Permian – update until 2016-03


The above presentation contains oil & condensate production data from horizontal wells in the Permian (both New Mexico and Texas) until March.

As you can see, total production has increased again slightly from the dip in December, and is higher than in 2015. I still expect some upward revision of production in recent months as is typical for Texas. The difference with the Eagle Ford, which has shown large drops in recent months, is striking.

Total production is larger than in the previous update, as I include now basically all horizontal wells in the Permian (9529 producing wells vs 7768 in the last update), and also condensate production from gas wells in Texas, which were excluded before.

New wells in the Permian have increased in productivity since last year, as can be seen in the “Well quality” tab. Looking at the production curves, it appears that the increases in productivity in recent years have been made mostly in the first two years in the life of the average well.

For New Mexico, in the “Well status” tab, you can also see the wells that are spud, but not yet producing, and also whether a well is plugged. These statuses are not available for Texas.

I expect to have another update on the US around Sunday. During next week, I hope to be able to present a post on gas production in the Marcellus (PA), deviating from my earlier focus on oil only. After that, I plan to present a post on the total oil production we may expect in the coming years from existing wells.

====BRIEF MANUAL====

The above presentation has 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, and include or exclude categories.
  • 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.

47 thoughts on “Permian – update until 2016-03”

  1. Can you explain again how your model deals with lag of Texas RRC getting all the data in?

    1. Nony,

      Every month I access the entire 10-year production history of all the leases of wells I monitor, and use that, together with individual well data (such as completion date), to re-estimate the production profile for each individual well.

      By doing so, I adjust the results each month with the revisions that were made to the data.

      The impact of currently missing data on the results can be:
      – total production in the last few months is likely to be revised upwards
      – the tails of the production profiles of wells (which is calculated from the last few months of production data), that are later revised upwards, are a little lower now than where they will eventually end up being.
      – the total number of producing wells may end up a little higher, every time when new producing wells are reported after a delay. I belief that this is a major source of the revisions (new wells, not revised production from legacy wells), although it is not easy to check this theory comprehensively.

      I have found a better way now to monitor revisions, and will probably report on this once I have 3 more months of revision data.

      1. Thanks.

        It’s curious that you don’t have that strong hook shape that the rest of Texas data does (apparent peak even when was increasing).

        Would be interesting to see for your results how much the month to month revisions are. IOW show the hook charts (month by month graphs of total production) so we get a visual of how much your total changes and how far back.

        I would think the new wells would mostly be in the Permian (and the EF). And the old wells would be in the non shale areas. So kind of surprising that the Permian (most rigs) does not show much lag and revision. versus the whole state. (there is including of NM data that may not have revisions. and EF versus Permian. But still surprised that we don’t see radical need for revisions/corrections if the issue is new wells.)

  2. Enno,

    Thanks for your consistent hard work. As PXD is the shining light of the Permian I had a look at their well quality. Also I have heard numbers of URR of 800 to 1000 mbo, I assume these numbers relate to PXD being the pin up child of the Permian, but what I see from your graphs, the current cums are 150, battling to make 200 mbo, with the exception of one well drilled in Oct 2011, which currently produced 422 mbo. It looks like they drilled into a oil production pipeline on that one well! Smiles.

    The only thing that makes sense to me, this being a stacked area, the reserves incorporated in the other horizons have been taken into account, to reach the elevated numbers of 800+ mbo URR. If these were vertical wells, where a simple plug and perf would bring on the new reserves, it would make sense. But to drill a new lateral by cutting a window in the casing and drilling a new horizontal lateral, would cost nearly as such drilling a new well!

  3. 1. What percent of URR do you think is flowed in the first 3 (or 2 or 1) years? IOW, how can you look at a current cum and say that a well at 150 or 200 or whatever, will not get to 800. NOTE: I’m not saying they will. Probably not. But just how can you possibly make an argument in that vein?

