This thread is for oil and natural gas related comments.
Non Petroleum comments should be in the other thread.
If anyone is interested in posting please contact me at peakoilbarrel@gmail.com. The posts can be brief. Thanks.
426 thoughts to “Open Thread Petroleum, June 7, 2017”
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It appears that US crude oil exports are significant enough and variable enough to have a major impact upon US crude oil weekly inventories.
Hi shallow sand,
Yes they were quite high last week, but I don’t really trust the weekly numbers, probably better to focus on 4 week averages or the monthly data in my opinion. Last week’s 1.3 Mb/d of exports would amount to a stock decrease of 9.1 Mb over a 7 day week, quite significant.
Dennis, I do not disagree with you, but look at the drop in oil prices after this data was released.
Just as there were large swings to the high side 2007-08 and 2011-14, it appears the reverse is now true.
Paper barrels. For some reason, OPEC sells its oil based upon prices determined in London and New York. I have never understood why OPEC does not try to exert any influence over the pricing mechanism. Or, maybe they do?
I take full responsibility for staying invested in oil despite the crazy price swings since 1998. I started in 1997, so I guess I was lulled into thinking it wasn’t so volatile as the 1990-1997 period was relatively flat.
Our average annual crude price from 1990-1997 was in a range of $6, less than $4 if the Gulf War year is excluded.
Does anyone have data on oil exchange volume from that time period compared to recent? How many more paper barrels are traded now,?
If you were Russia and sought victory, what would you do?
BTW re volume. To sell a contract there has to be a buyer.
Shallow: “For some reason, OPEC sells its oil based upon prices determined in London and New York. I have never understood why OPEC does not try to exert any influence over the pricing mechanism. “
There are many reasons, some political, some not, but big one is that allows them free access in trade in financialized economy dominated by payments to the finance, insurance and real estate (FIRE) sector, and to newly privatized monopolies that Wall Street and City of London love.
By trading oil in New York and City of London, it allows them to derive significant rentier income and way beyond and above just oil trade.
“One cannot discuss the roles of finance and government without the concept of economic rent, because rent seeking is the largest category of bank lending – and also of tax favoritism. But economic historians will recognize the concept of a free lunch as the centuries-long description of rentiers – bankers and landlords in the private sector. It is to this class that Keynes referred to when he spoke of “euthanasia of the rentier” as the wave of social reform to avert future depressions.”
(not strictly about oil trade more about financialization of world trade)
More here, http://michael-hudson.com/2011/10/trade-theory-financialized/
Dennis
Quick followup on one of your comments to Glen, regarding USGS Permian assessment …
Seems pretty common for people to take the Wolfcamp USGS assessment of 20 billion barrels as applying to the entire Basin.
It’s not. Only the Midland sub basin was assessed.
That 20, along with the Spraberry’s 4.2 billion gives about 24 billion barrels TRR for the Midland ONLY. (and not including the other Midland horizons).
The Delaware portion of the Permian is actually larger, but no recent USGS analysis yet.
Hi Coffeguyzz,
Yes the TRR of both recently assessed plays is about 24 Gb, not all of that will be economically recoverable, and we will have to wait to see what the Delaware assessment is. The other horizons were not assessed because there is not a lot of oil there. They assessed the parts of the Wolfcamp and Spraberry where they believed there was oil.
Remember it’s the rate that the oil can be produced that is important as well as if it is profitable to do so. How much of the 24 Gb assessed so far will be profitable at less than $50/b? Maybe 20% would be my guess.
So that is about 5 Gb, less than a years input into US refineries (about 6 Gb per year).
coffeeguyz,
Here’s a link to the USGS study.
https://pubs.usgs.gov/fs/2016/3092/fs20163092.pdf
The USGS study not only omits important producing areas such as the Delaware Basin and the Alpine High (where Apache recently announced it believes it can produce 15 billion BOE on its acreage: “The Alpine High: A Big Deal Last September, An Even Bigger Deal Today” https://www.forbes.com/sites/davidblackmon/2017/03/02/the-alpine-high-a-big-deal-last-september-an-even-bigger-deal-today/#687d7ec45d51 ), but also the Clear Fork, Jo Mill, Spraberry, Atoka, Barnett and Woodford resources benches in the Midland Basin.
The evolution of these other resource benches (with the exception of the Spraberry) is still very much in its infancy. This, however, does not mean that “there is not a lot of oil there,” as Dennis asserts.
Take the Jo Mill, for instance. Since 2014 Pioneer has completed 5 wells in the Jo Mill over a broad geographical area (see attached map).
The first two, completed in 2014, have already produced 200,000 BOE and 220,000 BOE in the first 630 days of production. The best wells, however, were completed in 2016: one has produced a cumulative of 180,000 BOE in the first 240 days of production and the other 60,000 BOE in the first 75 days of production.
The cumulatives the Jo Mill wells have achieved brings us to a second issue with the USGS study.
If one takes a look at the study, its calculations are based on the following EURs:
However, even Dennis concedes that the wells completed in the Permian Basin in 2016 had an average cumulative production during the first 12 months of 119,000 BO.
http://peakoilbarrel.com/world-crude-plus-condensate-and-conventional-oil/#comment-604752
The EURs used by the USGS in its study, therefore, are obviously way too low.
Hi Glenn,
The study probably used older data for Permian wells, but often the more productive early stages of output simply pull production forward to the beginning of a well’s life with very little increase in overall EUR. This can be seen by looking at the Bakken well profiles at shaleprofile.com.
The well profile I use has an EUR of 280 kb and I assume well productivity is flat from 2016 to mid 2019 and then well productivity gradually declines. The wells completed are about 6000 per year from 2017 to 2023, with 50,000 total wells competed by mid 2023 (roughly the peak output).
Hi Glenn,
To illustrate the changing well profiles in the Bakken the chart below shows 2013 to 2016 well profiles and after month 25 we can see they match pretty closely. Note there was very little change in the average well profile from 2008 to 2013.
Note the chart from this comment and the next is from
https://shaleprofile.com/index.php/2017/05/13/north-dakota-update-through-march-2017/
The cumulative well profiles are in the chart below.
The 2016 average well EUR may be about 16% higher than the average 2014 well EUR. The average 2015 well EUR is about 8% above the average 2014 well EUR. This assumes the 2015 and 2016 wells do not cross below the 2014 well profile in the chart above. That assumption may be optimistic.
have you looked at the recent gross oil addition per new horizontal well data from rystad? looks like it could have already peaked..
Dennis, Do you think they are being more efficient at capturing more of the initial transient? So sharp sometimes that depending on the width of the measuring period it could vary all over the map.
Hi Paul,
These are averages for many wells (usually over 1000 per year) so although there is quite a bit of variation from well to well, the overall yearly averages have not changes very much from 2008 to 2014, there was a bit of a bump for the first 24 months for the 2015 wells and the first 15 months of the 2016 wells, Fernando has suggested that the overall EUR might not change and that the gains in the early months might be offset by lower output in later months, this implies that the monthly well profile (not the cumulative profile) for 2015 and 2016 will drop below the 2014 well profile in future months. In other words there is only so much oil there to be produced, the newer wells with more frack stages and more sand and water just produce the oil faster without increasing the recovery factor. We will have to wait for more data to see if this is the case.
they could produce more because of longer laterals. but then you have to temper spacing assumptions.
Yup, recall that when modeling the extraction, if we use diffusion theory, there is a huge transient at the initiation which comes right out of the diffusion math. So diffusion has a sharp initial spike and a fat tail. The tail of the diffusion contains much of the volume so that may not change much but how the spike gets measured will effect this chart.
Hi WebHT,
I have been using an Arps type hyperbolic decline to model the decline, so I misinterpreted your question. It is unclear whether the diffusion model fits the data well over the early part of the well’s life, first 24 to 36 months and using a hyperbolic model transitioning to exponential decline at roughly 8 to 10 years or so.
There are two separate completion innovations that are having an impact on production and curves these past few years, diversion processes and – most recently – the introduction of micro proppants (200/400 mesh ceramics).
The degradable diversion material temporarily blocked fissures, allowing pressure buildup and new fissures to form.
This ‘near wellbore’ approach allowed much more comprehensive ‘rubbilizing’ of the formation.
Shortly thereafter, engineers developed ‘far field’ smaller degradable proppants to inhibit the unwanted spread of fractures.
This enabled a much greater degree of control over the size of the frac’d area.
When elevated hydraulic pressures cause fractures to form, the majority of fissures are too small for even 100 mesh to enter. The 200/400 can.
These smaller sizes are said to double the reservoir volume that can be stimulated/propped.
An additional consequence is the lengthy, minute passageways will extend the production tail significantly.
The recent presentation by the CEO of Core Labs elaborates on all this.
Hyperbolic is really diffusional to some degree, just a heuristic that is often a bit more handy to use. All these statistical models reduce to power laws, which is what the diffusional and hyperbolic models represent.
Dennis Coyne,
Wow! What a wealth of information Enno Peters has put together there.
But why the switch to the Bakken, because Peters’ Permian Basin data tells a different story.
.
Hi Glenn,
The Bakken is a more mature play and you had suggested there has been a big change over time with improved fracking methods, not really the case in the Bakken and Eagle Ford.
Yes there has been a great deal of improvement in the Permian from 2013 to 2016.
Notice how the 2013 well profile (not the cumulative well profile) falls to the 2012 well profile at about month 40. The 2014 well also looks to fall to the 2013 well level at around month 36. We will have to wait and see on the newer wells. Eventually the well profile will reach a maximum, my guess is around 2019. Maybe at 300 kbo for maximum EUR, but then well productivity may start to decline. Hard to guess for sure when that will occur.
It will occur, if we assume the character of oil fields has not changed.
Mike, shallow sand, Fernando, George Kaplan, and SoLaGeo would know better than me cause those guys have actually produced some oil, I just put gas in my car. 🙂
–
Hi Glenn,
A similar increase in the Bakken was seen from 2005 to 2008 where well productivity doubled, then there was very little progress beyond that.
Dennis,
I don’t know about that.
It doesn’t look like Bakken well productivity has done so bad since 2008.
The Bakken, however, has a whole slew of strikes against it, including:
• High transportation cost.
• Most of the Bakken operators shot their wad back when oil was $100, so now lack the capital to drill new wells.
• It’s a mature basin, so the inventory of new drilling locations is limited and there are fewer possiblities for high grading.
• Limited possiblities for pad drilling, which substantially reduces drilling and completion costs
• Hostile climate
Hi Glenn,
The Bakken well profile was essentially unchanged from 2008 to 2014, with a small increase in 2015 to 2016 (probably due to high grading to the core sweet spots).
The point you seem to be missing is that the Horizontal drilling started in 2005 in the Bakken and by 2008 they had more or less optimized with very little improvement in well productivity beyond that.
The Eagle Ford has seen some marginal improvement in well productivity (horizontal drilling and fracking picked up there in 2011), but from 2015 to 2016 increased well productivity was quite marginal and was also likely subject to high grading due to low oil prices.
The point is that the Permian will also reach a maximum well productivity within a few years (probably before 2020), we can only guess what this will be. Also keep in mind the oil in the Permian Basin is limited, more productive wells just drain the tank faster, not many wells will be profitable at $45/b.
You would be wise to talk up oil prices, unless you prefer small royalty checks 🙂
Note that looking at the first 14 months, that is likely to be the total increase for the entire cumulative well profile as the higher initial months quickly decline back to the 2008-2014 average well profile. So over 3 years the well profile increased by about 36 kb for a 320 kb EUR or roughly 12% over 3 years or about 4% per year, this is mostly due to high grading in 2015 and 2016.
Dennis,
I would “be wise to talk up oil prices”?
And just how am I supposed to do that? The same way you have made the shale oil revolution go away with talk?
Hi Glenn,
You would do that by a recognition that Permian output is not likely to rise enough to offset the cuts of 1.8 Mb/d by OPEC, Russia, and others by 2018.
I have never said the shale revolution is going away in the near term, in fact my US LTO scenario is more optimistic than the EIA’s AEO2017 reference scenario for tight oil through 2021, the difference is that I use the expectations of the geologists at the USGS rather than the economists at the EIA to estimate future economically recoverable resources(ERR).
In addition, World unconventional resources such as extra heavy oil fro Canada and Venezuela will take a long time to develop and will not be able to stop decline after 2023 when US LTO starts to decline fairly rapidly, perhaps output from LTO outside the US will ramp up just in time, but that seems very optimistic.
So it is only a matter of looking at World reserves and depletion rates (roughly 2.2% of conventional 2P reserves were produced in 2011). If discoveries plus reserve growth are equal to output each year (on average) and the depletion rate (production divided by remaining reserves) remains constant, then a plateau in output could be maintained forever.
Increasing output requires either increasing discovery plus reserve growth over time or an increasing depletion rate.
Eventually limits will be reached where discovery plus reserve growth increase falls below output which might allow a plateau to be maintained by an increased depletion rate, but this will also reach a geological and technological limit and output will decline. From 1988 to 2015 the average depletion rate was 2.28% (using BP data) with a range from 2.17%(1991) to 2.36%(2015) for C+C+NGL less extra heavy oil.
Models can easily be constructed using reasonable depletion rates from historical data and current reserves and cumulative production. A model that peaks in 2025 at 35 Gb annual output would have a URR of about 3600 Gb under reasonable assumptions.
Hi Glenn,
It occurs to me the cumulative well profile has only increased by about 20% from 2008 to 2014 or about a 3% increase per year on average over that time. The larger increases were from 2005 to 2008 when well productivity increased by 46% over a three year period. The Permian’s big increase in well productivity from 2013 to 2016, may be similar to the Bakken increase from 2005 to 2008. If the Permian is able to match the Bakken rise from 2008 to 2014 over the 2015 to 2021 period, then EUR might increase to 336 kbo over those 6 years (about 20% higher than the average 2015 well). We will have to wait and see how the 2016 and later wells perform over time to make a judgement.
