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How Many Barrels Did THAT Cost?









2022; Rystad: $29 netback @ $80


Once again, please..."breakeven" oil prices is a dumb metric to use to gain insight into tight oil well economics. It's use is designed specifically to prove to you, the non-oily person, that the difference in breakeven and the real price of oil is pure profit.

Netback is the difference between breakeven and the price of oil received at the well head, the profit margin per barrel of oil. Forget the net present value (NPV), discount rates, full-cycle, half-cycle BS...that is stuff you don't need to know.


This Rystad chart above was created in March of 2023 mostly about 2022 Permian Basin HZ wells. Incremental lift costs per BO increased in 2023 for inflationary and regulatory compliance reasons in the Permian; well productivity declined further in 2023.


When estimating the true costs of extracting a barrel of oil, some costs are fixed, like corporate overhead, dividend expense and interest on debt, some costs decline, like severance taxes (4.6%) per barrel of oil paid to the State, lift (extraction) costs per BO in high and increasing produced water wells will increase over time. Problem wells cost more money to operate. Declining oil production does not mean declining OPEX costs.


That too is complicated, and more stuff than you need to know. I don't understand the Rystad reference to drilling and completion costs of a given well in the breakeven metric. Some ANALysts determine "breakeven" based on a hypothetical two-year payout period of well costs, others on a 10% internal rate of return basis...thats all confusing as hell and designed, intentionally, to be that way. Forget that.


We just need to know, after ALL costs are deducted to get the nasty stuff out of the ground, how many dollars we are going to make per barrel we produce. So, for the sake of simplicity, lets use Rystad's $51 per BO breakeven for a typical well in the Midland Basin in 2022 and the Dallas Fed's estimate for 2024 wells, below, and average the two.


The price of WTI on the NYMEX closed at $80.06 on Friday, May 17, 2024. So if Rystad was right and nothing has changed the past 15 months, the different in breakeven prices and the actual price of oil being paid to us at our well head is $51 less $80, or $29 bucks a barrel. The Dallas Fed in March said $38-$80, 0r $42 bucks per BO.


Remember oil production is always reported in gross barrels to the 100% and royalty deductions have to be taken right right off the top. Shale R Us, LLC might make 25,000 barrels of oil from the Come to Jesus No. 12-H well in Loving County, Texas in May, but its only going to get paid on 19,500 net barrels, for instance. The rest of that oil is free to the royalty owners and the working interest, the people that pay for everything, has to belly up for that too. Royalty is a cost. [1]


2024; Dallas Fed: $42 netback @$80


Oil and gas produced from a well owned by any company, big or small, has to pay salaries, corporate overhead, from copy paper to jet fuel for company planes, parts, supplies, interest on long term debt, all incremental lift costs (OPEX) per incremenal BO including electricity, rentals, chemical costs, surface facility maintenance, down-hole maintenace weighted over a three year period including well interventions, gas lift/ESP replacements, fishing jobs, cleanouts, etc. etc., water disposal costs including, if applicable, capitalized infrastructure costs, dividends, P,A&D costs (when wells no longer make money they have to be plugged), health insurance for employees, liability insurance, regulatory compliance costs, and dividend expense.


If we're netting $35 bucks a barrel, how many barrels of oil do we then have to produce to pay for an $11,000,000 HZ well that we drilled laterally 14,000 feet into the Wolfcamp A and shoved 600,000 pounds of frac sand into?


314,000 barrels. Not too many current Permian wells declining at the rate of 75-80% the first year of production life are going to make 314,000 BO in the first 5 years.



According to Novi, the best wells in the Midland Basin were drilled in 2021 and they only made 254,258 barrels in 36 months. 2023 wells, in the chart above, are on track to have less cummulative production than previous years by month 36. The stuff you read about two year payouts is horse dookey.


So, from a money spent v. money received standpoint, like it was our own money and we were balancing the household budget, from an acual checkbook, things are pretty damn skinny in the tight oil biz. It now takes a long time to get $11,000,000 well costs back...before we make a dime of profit. [2]


The sector has to keep drilling wells one after another or it is toast. It can't borrow money anymore so it has to work from net cash flow from operations. It also, beleive it or not, has to actually pay debt back. And...it better be saving about $100,000 per well, at least, to plug, abandon and decomission its entire well inventory. If it has 1,000 wells to be plugged someday, thats $100 MM it better have saved, at least. They ain't going to get cheaper to plug, they are going to get way more expensive. Dividends paid to demanding investors is also now a "cost" per incremental barrel of oil produced. [3]


If you want to consider natural gas and natural gas liquids in all this, knock yourself out. As the Permian Basin gets gassier and gassier, prices are going down from vast oversupply and it does not help well economics much anymore. Those associated gas prices need to be above $4 per MMBTU to ease the pain. For 75% of the Permian Basin, associated natural gas is no where near that. price. [4]


If somebody tells you that the US tight oil sector is making money hand over fist at $80 WTI, they are trying to sell you something. They are conveniently leaving many costs out of the breakeven calculation and only focused on gross cash flow, calculated using unacceptable general accounting practices (NON-GAPP) and trying very hard to put lipstick on a pig. [5]







 


[1] In Texas tight oil basins, 22.5% total royalty burdens is a fair number to use, though I have seen overriding royalty burdends added to royalty that take net revenue interest down to 0.730000. Leases in Texas taken after 2015 often have 25% royalty burdens alone.