    1.5. Or turning it the other way around, given the cums you see, what do you estimate as URR and why?

    2. PXD has a very VERY noticeable improvement in their well quality year over year. No CLR/EOG investor presentation story there. Using Enno’s own tool, you see it very clearly. So, just be careful about saying what today’s wells will do based on old ones.

    P.s. I doubt the operators are considering new laterals or even refracks in their type curves and URRs.

    1. Nony,

      how can you look at a current cum and say that a well at 150 or 200 or whatever, will not get to 800

      If you look at the CUMs for all the quarters, all bar the 6 months production line are flattening to flat, and this is all below 150 mbo. The only anomaly is a single 2011 well. But, I can answer my own question, and reconcile the difference in one word, thanks to Shallow Sands and his comments in other places. BOE!

      1. So to clarify, you think the EUR is 150?

        And what about the improvement year over year?

        1. Nony,

          I am saying the current CUM is around the 150 mbo. With the slope of the graph in Enno’s charts they would be lucky to make 200 mbo. But this is OIL! All the presentations refer to BOE, which as you are well aware includes gas. Shallow, who has access to all the detail from drillinginfo, has stated how quickly the oil portion of the Permian production drops of, and the wells become mainly gas wells. So the presentations you hold in such high regard, can technically be correct, you just have to read them with legal eyes.

  4. OK, thanks for letting me pin you down. Then that is 200 EUR you predict based on 150 at year 3? I’m not trying to jerk you around. Just it is very hard to think about what a well will deliver over 30 years, even if at a low level production now. So about 75% done by year 3?

    BEO gas would account for 15-20% in Permian and Bakken. Doesn’t swing the needle on a dispute of 800 versus 200.

    Seriously, watch out for the year by years getting dramatically better for Permian/PXD. That is Enno’s own tool that shows that. Very different than Bakken where things stay close to equal.

    1. Nony,

      You maybe correct in the new wells are getting better, but we will have to wait a little time to see the proof. Looking at Enno’s charts, PXD, well quality, 2014 and 2015 after starting higher, are now back to the 2013 line. We will have wait and see what happens with the 2016 vintage.

      1. I see what you are saying on the rate curves. Does look like the rates come down fast. That said, those charts are hard to read with all the squiggles at the bottom and a little noisy for the last few data points of a year group. Looking at the cum curves, they are radically different. While it’s possible that is just moving the same EUR to earlier in lifetime, we should also be open to the Occam’s razor explanation that new wells are just much better! In any case, it’s very different in comparison to Bakken overall year group well cum curves (slight improvement, but almost unchanging really).

        1. Nony,

          You did a very insightful well economics analysis. Could you run one for Pioneer?

          It’s hard to get a fix on the parameters, but some estimations I have:
          – average horizontal well cost in the Permian : $7.5M (based on statements from the AR 2015)
          – royalties of 25% (I understood from 2 Texan operators that these are normal amounts in the Permian)
          – We all agree that it requires some guess work what these wells are going to do. However, so far wells have behaved very similarly as earlier wells, after 1-2 years on production. If we make this assumption also for 2015 wells, I estimate that Pioneers horizontal wells from 2015 are going to do in the neighborhood of 160 kbo by year 5.
          I arrive at this number by
          1. taking the actuals of 2011 wells (101 kbo year year 5)
          2. adding the excess that 2015 wells have over 2011 wells by month 15 (97-53 =44 kbo),
          3. adding 15kbo extra production, given that between month 15, and 28 (which is where 2014 & 2011 wells converge) the output of 2014 was still higher than 2011 wells, roughly by this amount.

          – I haven’t checked what is reasonable, but maybe you can assume a GOR of 4.

          Feel free to use other parameters (with motivation), just getting to a ballpark number would be great.

        2. I also noticed the fast decline of oil after 2 years of production for PXD wells. Now, Shallow also says GOR is going up fast. This is quite similar to what happened in Miss Lime — there, the GOR quickly shoot up 10x and oil drops to nothing in 4-5 months, while only water is left.

