None of the above had a damn thing to do with drill baby, drill...

and the price of gasoline has gone up, not down...

Now that the oil goes down the shale folk recognised they peaked. They want to bring the price back: https://www.zerohedge.com/commodities/we-are-tipping-point-shale-giant-diamonback-says-us-oil-output-has-peaked-slashes-capex

Click to read

Its difficult for me to follow this line of reasoning as it pertains to shale oil. Across an entire spectrum of well inventory there are 20 BOPD wells nearing eonomic limits at $50 oil prices, 100 BOPD wells and new 900 BOPD wells declining at the rate 6% per month. More than half of America's shale oil production comes from wells that make <40 BOPD and loads of water on artificial lift. Half of those wells are now below economic limits at $50 0il prices. If they break downhole, they will not get fixed. P,A&D liaibility goes up exponentially when prices are near $50.

Every BO extracted is burdended by corporate overhead, dividend costs and debt... old, middle aged or new born. Stop drilling new wells and the cost burden of legacy wells increases as they assume greater responsibility for costs and liabilities. You can't fix that; it is what it is. If you stop drilling new wells in the shale biz you are sliding into the abyss.

The shale oil sector loses money drilling new wells below $70, IMO. It muddles thru that with cash flow. But when cash flow gets whacked 30% things get bad, fast. The company has to reconfigure itself, change its model, tell its investors no mas on dividends, try to amend loan covenants at the bank, change drilling committment clauses in OG&M leases, cut staff, cut overhead, cease the stupid buyback programs, drop rigs, break more TRRC rules, sell shit, defer plugging, stop R&D, suspend recyled water projects, flare more gas in lieu of expensive tie-ins, downspace and keep kicking the debt can down the road for another day.

The financial health of the shale oil sector is NOT determined on the economics of individual wells. That seems to be part of what I don't understand about today's financial engineers and internet analysts.

And if one thinks these things eventually blow over and everybody goes right back to there old selves, nothing gained, nothing lost. No sir. Look at what happened post 2020 COVID. The only basin that really recovered was the Permian but that was four years and 25,000 wells ago; its not the same basin.

The breakeven metric has done little other than to create more confusion in an otherwise very confused public. It was designed to raise money, I suspect, by conning investors into believing any price over $53, or whatever the breakeven de jour is, is profit.

Again, are you really profitable while your still in debt? If you had to personally guarantee that debt I promise you'd feel differently about it all.

Objective Well Economics

By stuff people send me, including final well costs (different than AFE's) I consider these costs in the chart above roughly 10% lower than reality. And this was before tariffs and trade wars increased the cost of tubulars, which I don't have a handle on yet. So I suggest a typical Midland Basin well to cost $10MM with three strings of casing, 12,000 feet of lateral, and no problems, which is rare.

I choose to ignore "tie in" costs mentioned in this chart as most wells drilled in the Midland Basin are infill stuff on existing units with massive tank batteries and treatment facilities already in place and requiring only several hundred K to lay flowline, electricity or gas make up for gas lift, etc.

What I choose NOT to ignore is "land costs." Lots of internet experts consider leasehold, or land costs, sunk. So they are conveniently ignored in the economic analysis. I guess, however, that 65%-75% of wells being drilled in the Midland Basin now are on acquired acreage in an M&A, like Exxon and Diamondback, for instance and on a per location basis those M&A's have run leasehold costs back up to $4 MM each per drilling location (Enverus). Each M&A contains compensation for existing production, deeply discounted; most of the value is in drillable locations, something the Permian Basin is running out of. Assuming each acquired drilling location has two benches that can be accessed from the same acre of land, total full cycle well costs in the Midland Basin are pushing $12-$13 MM each. And likely to go higher with steel costs.

Above, the $4.5 MM number was about the same Diamondback paid Endeavor.

If one reasearches leasehold costs on a corporate K, or Q, one will find that that leasehold costs are lost somewhere in non-GAPP cyber space, as are infrastructure costs for water systems, water treatment systems, what few there are, electricy systems etc. that service many different units and wells in those units. SEC filings have become useless, almost, unless you want to take days to dig the real numbers out of the dung heap. Its like big government.

Anyway, I am sticking with $$12-13 MM per well. If the M&A is an all stock deal, shareholders are getting hosed and this is a sort of cost that has to be paid back, right?

Damn straight.

The difference in breakeven prices and well head oil prices (NYMEX less, transportation and marketing costs, generally $3/$4 per BO) is net back. Or, the profit per BO produced. Divide that profit per BO by well costs and you find how many barrels that well has to produce to payout. It is not rocket science; EBITDA, or discounted cash flow (NPV) or ROCE and all that hooey is just noise. Money spent v. money returned. Only those people wanting to fool you, or con you, complicate it.

So I suggest you use whatever breakeven you want, Novi's bullshit, or Rystad's bullshit, or my bullshit, get the net back price and divide that into well costs. Then go find us Midland Basin wells with those kinds of EUR's, that will produce enough oil over their 14 year life span to pay drilling and completion costs back.

You won't.

It's already started. Lower oil prices are good for the economy, too low is almost worse. Erasing reserves due to the price again. Funny though it won't all come back when prices shoot up. Inventories are low world wide, there won't be much cushion on the other side. Wells are going to get plugged, and all the small guys kicked in the nuts again.. we need the smaller firms, they keep big boys honest.

One third of first quarter 2025 Trump was not even in office yet, the other two thirds of the quarter the price went down $10 a barrel, mostly baked-in declines from him coercing the KSA and rest of OPEC into production increases. It was not until the beginning of April, or the 2nd quarter, did tariffs and trade wars drop the the price of oil another $10 a barrel, $20 all toll in the first 100 days of office.

1Q25 production revenue in the Permian Basin and other U.S. shale oil basins was paid for from 2024 budget allocations and wells that were drilled and completed in shale basins in 2024. 1Q25 earnings have nothing to do with the current state of affairs. Like bringing Ballyhoo on line recently in the Gulf of Mexico, discovered in 2018, has nothing to do with drill baby, drill policies.

Below $60, nobody makes enough money in the shale oil business to stay on the drilling hamster wheel, pay dividends, service debt, pay down debt and rack back for well retirement. Nobody. So, we haven't seen anything yet. Lets wait an entire quarter of low $60's, and tariffs on casing, tubing and DP (almost all drill pipe comes from China), then see what those earnings are, and how many rigs get sent to the barn.

For a sector that has a PDP reserve to production ratio of 3.25 years, maximum, and essentially lives had to mouth from cash flow anyway, often having to borrow to pay dividends to shareholders, this is going to get really ugly.