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Page added on February 18, 2017
Can Other Oil Basins Ever Catch Up To The Permian’s Prosperity?
While many exploration and production (E&P) companies hustle to buy diminishing available acreage in the Permian Basin, other basins are lining up to the be next play that cashes in on $50-plus oil.
Increasingly, the rig count bears out the possibilities. Although the Permian remains the leader in rig addition, others are showing signs of life. For the week ending Feb. 3, RigData reported another 33 rigs bringing the total to 707 rigs in U.S. service. Of those 33 new rigs, two were activated in the Midland and eight were added in the Delaware areas of the Permian. But outside of the Permian Basin, Eagle Ford added seven rigs and Haynesville added four.
“Both the Eagle Ford and Haynesville saw nice jumps in activity [week over week] and have actually put more rigs back to work over the past month than the Midland cluster,” analysts at Tudor, Pickering & Holt wrote in a note to investors, adding, “Keep an eye out to see if this trend continues going forward.”
Driving much of the interest in other plays is the high cost of acreage in the Permian. Recent deals in the Eagle Ford were priced close to $16,000 per acre, but in October, RSP Permian bought Permian acreage in the Delaware region for an estimated $48,000 per acre. And prices could go higher, said Darin Turner, Invesco Ltd. managing director and portfolio manager.
“I could see somebody paying above that,” Turner said. “That can be very location specific [within the Permian], but we wouldn’t be that surprised to see a higher land cost.”
A key reason the Permian remains a hot buy at $40,000-plus per acre is that profit can be made even when oil is $30 per barrel, according to both analysts and E&Ps. But the West Texas play might not be the only basin with a low breakeven cost. In fact, the powerhouse Permian production might be no more economic than Oklahoma’s SCOOP and STACK plays.
“We think the SCOOP/STACK today is [profitable at] low $30 economics as well,” Turner said.
Companies have been drilling into the Permian for almost 100 years. As such, they’ve learned a thing or two about how best to coax the hydrocarbons. Commercial potential of the SCOOP was found in 2011, and in the STACK, just two years later – indicating there’s a significantly longer learning curve.
“There’s just been a lot more trial and error in the Permian, and we would say the SCOOP/STACK is much earlier on in its life,” Turner said. “And what you generally see is that as more drilling occurs, the operators start to understand the most efficient way to proceed with their drilling, so you can generally see costs coming down just because of expertise getting better.”
But even among the plays that aren’t the Permian, there are economies of scale.
“When we think of the Permian versus the Eagle Ford or versus places like the Bakken, we still believe the Permian is in such a better place than those basins,” Turner said. “Our view would be you need to see oil move significantly higher … mid-$60s … before you would start to see capital truly move away from the Permian to the Eagle Ford or to the Bakken.”
At the end of year, Ethan Bellamy, senior analyst at R.W. Baird & Co., said 2017 may be the year of other basins’ uprising.
“Everyone loves the Permian, but we think 2017 will see a renaissance in lesser-loved areas as rig productivity changes the profitability equation and as assets change hands to new, better-capitalized owners,” Bellamy said. “Keep your eye on the Haynesville, for example, that was once written off as dead. Watch for export markets and asset turnover to re-ignite the Eagle Ford.”
Indeed the Permian led global deal-making with $20 billion in transactions last year. That accounted for one-quarter of all mergers and acquisitions (M&A) activity for the year, according to Wood Mackenzie.
And that’s despite the increasing price tag on Permian acreage. Data from East Daley shows that acquisition prices in the Permian have returned to – and in some cases, exceeded – prices during the height of the shale revolution. Four Permian deals averaged roughly $29,000 per acre in 2014. While most of 2017 is still at hand, deals within the last year have exceeded $40,000 per acre. And in more recent months, M&A is still trending close to $30,000, according to East Daley’s data.
But the cost of getting into the Permian – prohibitive perhaps for some companies – has provided an unexpected consequence for lesser plays, said Justin Carlson, vice president and managing director of research at East Daley Capital Advisors. For example, this year Exxon Mobil Corp. has doubled its Permian exposure while Anadarko Petroleum Corp. divested its Eagle Ford assets in a sale to Sanchez Energy Corp., which has been amassing acreage in the South Texas play.
“Permian growth has been good for some of the Tier 3 basins, meaning that the larger producers are focusing on the Permian and shifting away from some of those other basins – freeing up cash flow by selling those assets. And smaller operators are coming in and picking up those assets and starting to drill on that acreage,” said Carlson. “Permian growth has actually indirectly caused growth in some of the less lucrative areas.”
8 Comments on "Can Other Oil Basins Ever Catch Up To The Permian’s Prosperity?"
James boags on Sat, 18th Feb 2017 8:00 am
Rigporn Nuf said
rockman on Sat, 18th Feb 2017 8:33 am
“A key reason the Permian remains a hot buy at $40,000-plus per acre is that profit can be made even when oil is $30 per barrel”. We are at least a couple of years away from proving or disproving that for the AVERAGE well. It will certainly be as true for some wells as it will not be true for others. Probably many others just as there were many Eagle Ford wells that didn’turn a profit when oil was $100/bbl.