          Reading the past vertical wells in Wolfcamps and Spraberries and BoneSprings, it says that if you drilled to the right formation without much water, the section along could produce on average of 30->50M BO over 5 years, with each section about 100~300 feet and a single plug and perf with sand. If we scale it up with 5,000′ of lateral and over 40 stages of plug and perf and a lot more sand, we should have over 1.5MMBO.

          I believe this is happening for several reasons.
          1. Some stages have less oil than the sweetspot a vertical well targets, which usually they use down-hole to map it after drilling and then pick out the best to frac and produce.
          2. Certain part of the lateral has high water produced, and wash away the others. Such thing already happened before in Permian and Miss Lime. Sometimes, they tried to produce from certain stages of lateral and vertical only, and the water cut is dramatically different from stage to stage; or they know certain stages have high water cut, and they plug it and improved the production of the whole well.

        3. Nuassembly,

          Thanks for your comments.

          Shallow’s comments were about the SCOOP/STACK in Oklahoma, which appear to be mostly gas plays (especially after the initial liquids flow has stopped). The Permian isn’t that gassy.

  5. Enno, somdthing happened with PXD production data.
    The Permian wells in 2011 and 2012 all have their tails up now.

    1. Nuassembly,

      Well noticed. I will check this in the next update. An issue with PXD wells is that some of them are located on leases with very large numbers of wells, and then my estimation algorithm may sometimes encounter issues correctly estimating individual wells. I suspect that that is the case here, as it looks really unnatural. Unfortunately, production in Texas is only reported by lease, instead of by wells, so this estimation is the best I can do (unless Pioneer sends me their data directly, which I hope they will at some point).

  6. Hope you can see this. I beleive this is Apache work from 2014 or so on simulated Wolfcamp production and recoveries versus GORs.

    Attachment

    1. Thanks for sharing that Jim.

      The quality of the pictures isn’t great, but that probably has to do with the settings of this site. At least I could make out some of the graphs. If I see it correctly, it also includes several projections of total ultimate oil return, between 220 kbo – 270 kbo per well.

      1. Yes that is correct. And the influence of GOR on Recovery is huge.

        All about conservation of reservoir energy (gas expansion) to recover oil and not gas.

        Is there a real oil play outside the Bakken and Eagleford oil window (< 2,000 GOR)?

        1. Now I completely get it, thanks Jim, very interesting.

          “Is there a real oil play outside the Bakken and Eagleford oil window (< 2,000 GOR)?" Good question, I think the answer is No.

  7. Enno, thanks for the kind words, stud. Just coming up for air from a 2.5 week due diligence. Victory. Pulled it out of my ass at the end (got a bunch of targeted interviews and got industry data we were missing…nothing to do with oil…just basic industry analysis.) Anyhow…success. and for a German who expects a lot. Blew away his boss and presentation headed to the corporate board. Scary isn’t it? But…for all my faults, I might be better than the average idiot. Got to go somewhere, right? Drinking beer now….

  8. Enno:

    I think we ran enough variations of the simple payback to know how a 150M bbl well will turn out Yeah we could make estimates or research the nuances (expenses lower in cost, unless more water; little better basis, worse royalty, better taxes.) But the key is the volume assumptions.

    1. Is your calculator correct and PXD is way out to lunch with the general statements about wells coming in at 800M+ EUR as a class? Or is PXD correct and something is wrong with your system. There are some confounding factors (like the multiple wells per lease), the slow reporting, the old verticals that might be messing with your calcs and making the wells look worse than average. No accusation–just trying to think openly.

    PXD does show a behavior of drilling which implies that their statements are correct (at least the put their money where there mouth is). Also, the land values for the Permian are pretty strong. Also implying that oil can be profitably extracted with current strip.

    Again market could be wrong…I think that is one of the things you want to check. But just be on patrol to look at the logic of your method. (For one thing if the wells ARE getting better as a class, is it possible that your method might be systematically understating the better performance? IOW, the way that you divide up production on a lease with old and new wells, is it possible there is an implicit assumption of a non changing population over time?