Dennis,
You go to great pains to explain why the shale revolution shouldn’t be happening at $50 oil, that it doesn’t make economic sense.
And yet the shale revolution surged forward when oil prices rose above $40 per barrel, and gained strength with every passing day as prices inched towards $50.
Why do you believe that was?
And your efforts to talk down the shale revolution, what effect did they have?
After months and months of rising LTO production in America and the beating that conventional working interest owners/operators have taken with falling oil prices as a result, I have had a belly full of your shale oil bullshit, Mr. Stehle.
“And yet the shale revolution surged forward when oil prices rose above $40 per barrel, and gained strength with every passing day as prices inched towards $50.
Why do you believe that was?”
Its a simple answer, hand: your “revolution” is still limping along, after years of the worse economic performance in its history…on the backs of other peoples money.
Nobody in the shale oil industry is remotely profitable enough even at $50 to now work off net cash flow and get out of debt. Its borrowing more money, selling assets, bankrupting out and starting over, diluting shareholder equity, and kicking debt maturities years down the road, anything it can do to stay afloat hoping for the miracle of higher oil prices. And get this, at the same time it is doing everything it can to keep the price of oil low and volatile with its out of control spending spree. As Forrest says, stupid is as stupid does.
Why is it the shale oil miracle is still working, so you seem to think?
Its not working. It never worked well. If it was profitable at $90 dollar oil it would have stayed out of debt. At 50 dollar oil it will NEVER get out of debt. The shale oil industry can not stand on its own two feet without other peoples money to borrow!
You know that; its just not in your best interest to admit it. The only reason you promote its sustainability is because you depend on it. I am blessed to have RI and ORRI in shale oil wells also, just not to the point I can’t think for myself and determine that the shale oil phenomena, and that is all it is, is woefully unprofitable for the folks paying the bills.
Hi Glenn,
Yes I use basic economics to show why the average LTO well in the US will lose money.
Generally smart investors do not invest in something that is likely to lose money.
This assumes people are rational.
In the US LTO industry, there are not many rational people, apparently. 🙂
Mike,
I am sorry that the shale producers have rained on your parade.
But sometimes things happen that are out of one’s own control.
Dennis,
So what?
Even if your analysis proves to be correct, which I doubt it will be, has it slowed down the shale revolution one iota?
There are others who have a much bigger soap box than you do, and a hell of a lot more money, and they happen to disagree with you.
Hi Glenn,
Correct. There are many different opinions on this.
My opinions are based on the data we have on output and the analyses by the USGS, as I have pointed out my analysis through 2023 is slightly more optimistic than the EIA’s AEO 2017, I doubt output will be any higher than that.
If LTO is as plentiful as you seem to believe ( where pretty much any hype seems to be taken as correct), oil prices are likely to be very low and earnings will continue to be negative for LTO companies.
Perhaps you believe this can continue indefinitely?
I do not. If oil prices remain at $50/b or less until 2023, US LTO output will not rise to 6.5 Mb/d, it will probably not make it above 5.5 Mb/d due to lack of profits, it might not even make it past 5 Mb/d.
Higher prices, ($80/b) might enable output to rise as high as 6.5 Mb/d, it will depend on future price expectations and OPEC spare capacity.
I expect supply will run short and prices will rise by at least 2020, possibly to $100/b or more. The World peak in C+C oil will likely be between 2020 and 2030, a precise date is impossible to predict.
,
How about the Hz Wichita wells Apache operates in the Three Bar Shallow Unit in Andrews Co., TX. Nearing 5 million BO and 10 million MCFG from 40 wells, which I presume cost much less to D & C than the zones mentioned above.
Those wells had first production in 2012-15, yet I hear much more about Alpine High.
Still think Oxy’s West Sundown Unit in Slaughter Field, Hockley Co., TX is worth following. Production is increasing, not declining.
not to disagree blankly, as these ARE somewhat early days (if you assume verticals haven’t drank some of that milkshake already), but these various horizons could be a bit like 3F in Bakken – everybody was super excited 2 years ago and not so much anymore.
Hi Glenn,
Data on 5 Jo Mill wells tells us very little, I am sure they chose the best 5 wells they have to present and then claim these are “typical”, are you really that gullible? I don’t buy hype.
Of course you don’t buy the “hype.” If you did, then you would have to give up the mantle of peak oil now advocate.
Hi Glenn,
As I have pointed out there are numerous studies pointing to a peak from 2020 to 2030, 2025+/-5 years seems a reasonable guess. If 2025 is now then you would be correct.
See
http://www.ukerc.ac.uk/publications/global-oil-depletion-an-assessment-of-the-evidence-for-a-near-term-peak-in-global-oil-production.html
From the executive summary of the report linked above:
For medium to long-term forecasting, the number and scale of uncertainties multiply making precise forecasts of the timing of peak production unwarranted. Nevertheless, we consider that forecasts that delay the peak of conventional oil production until after 2030 rest upon several assumptions that are at best optimistic and at worst implausible. Such forecasts need to either demonstrate how these assumptions can be met or why the constraints identified in this report do not apply. On the basis of current evidence we suggest that a peak of conventional oil production before 2030 appears likely and there is a significant risk of a peak before 2020. Given the lead times required to both develop substitute fuels and improve energy efficiency, this risk needs to be
given serious consideration.
In the report they define “conventional oil” as C+C+NGL output with API Gravity >10 degrees and they exclude LTO output.
LTO output and extra heavy oil output might delay the peak by a bit, but extra heavy will take a long time to develop and the 50 Gb of LTO that might to be produced by the US will be a drop in the bucket relative to a World URR of 3800 Gb of C+C+NGL.
We’re dealing with a complex system that involves economics, politics, and many other moving parts. Heck, the geology and well productivity are the easy parts, and they’re far from easy.
One would be lucky to predict what’s going to happen next year in a complex system, much less what’s going to happen 5 or 10 years from now.
I don’t think he gets it.
Hi Glenn,
Read the paper. Of course it is complex. That is why it is not possible to predict a precise data for the peak and why a 10 year window is the best they can do. It will depend on economics, politics, geology, and technology and how these interact.
Consider a capped water bottle thrown in a stream, the precise path of the bottle on the stream’s surface is unknown, but one can be pretty sure of the general direction of the bottle (it will move downstream).
Given what we know about conventional oil resources, the rates that they are extracted and the natural decline rates of post peak fields, it is pretty difficult to create a scenario where the peak occurs after 2030, and if the peak is close to 2030, conventional output will decline very rapidly.
What is your estimate of World Conventional Oil URR (exclude extra heavy oil with API gravity less than 10 degrees, kerogen, and LTO)?
Shallow
That shipment last week from Corpus on a VLCC – 2.2 million barrels – was a trial run.
With offshore lightering, operators will be ramping up this method somewhat rapidly impacting Brent, as well as everything else, I suppose.
The downtrend in US crude oil stocks still looks intact, even after this weeks 3.3 mb increase.
There’s a chart for everything on twitter: https://pbs.twimg.com/media/DBuuasAVoAA4fa-.jpg
9 charts including exports
https://pbs.twimg.com/media/DBuce7QXYAAFgzI.jpg
To the “wise guys” on this forum .
Is this “All bullshit ,no bull” or is there some punch in this ? Is this a game changer or hype ?
http://www.zerohedge.com/news/2017-06-07/saudi-america-%E2%80%93-how-new-tech-creating-another-oil-boom
They don’t explain how it’s done. How did they make it cheaper, magic waves? Asphalt is a highly viscous liquid or a semi-solid. It takes a lot of energy to liquidise it enough to make it flow through a pipe. https://en.wikipedia.org/wiki/Asphalt
100 mmbbls isn’t very much – I doubt Saudi is too worried. I guess they are talking about sound waves are they? Difficult to follow as Energy News said, but I think the idea may be to stimulate the oil in the pores with the sound frequencies, and then carry them away with steam; I don’t think that will be particularly cheap compared with a conventional oil reservoir, maybe compared to a new and deep SAGD oil sands development though. I don’t know what the S-BRT one is – looks like it might be in-situ gasification.
How come it’s only Saudi that is supposed to get worried with these new things, there’s a lot of much more expensive oil being produced than they have which would feel the impact first.
Hi George
Zenith energy have finally finished drilling the side track on the M195 well in the Muradkhanli field in Azerbaijan. The original workover failed as the open hole section of the well was found to contain soviet era scrap metal fragments and the formation was damaged by primitive completion techniques.
Pre intervention the well was flowing 5 barrels per day. The new side track if flowing on clean up at 150 barrels per day and they plan to fit a pump. Could be one to watch they have a new COO and he has a good track record in country.
http://www.lse.co.uk/regulatory-news-article.asp?ArticleCode=ssk8i2ct&ArticleHeadline=Success_of_sidetrack_at_well_M195_in_Azerbaijan
H-I-H
Wanna super fast, slam dunk response to your query?
Go to oilpricedotcom, scroll down left side under heading “SPONSORED Articles”, mull that over, oh, say, half a nanosecond … and then you can decide.
Coffee, I read that ,but was intrigued and so asked for a second opinion from the “wise guys”.tks
It’s baloney.
Oilpricedot com also promoted some miracle solar cell recently, pure B.S.
This $10 Stock Will Unleash the Greatest Leap in the History of Energy…
And Its Stock Could Hand You 20,280% or More.My name is James Stafford.
I’m the Founder and Intelligence Director at OilPrice.com.
I know that a 20,280% gain (that’s over four years)
https://oilprice.com/er/transcript/179
Sonic waves liquidising rock bound asphalt sounds just as plausible.
People who aspire to make America like Saudi Arabia are pretty obnoxious.
Given how expensive bitumen production is said to be, I was surprised to see that activity has recovered so quickly especially as oil prices are still lower than I thought were needed. This chart is for in-situ steam recovery in Alberta, updated to March.
But I think it depends on what projects are being developed, and that was decided in the high price years. This year there are Mackay River and Hangingstone (maybe Horizon but that might be mined rather than SAGD), previously there was Surmount, Foster Creek, Kearl (might be mined as well though) and others. I think it takes a year or more to steam and start producing and while they are doing that they are continually drilling producer/injector pairs. I’d guess existing SAGD plants have to move out from the original area (also I worked for one company who had to redrill some as they were too far apart or in the wrong location so they didn’t get the production). Once the plant is in place it almost always makes sense to keep it as full as possible so the same economics do not apply as to new projects. Note after Fort Hills and Horizon this year there is not muchelse on the … er … horizon, so I’d expect drilling to decline even if prices recover.
After Fort Hills and Horizon there are very few or maybe no mining oilsands projects on the horizon. As costs have come down in the oilsands, SAGD projects have been announced. Cenovus Foster Creek additional phases for one. I believe this is what the industry is expecting for the future of oilsands. Small add-on projects to existing SAGD operations.
The CAPP report from last June, at link below
http://www.capp.ca/publications-and-statistics/crude-oil-forecast
CAPP=Canadian Association of Petroleum Producers
Last year’s report was released on June 23, 2016, hopefully a new report will be out before month’s end. Any Canadians out there who would like to do a brief post on it when it comes out? Let me know here or at peakoilbarrel@gmail.com
Looks like the cowboyistan shares are at or near 52 week lows. Will we see investors stick with them if we have a double bottom in WTI?
If you are an investor, will the allure of E & P’s that have a forward looking P/E around 100 at $50 WTI continue as WTI heads below $40?
Might not be a bad idea for Russia and OPEC to open the spigots right now.
Would be interested in AlexS view in this regard.
PDX has a market cap of $30B, with a big ‘ol B; the best it could do 1Q17 was to fabricate a $66M ‘free’ cash flow number (whatever the hell that means with $2.7B of long term debt), from somewhere, with some funky non-GAPP accounting methods I’ve never seen before, and that’s a good thing?
Well, that’s the best the shale oil business has to offer these days, after three consecutive years of losses.
Morgan Stanley said this 5 June 2017: “Over the past 18 months, public US E&Ps have raised $40bn in equity and realized $60bn in asset sales. We note that this may include some degree of double-counting from asset sales among industry players, but it also excludes debt financing and equity injected into private companies (which have been responsible for 50% of the incremental rig count increase vs. the trough). Regardless, it is obvious that the capital injection has been massive by any historic measure. The rationale for drilling has been driven by Wall Street factors and not by economic returns or internally generated cash flows.”
Never let profitability stand in the way of productivity, not with OPM, no sir. Giddy up !
Hi Mike,
Great to have you back.
Just so everyone knows, I messed up something that was inadvertently blocking Mike from posting for about a week.
Sorry folks. I was tearing my hair out trying to fix the problem and I finally figured it out. I always want to hear what Mike has to say, I learn something every time he comments. Thank you Mike.
Mike: I am just wondering if there will be some more Whiting’s as we see WTI struggle to stay above $50.
When I first showed up here, and for most of 2015, Whiting was getting the hype for more productive wells, increased frac stages, more sand. Seems like coffee was touting a 103 stage well back then.
Whiting closed at $6.11 per share, off 11.45% today. That is down from $92 back in 8/14, but also down from $38 in 5/15.
Maybe those Permian cowboyistanis have figured out something the Bakken brethren haven’t. Oasis is at $9. CLR is $35 due to OK, but was at $58 six months ago. SM doesn’t even mention the Bakken in investor presentations, but the street knows they have it, off 12.17% today at $16.74, was $58 in 5/15 and $39 six months ago. QEP is also trying to keep their Bakken position a secret, but closed at $9.68.