[2] After 50 years of drilling oil and gas wells with our own money my family and I use to think about how many barrels of oil something would cost, as in an unexpected household expense would solicit the immediate question...on shit, now many barrels of oil will THAT cost ?!! Now you know a typical Midland County HZ well is going to cost 314.000 BO just to reach payout. Basically, you might hope to only make $4.2 MM profit on a $11 MM investment.


[3] Typical EUR's for Midland Basin HZ wells are 434,000 BO, give or take (Novi). Back out how many barrels of oil it will cost to drill an $11MM well, multiply that by $35 netback prices, stay on the drilling hamster wheel, pay your CEO $26 MM a year, pay dividends, pay down debt and cover plugging liability and its tough way to make a living.




[4] Permian Basin natural gas prices



[5] Cash flow from legacy production is propping the US tight oil business model up and makes it appear as though things are just peachy. But remember, legacy production is declining 43% per year across the country. As long as the tight oil sector can keep drilling wells with the exact same level of productivity, one after another, like cans of Coca-Cola dropping out of a vending machine, things will be OK. When it can't, soon, things are going to get ugly very fast. The public and private sector is still over $100 B in long term debt and its facing $10 B, minimum, in upstream abandonment costs.







15 Comments


Another question about royalty/working interest revenue calculations. Is the gas volume the producer gets paid for what goes through the custody meter to the gathering system or is it measured somewhere else? I'm working up my BOE example and don't know whether to include the LUA (Lost and Unaccounted For), re-injected, gas lift, fuel, and/or flared gas in the royalty volume numbers.

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I go so far back that I remember when producers quit selling direct to the pipeline. That kicked off the arguments. The producer I worked for set up a cutout "marketing affiliate" to sell the gas to as close to the wellhead as possible, except that it wasn't exactly in marketable shape there. And we were off to the courts from then on arguing about value at the wellhead. Like you said, Texas itemizes the pieces and parts of gas disposition so I can just run it with different sets of assumptions to shed some light on how being really specific in your lease language can play out. As a gas processor though I have to say…


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Dear Mike,


I am with you all the way. My favourite for an excuse is EBITDAX. Only the oil producers seem to use use that BS term.. I much prefer you simplified explanation of the reality of oil production- large or small. Like you I have paid my way in life without much debt. I became debt free at the age of 40 and never looked back, and have not paid a cent in interest for over 27 years.


For those needing a little more information here the Youtube clip that Mike posted a few moths back on the realities of the economics of stripper wells.. The same economics apply to the big boys.


https://www.youtube.com/watch?v=fC0zvefXfeQ


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Mike
Mike
May 22
Replying to

Thank you, Stephen. Very much.


I had hoped this post would gain more attention; clearly I did not do a very good job of explaining the burdens that each of barrel of oil taken out of ground must bare...while the original investment pays out.


I am not good at understanding the shale business model, mass manufacturing wells and living off cash flow, I admit. If it takes more than three years to pay back $11 well costs, I see that as a big problem. I also see 50% rates of return over 14 year well life as a big problem. That model does not compute to me. Respectfully, it has not worked for the shale biz, IMO.


If anything I…


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Mike
Mike
May 20

Let's say, for fun, that a major, public tight oil company working entirely in the Midland Basin is $6B in long term debt and its oil production from the Basin is 300,000 BOPD, or 110,000,000 BO per year. Its mission is to deleverage all that debt, $1 B each year for 6 years. That alone will reduce its netback $10 per BO each year until that debt is gone...providing it can maintain that 300,000 BOPD for six years. In the mean time, that company is paying say, 6% interest on that debt. Thats $3.60 per BO... just interest expense. In this plan to get out of debt I have reduced the theoretical netback by $12-13 per BO the …


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Mike, I lost you at the $11M / 314k bbls paragraph. I thought the $11M DnC cost was covered already—to get to the net profit of $35, hence breakeven. Is that the point that it's not? 😮

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Mike
Mike
May 20
Replying to

Mr. Man, thank you for commenting and asking.


In my little excercise I assume the imaginary well has already been drilled and it cost $11 MM. Now every barrel that comes out of the ground from that new well is subject to royalty burdens and operating expenses like electricity, chemicals, looking at the well two times a day by a gauger, pumper, workovers, taxes....that barrel of oil has to pay for interest on debt, rent at the big office, salaries, ete. etc....all the everyday costs that keep the company floating and well producing. Those are costs born by the barrel of oil that is extracted from the new well. They have to be paid...first. All the while the new wel…


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Gonna read this again, but here in West By-God Virginia, that produced water don't haul itself...

So happy my royalty is free of PPC (post production costs) $2.o0 natty does not allow much wiggle room. Glad to see it improving.

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