The Permian Basin remains resilient in spite of the pullback in domestic onshore activity, with more active rigs than any other major U.S. play combined, a positive sign for the bulls when the upturn begins.
The play, which extends from West Texas into northeastern New Mexico, remains resilient because of the “competitive economic metrics” of the wells that are drilled in the sweet spots, according to a review by Rystad Energy. The “most lucrative” areas today are in the northern part of the Midland sub-basin of Texas, mostly on the border between Midland and Martin counties, as well as the area on the borders of New Mexico and Texas in the Delaware sub-basin.
Drilling efficiencies in the Permian have evolved, keeping the legacy play ahead of the pack as well costs continue to fall and estimated ultimate recoveries continue to increase, Sanford Bernstein’s Bob Brackett, Andrew Pizzi and Jackson Kulas said in their analysis.
“The Permian Basin is the last large arena for oil production growth in the U.S. for four powerful reasons,” according to Bernstein. “It has demonstrated it can grow, it has demonstrated significant inventory, it is in a region of low geopolitical risk, and, at its best, it has powerful economic returns.” Because of those reasons, many exploration and production (E&P) companies are able to invest and achieve growth a returns. Bernstein estimated that “at least” 27 publicly traded E&Ps and integrated operators have significant exposure to the basin.
The shale revolution began in natural gas in other places across the United States, but the evolution clearly has ended in the Permian, Brackett said.
“The U.S. added nearly 4 million b/d of oil from the beginning of 2011 with more than half of the growth coming from Texas, with North Dakota’s Bakken a strong silver medal,” he said. “However since the collapse in oil price, the U.S. has moved from growth to decline. And the rapid growth in Texas has rolled into declines. But if we split Texas into the Permian and non-Permian (e.g., Eagle Ford, Barnett, Granite Wash, etc.), we can see that the Permian has remained fairly resilient to falling price.”
The Permian’s resiliency matters, as it is “a fifth of U.S. oil production and has turned around production after falling substantially over the last several decades, and from wells that average barely 10 b/d.”
Brackett and his colleagues used the beginning of 2011 as a division between legacy production and unconventional growth. The legacy Permian, vertically drilled for decades before unconventional drilling took hold, was estimated at 0.5 million b/d from less than 5 b/d wells, while Permian growth since 2011 comprises 1.5 million b/d. “Simple math” illustrates the point. Since 2011, legacy and vertical/non-horizontal growth has held 1 million b/d flat, while there has been 1 million b/d growth from horizontal drilling.
“In summary, the Permian is big, important, and has been growing in a time when others are struggling to stay flat,” Brackett said.
BofA Merrill Lynch Global Research made similar points in a note on Friday. Efficiency is improving across all basins, but the Permian “is the only shale play where output is still growing year-on-year,” based on data by the Energy Information Administration (EIA). In its latest Drilling Productivity Report, EIA said it expected Permian output to fall slightly in June from May to 2.017 million b/d from 2.029 million b/d (see Shale Daily, May 16).
By contrast, the Bakken Shale is facing year/year output declines of 17%, while the Eagle Ford Shale is expected to see a drop of 24% and the Niobrara formation should be off by 20%.
“The reason for such a production discrepancy between the various basins seems unrelated to the number of rigs being shut down,” BofA said. “Looking at the oil rig count, declines have been relatively similar across the major shale basins during the past two years. Yet productivity trends have diverged tremendously, with the Permian Basin showing the most dramatic improvements.”
Well productivity gains still are ongoing in some onshore basins. Initial production (IP) rates increased by 5% a year between 2009 and 2014, BofA said. In 2015, IPs averaged 16% from 2014 levels and to date this year, average growth has leveled off at around 8%. However, in the Permian, IP growth rates to date are 31% higher from the same period of 2015 after averaging 27% higher year/year in 2015 and 18% higher in 2014 from 2013.
A Permian cash flow model completed by Tudor, Pickering, Holt & Co. found that the basin should be able to hold production flat within cash flow at $52/bbl, which is down from an earlier forecast of $55.
Lower costs to drill and produce mean the Permian should be best positioned in the price recovery, BofA analysts said.
“Looking at the one year cumulative production for an average well in the main plays, the Eagle Ford continues to provide more barrels than other plays. Yet while Eagle Ford gained 67% since 2009, cumulative production for an average well in the Permian expanded 160% over the same period.”
BofA analysts estimated that overall, it is going to take on average five to nine months for U.S. unconventional output to respond significantly to price changes. However, with the Permian experiencing the most dramatic improvements in productivity — despite fewer rigs and less money spent — output should begin to increase soonest in the basin, while it could take “twice as long in other areas.”
Wells Fargo Securities LLC analysts noted the optimism of Permian operators during their recent first quarter conference calls.
“Our view is that as Permian operators climb the relatively steeper learning curve and high-grade acreage it will translate into further cost savings perpetuating this efficiency trend and, judging by earnings commentary thus far, we get the sense there is potential cost savings on the service side as well,” Wells Fargo analysts said in a note last month.
For example, Permian-focused Diamondback Energy Inc.’s management still views the play as early stage.
“I think the remarkable thing about the Permian Basin…is that we’re almost a basin that’s perpetually in the third or fourth inning,” Diamondback CEO Travis Stice said during a conference call in early May. “And that’s because there’s just so much hydrocarbons in the stack column that things like technology improvements, horizontal drilling, fracking technologies, all of those things perpetually bring you back in the third or fourth inning.”
Anadarko Petroleum Corp. onshore E&P chief Darrell Hollek said in May that “in all cases we’re pretty excited,” about the Delaware, where the company has planted its biggest flag. The EURs “are definitely picking up, but so are the GORs,” the gas-to-oil ratio. “I think over time it’ll prove that [the Permian] will increase our oil percentage as a whole in the U.S., particularly for onshore…”
Delaware well costs have declined to about $6.2 million a well, and “I can tell you that that’s better than we thought that we’d be doing at this point. And so it gives us pretty clear line of sight to the $5.2 million when we get to a pad drilling situation, so we feel really good about that.”
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