Increased
oil output in the US has kept World oil output from declining over the past few
years and a major question is how long this can continue. Poor estimates by both the US Energy
Information Administration (EIA) and the Railroad Commission of Texas (RRC) for
Texas state wide crude plus condensate (C+C) output make it difficult to
predict when a sustained decline in US output will begin.
About 80 to
85% of Texas (TX) C+C output is from the Permian basin and the Eagle Ford play,
so estimating output from these two formations is crucial. I have used data from the production data
query (PDQ) at the RRC to find the percentage of TX C+C output from the Permian
(about 44% in Feb 2015) and Eagle Ford plays (40% in Feb 2015). Dean’s estimates of Texas C+C output are
excellent in my opinion and are close to EIA estimates through August
2014. I used EIA data for TX C+C output
through August 2014 and Dean’s best estimate from Sept 2014 to Feb 2015. By multiplying the % of C+C output from the
RRC data with the combined EIA and Dean estimate, I was able to estimate Eagle
Ford and Permian output. The chart below
shows this output in kb/d.
The
following chart shows the combined Permian and Eagle Ford output from 2012 to
2015 in kb/d, this chart is not zero scaled.
Below I have
created a few scenarios for the Bakken and Eagle Ford. This analysis is based on the pioneering work
by Rune Likvern at the Oil Drum (Red Queen series) and his blog at Fractional
Flow, any errors in analysis are mine. I
doubt that Mr. Likvern would speculate beyond 2 years forward in time (or he
has not done so in the past). My reason
for speculating beyond this are simply to see what the eventual resource
recovery would be if the assumptions of the model hold true in the future, though this is highly unlikely.
For the
Bakken Scenario
OPEX=$4/b
Other costs= $4/b
Real Discount rate=7%
Transport cost= $12/b
Well Cost=$8 million
Royalties+Taxes=26.5%
Natural gas sales of about $3/b are used to offset OPEX and other costs. All costs in real 2015$.
Other costs= $4/b
Real Discount rate=7%
Transport cost= $12/b
Well Cost=$8 million
Royalties+Taxes=26.5%
Natural gas sales of about $3/b are used to offset OPEX and other costs. All costs in real 2015$.
Oil prices
are shown on the right hand scale. The
average new well estimated ultimate recovery (EUR) rises from 350 kb in Jan
2013 to 430 kb in Dec 2014 and then gradually decreases starting in June 2015
reaching an annual rate of decrease of 7% in June 2016. New wells are added at a rate of 120 wells
per month from March 2015 to June 2023 and decrease to zero by May 2028. Total wells drilled are about 25,300. Chart with Scenario below (real oil price and
# new wells added each month on right axis).
Eagle Ford
scenario has the same assumptions as the Bakken scenario except for the
following assumptions.
Other Costs=
$2/b
Transport Cost= $3/b
Well Cost $7 million.
Transport Cost= $3/b
Well Cost $7 million.
It is
assumed higher associated gas sales are uses to reduce other costs and better
access to pipelines and refineries
reduces transport cost.
Note that
David Hughes estimates about 7.8 Gb in Drilling Deeper from the Eagle Ford.
In the Chart
below the two scenarios are combined, ERR is about 14 Gb through 2030.
If the
Permian Basin is able to remain on plateau and other US output remains
relatively flat, then US output may remain on a plateau until 2017 if oil
prices rise from $50/b today by about a 4.7% annual rate. I believe such a price scenario is relatively
conservative.
If I go back and look at your previous Bakken scenarios, would I find the Bakken has already outperformed predictions? I know there are a lot of them, but in general. And going back enough to make it meaningful? When the Bakken was 0.8 or less, did you predict it to get to 1.2 so fast?
ReplyDeletehttp://oilpeakclimate.blogspot.com/2012/10/using-dispersive-diffusion-model-for.html
Deletehttp://oilpeakclimate.blogspot.com/2012/12/quick-update-to-tight-oil-models.html
The first one is not bad, but the second one seems under a fair amount (for to date).