Their aren’t as many EFS specialists, but SN dropped 12% to $6 today.
PXD is hanging in there. $165. Was $199 2/17. $232 6/14. Will it be a Whiting, or is this time different?
Of course Halcon was a heavily hyped Bakken and EFS player. The pre-petition common shareholders received 4% of the common stock of the reorganized company. Floyd Wilson is still CEO. He is getting $24 million a year now, more than in 2013-2014. Pre-petition shareholders got a 1 for 34 reverse split, with the stock closing today at $5.93. In 2014 it traded at a reverse split adjusted $1,200+ per share.
I seem to recall PXD’s Sheffield touting Permian 5 million bopd. Seems Hamm said Bakken 2 million bopd in late 2013. That isn’t all that long ago.
Things can change fast in the world of shale. Heck, they added 4.6 million bopd in no time, crashed over 1 million bopd in a year, then have rocketed back up almost there again.
Shale trades higher per BOE in the Permian than XOM per BOE, assuming zero value for all of XOM’s refineries, chemical plants, pipelines, and cash. It used to in the Bakken and EFS too.
PS to Mike. We like being checkbook oil producers. Our friend needs to copyright that term somehow. A dying breed if there ever was one.
Hi shallow sand and Mike,
It does seem strange that someone who claims to collect royalty checks would be cheering for lower oil prices. As a simple example, higher output may be nice (bigger check), but if output doubles and the price is cut in half as a result you do not come out ahead as a lease holder. Or do I not under stand this correctly?
Dennis, you are correct.
However, first and foremost, an owner of minerals wants them developed. Of course, no income until leased, and no monthly income stream typically until developed.
An example. If I own all the minerals and one shale well is drilled, and produces 100K of oil in the first year, and I own 1/4 RI, I am receiving pre-tax over $1 million. It is like winning the lottery.
New York mineral owners are incensed about the states fracking ban. Many financially strapped farmers and others who would be bailed out by development of their minerals, even at very low natural gas prices.
Easy to see why it is political for Glenn and TT. Bernie Sanders is anti-oil, same with most left leaning politicians. No fracking = those guys minerals are not developed.
While you, Mike, me and others look at profitability from an operators view, Glenn and Texas Tea are looking at it from a mineral owners view. Yes, lower oil = lower income, but they are better off that the wells get drilled at $30 WTI than not at all.
Glenn and TT don’t give us nuances. They appear to want more oil drilled everywhere, not just on their properties. And by continuing to say we have unlimited oil supplies, that talk promotes lower oil.
Their comments don’t add up for either themselves or anyone else who hopes to make money from oil production.
In Colorado few homeowners own mineral rights and I don’t think many farmers do, either. So there is a lot of push back when drillers want to get close to homes and schools. With no royalties coming to them, most people see little benefit. And with the state having the lowest unemployment rate in the country, no one sees oil and gas as a needed economic boost.
The Permian boom as a been a good thing in Colorado because there is less interest in drilling here than there was before oil prices collapsed. Some of the money has gone elsewhere.
Hi shallow sand,
The oil industry did pretty well from 2008 to 2014 with a “left leaning” politician in the White House. You don’t blame the fall in oil prices on Obama, do you? That was simply a case of too much oil on the World Market, maybe in part because the US oil industry expected that OPEC would be willing to cede market share to the US, which was incorrect.
Do we have any idea how many barrels were hedged at $55/b?
Nobody, I repeat NOBODY, remotely associated with the worldwide oil industry, particularly the domestic oil industry in America, is cheerleading for lower oil prices.
If you are a roughneck employed by H&P worried about job security, a stripper well operator in Kansas, or little more than a day trader flipping shares of CHK, you want HIGHER OIL PRICES. If you are one of several hundred thousand good men and women still out of work in America’s oil industry, you’d get on your knees for HIGHER OIL PRICES and the chance to go back to work. If you provide services to the oil industry, own a motel in Karnes City, a beer joint in Williston, or a taco stand in Pecos… you want HIGHER OIL PRICES. A private equity lender with all your eggs in the shale oil industry basket? You desperately need HIGHER OIL PRICES. School districts, county taxing authorities, entire state budgets rely on HIGHER OIL PRICES. If you are an operator, or a working interest owner that must pay exploration and production costs, you are praying for HIGHER OIL PRICES. Even the US LTO industry needs HIGHER OIL PRICES, its just too stupid to know how to achieve them. If you are a royalty owner, or an overriding royalty owner, that receives mail box money, free and clear of all costs, of course you want HIGHER OIL PRICES; you don’t want to see all of your grandpa’s minerals produced at $40 oil, and depleted, forever, when $65 is better. Not if you have a family to care for in the future.
And nobody should be very surprised to hear that if you are actually IN the oil business you don’t particularly give a rats ass if the American public pays $2.39 a gallon for gasoline, or $3.19. America has done very little with the windfall from lower oil prices the past 3 years other than… buy more gasoline. HIGHER OIL PRICES ultimately lends itself to conservation of our remaining hydrocarbon resources and ensures a healthy oil industry that can service America’s oil needs way into the future, past this temporary oversupply.
If you claim to be in the oil business and think lower oil prices is a good thing, you need to get your swivel re-packed ASAP.
Heck, we even have a trust set up by a retired school teacher, now deceased, that consists entirely of oil royalties, that pays the income out in the form of scholarships for deserving college students.
Was over $50K per year for awhile, now it’s around $20K.
Dennis,
Since when is being a realist or a pessimist about future oil prices the same as “cheering for lower oil prices?”
Those like myself who lived through the oil price crash of the 1980s learned from the school of hard knocks to be pessimistic.
I think many of those drilling shale wells in the Permian Basin are fairly pessimistic too. If not, then why did so many of them hedge their 2017, 2018 and 2019 production back when oil was in the $50 to $55 range?
Hi Glenn,
You consistently say low oil prices are a good thing for Americans.
Here’s the problem. Low oil prices lead to a lack of investment and the lead time for many projects is quite long (3 to 5 years), World Oil Supply will not be able to meet demand without adequate oil investments and this will lead to oil price volatility.
So the problem for the unsuspecting American that listens to the cheerleaders who claim that the US is the new Saudi Arabia is that they buy a new Chevy Suburban or Ford Expedition because gas prices are so cheap. When the cheerleaders are proven wrong and gas prices are $4/gallon or more, those people are stuck filling up at $100 per tankful an extra $2000 per year.
The low prices are good while they last, but they won’t last long.
Even if the US hits a new peak in crude output at 10.5 Mb/d, crude inputs to refineries are 16.5 Mb and we will not be able to import the rest from Mexico and Canada as they need to use some of their own oil.
CAPP forecasts about 1.5 Mb/d increase in Canadian oil sands output from 2016 to 2030 and Mexican output has been declining. World supply may be able to meet demand until 2020, but after that it may be a struggle just to maintain a plateau in World C+C output, though higher oil prices might help. (As it would both reduce quantity of demand and increase quantity supply for any given demand or supply curve.)
Hi Glenn,
Pioneer only has 20% of projected 2018 production hedged, they may be pessimistic through 2017 though with 85% of expected output hedged. Info from PXD June Investor presentation.
These producers are likely to be pessimistic about oil prices, if they believe their own hype.
The thing that does not add up, if they are profitable at $40/b as drilling info claims, why are all these companies reporting negative earnings? It doesn’t sound very profitable when GAAP earnings are in the red.
Hi shallow sand,
It’s pretty difficult to get all the players to cooperate so I imagine OPEC and non-OPEC countries that are cutting back will give the market a little time to balance.
It is not clear that Russia and the big Mideast OPEC producers believe the hype coming out of the US tight oil companies.
I sure don’t.
shallow sand,
If “WTI heads below $40,” the cowboyistanis are hardly the only ones who will be in a world of hurt.
How did that “opening the spigots” work out for Russia and OPEC last time?
.
Hi Glenn,
http://www.haynesboone.com/publications/energy-bankruptcy-monitors-and-surveys
Haynes and Boone has tracked 123 North American oil and gas producers that have filed for bankruptcy since the beginning of 2015.
…Haynes and Boone, LLP have been tracking and reporting industry developments in oilfield service restructurings. Our research includes details on 127 bankruptcies filed since the beginning of 2015,…
So about 250 bankruptcies since the beginning of 2015. If that was their aim, it worked quite well.
Anyone selling oil now that is paying LOE is not doing too hot.
WTI is below $46. 2016 it averaged $43, so not much better than 2016.
Natural gas is somewhat better than 2016, so that helps producers that are marketing associated gas.
I agree, I’m not sure Russia and OPEC can stand sub $40, that is why they cut.
The only way prices rise are #1, Wall Street and Main Street investors bail, or #2 prices stay low till it is clear that US production stops climbing, despite a high number of rigs working.
Maybe the investors will take note of #2 and choose #1. Or maybe they won’t.
Does anybody know if there’s movement on getting Keystone XL finished? There’s talk in Washington about a government move to prohibit Venezuelan oil imports, which tend to be heavy crude blends. I suggested to a couple of government types it would be better to forbid USA oil and refined product exports to Venezuela. The Maduro dictatorship would have a hard time complaining.
Not gonna go back previous thread to find comment. It was from a blurb about 2 something billion dollars into a hmmm puerto del la cruz refinery complex in Venezuela, funded by China and . . . get this, Goldman, scheduled to be online in 12 months, and is on schedule.
It’s designed to refine viscous Orinoco stuff and pretty big numbers, probably serve all of domestic consumption. This takes another step towards eliminating US leverage.
The question is, can Maduro or someone in the government, hang on that long?
China and GS are betting so— the genie is out of the bottle in Venezuela, and the odds of going back to US Client State status is slim.
All of my contacts are no longer in the country, so I have no primary information.
And all MSM news is useless, as we know from experience.
Horrific conditions for a populace.
The Puerto La Cruz refinery project has been going on for almost a decade. It involves adding facilities to upgrade the oil in the refinery’s front end. The process scheme is not proven at large scale, it’s based on work done in Germany by Veba in a joint venture with PDVSA. I reviewed the technology over a decade ago, and had discussions with the Veba engineers who had worked on the project (they had retired but we’re working as consultants). I’m not going to get into the details, let’s just say the original German idea seemed to be viable, and was proven up to 10,000 BOPD. The project pdvsa launched is a variant which hasn’t been proven at large scale, but I imagine a competent staff will work out any start up kinks within a few months.
On the other hand, this week we heard that portugal’s government is planning mass evacuation of over one hundred thousand Portuguese citizens living in Venezuela.
The protests against the Maduro dictatorship continue (today it will be day 72), the regime has increased the violence of repression, and also resorting to robbing protesters or destroying their properties. Luisa Ortega, the equivalent of a USA General Attorney, broke ranks and is actively opposing Maduro, who made the first moves to detain her. The problem for the dictatorship is Ortega’s red credentials and apparent support within the military.
On the legal front the resistance are moving to have a Spanish judge start an investigation which will focus on Supreme Court judge Gladys Gutierrez, a key contributor of the Maduro faction’s coup de etat (the judge got weak knees and fled Venezuela, nowadays is hiding in Spain). There are also filings against Maduro in the criminal court in The Hague.
The point is that Maduro’s survival chances are dropping, and even if he manages to “win” there won’t be much of a country left. I keep telling my friends that communists are hard core murderers and genociders, they are similar to the Nazis, therefore the peaceful protests should continue to see if there’s a reaction from the international community (we need sanctions on key individuals in both the Venezuelan and Cuban dictatorships, given that Cuba has tremendous influence over Maduro, and over ten thousand agents and military already in Venezuela).
I would expect Venezuela’s production to continue dropping, and sonetime this year, if the Maduro Mafia doesn’t give up, there will be moves to sabotage the oil fields and plants.
Fernando
The much publicized cross border federal permit was okayed a few weeks ago, but Nebraska is about 2 months off from giving state approval, if they do.
Legal challenges are a certainty no matter what happens, but TransCanada seems determined to forge ahead.
Capacity is 800,000 barrels/day and the Canadian operators are hoping for completion within a few years time.
I just got a message the Committees for Defense of the Constitution are almost structured, and a date for a national strike will be announced. I believe this will escalate into sabotage and possibly civil war.
Hopefully Trump will reinstate the sanctions on Cuba and request that all Cuban agents and military personnel leave Venezuela. In any case, that Canadian heavy oil will have to replace Venezuelan oil if this keeps escalating.
Any thoughts on the Qatar , Saudi fight ?
The border with KSA is about 35 miles wide. There are few highways north from there. Doha is 60 miles north of that border and on the coast. KSA’s 320 tanks are located mostly in the far north of Saudi Arabia. They will take weeks to get to the border.
The Saudi Air Force could bomb, but targets are a problem. The LNG port is like a giant bomb in and of itself. Hard to imagine KSA wants to kill all those people. In the modern world, the upside of having almost no military is an enemy has to bomb population centers since there’s nothing else to hit, and doing that will generate PR problems.
This morning Iran offered use of its ports to reduce the impact of the Saudi move prohibiting shipping from stopping at their own ports if a stop to/from is scheduled for Qatar. That undercuts the action. Overall it doesn’t look like KSA has any teeth in this matter unless they are willing to kill Doha residents.
Well said Watcher . How about another scenario ? KSA annexes Qatar (not very difficult) .After all they did go into Bahrain to quell the uprising . Trump / etc is wink,wink . Now we have an entity which is rich in both oil and gas to counter Russia .
Qatar doesn’t have an uprising. It has a government which refuses to bow to the Saudi king. This means Qatari resistance would be coordinated by its security and military (in Bahrain there wasn’t a united front).
I doubt the Saudis would open a military front on the East when they already have trouble genociding the Houthis in Yemen. But who knows? The Saudi leadership sure seems to be nuts and will eventually take the country to civil war and utter destruction. It won’t be pretty.