    2. I don’t actually get the same numbers as you, trying to use your calculator (this is not the main issue, but FYI).

    a. For one thing, it is hard on the rate chart to get your cursor on the last few data points where they are all together in the spaghetti. The opposite is true for the cum charts (anfang is the issue). Any chance you could tweak the code so BOTH rate and cum are displayed for the mouse-over feature on BOTH plots. Then one can grab the data needed.

    b. 2011 is very different than 2015. Just the shape of it. Maybe it is just an issue of moving oil forward in extraction. But I such a huge difference in shape, I think of them as fundamentally different. I mean, heck 2011 is flat to UP over the 5 years. What the hell is that?? Refracking? Some issue of the lease split or verticals exclusion assumptions?

    c. 2012 has a wonky shape also, with the shift up in rate.

    d. 2013 shows that interesting flattening around month 27. But if you look at 2014, it’s not really flattening yet at 27 (higher slope on the cum, higher absolute on the rate).

    e. Another thing is I don’t see year 2015 converging to 2011 rate. It’s actually expected to be much worse than that. Or at least if you look at 2014 and 2013, they are pretty clearly already UNDER the 100M+ bpd that the 2011 flat-lines at.

    f. I show different numbers than you for the month 15 2011 and 2015 cums. I see 43M and 131M respectively. Which of us is reading the tool wrong?

  9. Few other things.

    a. I only see the Spraberry coming up as a formation for “all”. No Wolfcamp?

    b. There are only 3 wells in the 2011 data. Do we really want to base off of that?

    c. What happened to 3 year paybacks? Seems like you are wanting to look at 5 now? I could do both I guess, but asking. FWIW, I don’t have a huge feel for how NPV corresponds to payback, but given the massive decline rates, my bias would be to using 3 year payback as the thumbrule, not 5. (Note this is a stricter hurdle.)

    P.s. I am starying to mess with it, but you know how it will come out. 😉

  10. (This fits under the “they’re drilling so they must think it’s worth it”, but it’s a slightly additional insight: PXD actually brought MORE rigs on line recently. The point here is that it is not just “sunk cost from long term contract”. They made an optional decision to drill more after prices went up to 47 from 27. [And before that, they reduced at 27.] So, at least it appears they are making some sort of rational drilling decisions. Not just full out stock pumper craziness.)

  11. One other small idea: if you think about this implicit assumption of same population from year to year (when dividing wells on a lease), if it is minimizing the improvement of later wells, could it also be making the earlier ones look better later in life? Perhaps that is some of the explanation of the strangely low decline rates of old wells (and the very high declines of the recent ones). IOW, the new wells on a lease are getting a little bit of the bad performance of the old ones mixing in and visa versa. Not sure if this is happening, no accusation, just something to check.

  12. Ok. So here is my first case (discussion below):

    basic assumptions, reading bbls off of Enno chart
    CAPEX 7,602,000
    bbls 222,750
    gas add % 28%
    gas boe 62,827
    bbls boe 285,577
    gas mcf 376,962
    WTI oil 50
    oil basis diff 2
    Perm oil 48
    HH gas 3.00
    gas basis diff 0.20
    Perm gas 2.80
    oil rev 10,692,000
    gas rev 1,055,492
    EP rev 11,747,492
    oil sev % 4.6%
    gas sev % 7.5%
    oil severance 491,832
    gas severance 79162
    total severance 570,994
    EP-sev 11,176,498
    RI % 20%
    RI 2,235,300
    EP-sev-R 8,941,198.71
    LOE/bbl boe 4
    LOE cost 1,142,308
    GA/bbl boe 2
    GA cost 571,154
    opex (LOE, GA) 1,713,462
    EP-s-R-opex 7,227,737
    return-capex (374,263)

    (see PXD JUN IR presentation for several references)