DeleteAlso, with price staying at 100+ (or even going higher as in your scenarios), think we would have had some pretty serious growth, given what we have seen from the Bakken.
Hi Nony,
DeleteEagle Ford is under because my guess at the rate that new wells would be added was too low.
The bakken model was low by about 50 kb/d for April 2015, give me a break, that was done 2.5 years ago. Find me a better prediction from 2 or more years ago. We can speculate about how much growth we would have seen, eventually new well EUR will start to decrease and further output increases will require more drilling, the frack stages can be increased or wells can be spaced more closely, but well costs will go up and new well EUR will go down.
The scenarios have oil prices at high oil price (100+) after 2030.
The first one was good.
DeleteMostly a lucky guess. It is very difficult to predict how many wells will be added in the future. At some point new well EUR will begin to decrease. This is impossible to predict in advance, I think this will happen in 2015, maybe 2016 at the latest, but it depends n part on the drilling rate, if fewer new wells are added each month it will take longer to reach the point where the average new well EUR decreases.
DeleteP.s. Maguerri 65 not looking so crazy right now. No, he didn't predict the exact shape of the crash (I think that's an unreasonable expection). But he did predict something very different than your ramp to 135 or 150 or the like. And his price predictions even seem better than what the futures market would have told you at the time.
ReplyDeleteHi Nony,
DeleteYes I have said before that I got the oil price wrong, my estimate was based on the EIA's scenarios.
Do you expect the oil price will remain at $65/b or less long term? I think we will see $85/b at least by June 2016 and $100/b minimum by June 2017. I have been wrong before and will be wrong in the future. What are your predictions? Do you expect WTI will be under $64/b in Dec 2017 (current futures price)?
My best guess is the futures, both because it's Bayesian and that it makes sense if I had to pick on my own. Obviously a recession could blow it low or a ME war could blow it high and those are hard to predict. But I think shale is pretty much the marginal barrel and that 100 is unsustainable because too much shale starts coming on line. See this video from 22-28
Deletehttp://www.c-span.org/video/?325957-1/discussion-future-us-fracking
Much to the discomfort of peakers, companies were NOT losing their shirts at 100 (it is silly to expect a heavy capital business with 30% growth rate to be cash flow positive). And what we saw over 2012 to 2013 to 2014 was an ACCELERATION of growth (in terms of absolute amount) and that is even with 2014 starting to have the price slide. Too much danger of a serious 1-2 MM bpd/yr C&C if we go to 100. They're not going to run out of drill locations at 100 in a year or so either. It was not some little blip that was going to end on its own.
US LTO literally brought world price down. It is self limiting now. I would also caution you that you were predicting 135 and such.
http://www.reuters.com/article/2015/07/01/oil-prices-kemp-idUSL8N0ZH3DN20150701
DeleteJohn Kemp sees an equilibrium.
Hi Nony,
DeleteMy "predictions" for oil prices were simply a simplified version of the EIA's reference price scenario for AEO 2014 (using an exponential as an approximation to keep the model simple). We will not see much of an increase in US oil output from April 2015 levels if oil prices follow the futures strip. We will have to just wait and see if $64/b(2015$) in Dec 2017 proves correct, I will be very surprised if we are not at $100/b by then, the EIA's AEO2015 reference case has WTI for 2017 and 2018 at $71/b. the high price case is about $138/b in 2017/2018, the average is about $104/b, my guess would be $95/b to $104/b in 2015 $ at the end of 2017. We will have to revisit in 18 months and see who is better at guessing the future.
If Maugeri is correct on long term oil prices at $65/b, then his prediction of 1.8 Mb/d of output from the Bakken/Three Forks by 2017 will be incorrect. Even with oil prices at $100/b by 2017, the Bakken will remain under 1.35 Mb/d through 2017 if oil prices remain $100/b or less from 2015 to 2017.