Turkey also has a military base in Qatar, so invading the country just has a lot of downside.
The USA has a military base in Qatar (one of my grandsons is in the USA military in that base). Maybe you meant USA foreign policy is a Turkey?
Qatar KSA had a small skirmish in 1992. KSA was implicated in a counter-coup in 1996 and 2005. KSA has no doubt had designs on Qatar for a while. The regional balance of power is gonna shift a little. Iran will capitalize on it. KSA will shit the bed.
https://www.theatlantic.com/international/archive/2017/06/qatar-gcc-saudi-arabia-yemen-bahrain/529227/
Turkey will move closer to Iran and Qatar.
https://www.youtube.com/watch?v=Q3t6NkVcyMA
Pootin’s fault … “The ubiquitous “Russian hackers” are now accused of providing the spark for a diplomatic fire between Saudi Arabia and Qatar.”
https://www.bloomberg.com/view/articles/2017-06-07/russian-hacking-in-qatar-and-putin-s-ambitions
Also of Interest is latest 2 WSJ Articles on US Oil Exports reshaping ” Vast Global Markets” .. At Least now it’s “Oil” … not “Crude” exports..
Longtimber,
Yes, it’s always those PESKY RUSSIANS causing all the trouble and riff-raff. It’s a shame the Russians haven’t learned how to over-throw governments like the PRO’s up in the White House, which at last count is over 30+:
https://williamblum.org/essays/read/overthrowing-other-peoples-governments-the-master-list
Of course, this is an OIL THREAD, so I have to make sure I stick something having to do with oil in it. I would imagine, the motivation to overthrow many of these foreign governments had less to do with getting rid of a horrible ruler, and more to do with putting in some CORRUPT LOUSY DICTATOR SLOB that would provide us with cheap oil.
Anyhow… we will continue to experience some of the most INSANE and gullible MSM PROPAGANDA in the U.S. before collapse takes down the GREATEST LEECH & SPEND SUBURBAN ECONOMY in history. Furthermore, I no longer put on the Mainstream Press… it’s a complete and utter CIRCUS… LOL.
The world now watching our media must be wondering… what in the living F*CK happened to the United States… LOL.
steve
Steve , believe me u r 100% correct . I am in Europe and the Americans living here believe the US is having a “Suicide wish” . The crazies have taken over the asylum .
Many of those of us in the US feel the same way.
Certifiably insane. Tough to watch when you know it’s gonna bite you sooner or later. Interesting times indeed.
The USA hasn’t had much of a foreign policy since the days of George Bush the father. It’s amazing. Reminds me of the fall of Byzantium under a line of really incompetent emperors.
Steve. It is awareness of weaken client states like Qatar (that host US base there) that desperately seeks opening lines to Moscow (scheduled visit on Saturday), which in turns gives MSM narrative of Russian hackers meddling ? That is all to it.
A why now? The war in Syria is drawing to some frozen status quo and that Qatar gas should go somewhere. If not to Europe it will go to Asia via Iran.
This situation with Qatar is quite stunning considering that Qatar is not really a country but one huge gas field. The first one was Turkey that got out of NATO orbit as consequence of Syria war. German fighter planes had to be “forcefully” relocated from Turkish Inclirk base. So, things are unrevealing fast.
Shallow Sand,
While Pioneer’s Sheffield may believe that the Permian is going to produce 5 mbd of oil, it would be nice if they could make some fricken positive free cash flow with the oil they have been producing. Pioneer continues to spend more money on CAPEX than they receive in cash from operations.
Since, 2011, Pioneer Resources has reported consecutive NEGATIVE FREE CASH FLOW. For example,
Free Cash Flow:
2011 = -$760 million
2012 = -$1,218 million
2013 = -$730 million
2014 = -$1,210 million
2015 = -$1,145 million
2016 = -$562 million
2107 Q1 = -$155 million
So, maybe some of these oil CEO’s may finally have to start speaking out of their MOUTH rather than their ARSE.
steve
Steve. I think investors should be the ones paying attention. As long as there are naive investors out there, the CEO’s could care less.
See my Floyd Wilson Halcon example above. He is getting $24 million a year in salary and other compensation. The pre-petition investors experienced a 1 for 34 reverse stock split that took one post-petition share from over $1,200 in value to $5 and change today. Is that not a loss on paper of over 99%? It is better than Sandridge, who’s pre-petition shareholders got $0.
Whiting is not looking good if things keep heading South on oil price. Again, read the hype headlines from 2012-2014, Whiting was the bomb. Even in 2015, they were going to technology and efficiency their way through the low price environment.
I wonder how many CEO’s own overrides in company operated wells? Didn’t McClendon do that? Doesn’t matter if the well ever pays out if you own an ORI.
Shallow,
Yes, McClendon did do that as well, from what I remember. McClendon also did a lot of other nefarious things which eventually made him end up crashing head-on 60 mph into a bridge over pass.
GOD HATH A SENSE OF HUMOR…
steve
Every time someone comes here and posts info about companies that are going to make a killing in gas and oil, I assume there is some connection to bilking gullible investors.
Boomer II,
That last time U.S. oil Industry (not individual companies such as ExxonMobil) made a real KILLING is when John D Rockefeller and John Jr. were running Standard Oil.
I may be exaggerating a bit, but the companies producing shale today have been LOSING THEIR FRICKEN SHIRTS for nearly a decade. Unfortunately, they were we able to send the BILL to the poor slobs managing the PENSION MARKET as well as other industries such as the INSURANCE SECTOR.
From what I have read, the Insurance sector, needing a high return or its business model goes down cesspool, has been also investing in the WONDERS of Shale Oil & Gas.
I am certainly glad that I have not pinned my retirement to any of these sectors.
steve
I’m not a gold bug, but one thing for damned sure I am sure of. SRSrocco is dead on about putting faith and confidence in the managers and sellers of advice of the stock and bond markets.
Back when I was just a kid, I listened in on a conversation among some adults about what they did for a living, where they worked, at what, and so forth.
A little later, the older relative I was with for the day explained life to me in these words, paraphrased.
If you ever want to get anywhere in this world, you work FOR YOURSELF. You can and probably will have to sell your time and what you know, but never forget, you work FOR YOURSELF.
I’m not rich by any means, but keeping that thought in mind has enabled me to avoid making a LOT of serious mistakes, and enabled me to make a decent number of investments, small to be sure, but nevertheless investments that have paid off very handsomely indeed. It’s been quite a few years since I had to kiss anybody’s ass for reasons having to do with money, lol.
Folks like Shallow Sand will almost always be ok because they either manage their own money, or at least make damned sure they know enough about the places they invest to keep from getting skinned.
I have good friends that would and do occasionally trust me with their very lives who have refused to take my advice about investing LONG TERM in residential real estate, preferring to take the advice of people they will NEVER know personally, because – Well, because they have been hoodwinked by the power of advertising, I suppose. Their stock brokers will never invite them over for an evening, or even say hello to them on the street, not knowing them.
One guy who was a perpetual renter did finally take the plunge with my encouragement, and has seen his initial three thousand bucks down payment grow into a quarter of a million, plus he has saved mid four figure money every year for over twenty years as a homeowner, compared to RENTING a more or less identical house across the street.
His fucking stock broker talked him into not trusting my advice to pick out another house, or half a dozen houses, as long term investments. He said my advice was worth what I was charging for it, namely nothing, lol. This broker has not done well enough for him to cover his fees and still match the average of the market. My friend would have done better to invest in index funds with very low overhead, lol.
My own bank recommends certificates of deposit as EXCELLENT investments. I can’t think of any thing I habitually buy that doesn’t go up faster than they accumulate interest, excepting petroleum products over the last few years.
I can’t help but believe, sometimes, that there is some sort of unspoken and unwritten intent originating from the highest levels of government and the banking and stock and bond industries, etc, to keep the tight oil business up and running and producing.
This could go a LONG way towards explaining why we don’t hear anything significant from the supposed watchdogs that are SUPPOSED to keep bankers, stock and bond brokers, etc, from screwing us, when it comes to the money flowing into the tight oil industry, which is according to the expert consensus here in this forum, NEVER going to be repaid.
The banking industry, the stock and bonds industries, and whoever controls the federal government, D or R, at any particular time in my estimation don’t give a flying fuck at a rolling donut about the people who are either workers or investors in the oil biz, because there aren’t that many of them, compared to the general public.
What all these folks, the ones who control or at least exert SOME control over economic matters, want is for the economy to hum right along. If one industry, especially a smallish one, is bleeding out, but that loss is blood fertilizer for the REST of the economy, that suits them JUST FINE.
Cheap oil is entirely consistent with the overall desires of all the WESTERN elites, excepting those members of the elite who happen to be heavily involved in the oil biz.
It weakens our real or perceived enemies that are exporters, it boosts the sale of larger domestic cars and trucks, it encourages optimism in relation to the economy which in turn means people are willing to borrow, and to lend, etc, etc.
Cheap oil is unquestionably GOOD for the economy, short term at least. It means just about everything is cheaper, from bread to bullets. Long term – well that very phrase consists of TWO FOUR LETTER words, lol, from a politician or bankers pov.
OFM. Sorry if you have commented on him and I missed it. Have you read Joel Kotkin? If so, what do you think?
I live in the middle of grain farms, livestock farms, coal fired power plants, auto parts manufacturing facilities, oil refineries, oil and gas wells, ethanol plants and people who generally work or service one or more of the above.
22% voted for Clinton in my county in 2016, which was on the high end. Several were 12-18%. I know I am veering off course on oil, but I guess it is oil related that when electric cars take over, I figure at least 30% of the jobs here, including most of the higher paying ones, are toast.
Is the idea to just let the middle wilt and blow away? I suppose for now people still need to eat.
I’d be happy to take this to another thread, so sorry Dennis that I posted this to OFM here. I don’t see him on the oil side much anymore.
Hi shallow sand,
A suggestion is just to tell OFM you are responding in the other thread and put a link to that comment. I know it is a pain, but often one innocuous comment leads to a huge sub thread that makes the oil and gas thread unreadable.
So it’s ok, just try not to do it too much please.
Also OFM’s post was pretty oil related and you are responding directly to that, but maybe OFM and others could respond in the other thread.
OFM said:
The “expert consensus here in this forum” is an echo chamber.
Hi Glenn Stehle,
Just because we do not agree with you does not make it an echo chamber. An echo chamber bans dissenting views.
Dennis,
An echo chamber is a metaphorical description of a situation in which information, ideas, or beliefs are amplified or reinforced by communication and repetition inside a defined system.
Inside an echo chamber, different or competing views are underrepresented.
Banning dissenting views certainly can achieve this, but it’s far from being the only way that an echo chamber can come about.
I also tell people that it’s practically impossible to pay for good investment advice; if it is good advice, the advisor’s fees take all the profits.
I could be entirely wrong, but I think that McClendon had a WI.
You’re not, it was 1% WI across the board, anything CHK drilled, good and bad.
Sorry for the misinformation. There is a 2012 Forbes article which states 2.5% WI and he was not carried, but one time received a $75 million bonus to help pay for some of his Founders Well Program well expenses. He also received a nonrecouse loan from a private equity firm to fund these expenses.
I should have went back and read over previous articles on this subject.
I do not believe it was carried, no, but I am not clear on non-consent options and/or applicable penalties, etc., nor am I clear on how all that was resolved upon his departure from the company.
i might be mistaken but i think i saw an article somewhere where CEO bonuses are explicitly tied to production volume growth.
https://www.nytimes.com/2017/06/08/business/energy-environment/oil-north-sea-shell.html?_r=0
PeakOilBarrel Group,
Now that the oil price is trading in the $45 range, it seems quite likely we may head lower towards the high $30’s. Of course, when the market price of oil reaches $38-$39, then it makes perfect sense that the Shale Oil Industry will announce it can make a profit at $30.
With this sort of mentality, what is keeping the oil market price from going even lower towards $20? With the wonders of technology, I don’t see any reason why the U.S. oil industry (now Saudi America) can’t produce oil in the Permian for $10 a barrel.
It’s a shame the Oil Industry didn’t think of this sort of WISDOM earlier in the game.
steve
EOG already has said their Premium locations are profitable at $30.
Shallow,
I would imagine EOG would state their Permian locations are profitable at $30. And why wouldn’t they?? However, their FREE CASH FLOW was a NEGATIVE $49 million for Q1 2017.
Furthermore, the only years EOG enjoyed positive free cash flow was in 2013 & 2014 when the price of oil was above $100. So, it makes perfect sense that they can produce the Permian at $30.
According to the data, EOG suffered NEGATIVE FREE CASH FLOW for eight of the past ten years. The highest negative free cash flows were during 2010, 2011 and 2012:
Free Cash Flow
2010 = -$2,873 million
2011 = -$2,372 million
2012 = -$2,118 million
Then we had the BIG positive free cash flow years:
2013 = +$269 million
2014 = +$402 million
Then, EOG returned back to negative free cash flow
2015 = -$1,418 million
2016 = -$224 million
So, with the average WTIC price of crude at $51.77 for the first quarter of 2017, and with EOG reporting a negative $49 million in free cash flow for that quarter, it makes perfect sense that they can be profitable at $21.77 less than the average oil price for Q1 2017.
Oh, by the way.. I forget to mention that EOG’s Long Term Debt has ballooned from $1.1 billion in 2007 to $7 billion in 2016. It’s good to see that they made a KILLING producing that shale oil and gas.
Maybe I am missing something here… but have IQ’s gone totally F*CKED these past 10 years???
steve
Are we going to look back on this era as one of the biggest financial cons ever?
