethane rejected into natural gas, has increased to about million b/d today from around 800,000 b/d last September, a 25% gain in eight months.
RBN’s mid-curve forecast scenario, which is based on crude and gas prices similar to current forward curves, “projects that Permian NGL output will grow to more than 1.1 million b/d by the end of 2018, 1.3 million b/d a year later and 1.6 million b/d by the early 2020s,” Carr said.
The Permian already had substantial NGL capacity before unconventional development began to torch the region. “But a number of the NGL pipes out of the Permian also move barrels from other basins, either inbound flows from the Rockies or volumes added downstream of the Permian in the Eagle Ford and Barnett shales,” Carr noted.
“In addition, the vast majority of the Permian’s incremental NGL production is occurring in the Delaware, which had only a limited number of pipes and suddenly needs more.”
Also factoring in is ethane rejection, with about 100,000 b/d now being rejected. Ethane rejection in 2019 could fall to minimum operational levels as demand increases from steam crackers set to come online along the Gulf Coast and from ethane exports, Carr noted.
“The effective end of material ethane rejection in the Permian will boost the total NGL volumes that need to flow out of the play (mostly to the NGL fractionation and storage hub in Mont Belvieu, TX), putting additional pressure on pipeline takeaway capacity between the Permian and the Gulf Coast,” he said.
Several Permian producers during first quarter conference calls touted agreements to ensure there’s a home for their oil and gas. Bernstein’s team took a deep dive on the subject, compiling data based on presentations, conference call transcripts and filings.
What they found is that about half of the Permian producers had firm transport commitments for close to 53% of 2018 gross oil production and 48% of 2018 gross gas production. Most of the remainder of the output is going to be sold to buyers that have secured takeaway in one form or another. Close to 16% of oil and 11% of gas is not directly tied to a form of takeaway.
“Even with takeaway capacity, the final destination also makes a difference for price realizations,” Brackett said. Analysts also looked at the basis hedges by the Permian producers.
Oil basis hedges averaged around (0.94) on 460,000 b/d, and gas basis hedges averaged (0.66) on 400 MMcf/d.
Jefferies LLC analysts, in their review of Permian crude basis differentials, said near-term basis volatility is impacting realizations and project returns, but “we still see basis-exposed project returns holding in well, given the strength in benchmark crude.”
Weathering The Storm
Jefferies analyst Mark Lear said some Permian operators are insulated from basis risk because of secured firm transportation agreements, but some that aren’t still appear able to weather the storm.
“That said, there still remains uncertainty on how many Permian operators will navigate the tightening infrastructure environment through the first half of 2019, and as such, we think there are good opportunities to play the bullish oil macro environment outside the Permian,” Lear said.
In a sample of project returns for Jefferies covered operators that work the Bakken and Eagle Ford shales and the Denver-Julesburg Basin, returns in many cases were “as good, if not better, than the Permian in the current pricing environment.”
PLG Consulting President Taylor Robinson, whose firm provides industrial logistics and supply chain solutions, outlined in a blog post for RBN the transportation issues on the ground. Permian producers and shippers are considering “every possible option for moving incremental barrels out of the play, including two old short-term standbys: tanker trucks and crude-by-rail.”
Cost isn’t a major issue as the price spread and low breakevens in the Permian should justify higher expenses associated with trucking and rail, he said.
“But that doesn’t mean that badly needed truck and rail capacity can appear with a poof as if by magic. No, even wads of cash may not be enough to quickly round up the hundreds — thousands? — of trucks and drivers that would be required to make a significant dent in the Permian’s takeaway shortfall.”
Developing more crude-by-rail terminals takes a year or longer, “too much time to address the play’s more immediate needs.”
Many trucks now hauling crude are owned/leased by locals, whose small fleets likely are working “flat-out already,” said Robinson. There also are limits about how many trucks could be available to be moved from other regions.
“Then there’s the driver issue,” he said. “There’s already a severe nationwide shortage of drivers,” which by some estimates is about 60,000 short across the United States, “and the Permian has been hit particularly hard, largely because of the need for drivers to haul the ever-increasing volumes of fresh water and fracture sand being used in well completions and produced water emerging from producing wells.”
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