On shale companies losing money at $100/b, I have never said that and neither has Rune Likvern. They have racked up a lot of debt and they just started to reduce their debt levels in 2013/2014 when prices crashed. The cash flow is negative at $65/b or less and it does not look financially sustainable at these prices, at $80/b or higher the economics works, in fact $80/b to $90/b could be the sweet spot where output increases slowly enough that prices are sustainable.
DeletePrice has actually been more extreme low than LM predicted (since we had the drop to 47 and then back up to 60...oops 55 right now). He had a simple ramp down to 65, so this last 12 months would have been higher in his model.
DeleteIf you really think we will be 100 in DEC17, buy a futures contract. Or even go on margin and play with options. But at least the futures contract. you will make a killing, given your median expectation is for 100 and the market predicts 65. (OTOH, you never know...we might be under 65....look how we just dropped to 55 last week. Shit happens.)
I know it's not exactly your comment, but I think with 100 staying through DEC2017, that we would have hit 1.8. The Bakken seemed to be adding 200+ M bpd/year every year in a very linear fashion.
But I agree we are probably not going to hit his predictions along with low price. Always thought that the high production under low prices was tough thing in his model (and said it).
DeleteI could buy the continued LTO growth though, in a 100 environment. Despite all your models showing near term turning points, what we saw going on from DEC11 to DEC14 was linear growth, even accelerating.
Hi Nony,
DeleteIf the Bakken were uniform and there were no sweet spots then you might be correct. There clearly are sweet spots if you look at the map, at some point the new well EUR will drop.
Look at some of my more optimistic models such as
.http://oilpeakclimate.blogspot.com/2013/10/exploring-future-bakken-decrease-in.html
See figures 5, 8 and 9. I doubt figures 8 or 9 are correct and only figure 9 is close to Maugeri's prediction for 2017. The model has worked pretty well through 2015, I doubt it will be far off the mark if we predict the rate that new wells are added correctly. Try downloading the spreadsheet and play with the model.
A 13.6 Gb TRR (no economics) (high end of USGS estimate) in chart at link
https://drive.google.com/file/d/0B4nArV09d398UjZjTG0xOXBhalk/view?usp=sharing
EUR decrease starts in June 2016 and takes 3 years to reach the maximum annual rate of decrease of 7%, wells are added at the rate of 200 wells per month starting in July 2013 and continuing for 250 months, 56,000 wells total.
I think we saw evidence of increasing efficiency in drilling, filling out the pads for example. The decreasing EUR has been a concern going back to Rune 2012, but really hasn't materialized yet. For that matter, if you can drill more wells per rig, it doesn't matter if they get worse (well count goes up).
DeleteThe concern about ultimate resource is reasonable, but even there, we really don't know what is going to come out of there. They revised the estimate once to double it. The OIP is huge, so the key unknown variable is percent extracted economically.
Hi Nony,
DeleteIf the oil price is high enough and enough new wells are added each month, then output could increase more rapidly than this possibly reaching 2 Mb/d by 2020 if 3600 new wells per year were added, but if the USGS estimates are correct (that is the TRR is no more than 13.6 Gb) output is likely to peak at no more than 2 Mb/d by 2020 under very optimistic assumptions. A more reasonable scenario would peak around 2019 at 1.4 Mb/d.
We were adding .2 per year and were. At 1.2. I figure 1.4 by year end 2015 with no price drop.
DeleteThe eur stuff would work itself out. Just a faster up and down. Or more available than usgs thought. Companies were talking about 8 years of drilling inventory.
DeleteHi Nony,
DeleteYou would only be right about 1.4 at the end of 2015 if there was no EUR decrease and a much higher drilling rate. The highest 12 month average completion rate was about 187 new wells per month, let's say this increases to 200 new wells per month by the end of 2015 and remains there.