I suppose we won’t until we have another financial collapse like we did with the savings and loan collapse and the 2008 derivatives collapse.
Musical chairs. You lend, knowing how fragile everything is, hoping you’ll cash out before it catches you.
Shale stocks trade like tech stocks, till they don’t.
The Tesla run is really something. $370 a share close today. I just don’t know what to think about Tesla.
I think Tesla is overvalued, but it illustrates that many investors are more interested in tech companies with a potential future than in oil companies that mostly represent the past.
Stock market anticipates. $370/sh is probably a fair price for Tesla two years from now if everything is executed well… but the stock market anticipates.
A word about “breakeven prices,” then I need to go back to work:
I can actually make a case for $25.00 breakeven prices in the Permian here: $50 hedged oil – 7% severance and property (ad valorem) taxes – 25% royalty burdens – $2.75 G&A per incremental BO – $3.65 interest expenses per BO – $7.00 incremental lift costs per BO = $21.47 per BO, take home pay. *10K/Q & SEC filings.
So what? According to Drillinginfo, that includes leasehold, infrastructure and geophysical expenses in determining its Permian well costs, and actual drive-out frac costs for several 15M pound jobs I have personally seen from the Permian (that include the cost of fresh water and/or the treatment and blending of produced water with fresh water (minimal), AND flowback disposal costs, which always get shuffled into CAPEX well expenditures)…wells in the Permian cost $9.0M. At least. Check the investor presentation BS at the door and that’s a fact, Jack. $9.0M divided by $21.47 take home pay per BO = 419,189 BO to pay the well back, before one dollar of profit is actually realized.
As to the role associated gas and NGL plays in the revenue stream, I leave that at the door as well. Most of it gets pissed up a flare stack for the first 8-12 months of production anyway, but is mysteriously used in EUR determinations nevertheless, or if you can sell it, and infrastructure, marketing deductions and OPEX are included in the economic evaluation, the value of gas is a negative number. (Where is Rune Likvern when I need him?). And the BOE BS, as we all know, should 18:1, not 6:1. Folks can hyperventilate about BOE all they want, it changes the economics of a Permian well very little. Nobody really knows what wells cost out there because there is so much funky accounting that goes on. Knock of a half mil for all those 30 well pads if you must; it doesn’t change the picture much.
Productivity of Permian wells have increased dramatically, no doubt. Enough for all wells being drilled in the Permian to reach payout? I don’t think so, and neither does Enno Peters, who in his last data sets for the Permian says this on shaleprofile.com: “Extrapolating the curves for the wells that started in 2016, leads to a recovery of about 300k barrels of oil per well before they hit a production rate of 20 bo/d.” Use Enno’s tools and one can decide for oneself how many wells drilled in the Permian will actually reach UR of 419K BO. Fewer than 4% my research suggests.
Every producing shale oil well in America now carries the burden of legacy, long-term debt. The lower the production rate becomes for legacy wells, the greater that debt burden becomes on new wells. “Breakeven” is a totally meaningless metric in shale well economics.
Hi Mike,
Thanks. At about 280 kb for the average Permain well, I calculate “true” breakeven at about $70/b this includes a 7% annual real rate of return over the life of the well (a 9.5% nominal annual ROI assuming 2.5%/year inflation).
In my opinion if you can’t get at least a 7% real annual ROI for a risky venture like drilling an oil well, you might as well park your money in a mutual fund invested in the S&P 500, probably far less risk and an equal reward over 25 years. Many would argue that the 7% annual real ROI is too low and I tend to agree, 10% might make more sense.
I agree, 7% ARR is woefully insufficient on a $9M dollar, risked, investment. What’s the risk in drilling oil wells, even shale wells? Plenty that I won’t even bother going into. What bigger “risk” than oil prices collapsing 65% in 2014-2105, or even 18% the past three months?
More importantly, to be able work off net cash flow to drill more wells, the ultimate ROI must exceed 225%, minimum. I will not personally drill a well unless I am certain my ultimate ROI is at least 3:1. This current crop of shale oil operators are touting 125-150% ROI and think that is peachy.
Pretty much all that is meaningless now given the legacy debt loads these shale companies carry; Rune Likvern determined, for instance, with long term debt north of $4.5-5.0B the price of oil must be over $90 to manage that debt, and new debt.
Hi Mike,
If we use a wellhead price of $80/b and your numbers in the example above it takes 219 kbo for the well to pay out. If the average well has an EUR of 300 kbo (optimistic in my view), that is a net of 27% over the life of the well and would be much less annually after discounting. Clearly at $45/b this is a money loser and at $63.82/b at the wellhead, 300 kb pays the $9 million for the well.
This would be the breakeven for an investor who uses a discount rate of zero and assumes the rate of inflation is also zero.
A true breakeven (one that results in a reasonable ROI of 10%) would be about $85/b, perhaps more, I haven’t done the discounted cash flow analysis.
Edit,
Just did the DCF analysis with real discount rate of 7.5% per year and using Mike’s numbers. The breakeven wellhead price is $74.34/b with a nominal discount rate of 10% (assumed 2.5% annual inflation rate). This example is for an average Permian well with EUR of 282 kb over its life (215 months shut in at 10 bopd).
So this breakeven price assumes a real ROI of 7.5% per year.
If we assume discount rate of zero, the break even price is $58/b. A 2.5% discount rate (matches inflation) results in a breakeven of $63/b, 5% DR-$69/b BE, 10% DR-$79.5/b
all prices in 2016$.
For the well to pay out in 60 months (shallow sands rule of thumb) the well head price would need to be $82.5/b. For Mike’s more conservative 36 month payout rule the wellhead oil price would need to be $96.85/b. Mike’s rule implies a real annual ROI of 19% and shallow sands rule implies a real annual ROI of 11.5%.
$20/bbl gets interesting. It’s the price where oil starts actually being competitive with electric cars again. But who can *really* produce at that price?
This could rebalance the oil markets:
And someone has made a rather large wager that it might actually happen:
Hi Glenn,
A major war in the Middle east between Iran/Iraq/Syria on one side with Saudi Arabia, Kuwait, and UAE on the other with Russia and US supporting the opposing sides could take quite a bit of oil supply off the market, maybe 15 Mb/d, oil prices would go to about $300/b.
I certainly hope that is not what happens. But hey, America first, we can choose not to join the fight and let them duke it out, we’ll just ramp up output in the Permian basin 🙂
Dennis,
Well look on the bright side.
For those coveting collapse, this could be the way they finally achieve their much longed-for peak oil.
And besides that, just imagine what this could do for Telsa’s EV sales.
Hi Glenn,
I am not one who looks forward to collapse. My angle is to recognize potential problems of the future and to look for realistic solutions to mitigate those problems.
A gradual increase in oil prices over several years (say a 7% annual rate of increase) would enable people to gradually change their behavior, sharp spikes in oil prices are likely to lead to a recession that is the reason that $60/b would be better than $40/b with a gradual increase from there. We might see this by late 2017 or early 2018, if Permian output doesn’t rise too far too fast.
Frenzied activity in the Permian may keep prices low, but my guess not enough hedges were purchased to cover all the output so some wells will lose money (those that have to sell on the spot market).
Tesla will have no trouble selling the Model 3, demand will outstrip supply for quite a while at least through mid-2018, even at $2/gallon gasoline.
Dennis,
I know you are “not one who looks forward to collapse.” That’s more where the folks over at Our Finite World are coming from.
Nonetheless, have you ever heard of the phrase from Gramski, “the old is dying and the new cannot be born”?
Techno-optimists (like yourself) have a very well defined vision of what the “new” should look like. And this future does not include fossil fuels.
The Mexican billionaire Carlos Slim did a press conference recently where he talked about the “new civilization” and the “old civilization.” (minute 5:47)
http://www.unotv.com/noticias/portal/nacional/detalle/el-ing-carlos-slim-hel-dar-conferencia-de-prensa-este-viernes-495136/
Slim explains that he is a creature of the new civilization, and Donald Trump a creature of the old. Trump desires “a return to the past,” Slim says.
The old civilization ran on fossil fuels, and the new, its proponents believe, can run on renewables.
The problem for the techno-optimists, however, is that the old civilization just won’t die. And the reason it won’t die is because, for the majority of Americans, and Mexicans, the new civilization hasn’t worked out. It’s been great for a mass minority, but for the majority it’s been a bust. It’s resulted in more losers than winners. And nowhere can this be seen better than in California, the poster child for the new civilization, with its medicore economic growth and high poverty rates. (And, as can be expected, Slim is in complete denial of this reality.)
And so the old civilization and the new are at war, with neither side being able to gain a measurable advantage. The result is that Slim and his propaganda arm, the NY Times, and Trump are caught up in a Mexican standoff, with each trying to stare each other down.
When did this new civilization appear?
Ohhh ok… so like a film; flash-forward?
Hi Glenn,
I occupy a middle ground called realism. The fact is oil and other fossil fuel resources are not unlimited. So we need to become much more energy efficient and use far less energy, reducing population growth through more equitable income distribution, better education opportunities, access to birth control, and improved human rights for women would help here.
For those who understand science, there is also the need to reduce fossil fuel use to protect the environment.
Assuming fossil fuel use can continue to grow forever is simply wishful thinking by those who do not understand physics.
Dennis,
What does any of that have to do with predicting when peak oil is going to occur, an event that of course would give the proponents of the new civilization a measurable advantage?
Your comment is prescriptive, not descriptive.
As I have posted on the non-petroleum forum, it’s too late to stop what is happening around the world economically. You’re right that there is money to be made by proponents of the new civilization.
That’s capitalism for you. Creative destruction. There are a lot of companies and countries who see advantages in weaning off fossil fuels: less pollution, less need to import fuel, economic dominance in new industries, new sources of jobs, etc.
The alternatives to fossil fuels look attractive for many reasons. And whether or not peak oil hits soon or is delayed, people and money are moving beyond them.
You may be posting here, but the moneyed decision makers are making their decisions without your input. Utilities, for example, are moving away from coal no matter what pro-coal info is being put out. And natural gas sellers are happy about that because they can sell more product.
The transportation industry as a whole is seeing a future where there are many alternatives to business as usual.
Even if there is no peak oil for a long time, the signs point to a decline in the gas and oil industry. There’s not the predictable money in it that there once was. Investors see other, more attractive, alternatives.
So the “no peak oil” mantra doesn’t change trends all that much any more because the money is being attracted elsewhere. Yes, a new civilization where we have a different bunch of rich people and rich countries.
The timing of peak oil can be something that is discussed here, but the decisions being made in energy and transportation aren’t really tied to peak oil timing anymore.
What Boomer II says plus this:
Peak Oil is an umbrella term. The exact date of peak oil is not as important as gauging roughly how much oil will be available now and for every year in the future.
What Dennis is doing is using historical numbers and physical models to help gauge how it will all play out.
All Glenn is here to do is play gotcha games. It’s possible he does this because he is no longer a member of his high school debate team and needs an outlet.
Hi Glenn,
Read your comment it was a response to that which talked specifically about different visions for the future.
Fossil fuels will peak, the science suggests that may be good for the environment.
Even if that is wrong renewable energy will be cheaper than fossil fuels before long no point in hanging on to our buggy whips.
Dennis Coyne said:
Nice maneuver, Dennis, shifting the argument from the present to speculation about what could happen in the future.
This rhetorical strategy is exactly as Hannah Arendt identified in The Origins of Totalitarianism:
When “renewable energy will be cheaper than fossil fuels” and when peak oil will occur are future events.
They may happen “before long,” or they may not. The future is not known, and speculation is not the same as knowledge.
Hi Glenn,
The reason that things have not worked out for the middle class has very little to do with fossil fuels and more to do with the nature of capitalism.
There are problems with capitalism no doubt, but isolationism can hurt just as many workers as it helps, is raises prices and hurts those workers in industries that export their goods.
Poor tax policy is a major reason for the inequitable income distribution and I favor no loopholes for the wealthy and a much more progressive tax code, take 1945 tax code and adjust income brackets for inflation from 1945 to 2017 and then write into the tax code that the tax brackets are adjusted annually automatically based on either the CPI or GDP deflator’s change from one year to the next.
The middle class has been hurt by technological progress, I don’t think the average citizen would be helped by stopping that progress.
Well regulated capitalism (like in Scandanavian nations) is the best system we have come up with in my opinion.
Fossil fuels are not unlimited and are bad for the environment, these are basic facts.
Yes the future is unknown in detail, that does not mean reasonable scenarios cannot be created.
We could assume fusion reactors and warp drives are right around the corner, but that does not strike me as good planning.
Dennis Coyne said:
“The reason that things have not worked out for the middle class has very little to do with fossil fuels and more to do with the nature of capitalism.”
The “nature of capitalism” could have something to do with it.
But rising energy costs could also have something to do with why “things have not worked out for the middle class.”
And if that’s so, when “renewable energy will be cheaper than fossil fuels” and when peak oil will occur, these events would greatly impact the wellbeing of the average person on the street.
Open-ended predictions (e.g., such and such will happen at some unknown date in the future) are pretty much worthless for anything except religion.
Hi Glenn,
I have given estimates for peak oil (2020 to 2030) and electric transport is already cheaper than fossil fuel transport, for natural gas vs electricity for home heat and hot water, heat pumps are very competitive with natural gas, when that peaks, (2025-2035) electricity will be cheaper.
There are many places in the US where wind is cheaper than natural gas for power (plains states and Texas) and others where solar is cheaper than natural gas. As natural gas prices increase and renewable costs decrease there will be wider areas where natural gas can no longer compete in power markets. It is already the case that coal cannot compete in most US markets so coal may also peak between 2025 to 2035.
Energy prices have very little to do with the problems of the middle class, it is machines replacing people so that fewer factory workers are needed.