    CAPEX: I use 7.6 based on the 4Q15 number from page 13 of the IR deck. Using 1Q16 would only be slightly lower at 7.56. You wanted 7.5. So no big difference. Note the caveat at the bottom of that chart though. 1Q16 had 3 wells with higher capex costs. Don’t know what the true costs were so can’t include them. You could say I’m avoiding the bad quarter, but what to do? I suspect they are not completely failed wells (like at the end of completion breaking a tool that can’t even be drilled through…and needing to drill a whole new well. They do list number of unsuccessful wells in the annual report and there was only one of those in the last 2 years.) I suspect they were a couple million high on 3 out of 24 wells (one eighth) and it just messed up their pretty trend line. Anyhow, I think 7.6 is OK.

    bbls: I read 132 at the 15 month mark for 2015. I come to 222,750 by assuming half the production for the next 15 months and then three quarters of half of half (because 6 months) for the final 6 months. 1 +1/2 +3/16 if you get my drift. Not sure on the shape or how that compares to rate, but seems reasonable given general shale decline patterns. Could be worked up more of course. And it is the key driver for the whole exercise!

    gas add: see page 6 of the IR deck, has been 77% or 79% oil, the last couple years. Doing the ratio .22/.78 gives the 28% add-on.

    WTI oil and HH strip: just used the same numbers from a couple weeks ago (50 and 3). Don’t think it has changed much recently, haven’t watched. And in any case, PXD made decisions a few weeks ago regardless.

    oil basis diff: 2 bucks is out of their IR presentation, I forget what page. It has been as low as zero or negative, reflecting higher quality of “true” WTI over “mix” WTI from the storage tanks. But we hit it with the 2 dollar haircut as that is from them.

    gas basis diff: That’s from a March Plains or Platt pricing bulletin on the web. Prices were terrible low than so the basis may be a little different now. But I don’t think delta will be much higher or lower and we are talking 20 cents (less than 10% of price) on a not large volume part of the problem. Could be researched more by someone who subscribes to hub pricing. Or sometimes you can get some of that from Natural Gas Intel (some data is public, some paid.) Don’t think it changes the answer and .20 is reasonable.

    N.B. One thing about the natural gas though. We are not giving the project ANY credit for NGLs. They tend to have BOE prices intermediate between gas and oil. And I suspect gas from an oil well is pretty “wet”. So this is conservative. We are ignoring money they are making on NGLs. Pipelines to the Permian had issues 3-4 years ago but there has been a bunch of infrastructure that went in right as the crash was starting. So I have heard it is not a problem getting piped out of the Permian (oil or Y grade NGL) and transport prices are really low with too much pipeline capacity built. (Remember everyone expected 100 to last and was sizing for the continued growth of US oil, not even for just treading water in the Permian).

    severance tax: the rates are off the RRC site. Hope I did them right. There are some incentives for EOR and the like, but I don’t think any of them applied and did not give the project credit for any of them. The impression I get in Texas is that severance is collected before royalties (i.e. on the RI’s money). In ND is the opposite (actually I think ND has two $5 taxes and one is before and one after). It actually doesn’t make any difference to the operating company, just the tax authority and the RI. [80% times 95% is equal to 95% times 80%.] But if I have something wrong, let me know, Sandy.

    severance: I’m not trying to be a corny, just use my best guess and it is 20%. Did a search on the web and Credit Suisse analyst report for starting coverage had assumed 20%. Also, I think 25% (or even higher) is reasonable for new acreage (e.g. much of the Eagle Ford ended up like that). But the Permian already had a lot of the acreage leased and held by production off of the vertical wells. I agree it’s probably not 1/8, but I think 1/4 is excessive given their legacy position. [Also note that the ABILITY for RIs to extract higher percentages on new leases is a pretty strong economic argument that the play IS economical. Marginal land does not extract outsized RIs.]

    LOE rate: see page 14 of the IR presentation. Page 20 has a higher amount, but that is corporate wide, not just the Permian core. Given their development (putting in pipes, managed field development, etc.) the low rate in the Permian makes sense. Page 20 also shows a workover charge (.3-.6 per boe). Let me know if you want a row for it added. I think the bigger uncertainty is in the G&A, though.