At an oil price of $115/b the wells become unprofitable in August 2020 and ERR is about 8 Gb without higher prices (this assumes a TRR of 11 Gb). So with no price drop and no EUR decrease until June 2016 and assuming 2400 new wells per year ( highest so far has been 2200 new wells per year) we get 1.3 Mb/d by Dec 2015, 1.4 by Dec 2016, and 1.5 Mb/d by Dec 2017, peak is about this level in April 2018, total wells drilled (due to no profits at $115/b after Aug 2020 so no wells drilled from that point on) are 22,500 wells. The reason for higher oil prices in my scenarios is to make the economics work.
A more optimistic scenario with TRR=12.7 Gb, has an ERR of 9.3 Gb, with a peak of 1.53 Mb/d in Sept 2018, and about 27,000 total wells if oil prices can rise no more than $115/b (in 2015$). Drilling stops in Aug 2022 in this scenario (200 new wells per month as before).
Output is 1310 kb/d in Dec 2015, 1440 kb/d in Dec 2016, and 1510 kb/d in Dec 2017 with peak output at 1528 kb/d.
Note that none of these strike me as realistic, but I am trying to indulge your optimism.
The thing that the optimists fail to realize is that as output increases prices are held down which leads to less profits, costs can be reduced, but not without limit in the real world.
Oil men will tell you that there is a limit to how quickly the oil can be extracted and that no oil field is uniform. If it were easy anyone could do it and oil would be free. :)
Ron: "Dennis, there is no law against exporting condensate and a lot of condensate is exported to other countries."
ReplyDeleteA similar blank strong declaration that is wrong, like when he said Three Forks oil did not come from Bakken shale source rock.
The guy is just too confident in himself. And not deserving it.
Lease condensate is definitely NOT allowed to be exported unless it has been run through a distillation tower (primary refining process).
You can find ten million articles that explain this or look up the law itself. It's just simple knowledge.
http://www.ipaa.org/wp-content/uploads/downloads/2014/08/Crude-Oil-Exports-Fact-Sheet-07-17-2014.pdf
P.s. And if we export the stuff so readily, why is there a ten dollar split from Asia to Texas? That's more than transport costs (~3).
It's bizarre watching Ron babble about EIA versus RRC. This is the same dude who said several months ago from the shape of the curves that they were peaking. Who had to have it rubbed in his face to realize the corrections even though you had posted them before. Just move on. Dude is a total lightweight peaker type and has been for 10 years. Hang out with Enno and Dean, sharpies.
ReplyDeletehttp://www.oilandgasinvestor.com/videos/discussing-step-changes-well-completion-design-791486
ReplyDeleteSee in particular predictions after 4:00.
http://www.theoildrum.com/node/9910 (see comments on Blanchard analysis)
ReplyDeleteInteresting to see history of mistakes on EF prognosis and on RRC adjustments. I get the impression that Ron just doesn't learn.
Hi Nony,
DeleteThe Eagle Ford ramped up much more quickly than I expected, I was basing my estimates on a Bakken level of ramp up, but that was too conservative, my early estimates for the Eagle Ford were about 1000 kb/d by Jan 2015, about 500 kb/d too low. My mistake was only predicting about 5000 wells at that time and this was about 50% too low (there were about 7500 wells online by the end of Jan 2015). See the end of the post below:
http://oilpeakclimate.blogspot.com/2012/12/quick-update-to-tight-oil-models.html
Good question for Dean and very interesting that he has been saying for the last several months that EIA was overestimating, but then he has been coming up towards EIA every month that goes by. Seems like something in his algorithm is pinning at the end. Either that or just the corrections have changed and EIA is closer than he is. Even with their linear model.
ReplyDeletehttp://www.eia.gov/petroleum/supply/monthly/pdf/crudemeth.pdf
ReplyDeletedetails on how the EIA estimates texas (discusses in more than one part of the document, so read through).
Thanks Nony,
DeleteThis seems to be something like what Dean does, but he doesn't have access to the DI data (neither do I).
In the past the EIA estimates have been pretty good. A problem occurs when there is a change in trend and the EIA could be overestimating as the output flattens in Texas, as always, time will answer this question. I really shouldn't bother with it as it gets everyone in a huff.