A lot of jobs can be created in the renewable power industry, both utility scale and distributed solar. There is also the need to create light rail and electrify railroads, more jobs. There is also a need for an integrated high voltage direct current (HVDC) transmission network, more jobs.
Knowledge is more than history.
Glenn accuses everyone of totalitarianism by suggesting that:
“Open-ended predictions (e.g., such and such will happen at some unknown date in the future) are pretty much worthless for anything except religion.”
Huh???
I can predict tides and when the sun will rise and set in the future. Both of these are predictions with more than a yes/no response, i.e. open-ended.
That’s not religion.
Example of close-ended question:
Are fossil fuels a finite resource? Yes
Example of open-ended question:
What course will fossil fuel consumption take?
A rise followed by a decline.
And that’s what we are here to analyze. LOL
There have always been those that don’t like questions in the pursuit of knowledge. They especially do not like answers.
Galileo had a bit of a problem with that.
Tesla has reservations for Model 3 sufficient to sell out all production until 2019. There may be some cancellations but still they’ll have a backlog well into 2019.
It’s a pity nobody else is ramping up electric car production as fast as Tesla. The others with decent cars are selling out as fast as they can produce cars too.
What other EVs do you have in mind?
The UAE are not stupid enough to get involved in a war with Iran. If KSA did, they’d sit it out on the sidelines. Kuwait seems to want to avoid war too.
Hopefully the US will not be stupid enough to keep backing KSA.
Once Stalwart Oil Stock Bulls Starting to Say Enough Is Enough – Bloomberg: “The underperformance in the shares has not only opened up a rare gap with oil prices, but also is in contrast with narrowing spreads in the high-yield energy bonds.
‘What’s the divergence telling us? It really speaks to the excess pessimism about the future of oil,’ Tom Lee, managing partner at Fundstrat Global Advisors, said in an interview on Bloomberg Television last week.”
I have been buying a bit, but I focus on both upside as well as dividends. Thus far it seems to be a good diversification away from bonds. The key in my case is that I know most new oil plays and developments aren’t viable at $60. Therefore it’s just going to take a bit of time until this reality sinks in.
Hi Fernando,
Does the 2020-2030 guess for a peak in World C+C output seem reasonable (2025 best guess), regardless of the oil price level?
Pessimism Sweeps The Oil Markets | OilPrice.com: “‘If the market’s telling you anything, it’s saying, “E&P guys, slow down,”‘ said David Pursell, an analyst at investment bank Tudor, Pickering, Holt & Co. ‘Investors are more worried about whether the market can absorb this slug of growth from U.S. shale.’ The investment bank says that shale is probably on its way to strong growth this year, but if prices stay between $40 and $45 then it could derail the production growth in 2018. ‘That $10 makes a big difference,’ Pursell said.”
Open Thread Breaktime: Energy SnapShot + entertainment. whats not to like. Lawyers guns and money. oops. Lawyers Nukes and Ivan. http://ultimateclassicrock.com/jackson-browne-lawyers-in-love/
Where is the cobalt going to come from?
Mines, mostly. There will be a short price spike due to the delay in opening new mines.
Oil price slide widens junk bond yield spreads: “Among the 15 worst performing junk bonds on Wednesday and Thursday, a dozen were debts issued by groups in or directly tied to the energy industry, according to credit trading platform MarketAxess.
By the end of the trading day on Wednesday, the risk premium that investors demanded to hold high-yield US energy bonds had climbed to its highest level of the year, separate data from Bank of America Merrill Lynch showed.”
I wonder if anyone [Mike, Shallow, Dennis] has a feel as to what and where the value is in a current average Permian well [using $45 – $55 bbl for oil]. By that, I mean, assume for example that there are holders of a 20% royalty and there holders of 100% of the working interest [80% revenue] of a well. What is the value of the proposed well to each group? Do the royalty owners hold 80% of the value or more? At what ratio, if any, do you think that they would exchange a royalty interest for a working interest – for example, I will give up my 1% royalty for your 5% WI? This is a pre-drilling question. After the well is drilled, the WI owners have already paid all the upfront costs.
I recognize that this is a subjective question in that a number of assumptions and guesses would have to be made. But, is there any annecdotale evidence from actual transactions?
I am not aware of any transactions of this kind.
I personally would not want to risk the possible losses of owning WI if my well turned out to be a dud, nor would I want to incur the very high upfront cost ($300,000-400,000 for a 5% gross working interest).
Say my well only produces 80,000 BO in years 1-3 and is then producing 20 BOPD after year 3, and further assume 80% net revenue interest (which from what I have seen is better than average in the Permian).
On gross oil sold, the 1% royalty owner in this well receives $40,000 at $50 oil.
On gross oil sold, the 5% WI owner in this well receives $160,000 at $50 oil, but has presumably paid in at least $300,000 to drill, complete and equip the well. I have not even figured the operating costs into this example, which makes things even worse for the WI owner.
Now, if I am lucky and my well kicks out 300,000 BO in the same time, a 1% RI = $150,000,whereas a 5% WI =$600,000. But, we have the well costs, which can vary. We also have operating costs. Finally as a RI owner, I have no worries about receiving future JIB’s in excess of income, nor do I have to worry about paying 5% of the cost of plugging the well.
Cllueless, I am sure you understand that at $50 oil it rarely makes sense to choose WI over RI on US shale wells. There are almost always small WI for sale in the Bakken, the sellers having made the wrong choice is this regard.
Thanks Shallow. Without knowing exactly what other people are thinking, I was thinking that a lot of working interests in undrilled wells are really not worth very much at recent oil prices. And, if a small WI owner declines to participate in a well [not pay the JIB], it probably still is standard policy to be excluded from payments until the well reaches 2 or 3 times “payout,” virtually guaranteeing that such a WI is totally worthless. Further, not too many individuals with a 5% WI have the wherewithall, let alone the desire, to put $300,000 or more on the line to find out if they have a winner.
Hi Shallow.
The first well to test the HRZ shale on the north slope Alaska has just been drilled. Fracking is expected imminently and flow testing is scheduled for late June early July.
http://www.lse.co.uk/regulatory-news-article.asp?ArticleCode=0cxwu3ou&ArticleHeadline=Icewine2_Operations_Update
Siliceous shale hasn’t been found to produce in commercial quantities in other basins, this will be an interesting experiment.
Hi Fernando
I am rather sceptical myself and as you can imagine the share price of the company has been ramped up by brokers and speculators.
Its interesting that Paul Basinski of eagle ford notoriety is behind it. They claim the oil is “in the vapour phase” and there are super highways whatever that is supposed to mean. Still they will try to flow it in a few weeks so as you say interesting to watch.
WI have cleanup costs when the well is at end of life. With the market for oil vanishing, I would never own one if I could help it — they have the potential to become unlimited environmental liabilities. Royalties at least can never become liabilities.
Hi Clueless,
Using a DCF analysis and Mike’s assumptions (32% royalties and taxes), G+A of $2.75/b, interest+other of $3.65/b, and lifting cost of $7/b and a $9 million well cost, along with a real annual discount rate of 10% and your assumed $50/b wellhead price, the net present value(NPV) of the well (capital cost minus discounted net revenue) is about $-4 million, if we reduce the discount rate to 2.5% (just meeting average inflation), the net present value is $-2.4 million. At a 0% discount rate the NPV is $-1.57 million.
At $45/b at wellhead NPV is -4.7 million dollars at 10% discount rate (DR).
At $55/b at wellhead NPV=-3.3 million dollars at 10% DR.
The average Permian well has an EUR of 282 kb at 215 months where it is shutin at 10 bo/d output.
Cumulative barrels at 36 months is 158.6 kb and at 60 months cumulative output is 191.4 kb for the average Permian well in 2015-2016.
Here’s a video from Goldman Sach’s web page, THE NEW OIL ORDER” – MAKING SENSE OF AN INDUSTRY’S TRANSFORMATION.
https://www.youtube.com/watch?v=dA21J1WbdtU
The oil and gas analysists at Goldman Sachs argue that the shale revolution has upended the world economic and geopolitical order.
In the old oil order, OPEC was the swing producer, and thus had the pricing power.
But in the new oil order, it is the shale producers who are the swing producers, and thus hold the pricing power.
Shale well payout in 1.5 years?
Is that what this graphic means?
There was no discussion whatsoever of how this was arrived at in the video.
Per shaleprofile.com, Permian wells completed in Q3 2015 with an average of 17 months online produced a little over 111K BO on average. That is not halfway to payout at $40 wellhead oil. I do not think well productivity in the Permian has more than doubled since.
The graphic doesn’t even assume the Permian, is just states shale.
shallow sand,
My guess is that they focus on the Midland, Delaware, SCOOP/STACK and Eagle Ford, where 72% of current rig activity is taking place.
The Goldman analysits probably rely on companies like drillinginfo, which collect elaborate data sets for the various basins. For instance, drillinginfo’s data set for the Midland Basin includes the following data for over 4,000 individual wells:
1) Completion date
2) TVD
3) Lateral length
4) Completion zone
5) Pounds of proppant used
6) Frac density
7) Production history
Then, because the Midland Basin covers such a vast area and there are so many stacked pays, drillinginfo breaks the Basin down into 49 different areas, delineated by surface area and zone of completion.
The following map, for instance, shows in yellow drillinginfo’s “Area 1 – Wolfcamp A.”
Using the most recent production histories for “Area 1-Wolfcamp A” wells, drillinginfo then creates average type curves for the area, which for that area look like this in its latest report:
.
Hi Glenn,
What does the analysis look like for the entire Permian basin? Or we could consider just Wolfcamp A formation for all of the Permian basin.
It is doubtful that the area you focused on will be able to drive Permian output up by 2 Mb/d by 2021 from April 2017 levels.
So rather than cherry pick the best areas, use the entire Permian data base, you can just pick the 2016 wells if you would like.
You will note that I don’t play the same game and pick the worst areas or companies and show how poorly the Permian wells perform. I use the entire Permian horizontal well database. That is the proper way to do the analysis.
There is not a lot of data for the Delaware basin in Enno Peters database fro 2016 and 2017, most Permian basin wells drilled have been in the Spraberry and Wolfcamp formations.
For wells with at least 11 months of output that started producing in 2016 there were 282 Spraberry, 188 Wolfcamp, and 4 Delaware. A total of 474 wells from these 3 formations and 99% of those wells were Spraberry and Wolfcamp wells.
Dennis,
No cherry picking.
Here is the summary for all the 49 areas that make up the entire Midland Basin.
Here’s a closeup of the average of the 49 areas that make up the entire Midland Basin.
Then drillinginfo made the following economic assumptions:
Using these economic assumptions, along with production histories and forecasts from its type curve analysis, drillinginfo then comes up with the following Economics Summary for the “Area 1 – Wolfcamp A” area.
Note that the payout is slightly less than 1.5 years.
Notice how the EURs have risen over time. For drillinginfo’s most recent 2017 report, the EUR for “Area 1 – Wolfcamp A” is 891 BOE.
The average EUR for all 49 areas in drillinginfo’s latest report is 916 BOE, of which 80% is liquids.
The drawback is that drillinginfo’s reports are proprietary, so all this information is not available to the gerneral public.
The average 2016 Permian basin well profile has a cumulative output of 285 kb0 rather than a cherry picked 627 kbo shown above.
Dennis,
No cherry picking.
Here is the summary for all the 49 areas that make up the entire Midland Basin.
Here’s a closeup of the average of the 49 areas that make up the entire Midland Basin.
Hi Glenn,
Note that if we use the true well cost of $9.5 million rather than the $6 million used by drilling info (which is not accurate), a proper analysis considers net present value(NPV) rather than ROR.
For the average Permian Basin well the NPV is 289,000 dollars with an annual discount rate(DR) of 10% at a wellhead price of $55/b and a well cost of 6 million. A more realistic well cost of $9.5 million (full cycle cost) and 10% DR and $55/b oil has an NPV of -3.2 million, so the well loses money. Land acquisition costs are not zero they are about $1.3 million (assuming 140 acres).
Hi Glenn,
The Drilling info type curves are not realistic.
For the horizontal fracked wells drilled in the Permian basin from
https://shaleprofile.com/index.php/2017/06/08/permian-update-through-february-2017/
for wells drilled in 2016-2017 in the Permian Basin we have 686 wells with at least 11 months of output and 156 wells with 14 months of output data. Using all horizontal wells in the Permian basin which started producing in 2016 and 2017 (from Enno Peter’s database, 2037 wells total) an Arps hyperbolic was fit to the data. EUR is 284 kb over the life of the well.
The Cumulative well profile for the average well profile shown above is below. Horizontal axis is months from first output.
This analysis does not cherry pick the best areas, it uses all the data we have for the Permian Basin. Note how the average EUR is less than half the best area which Glenn chose to focus on (284 kb vs 700 kb). The NPV of the well over it’s life at a 10% discount rate is zero at a wellhead price of $72.97/b (well cost of 9 million is equal to discounted net revenue).
If we ignore land cost and assume well cost is much lower than most companies report ($6 million in the drilling info analysis cited by Glenn). Then we can get an artificially low “breakeven price” of $53/b. The reality is that $53/b is not a breakeven price, it is a price that results in a $3 million dollar loss per well.
A great business model, the more you drill, the more you lose 🙂
Plus 700 BOE EUR’s are NOT substantiated by actual realized production data. Not including leasehold and infrastructure expenses in well costs is like bragging about how good a deal you got on a new car, without a transmission and wheels included. Well costs in the Permian are NOT $6M dollars each, as an operator I know that for a fact.
