Permian – update through July 2018

This interactive presentation contains the latest oil & gas production data from all 17,140 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through July.

Output has continued to rise fast in the first half year, adding over 400 thousand barrels of oil per day from horizontal wells. The apparent drop in July is as usual due to incomplete data. As the graph above shows, more than 75% of oil production in July came from the ~5.7 thousand wells that started since the beginning of 2017.

Natural gas production from these wells is also trending higher, and has now passed 8 Bcf/d.

The “Cumulative production profiles” plot in the ‘Well quality’ tab reveals the steadily increasing well performance in the past couple of years. Since 2016 this performance has increased just slightly. The average well that started in 2016 recovered ~200 thousand barrels of oil in the first 2.5 years (30 months) on production.

This area counts many operators; the top 3 operators, Pioneer Natural Resources, EOG & Concho Resources, produce together just 23% of total production.

The ‘Advanced Insights’ presentation is displayed below:


This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started.

Over the past 5 years, laterals have increased by almost 50%, while proppant loadings more than tripled. This has greatly affected well productivity, as you can see by the ever higher recovery trajectories. But based on preliminary data, it appears that the proppant per lateral foot ratio has slightly fallen in Q2 this year, as lateral lengths increased faster than proppant usage. You can analyze this in more detail in our ShaleProfile Analytics service.

Recent wells are on average on track to recover just over 300 thousand barrels of oil, before their rate has dropped to 20 bo/d (which for most operators is probably still an economical production rate).

Early next week I will have a post on the Eagle Ford, followed by one on all 10 covered states in the US.

Production data is subject to revisions.

Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations.

For these presentations, I used data gathered from the following sources:

  • Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests and oil proration data.
  • OCD in New Mexico. Individual well production data is provided.


The above presentations have many interactive features:

  • The above presentations have many interactive features:
  • You can click through the blocks on the top to see the slides.
  • Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.
  • Tooltips are shown by just hovering the mouse over parts of the presentation.
  • You can move the map around, and zoom in/out.
  • By clicking on the legend you can highlight selected items.
  • Note that filters have to be set for each tab separately.
  • The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.
  • If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.


  • Mike Shellman says:

    “Recent wells are on average on track to recover just over 300 thousand barrels of oil, before their rate has dropped to 20 bo/d (which for most operators is probably still profitable).”

    That is NOT going to cut it. Most Permian producers are now getting paid in the mid to low $50’s on an un-hedged basis and after all costs are deducted from a barrel of oil it will take plus 400K BO for today’s well…just to reach payout. How then is all that old legacy debt going to be paid back from todays more productive wells when the majority of them will struggle to reach payout? Answer: its not.

    Arguably the largest “pure” Permian oil producer in the basin, Concho, after paying over $8B dollars for RSP, LOST $199MM 3Q2018. If things were rocking in the Permian they would be paying down debt as fast as they could. They can’t.

    If I were remotely associated with lending the US LTO industry new money, or in the loop for refinancing old debt, there are two things I would do henceforth, ASAP: 1.) I would require 3rd party, independent reserve audits to see if these shale guys even have the reserve assets anymore to loan money to and 2.) I would set aside the investor presentation crapola and sign up immediately for’s full array of analytical tools. After knowing what these wells are actually producing, as opposed to what the shale oil industry wants you to THINK they are producing, the arithmetic is very simple. Its not working. Productivity is not the same as profitability.

    1. Seth brooks says:


      Shaleprofile, Drillinginfo, RSEG and others all suffer from the same problem. Everyone is “guessing” what the actual production is on a per well basis since Texas data is reported at the lease level.

      Amazon, has been losing money for the last few years as they build scale, how is LTO players like Concho any different?

      CAn you imagine where oil prices would be if its wasn’t for LTO industry? $150/bbl.

      LTO has filled the demand gap over the last 4 years on average of 1MMbl/d, without that we would be in serious problems with oil prices.

      1. Enno says:


        Thank you for your comment. I just want to respond to the lease-issue in Texas.
        Although it is of course a challenge (and a fun one!), I do think that in most cases it is possible to make a reasonable estimation of the production of individual wells in Texas.

