Qualifying "Tiers" Is ALL About Economics
Two weeks ago, I used Novi's own data and its charts to show you that based on its determinations of remaining Tier 1 /2 locations in the Midland Basin... at $70 WTI, there were only 4 years left of economical wells left to drill. I stand by that. 100%. Today's oil prices are crowding $57 WTI. People who should be telling America the truth have been saying U.S. tight oil is now going to stay on a long flat plateau. No way.
Drilling in the Midland is no longer economical. Travis Stice was correct when he said that very thing leaving Diamondback. He was spot on.
I have posed the question as to the definition of Tier 1 /2 remaining locations based on actual, full cycle well economics and I am going to publish something next week showing you that because of poor well economics and increased need for immediate cash flow, 3 and 4 mile laterals have now become an integral part of the definition of "Tier." Rock quality never defined Tiers, it was always economics. That is precisely why it is incorrect to even be considering Tier 3/4 goat pasture in the future. Nobody can afford to go out there. That is why most of the sector is still high grading in its best areas even with up to 40% degradation values. Their well productivity is falling (defined by EUR) but its still better than way out in the sticks.
Today is Friday and another press release from Novi, for me an almost uncanny one that sounds very familiar.
This is a chart showing different levels of imaginary degradation between parent and child, Tier 1 and 2 level wells in the Midland Basin. Degradation is a term for pressure depletion caused by over drilling on too close a spacing. The worse the interference between wells, the higher the degradation and new wells drilled in close proximity will produce less oil, their economics will be worse. I wrote about this very thing a few weeks ago. Almost to the t.
Now, we ought to get to the nut cuttin' as we say in the cow business. Create an algorithm to show us where, and how many locations there are for three and four-mile laterals. They are more cost effective to drill and complete, something analysts incorrectly call "efficiency." They produce significantly greater IP180's (but not greater EURs) and the more money the sector can get back from drilling a $12 MM well in the Midland Basin the fastest, the better.
In fact, at today's prices the Permian sector can only hope to breakeven and the faster they can breakeven, or get most of their CAPEX back, the longer they can stay afloat and live another day...hoping for higher oil prices, lower well costs, or much, much better wells.
Hope is not a plan but it's all they've got.
Great oily stuff Mike. You've been on top of this the whole way. How frustrating that the banksters have managed to keep the game going by continuing to fund and roll over debts on uneconomical projects. It would be far better to let nature take its course.
But, the reason I am wring this morning is because I am not easily shocked by shale patch data, being pretty familiar with the subject. But somehow I did not know this factoid buried in the latest Goehring & Rozencwajg Q3 commentary (emphasis mine):
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In 2018, the Permian was adding nearly 100,000 barrels a day each month—an annualized pace of 1.1 million barrels, a figure that meant nearly one out of every two new barrels of global supply was bubbling up from a handful of dusty counties in West Texas. By 2023 however, its growth had noticeably slowed.
Sequential growth slowed to 45,000 barrels a day, or 550,000 on a yearly basis. Then came October 2024, the peak. Since then, the basin has been shrinking at an average clip of 35,000 barrels a day, 250,000 in total. The question is inescapable: what explains the slowdown between 2018 and 2023, and the decline that followed?
A natural place to begin is with the rig count. In 2018, the Permian averaged 465 rigs; by 2023, capital discipline had whittled that number down to 335, and since October 2024 it has averaged 298. On the surface, that would seem explanation enough. Yet the production story does not yield so easily. Over the same span, operators managed to double the number of wells drilled per rig-month, from 0.9 to 1.8. The paradox is plain: with nearly forty percent fewer rigs, companies were drilling thirty percent more wells each month.
The wells themselves were almost a third longer than they had been, which meant that in aggregate, lateral footage drilled each month since October was seventy percent higher than in 2018. In short, the rigs had not grown lazy; if anything, they had become far too efficient to explain the slowdown.
The real culprit lies in falling productivity of the rock downhole. Between 2018 and 2023, new production per lateral foot slipped by five percent, and in the wells drilled since October 2024 it has fallen by another five.
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Wait!! Hold up there partner...you mean to tell me that the shale boyz are drilling 70% MORE lateral feet per month than in 2018, but gross output has declined from 100 kb/mo to nearly zero?!
I'm no petroleum/reservoir engineer, but even I can decipher that data set.
"We're there."
Mark it down.
And $57/bbl is only going to accellerate the decline process as capital and talent are released...and given a current 500 kb/mo natural decline rate across the shale plays the production declines will almost certainly surprise to the downside.
My only remaining question is, "How much longer will the EIA continue to fudge the data so as not to piss off Trump, using, I presume, BLS statisticians to help hide the reality?"