Eagle Ford - update through May 2019

This interactive presentation contains the latest oil & gas production data from all 23,030 horizontal wells in the Eagle Ford region, that have started producing from 2008 onward, through May 2019.

Oil production has stayed at a level of around 1.3 million bo/d in the first 5 months of this year, after revisions. Although not all well completions are reported yet, so far the number is lower than last year (688 vs. 809 through May).

An important reason why the Eagle Ford has been struggling can be seen in the “Well quality” tab. Since 2017, well productivity has no longer improved. Normalized for lateral lengths, well results have even slightly deteriorated.

Declines are steep in this area. Of the 17.5 thousand horizontal oil wells that came online before last year, over 10 thousand are currently producing below 25 bo/d. Fewer than 1 thousand of those wells are still producing more than 100 bo/d. In our advanced analytics service, these findings can be analyzed in full detail.

The ‘Advanced Insights’ presentation is displayed below:

This “Ultimate recovery” overview reveals the relationship between production rates and cumulative production. Wells are grouped and averaged by the year in which production started.

Also here you can see that the almost 2 thousand horizontal wells that came online last year are closely tracking the performance of the wells that started the year before. The wells that began production in 2010 have now fallen to an average rate of about 10 bo/d. However, many of these wells are gas wells (switch ‘Product’ to gas to see that).

Today, Tuesday September 3rd, at noon (ET), we will present a new monthly briefing (~20 minutes) on all the major tight gas basins in the US, in our ShaleProfile channel on enelyst. Registering is free: enelyst registration page.

Early next week we will have a new post on all covered states in the US.

Production data is subject to revisions, especially for the last few months.

For this presentation, I used data gathered from the following sources:

  • Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending lease reports.
  • FracFocus.org


The presentations above 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 the related data.
  • 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.


  • alex says:

    Looks like Eagle Ford is peaking for a second time, will this be the last time EF peaks? How much is geology and how much is low price?

  • nuassembly says:

    It’s quite interesting question.
    On one hand, 2 major producers in EF, Conoco and EOG are increasing production; while some 2nd tier producers with poor rocks like Sanchez just can not keep up, but at least hold flat.

    But the other old major, Devon fell off the peak 200K bopd by 2/3 and never seem to be able to climb back; while if you read news, Devon says it has good production in Eagle Ford. Judging from Devon’s EUR, the rock they are drilling is certainly not bad.

  • alex says:

    Just flipped through EOGs slide deck and was wondering if anyone could shed some light on the following with respect to their Eagle Ford asset:

    As at 2018, EOG claims to have 2,300 net undrilled locations remaining, assuming a spacing of 330’ and lateral length of 5,300’. They complete 300 net wells in 2019, thus they will have 2,000 locations left in December 2019 = 6.7 years of drilling. Page 46 in their Q2 results presentation

    On page 47 EOG states the average lateral length per quarter from Q2 2018 to Q2 2019, where average lateral length for Eagle Ford is 7,200’ – 7,300’ which is 36% more than in their drilling inventory assumptions.

    2 questions thus arise:

    1) Would they have fewer drilling locations than 2,300 if the same lateral length would be applied to their inventory assumptions as their current completed wells?

    2) 330’ spacing seems very tight, how does that compare to other operators in Eagle Ford? How does that compare to the current wells EOG is completing?

    Appreciate any insights/thoughts anyone would have.

  • Dennis Coyne says:


    If the average well drilled is longer the number of locations would be fewer, probably it would be reduced by about 36% to 1680 locations, assuming the spacing estimate is also correct, if that was increased by 33% to 440 foot spacing due to well interference, the wells would be reduced further to 1126 available locations.

  • alex says:

    Tnx Dennis, that was my initial thought as well. Using your assumptions above, EOG only have 3-4 years left of drilling left in Eagle Ford at current cadence. Yet they claim they can grow there for 10+ years. Something is off…

    1. Sjoerd says:

      I think the discrepancy is that the 2300 refers to “premium” wells, they could theoretically drill non-premium wells after that. Though I fully agree that their numbers are likely optimistic and wells probably stop being economical at current prices before they run out of “premium”.

      They state they have some 9500 premium wells remaining. Even though that’s probably at the high end of a realistic range, they drilled some 784 wells last year and are so far drilling quicker this year, so let’s be generous and say they have some 11 years left. It’s hard to justify a valuation of 10 or 11x when you have that number of years of inventory left, as you still need to apply a discount rate to future earnings, and a dollar earned in 10 years is about half as valuable at a 7% discount rate. There will be a production tail after drilling stops, but the drop remains incredibly steep.

      Given the current oil price, they will be lucky to earn $500 mln in the quarter, $2 billion annualised. If we are being generous and give them a 10x valuation, the other ~$23 billion of market cap is a very expensive call option on oil prices/improving “technology”…

  • Sjoerd says:

    Which is not to say 7% is an appropriate discount rate, I’m confident that’s on the low end given the historical risk of losing money in shale.

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