    G&A: I actually really don’t know what to put here. Like I don’t think it’s fair to charge the new well with the corporate center as that probably doesn’t increase for the new wells. But you can make an argument that it does. There’s also the question of if the LOE already includes some G&A or not (I really don’t know). Anyhow, I hit it with a couple bucks.

    End result: Well fails the 3 year payback, but just barely: about 5% in the hole still at 3 year point. Few more months and it clears. Or if I drop G&A to zero, it clears.

    1. The second para with “severance” is about “royalty”. Lysdexia, sorry. 😉

    2. Nony,

      bbls: I read 132 at the 15 month mark for 2015.

      Thanks for your detailed posts. I am still working my way through it all, but I did make one observation when looking through the charts. If you go to the monthly view for PXD in 2015. October is a standout month. 15 wells show up with much higher production than other months. No idea why, but I don’t know why they have not repeated them.

      1. I see November as the standout month (mouse over the cursor and you can see individual data point).

        I suspect shut-ins from completion work is the reason. I know they have to shut in all the nearby wells when they frac a new one. Think this can give you a slow month followed by a fast month just because of the work patterns (just the number of completions or the locations of them leads to more than normal shutins one month and less the month after). And there is a surge of production from a well that was shut in because of building up pressure again–this is what Coffee and milliondollarway are mistaking for halo effect (I think).

    3. I think LOE of 2/bbl will prove to be way too low. In fact, this LOE number is highly dependent on the volume, as there are substantial fixed costs of running a derrick. So yes if company divides its LOE by peak production rate 2 is very possible, but what is it over the life time? Stripper wells (which vast majority of shale wells become after 4-5 years) are known to be uneconomic below 20. So I’d assume 2 would be LOE/bble first year, probably 4-6 years two-three and probably in the teens for the long tail. If i had to guess i think it’s definitely in high single digits.

      1. I used 4, not 2. The 4 is out of their presentations. Note that per barrel high costs late in life are not relevant to the 3 year simple payback. If anything, the fixed versus variable might help the younger wells.

        FYI, I also hit it with $2 of G&A opex on top of that. So it is assuming $6/bbl of avoidable opex cost at the project level.

        I should also hit it with $0.6-0.3/bbl for workovers, but I just noticed that in a PXD doc after finishing the spreadsheet.

        1. And that added G&A was NOT in the PXD presentation. But I added it based on thinking maybe it needs to be there. I really don’t know though…there is so much uncertainty on that. E.g. is G&A already included to some extent in LOE? And remember we only want to list avoidable costs. IOW, if you DON’T drill that well, you should be saving that money (maybe firing some staff as the company shrinks and visa versa)

        2. And the fixed versu variable issue probably applies to G&A also. Should I think of G&A per well or per bbl? A more fixed view probably benefits the younger wells more.

        3. i dont think that’s how an average institutional investor joe looks at that. they look at acreage x drilling location x that mythical 1mmm eur. if the first three years was all that mattered these stocks would be trading at a fraction of their current valuations. and you only can squeeze out 1mmm curves if you have a very long tail.

        4. A stock valuation is an implicit option-adjusted NPV. The 3 year simple payback is an admittedly simpler calculation.

          Alos don’t get confused between evaluation of stocks overall versus with projects. the company overall has things like debt, hedges, whole portfolio of projects to consider. The project is just the project.

        1. maybe while the magical fairy dust in the form of all-forgiving shareholders lasts

        2. plenty of companies buying land in permian now. look at fang today. 2mil per drilling location, and thats with THEIR spacing.