Its easy to waste a Sunday morning searching for shale oil funded research that substantiates one’s claims. Personally, I like people who can think for themselves. I stand by my experience drilling nearly 300 wells in my career, from 1000 ft. to 10,000 ft. deep, all kinds, and actually paying the bills with my own money…Permian wells will require over 400K BO just to reach payout and very few of them will do that.
Folks concerned about their energy future, or their kid’s energy future, are inclined to be drawn to a blog and conversations about peak production issues, what things actually cost, what wells actually make, profitability, sustainability; you know, the truth. It tends to be “eco-chamber” alright. After eight years or so of data from America’s other two primary shale basins most anybody with an eight grade education can see its been a financial disaster for those companies doing the extraction. Why some folks think the Permian is going to be much different is beyond me. All this stacked “bench” BS requires additional laterals, different $5M frac’s, and will have their own economic challenges to overcome.
Shale oil is a good thing for America. My industry just needs to stop lying thru its oil stained teeth about how profitable it is. If it is not profitable, and it cannot pay back all those hundreds of billions of dollars of debt, it is not sustainable and someday soon something is going to break. America is entitled to the truth and I am embarrassed the shale oil industry, and its cheerleaders, cannot speak the truth. Basing UR and economics off “type curves” is a waste of time.
Thanks Mike,
I agree the LTO is a good thing, but it seems the oil industry needs regulation like the RRC used to do in the good old days. Maybe if the RRC started doing that the New Mexican, Oklahoma, and North Dakota agencies would follow the RRC’s lead.
Thanks for your input, you were correct that I am just wasting time.
Dennis,
No cherry picking.
Here is the summary for all the 49 areas that make up the entire Midland Basin.
Hi Glenn,
Show us the analysis for the entire Permian Basin then, the chart is not readable. Put it on Google drive or Dropbox and post a link so we can read it.
Here’s a closeup of the average of the 49 areas that make up the entire Midland Basin.
The percent liquids is not very useful as NGLs only get about half the price of crude per barrel, the average liquids EUR is 732 kb. That is about 2.5 times higher than reality (285 kb).
The cost per well is $6 million, where Pioneer’s June 2017 investor presentation results in about $11 million capital cost per well in the Permian.
Take capital spend of 2400 million and divide by number of expected wells completed in 2017 (221 in Permian, 85% of 260 total wells) and we get 2400/221=10.86 million per well.
Drilling info economic assumptions are not very good.
Glenn
I read your posts above. What is the appromimate oil and gas production that is needed to hit payout in 15-18 months in the Permian Basin? What royalty burden is being factored in? How are well costs determined, does that include equipment costs and costs to switch from submersible to rod pump as total produced fluid drops quickly? Do they give you an engineering report that shows these things?
I readily admit I have seen many wells in PB in 2016 and early 2017 that are strong wells, but when profit margins are very low to begin with, fudging on things like royalty, etc can make a big diffenece.
EUR baffles me as it apparently always includes 100% of all oil and gas produced. The companies almost never have title to 100%, many times 75% is it in PB.
Hi shallow sand,
I believe the analysis uses all the barrels but deducts the revenue from the barrels that are used to pay royalties and taxes.
For example if royalties and taxes combined were 32% and cumulative output was 100 kb yo would base your calculations on 68 kb of oil, those not familiar with the business take the 100 kb of oil and when figuring net revenue, they take the wellhead price and multiply by 32% and deduct this from total revenue, in the end the net revenue comes out the same, just a different way of thinking about it than the standard industry practice.
You make a good point though.
The economics leaves out royalty payments (thanks for pointing that out as I missed it).
Maybe in “Area 1” the mineral rights owners just don’t get any royalties.
It makes it much easier for the well to pay out quickly. 🙂
If this is the best that Glenn can do, clearly the Permian is not a great investment.
At some point the hedge funds will realize this and the money will dry up until oil prices get to $75/b or so at the well head.
Let’s say I have a really strong Permian well that produces 200,000 BO in the first 12 months, which is an average of almost 550 BOPD.
If I were an investor who knew nothing about oil, I would assume at $45 WTI the well produced $9,000,000 of pre income tax income.
However, if that well has a 25% royalty, the gross to the operator is really $6,750,000. Big difference.
Then, we have to look at severance taxes, ad valorem taxes, LOE.
Then, as a mentioned above, how are we calculating well costs. Are we including land, seismic, equipment? Are we including pulling the submersible and converting to rod lift? How are the big frac water holding ponds being allocated? Gathering systems?
I see above $10,000 per month LOE per well, then $5,000 per month. Is that realistic? Does that factor in pulling the down hole pump and fixing tubing leaks?
I have long ago accepted that the wells will be drilled and oil prices will be low for awhile. Wall Street has ahold of the US Industry and won’t let go.
I guess I just see a lot of glossing over of nuts and bolts expenses that all operators have to deal with.
Hi shallow sand,
Yes in my models I try to approximate that stuff at your suggestion, I do a fixed plus variable model, where the fixed portion is intended to cover downhole maintenance.
So say 3000+12times x where x is the monthly oil produced, 12 is the per barrel costs (G&A, lifting, interest, and other).
Pioneer has about 11 million per well in capital cost in 2017 for its forecast for the Permian basin, a pretty long way from the $6 million per well in the drilling info calculations.
shallow sand,
The drillinginfo analysis did not use an oil price of $45. It used an oil price of $54 and $3 for natural gas.
Here’s what assumptions drillinginfo used for well cost:
CAPEX: $6 million
Land Cost: $1.08 million ($9,000/acre x 120 acres)
Total well cost: $7.08 million
So if a well produces 220,000 BOE in the first 15 to 18 months of production, 10% natural gas, we have the following revenues:
198,000 BO x $54 = $10,692,000
132,000 MCFG x $4 MCF* = $528,000
TOTAL REVENUE = 11,220,000
*Natural gas heat value of 1.33 MMBTU/MCF
Here are the costs based on a 25% royalty burden and the operating costs reported by Pioneer during its Q12017 financials:
Royalty Payments = $11,220,000 x 25% = $2,805,000
Production costs = 220,000 BOE x $2.33 = $512,600
Production and ad valorem taxes = 220,000 BOE x $2.31 = $508,200
TOTAL COSTS = $3,825,800
$11,220,000 – $3,825,800 = $7,394,200
So it sure looks to me like the well pays out with 220,000 BOE
Hi Glenn,
The wells are typically 80% oil rather than 90%. Also the average Permian well takes about 39 months to reach 198 kb of oil based on a hyperbolic fit to Permian 2016 first quarter wells (which we have 12 months of data on).
So in 39 months we might reach 7.1 million, but the well costs almost 11 million so only 64.5% of the well is paid after 39 months.
Very optimistic assumptions lead to optimistic results, why is it that Pioneer’s earnings are negative if their payouts are so good?
shallow sand,
Where did you ever come up with the notion that the analysis omits royalty payments?
Perhaps drillinginfo failed to mention what royalty burden it assumed, but that hardly means royalty burdens were left out of the analysis.
I didn’t write drilling info was omitting royalty, I think I asked what they were factoring in.
Where I believe royalty is omitted is company published EUR.
$54 oil I assume means $56-59 WTI for PB? That is in the lower end of my preferred $55-65 WTI range. We have had just two months there since 12/14, or 2 of the last 30. WTI was $42 and change in 2016. It below $50 first 6 months of 2017.
Note Dennis Coyne’s comments about PXD CAPEX. A PE friend of mine has mentioned that too.
We will argue about this stuff forever, and it really does not matter because over 800 oil rigs are running in the US, the wells will be drilled and completed, the oil price will likely drop back down into the $30s WTI and no one will make money except upper management and Wall Street firms. It is what it is. We will just have to deal with it.
Well, the business model is to take money from sucker investors, pay it as bonuses to management, and walk away. A very very old business model.
The question is when they’ll run out of suckers. I see that happening sooner rather than later, because the news media is finally noticing the renewable energy revolution.
Hi Glenn
As I have suggested the total capital cost should be considered. In 2017 the expectation based on the June investor presentation for PXD is 10.9 million per well.
So Drilling info is low on well cost by about 4 million. and at 220,000 BOE the well would not have paid out,
Hi Shallow sand,
I think PXD uses $55/b for 2017 because about 85% of their expected production is hedged at that level in 2017, in 2018 it is much less, about 20% from memory.
I guess royalties were included according to Glenn, I don’t have access to drilling info data. The well profiles at 700 kb of oil are still much too high, there might be 10% of the well population that will have that kind of EUR, but the average well will be roughly 300 kb of oil over its life at most (280-285 for the average 2015-2016 well).
Also the well cost at 7.2 million that drilling info uses is also too low by $3 million based on PXD’s June investor presentation where capital cost in the Permian basin is 10.9 million per well.
shallow sand,
Looking at the average type curve, it looks like they’re figuring it takes just a little bit north of 200,000 BOE to pay out.
The above graphic “Economic Assumptions” is the only information drillinginfo gives in its report in regards to your other questions.
Another problem with these type curves is they call NGL, “oil”, it is liquid but only sells at half the price of C+C (which is oil).
Filloon just released a short summary and analysis of EOG’s 30 producers in the Permian (Delaware sub basin in Lea county New Mexico).
Average was 402 thousand barrels oil at 12 month mark.
Second month’s production averaged 78 thousand barrels oil.
This company is the recognized industry leader operating in possibly the most prolific ‘shale’ area in the country. Nevertheless, these are profiles and practices that other companies will strive to emulate.
Aside to Dennis … the Midland Basin USGS assessment does not include this area, as we earlier discussed.
Extending beyond the Delaware, to the northwest, is another sub basin – the Northwest Shelf – that is in the early stages of delineation.
This NW Shelf is expected to be far less productive than the Delaware, but much shallower and less expensive to develop.
One further aside, the British, via Cuadrilla, are due to start drilling their very first shale well in a few weeks time.
Coffee.
You must have missed it when Mr Fillioon was called out by one of shale’s biggest bulls, Nony, on SA.
Mr Filloon’s figures are estimates made by software he is marketimg, and not actual production data.
I see EOG with four hz wells out of 263 in Lea Co, NM with cumulative oil of 400,000+. 7 more have cumulative oil between 300-400,000 BO.
There are also 63 hz wells operated by EOG with first production prior to 7/1/2016 that have cumulative oil under 100K BO. Only 4 produced over 100 BOPD in the most recent month, 3/2017. I do agree that many of those are pre 2015 wells. There are some that are 2015 and later. Take a look at Trucker BRK State 1H and 2H. Those two wells cumulative oil 14,111 and 40,148, no oil sales reported for either in March, 2017, 2H sold 1234 BO 2/2017, 1H sold 527 BO 12/2016. Both are Bone Spring. Note operator is EOG Y, not sure the difference between that and EOG Resources, Inc.
I agree EOG has some monster wells in Lea Co, NM. They are doing much better than most operators in other PB areas. But, how is Whiting doing right now. I recall them being a premier operator not too many years ago.
EOG is trading at a forward PE of well over 100 at $50 WTI, and WTI is in the mid $40s.
A few “monster” wells always seems to cause those guys over on Seeking Alpha to hyperventilate.
Does anybody in the shale oil crowd ever bother to look at the bottom 96% of shale oil wells in America?
In any case, EOG ain’t doing so bueno these days: http://financials.morningstar.com/ratios/r.html?t=EOG
Shallow
Thanks for the heads up.
I will go back later and parse Filloon’s piece much more carefully.
Whenever I post comments on sites like this, I strive to present easily verifiable, historically demonstrated facts.
Estimates, future projections are well and good, but in highly contentious settings, seem more to invite arguments in which, frankly, I am disinclined to engage.
My initial understanding of Filloon’s work was that he picked 30 EOG producing wells from that area and packaged them for analysis.
Quick edit/PS and gotta go …
Shallow, EOG bought Yates in mid 2016.
Those early wells (dogs?) were Yates operations, I’m guessing.
Will do more followup later.
http://financials.morningstar.com/ratios/r.html?t=WLL
Yikes !
Hi Coffeguyzz,
Yes the Delaware has not been assessed.
I look at the entire Permian basin set of horizontal wells presented by Enno Peters at shale profile.com.
The well profile that fits the all data for 2016 to 2017 Permian horizontal wells (Texas and New Mexico). About 500 wells have 14 months of output, but I have combined all the data to find an average well profile (earlier months include more wells in the average than later months).
The well profile was redone using only wells from the first quarter of 2016 (585 wells) so we have data from the same set of wells for 12 months. The EUR is somewhat higher (304 kb), though a hyperbolic estimated on 11 months of data is not likely to be accurate, in future months we may be able to get a better estimate.
Click on chart to enlarge.
Definitions:
1) Oil resources are the total quantity of liquid resources in the
ground.
2) Oil reserves are the subset of resources that can be profitably
extracted.
3) Overproduction occurs when extraction costs fall below market prices.
Remark: Note that the amount of oil reserves in the world depends on price.
Conjectures:
1) Peak oil comes about because extraction prices rise faster than market
prices resulting in chronic overproduction.
2) The extraction of oil reserves peaked in 2014. Oil production has not yet
peaked because of the willingness of the financial sector to finance the
drilling of oil wells that will not pay out. In other words as much as 5% of
oil extraction since the collapse of oil prices in November 2014 consists of
resources that are not reserves (representing a higher percent of investment).
3) Extracting resources that are not reserves causes economic contraction.
Since the price of oil falls when the economy contracts, the current
overproduction is transforming reserves into resources that are not
reserves.
4) LTO is the perfect swing producer: extraction can increase and decrease
rapidly but LTO extraction is not playing the role of swing producer. LTO,
because of its speed and marketing prowess, is precipitating a sharp
contraction in oil production which I would put between 2020 and 2025 by
maintaining low prices which is shrinking offshore investment as well as
onshore conventional. Bad timing.