And even a very few that would have lost money even if oil had been $1,000/bbl. LOL.
Nony on Sat, 18th Feb 2017 10:11 am
1. I don’t believe the Permian overall grows at $30 oil. Status quo is probably low 40s. At least that’s what the most recent production numbers imply (little tricky to tell because of lags in timing, but something like that). Just watch the rig counts. There are lags because of contracts, but if price drops again and rigs start dropping, that tells you people can’t find projects that work at the new price (en masse and on the margin; there will always be some projects even at $30, but I suspect few of them).
2. The Haynesville is a dry gas play. It makes no sense to compare it to the Permian. One is affected by a regional gas price. The other by World oil prices. Very different. The Haynesville could care less if oil were to hit $25 if gas were at $5 for example!
3. DAPL will make a big difference to the Bakken. Marginal barrel could see a $9 improvement in price realization because of lower differentials ($12 transport cost dropping to $3 transport cost). Getting a better wellhead rice will enable more production. I wouldn’t count the Bakken out. It has nicer rock (little more of a conventional reservoir in the thin middle section) than the EF/AC at least. Lower decline, better EUR.
CrudevsCondensate on Sat, 18th Feb 2017 3:53 pm
The shale production is still mostly condensate.
I received a reply from Rockman that about 350,000 barrels a day are used to blend with bitumen but that still leaves more than 2.7 miliion barrels a day unaccounted for. It also does not explain the proportions of the lightest hydrocarbons like ethane and propane that are not liquid at ambient conditions. As I understand blending too much condensate will lead to undesirable characteristics like pre-ignition. The point is that refining the condensate takes more energy then refining crude oil and therefore condensate should not be classified as oil. As the supply of conventional crude diminishes the EROEI will also decrease.
rockman on Sat, 18th Feb 2017 6:24 pm
CvC – You make some interesting claims. But IMHO for credibility you should post some links supporting those suppositions. For instance:
“…but that still leaves more than 2.7 miliion barrels a day unaccounted for.” Accounted for how??? The latest govt numbers (Nov 2016) show 5.4 million bbls per day of oil and refinery products were exported. Add that to the oil and refinery products being consumed domestic: where do those 2.7 mm b/d show up “unaccounted for?
“It also does not explain the proportions of the lightest hydrocarbons like ethane and propane that are not liquid at ambient conditions.” Again you’ve lost me: ethane and propane from WTI, Brent and every other oil on the planet containing those lighter chains are not liquid at ambient conditions.
“As I understand blending too much condensate will lead to undesirable characteristics like pre-ignition.” Are you referring to “pre-ignition” of motor fuels? Regardless of how much condensate is in an oil blend that is refined the final product (gasoline of diesel) have no footprint in the fuel.
“The point is that refining the condensate takes more energy then refining crude oil and therefore condensate should not be classified as oil.” First, as already explained, everyone in the fossil fuel extraction and refining industry consider condensate to be crude oil. The Texas Rail Road Commission (the regulators in the largest oil producing state) classifies condensate as oil. In fact the classification isn’t based on the composition of the oil but its physical state (liquid vs gaseous) in the reservoir. You’re certainly free to not call condensate oil but there are a million+ oil patch PROFESSIONALS that would disagree with you. LOL. Also condensate, just like heavier oil, in general is not refined. Oil blends, often a combination of condensate and heavy oil, typically have a very narrow gravity range of 31° to 33° API. US refineries are opitimized to crack such blended oils. Just some friendly unasked for advice: lots of info on the www about refining you might want to study.
“As the supply of conventional crude diminishes the EROEI will also decrease.” The EROEI is not dependent on the composition of the oil. In fact, as a result of the oil prices crash the EROEI of all oil prospects currently being drilled (regardless of the oiol’s gravety) has increased. I suspect you’ll not understand that FACT. But I’ve explained many times before so I’ll skip it now.
CrudevsCondensate on Sat, 18th Feb 2017 6:51 pm
I was referring to the fact that of the 4 million barrels a day of shale production 70% is condensate. You mentioned that about 400,000 barrels a day are used to dilute bitumen. If another 400,000 barrels a day are refined with heavier oils that still leaves 2 million barrels of condensate, which should not be included in the oil production numbers Doing so is highly misleading. If the ERoEI of the entire process from the mining of bitumen to the production of condensate and the heavy oils to the refining process and finally the finished product is significantly less for condensate then condensate isn’t even the equivalent of oil much less oil.
Nony on Sat, 18th Feb 2017 7:38 pm
The condensate whining is tiring. 46 API oil sells for more than 26 API. The funny thing is the peak oil whiners all claimed the oil would be too heavy in 2008. And now we are swamped with WTI. HAHAHAHA!
Steve on Sat, 18th Feb 2017 9:16 pm
“according to both analysts and E&Ps”
There you go. The two groups of shalie touts that have led to one of the greatest misallocations of capital in history. Shale to date has been a commercial failure. Analysts are pumping so their firms can sell shares and debt for the shalies. E&P’s will say anything to bring money in.
Sorry, but it is highly unlikely that shale breaks even anywhere at $30/barrel. The snake oil selling needs to stop!