  13. This is a goal seek: how many bbls are needed to get to breakeven (all assumptions same as earlier):

    goal seek (bbls for breakeven)
    CAPEX 7,602,000
    bbls 234,284
    gas add % 28%
    gas boe 66,080
    bbls boe 300,365
    gas mcf 396,481
    WTI oil 50
    oil basis diff 2
    Perm oil 48
    HH gas 3.00
    gas basis diff 0.20
    Perm gas 2.80
    oil rev 11,245,647
    gas rev 1,110,147
    EP rev 12,355,795
    oil sev % 4.6%
    gas sev % 7.5%
    oil severance 517,300
    gas severance 83261
    total severance 600,561
    EP-sev 11,755,234
    RI % 20%
    RI 2,351,047
    EP-sev-R 9,404,187.09
    LOE/bbl boe 4
    LOE cost 1,201,458
    GA/bbl boe 2
    GA cost 600,729
    opex (LOE, GA) 1,802,187
    EP-s-R-opex 7,602,000
    return-capex –

    As expected, given how close we were to breakeven earlier, it just needs a little more. 234M bbls for breakeven. Less than 5% better well.

  14. Now take a look at page 6 of the IR presentation. The question is when can PXD’s type curves (not the ones read off this site) get to the needed 234MK bbls?

    The 1MM EUR type curve hits the needed level at ~ 2years. The grey line (7000 foot laterals and type one improved completion) hits it in about a year and a half. The blue line (9000 foot laterals, and I assume type two improved completions) hits it at ~250 days.

    Note, these are not small amounts of wells in the data sets either. I forget how many total wells they do a year in the Permian. It is a little hard to keep track with their southern and northern area and then the different layers. But my point is, this stuff is not like some CLR downspacing test at the anticline in rock that is way better than their typical. This sort of well is what PXD does. That is what they are going into manufacturing mode in the Permian to do.

  15. I’m running it with the 25% RI also.

    Enno site bbls with 25% RI
    CAPEX 7,602,000
    bbls 222,750
    gas add % 28%
    gas boe 62,827
    bbls boe 285,577
    gas mcf 376,962
    WTI oil 50
    oil basis diff 2
    Perm oil 48
    HH gas 3.00
    gas basis diff 0.20
    Perm gas 2.80
    oil rev 10,692,000
    gas rev 1,055,492
    EP rev 11,747,492
    oil sev % 4.6%
    gas sev % 7.5%
    oil severance 491,832
    gas severance 79162
    total severance 570,994
    EP-sev 11,176,498
    RI % 25%
    RI 2,794,125
    EP-sev-R 8,382,373.79
    LOE/bbl boe 4
    LOE cost 1,142,308
    GA/bbl boe 2
    GA cost 571,154
    opex (LOE, GA) 1,713,462
    EP-s-R-opex 6,668,912
    return-capex (933,088)

    So, this is same assumptions, just changing the RI. You are close to a million in the hole. Have an eight of your capital unreturned at 3 year simple payback test. (This is more serious for oil wells than mechanical projects like HVAC installs, because of how the oil declines. It’s why I don’t like a 5 year simple payback for a shale well.)

  16. Here is the goal seek for needed bbls with 25% RI:

    goal seek with 25% RI
    CAPEX 7,602,000
    bbls 253,916
    gas add % 28%
    gas boe 71,617
    bbls boe 325,534
    gas mcf 429,705
    WTI oil 50
    oil basis diff 2
    Perm oil 48
    HH gas 3.00
    gas basis diff 0.20
    Perm gas 2.80
    oil rev 12,187,982
    gas rev 1,203,173
    EP rev 13,391,155
    oil sev % 4.6%
    gas sev % 7.5%
    oil severance 560,647
    gas severance 90238
    total severance 650,885
    EP-sev 12,740,270
    RI % 25%
    RI 3,185,067
    EP-sev-R 9,555,202.28
    LOE/bbl boe 4
    LOE cost 1,302,135
    GA/bbl boe 2
    GA cost 651,067
    opex (LOE, GA) 1,953,202
    EP-s-R-opex 7,602,000
    return-capex –

    1. Nony,

      Thanks for the effort. I’m currently travelling, but early next week I’ll take a closer look at this, and respond.

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