I assume by four main Permian "plays" Mr. Berman means four main benches, like the Lo. Spraberry, Bone Spring and Wolfcamp A and B. If production in the Permian is plateauing, its "rolling over." From growing like a house 'a fire since 2014 to going flat 2H24, thats "rolling over." Depletion doesn't happen over night, it happens over time. Whatever; lets don't start changing definitions again, please. That bullshit is getting old.

"Base + core" means current legacy production plus Tier 1/2 level locations left to drill in the core areas = 5 more years of plateau at current production rates. Core areas are Midland, Martin, Lea, Eddy counties, etc. Base + noncore means legacy production plus Tier 3/4 flank stuff, like Culberson, Pecos, Reagan and Glasscock counties, etc.

Actually this is not Berman's chart it's a chart from a paper written in 2021 by three University of Texas Petroleum Engineers, Wardana Saputra, Wissem Kirati and Tadeusz Patzek, Dr. Patzek is a man I have heard lecture several times, NOT a stripper well operator. and very smart. The paper is titled Forecast of Economic Tight Oil and Gas Production in Permian Basin, published in 2021. It can be found in SPE publications or MPDI. It was a good paper except it made some very incorrect assumptions about well economics. OIl prices today are the same as 2021, well costs, however, are up 30%. More on EUR assumptions, below.

From the paper itself...

As previously mentioned, in 2021 this paper clearly assumed well productivity and EUR's were going to increase because of longer laterals and more proppant loading per peforated foot.

From the paper:

"The newer wells yield significantly higher EURs due to longer laterals and bigger hydraulic fractures. However, in areas of poor reservoir quality, these advancements of completion technologies do not help much;"

With regard to EUR's, Berman himself concluded a year ago that longer laterals and more proppant loading per perforated foot had reduced the average EUR's in the Permian Basin by +/-25% the previous 4 years. Given the exponentially higher decline rates of longer laterals and in new frac designs (73% in the Midland Basin at month 13), I concur with this. Short term production went up but, then declined quickly, implied EUR's are falling.

With regard to the remaining number of wells to be drilled over the next 5-6 years to maintain a plateau, at current rig counts the Permian can only complete approximately 5,200 wells per year. Gassy oil wells are turning into oily gas wells and first year declines have increased since 2018-2019 at 47% to over 73% in 2024, basin wide. Costs are going up (25% tarriffs on steel!), profits will be going down. The Permian shale oil sector can only support a rig count of 300 without other people's money; it is adding more debt to the nine figure debt it already has just to pay dividends to investors. If FANG buys Double Eagle for $6.5B, its total long term debt will be a knat's ass below $20B and it will be paying close to a B a year in interest.

To the casual observer the Permian HZ play is doing fine and can keep 300 rigs running, no problem; I personally do not think so. If so, why all the M&A's? Past results are NEVER indicative of future performance in the oil and gas business.

For the record, current Permian production is 6.3 MM BOPD as a result of a massiive number of DUC completions in 2023 and big six month production numbers from longer laterals, more densely populated staging along that lateral and much bigger frac's. The annualized decline of that legacy production (6.2 MM BOPD) is 43%, or 2.58 MM BOPD. To maintain a plateau the Permian has to find and replace 2.58 MM BOPD, every year, for the next 6 years. That's a new 700 MM BO oilfield, per year...as big or bigger that lots new structures being found in Guyana off the east coast of South America !

And as to remaining drillable, Tier 1/2 locations in the cores, a big contention of the Saputra paper is infill drilling. I am not buying that, particularly in the Midland Basin where wells are already drilled on <600 foot spacing, GOR is threatening bubble point in entire counties (Midland, for instance, Martin, next!) and wells are interfering with each other. I therefore do not believe 35,000 additional wells can be drilled in the next six years that will add another 16-17 billion barrels of UR to current Permian totals...it will take many more wells than have previously been drilled.

We always drill and complete the best stuff first; its naïve to suggest the last 55,000 HZ wells drilled in the Permian will be better than the first 55,000, longer laterals or not. Look at at TRRC GIS map and find room for 2,000, 15,000 foot laterals in Permian Tier 1/2 cores. You can't do it. The greater efficiency, better technology sound bites are clearly proving to be just that, sound bites. That technology bullshit is getting REALLY old.

The heart of the Permian Basin watermelon has already been eaten. Henceforth new wells will be gassier, less liquids productive, be more expensive to drill and complete, have lower EUR's and be even less profitable, if that is possible. The amount of long term debt the Permian has to pay off, and the retirement/decommissioning of existing wells, pads, infrastructure and fee land is still in access of $200 B.

Where is all the money going to come from to keep drilling these expensive, marginally profitable wells?