Agreed, catching a turning will be difficult. I find it interesting that they did an upward revision to previous months though. Would think if algorithm is not catching the turn, that more data/time would lead to downward revisions. Seeing the converse is curious.
DeleteHi Nony,
DeleteDespite what that EIA paper says, they only seem to revise their linear projection once or twice per year for TX, when they do the revision sometimes it is higher and sometimes lower. For the last half of 2014 prior to the April 2015 revision they had been underestimating, since Dec 2014 TX output may be following a less steep increase (or possibly a decrease) so future revisions may be lower. Time always tells.
http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_m.htm
ReplyDeleteTexas seems to have hit a new peak, breaking past the 1972 peak that it achieved and which Hubbert predicted. Pretty noteworthy, no?
I suppose it is, but I am not sure how well the Eagle Ford will hold up, the Permian will increase while the Eagle Ford decreases, this may be a couple of years away, depends on oil prices.
Deletesee my 3 part comment discussing Pareto distribution insight wrt rig cuts.
ReplyDeletehttp://www.aei.org/publication/chart-of-the-day-us-oil-output-increased-to-a-44-year-high-in-april/
Hi Nony,
DeleteAnother thing to keep in mind (I agree with your analysis) is that a large portion of the oil rigs that dropped were vertical rigs in the Permian basin. The amount of production per rig from these vertical rigs is considerably lower than from the Horizontal rigs, so that is also part of the explanation. Where it fits into your analysis is that these vertical wells were the less profitable wells which get dropped when oil prices fall to under $50/b. But what we have to keep in mind is that not all rigs are equal, we probably get about 3 times the incremental output from a horizontal rig vs a vertical rig.
Check out the pivot table at baker hughes, if you haven't already.
rock says vertical and horizontal rigs are the same thing. Just what they are drilling. I wonder if that is true though. H3 ma keys. A lot of mistakes.
DeleteRockman is probably correct, output per rig may be the same, he would know better than me.
DeleteI don't get "H3 ma keys". So you lost me there.
DeleteSomething weird with the autocorrect. "He makes a lot of mistakes."
DeleteI would check stuff when he says it. He has pulled some boners. Rockdoc has called him on it.
Art Berman predicted 0.6MM bpd drop in US LTO from JAN-JUN. We are more than half way there. I don't think he is going to be proved right.
ReplyDeletehttp://www.artberman.com/tight-oil-production-will-fall-600000-barrels-per-day-by-june/
Hi Nony,
DeleteWe will see if Maugeri calls it right for 2017 for LTO. He will be wrong on both price $65/b long term and on output. I agree that Berman will probably be incorrect for June, but if oil prices stay where they are he will be correct by November, the continued drilling at these oil prices is surprising to me.
JAN was at 9.3 MM bod. We would have to be at 8.7 to make his call. Let's even throw him a bone and use the 9.4 from DEC. Would still need to hit 8.8 to show him correct.
DeleteAs of APR, we were at 9.7. So you would need to drop 1 MM bpd in 2 months to make his call.
Recent STEO says we were down 50,000 in May. So call it 9.65 MM bod in May (assumes no revision up or down to the APR result.) To get to 8.7, we would need to drop 0.95 MM bpd in a month!
FWIW, I don't see June being down AT ALL versus January, let alone down .6 million barrels per day.
We are not going to hit 8.7 by NOV. We probably won't go below 9. EIA estimates 9.3 by year end.
ReplyDeletehttp://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_m.htm
http://www.eia.gov/forecasts/steo/pdf/steo_full.pdf
ReplyDeletebetter link. see page 6. if 1q2016 is 9.2, you are looking at something like 9.2 or 9.3 in nov.
possibly lower yoy over jan's 9.3 and likely lower tha dec 9.4.
still...jun was in no way lower than jan. and there is still a possibility of exiting the year with production higher tha jan15 or dec14. and definitely 15 versus 14 will be a higher production year versus year.
This comment has been removed by the author.
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