Permian Basin crude oil production is forecast to reach 5.4 million b/d in 2023, more than current production from any single member of the Organization of the Petroleum Exporting Countries (OPEC) except for Saudi Arabia, IHS Markit said Wednesday.
Natural gas also is expected to double from 2017-2023 — up 116% — to 15 Bcf/d, while natural gas liquids (NGL) should climb 105% to 1.7 million b/d.
West Texas and southeastern New Mexico crude output, already a factor in global supply growth, is likely to increase by nearly 3 million b/d between 2017 and 2023, a level of growth exceeding most recent estimates and up 116% over six years.
Nearly 41,000 new wells and $308 billion in upstream spending between 2018 and 2023 are forecast to drive the gains, a “stunning” figure that would comprise more than 60% of net global output growth over the timeframe, researchers said.
“In the past 24 months, production from just this one region — the Permian — has grown far more than any other entire country in the world,” said IHS Markit Chairman Daniel Yergin. “Add an additional 3 million b/d by 2023 — more than the total present-day production of Kuwait — and you have a level of production that exceeds the current production of every OPEC nation except for Saudi Arabia.”
The Permian production outlook draws on information from the company’s proprietary Performance Evaluator database, which includes information of more than one million global wells.
Despite the $308 billion price tag, which is sharply higher than the $150 billion spent from 2012 to 2017, access to capital should not be the primary challenge for Permian production in the coming years. Among other things, the outlook also sees wells operating with positive cash flow, unlike prior years.
Researchers anticipate a market where oil prices stay around $60/bbl or higher. In that price scenario, only delays in necessary infrastructure, rather than the availability of upstream investment, are seen as representing the biggest potential challenge.
“The infrastructure challenges in the Permian illustrate a fundamental mismatch between upstream oil producers and midstream players,” said IHS Markit’s Jim Burkhard, head of crude oil markets. “The former are focused on fast growth while the latter require sustained high utilization of infrastructure over decades for projects to be viable.”
The Permian outlook factors in the assumption that logistical bottlenecks will occur, causing, for instance, some wells to be deferred to the second half of 2019. However, robust production growth is expected even with constraints.
“Far from a ”best case’ forecast, the IHS Markit outlook applies realistic scenarios and anticipates likely bottlenecks,” said Executive Director Raoul LeBlanc, who is head of the Performance Evaluator. “That the outlook still expects the Permian to exceed existing (and already lofty) expectations speaks to the region’s unique and growing prominence to the world oil market. The level of growth, from 0.92 million b/d in 2010 to 5.4 million b/d in 2023, is truly stunning.”
IHS Markit assumed that upstream cost inflation would be roughly 33% by 2023 relative to 2017 levels. Net upstream cash flow from 2018-2023 is estimated at more than $47.5 billion.
Regarding pipeline capacity, researchers assume the region would see a 2.5 million b/d expansion in crude oil capacity, and an 8.0 Bcf/d expansion in gas pipeline capacity. About 7 Bcf/d of additional gas processing capacity also is expected by 2023 to handle liquids-rich output.
Researchers also estimate U.S. crude exports, driven by the Permian, increase from 2017-2023 to 4 million b/d from 1.1 million b/d.
In addition, “decelerating production growth” is forecast in the early 2020s because of high capital investment requirements and assuming “little productivity improvement.”
Growth is not guaranteed, Burkhard noted in a blog post that accompanied the report.
“The Permian’s reach may have gone global, but local factors will still determine the score as to whether it meets its full potential. In this case, the urgent challenge is the need for more pipeline takeaway capacity.”
The indicator of the need for more infrastructure is the price differential between West Texas Intermediate (WTI) at the Midland hub in West Texas and Light Louisiana Sweet (LLS), priced at the St. James, LA, trading hub.
“Since late May, WTI crude oil at Midland has been priced $17-20/bbl less than LLS,” Burkhard said. “As recently as March the price difference had been just $3/bbl. So, why the drastic change? Pipeline capacity for transporting Permian crude has become very tight and more expensive alternative means of transport were needed to pick up the slack. Higher transportation costs mean that WTI at Midland needs to be priced lower to compete with other crudes on the coast.”
While the region has several refineries, total capacity is limited to about 600,000 b/d, and the remainder has to be shipped to various end markets.
“There is also a larger dynamic at play,” he said. “The current infrastructure squeeze in the Permian illustrates the mismatch between upstream oil producers seeking fast growth and midstream players that need sustained high utilization of infrastructure over decades.
“This is not the first time such a dynamic has led to price discounts. The same has occurred at times in other areas, such as the Bakken in North Dakota and Appalachian gas.”
Even Midland price dislocations aren’t new. “From 2011 to 2014, Midland prices regularly fell anywhere from $15/bbl to as much as $40/bbl below Gulf Coast prices as incremental pipeline capacity lagged,” Burkhard noted.
“This latest period of very tight or insufficient pipeline takeaway capacity and Permian pricing weakness looks like it could be especially lengthy, potentially lasting the better part of a year.”
Adding oil and gas takeaway capacity “is key to the Permian realizing its growth potential — and adding the equivalent of ”Kuwait’ to the U.S. oil production system.”
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