        There are a couple of reasons for this:
        – There is quite some information that we can and do utilize, like the exact start and end times of wells in leases, incl. the exact well completion date. Also well tests, pending lease production (which is on well-level, and not on lease level), proration data, and well inactivity data.
        – We currently cover horizontal wells in Texas since 2008. There are ~41k leases with horizontal wells, and these leases contain ~67k wells (incl ~50k horizontal wells). This means that the ratio of wells to leases is in general rather small, and there are in fact many leases with just 1 or 2 wells on it, in which case the puzzle is not complex. Of course there are exceptions, and especially in the Permian there are some leases with over 100s of wells, in which case it becomes more challenging to do an accurate job.
        – The shape of the production profile of a shale well (high peak, followed by a steep drop), makes it more easy to identify the different contributions from individual wells on a multi-well lease.
        – Although there are cases where we may somewhat misallocate production between wells, at least all oil & gas production gets exactly allocated, so on an operator basis it should still exactly match.

        Again, not saying it is easy (luckily, otherwise I would not have started with it), but with the right methodology it is definitely possible to make some good sense out of the data.

        Several operators/people with knowledge about actual well production in Texas have told us that we do a pretty good job in general. We aim to add more improvements in the near future. Furthermore, in our paid analytics service we will make soon dashboards available in which we can show exactly how we have allocated the lease production over the individual wells.

    2. Enno says:

      Thank you for your comment Mike. Your insights into well economics and oil & gas finance are always much appreciated.

      I also slightly changed the related sentence in the post, to indicate that the production rate of 20 bo/d is probably still economical (I didn’t want to say that the 300 kbo recovery by then were already profit-making)

  • Mike Shellman says:

    Seth, I am fortunate to have worked with Enno a little on TRRC reporting matters in Texas, on “pending” files, for instance, where production is filed under drilling permit numbers awaiting actual W2 related lease numbers, and on analyzing well head W10 tests for individual wells. I think Enno’s data is amazing and very reliable. If you are implying that wells are actually far better than reported to the TRRC, or that newer, higher productivity wells (that cost more) are getting lost in a bunch of older, lousy wells on multi-well units or PSA’s; I do not accept that. Enno has a good handle on Texas production.

    The US shale oil industry is a decade old; its been building “scale” the entire time and finding all kinds of ways to cut corners, reduce rig time and costs; like pad drilling, zipper frac’ing, water gathering, mining its own sand, etc. etc. It has not worked from a business standpoint and the shale oil industry is not deleveraging its massive long term debt. If you believe that an even higher level of mass manufacturing of shale oil wells is the ticket to its ultimate success; I do not accept that.

    Borrowing money to manufacture an asset that declines in “value” at the rate of 28-15% annually until it is worthless requires careful planning and fiscal responsibility. That has hardly been the case. The shale oil industry is now painted itself into a corner it can’t get out. As it’s production grows prices are now declining, again, and the shale oil industry is set to shoot itself in its other foot.

    The oil industry, trust me, does not give a rats ass about its “contribution” to society. It is in for the money, that’s all. As are lenders from New York City into the shale oil industry, and cheerleading for it, to make money. This argument that its OK to be over $300 billion in debt, with $100 billion already lost, and still growing debt, all for the economic wellbeing of our country… is a bunch of hooey. Let the shale industry get out of debt and stand on its own two financial feet, without credit, and provide America with cheap fuel, then I’ll cheerlead for it too. Big time.

    Enno, in the Permian anyway, given produced water issues, 16-20 BOPD may indeed be reaching economic limits.

  • John Morris says:

    Hi Enno, I noticed that the number of wells in a group seems to stay the same, even though its likely that some wells are abandoned and eventually plugged as they develop issues, or are depleted. Sometimes the average production for a group is down to less than 10 bpd, even though I would think that was below the economic limit. Do those low averages actually reflect that some of the better wells in the group may still producing say 20 bpd while others produce zero to average 10.

    1. Enno says:

      Hi John,

      That is exactly correct. Wells do not drop out of the equation once they are abandoned/plugged, as that would cause survivorship bias. And indeed typically there are large differences in production rates for wells that are part of a group that produces on average very little.

      One way to see that for yourself is as follows: Go to the ‘Well quality’ tab in the first presentation, and use the filter to only select a year with such a low average production rate. Then group the wells by a more granular dimension, e.g. ‘Well’ (which will show you the profiles for all individual wells), or ‘Month of first flow’. You will then be able to see in more detail how this group was build up.

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