My prediction is that oil prices will remain below $60 a barrel until 2020.
At that time the IEA expects low investment in oil extraction will cause
offshore extraction rates to fall. Maturities in LTO bonds were around $25
billion in 2016. They will rise to about 10 times that amount in 2023.
Creditors will prevent LTO extraction from expanding at that time. Bad
timing.
The stock market is viewed as forward looking. Obviously, that is not always the case. However, if it is, with respect to oil, the unstainability of production at these prices should make itself known significantly prior to 2023 when the debt becomes unmanageable, and that fact is clear to all.
Hi Schinzy, I followed the link through to your site and quite enjoyed reading this article that you posted there.
https://link.springer.com/article/10.1007/s41247-016-0016-6
Do you feel anything in current events since you wrote this have changed or updated your opinion on probable scenarios or conclusions?
No big changes since we wrote the article. I can say some things we did not put into the article. My prediction is that when oil extraction rates begin to fall, this will cause a spike in oil prices which will pop a lot of financial bubbles causing the price to fall back down. A financial crisis will occur like in 2008 but I do not think the policy tools used in 2009 will be as effective next time. I believe that those communities that are developing local food and energy production will manage the best. That’s why I’m investing time in the transition town network. This is an opportunity to rethink our priorities and our goals. The last 12 years have really changed the way I look at the economy and the world.
Here’s one prediction of the next financial meltdown.
http://www.businessinsider.com/jim-rogers-worst-crash-lifetime-coming-2017-6
Thanks Schinzy. I appreciate it.
Glenn,
We have not seen that it can “swing” price to the upside yet? So far it is “swinging” the price only south. Or that upside price swing is going to happen when they run-out of sweet spots? 🙂
That could qualify them as a “swing” producer though so that term is not entirely incorrect. 🙂
I think this link is appropriate for inclusion here because the oil industry is one of the biggest and most important of all industries in terms of economic impact, and there has been a huge amount of discussion as to WHY the banks, or hedge funds, or somebody keeps pouring money into what looks like very bad bets in the oil biz.
The laws and regulations dealing with banking have a hell of a lot to do with the answer, for sure.
Maybe one of the regulars here will know something about the way this will affect the domestic and maybe even the international oil biz.
http://www.huffingtonpost.com/entry/bank-regulation-choice-act-house-vote_us_5939af49e4b0c5a35c9d91d8
I will have something to say about it in the non petroleum thread.
So if the Fed’s loose monetary policy and regulatory forebearance result in frothy evaluations for Telsa, it’s the best thing since sliced bread?
Tesla’s Stock Price Is Irrational, But Oh So Interesting
https://www.forbes.com/sites/hershshefrin/2017/04/06/tesla-stock-price-is-irrational-but-oh-so-interesting/#693fcdb379a4
Tesla’s soaring stock price is causing investors to overthink everything
http://www.businessinsider.com/tesla-stock-price-confusing-investors-2017-5
But if they result in frothy evaluations for shale oil companies with the bulk of their portfolio in the Permian Basin, the regulator’s practices are questionable?
Hi Glenn,
I don’t think most people here think the Tesla stock valuation is any more rational than the exuberance some seem to have for the money losing LTO business.
The hype over Tesla is that it is about to start selling the Model 3, which is a relatively affordable EV ($35k starting price) with relatively good range (215 miles), in July 2017.
Usually Tesla has had trouble meeting timelines so the price of Tesla’s stock will go back to $250 when production is delayed. A lot will depend on execution and a new company like Tesla will no doubt have trouble ramping up to 500,000 cars per year (expected rate for 2019). Even $250 may be too much for Tesla, but $360 is absurd until they are actually producing that many cars (500k per year or more).
I am pretty sure Mike doesn’t own any Tesla stock and he is waiting for the pickup truck 🙂
I think Tesla stock is overvalued.
But that makes the point. Investors don’t necessarily buy and sell on value. Right now oil is out of favor. It may continue to remain out of favor for a long time.
Here’s another video from Goldman Sachs web page, THE NEW OIL ORDER” – MAKING SENSE OF AN INDUSTRY’S TRANSFORMATION.
https://www.youtube.com/watch?v=Zilqznc5LCc
The oil and gas analysists from Goldman Sachs argue that global shale resources are so vast and so inexpensive to extract that the oil industry has now entered an “exploitation phase” of low oil prices that will last a decade or two.
There will be winners in loosers in this phase:
Winners
Losers
And talk about creative destruction! Goldman estimates that there are between $700 billion and $1 trillion worth of oil and gas projects around the world that have been rendered uneconomical in the new oil order. Looking at the map, it looks like these include the oil sands in Alberta, deep water Gulf of Mexico, Brazil sub-salt and the Norway sector of the North Sea, among others.
Hi Glenn,
Do you believe that hype?
Seriously? 🙂
A big problem with the analysis. Cost of production is much lower in OPEC, they are fine at $60/b, LTO producers lose money. Eventually losses year after year will drive a company out of business (250 bankruptcies in US oil and gas producer and services industry since Dec 31, 2014.)
Dennis,
“Hype”?
You would say that.
Has it ever occurred to you that there just might, might be a great many people out there, folks who know one heck of a lot about the oil busines, that disagree with you?
Here, for instance, is is one example:
THE PERMIAN PREMIUM: ARE RECENT HIGH PRICES JUSTIFIED?
https://info.drillinginfo.com/permian-premium-are-high-prices-justified/
The authors begin by acknowleding up front that “NPV and acreage valuation estimates are sensitive to the decline curve model used to forecast production.”
They then go on to state:
TABLE 2.
Hi Glenn,
Why a pre tax return? One would need to assume the firm loses money if it pays no taxes, otherwise the pre-tax return is irrelevant.
Also BOE is not relevant, very little money is made on the natural gas, it should be oil only as the NGL and natural gas are not sold it the price of crude, another mistake in the analysis.
The caption below your chart in the article (which was mysteriously excluded includes:
[Table 2. Five-year total recovery volumes (oil + gas at 6:1 BOE for the best and worst individual wells and the type curve using the three different forecast models. Oil and gas production was forecast separately and combined using 6:1 BOE, although these were all predominantly oil producers (65% to > 80%).]
So on average the EUR in that table needs to be reduced by 30%, the only meaningful estimate is the modified Arps, based on experience in the Bakken and Eagle Ford, the other well profiles are not accurate (they are hype).
So take 330 and multiply by 0.725 (to get the barrels of oil) and we have 240 kb, which is reasonable.
The authors then go on to state:
Hi Glenn,
Again you forgot the note under that table in your comment above.
Some might call this a lie by omission.
[Table 3. Net Present Value (NPV) of Pioneer Wolfcamp B wells drilled in Martin County using 5 years of forecasted production (Arp’s model) and a 10% discount rate. Costs include reported drilling and completion cost ($7.5MM) and facilities cost ($0.4MM), and estimated land acquisition cost ($1.43MM). Taxes and royalty burden are not considered.]
So three major flaws:
1. The analysis assumes the barrels of oil equivalent of natural gas and NGLs are sold at the same price that crude is sold at, which is not true.
2.Royalties and taxes are ignored, which at about 32% of barrels reduces income considerably.
3.The analysis is based on only 18 wells, too small a sample to be meaningful.
By contrast my analysis is based on about 500 Permian wells which started producing between Jan 2015 an November 2016.
Bottom line, such a poorly done analysis is best ignored by those interested in a good investment.
Hi Glenn,
I read the PXD earnings release from 2017Q1. The capital spending in the Permian in 2017 is expected to be 2.5B and 244 net wells are expected to be completed. This works out to $9.83 million in spending per well completed, some of this spending is for water and gas handling, but without that spending the operation cannot continue efficiently so these costs should be included as part of well cost. If we leave out the facilities spending it is 7.8 million per well, but in my view all capital spending necessary for the operation should be included, in any case even if we leave out the facilities it is not clear if land acquisition costs are included in the $7.8 million per well from reading the news release.
Including natural gas and NGL sales with crude output and assuming a 7.8 million well cost, the breakeven is $44.30/b, if well cost is higher (8.5 million including a portion of facilities cost), breakeven is $47/b.
Here I have assumed that the 2016 PXD ratios of NGL and natural gas to crude output will continue into 2017. Values from the 2016 Annual report were used to find ratios of NGL and Natural Gas output.
Hi Glenn,
I have read that article, also hype. When calculating break evens they ignore royalties and taxes, not well written.
Do you get paid no royalties for wells drilled on land you own? Are the tax rates zero in your state?
Mike and shallow sand know quite a bit more than I do about the oil industry, as does Fernando Leanme, George Kaplan, and SoLaGeo. Generally those guys all think I tend to be a bit too optimistic if anything.
Oh and my well profile is an Arps hyperbolic based on data from Enno Peters shaleprofile.com.
The EUR is 282 kb over 236 months with the well assumed to reach its economic limit at 10 b/d when it is shut in. A hyperbolic well profile is assumed until a 8%/year annual decline rate is reached and then exponential decline at 5.8% per year is assumed. This crossover from hyperbolic to exponential occurs at 180 months.
Thank you Enno, your site is awesome.
Dennis, you might as well bail on this debate; its a full time job for this fella to selectively find whatever links and quotes he needs. Its a game. We recently discussed the first 30 months of transient, frac-induced flow in tight unconventional oil wells and IP30 minute type curves used in decline curve analysis. Even modified Arp DCA methodology is suspect given initial flow regimes. As I pointed out, Permian wells require over 400K BO just to reach payout. Realized production data does not support that, as you point out.
I am reminded of George Costanza’s famous quote: “Jerry, just remember; its not a lie if you believe it.” We should all move on from this dribble.
Hi Mike,
Just trying to provide counterpoint to the hype.
Glenn seems to be a Permian promoter, a large dose of salt is needed.
And the Permian doesn’t need promoting, especially at these low oil prices — unless one is trying to sell something in the Permian.
Hyping the Permian just contributes to low oil prices. These posts make no sense in terms of maximizing oil prices. They only make sense if you are trying to sell something in the Permian to someone who doesn’t know better.
“Permian promoter”?
I can see it now, the engineers, geologists and managers over at ExxonMobil or Chevron sitting around and saying, “We should head over to the Peak Oil Barrel blog and see what is being said before we make such a big move into the Permian Basin.”
NOT!
Did some reading on what Exxon did.
Mostly New Mexico segment of Permian.
Exxon is XTO, their acquisition pre 2014 and focused on shale gas, not oil.
All the quotes of what can be found in what they acquired in the New Mex Permian talk about barrels of oil equivalent “with 70% of that liquids”.
Not oil. Liquids. This is XTO’s formula. Get the NGLs and let them pay for the gas that comes up.
“Exxon Mobil, the world’s largest integrated oil company, has announced its plans to acquire a bunch of companies owned by the Bass family of Fort Worth, Texas… The US-based energy company will pay a one time sum of $5.6 billion in the form of shares and a series of additional contingent cash of roughly $1 billion, to be paid between 2020 and 2032, depending upon the development of the resource….
This is Exxon Mobil’s seventh transaction in the Permian Basin in the last three years, and its biggest since its buyout of XTO Energy in 2010. In fact, Exxon’s XTO Energy is likely to manage the newly acquired assets in the region.
Exxon currently holds around 1.5 million acres in the region…that is considered to be one of the largest and most economical oil plays in the US….
At present, the energy company has 10 rigs working in the Permian region, and plans to add 15 or more after the acquisition closes in the first quarter of 2017….
The assets in the region are believed to have abundant oil that can be drilled at a much lower cost… Thus, the company’s assets in the region are estimated to yield 35%-40% higher margins compared to its other assets.
https://www.forbes.com/sites/greatspeculations/2017/01/26/does-it-make-sense-for-exxon-mobil-to-acquire-permian-assets/#11eab3092d41
Hi Glenn,
No we are talking only about you. The various analyses you have cited are full of holes, poor assumptions, or cherry pick very small areas to make your point.
Why do the economic analyses omit land cost and royalty payments, the $6 million per well cost is far lower than is likely with the most up to date fracking methods. For Pioneer in 2017 the capital spending in Wolfcamp/Spraberry (2400 million) divided by Wolfcamp/Spraberry wells (221=85% of 260) suggests an average capital cost of 10.8 million per well.
That well cost ($10.8 million) suggests a net present value for a completed well would be zero at a 10% discount rate at $85/b. At $55/b each completed well loses $4.5 million over its life.
These numbers are based on the Pioneer (PXD)June Investor presentation data.
http://investors.pxd.com/phoenix.zhtml?c=90959&p=irol-presentations
Chart below has Pioneer’s Permian Forecast (click on image for larger view)
Dennis,
Right.
Just how much influence do you believe the “expert consensus here in this forum” had on ExxonMobil or Chevron?
And whose analyses are “full of holes, poor assumptions, or cherry pick very small areas to make their point”?
Has it ever occurred to you that it is your analyses that are full of holes and poor assumptions, and that just maybe, maybe the engineers, geologists and managers who work for ExxonMobil, Chevron and drillinginfo have more knowledge about the Permian Basin than you do?
A note on the Pioneer forecast.
They include about 700 kb/d of output from vertical wells and conventional output in 2016. If we assume for simplicity that the output of conventional (non-LTO) output is flat at 700 kb/d through 2025, then the LTO output in the Pioneer forecast would be 4.3 Mb/d in 2025 (we have to guess because they don’t break it out). In 2023 using the above assumption output would be about 3.2 Mb/d, similar to my scenario below in 2023.
In fact my scenario is considerably more optimistic than the Pioneer forecast from 2016 to 2020 (my scenario is about 700 kb/d higher at that point).
So perhaps my “pessimistic” scenarios are in fact too optimistic as many of the oil industry guys have told me on many occasions.
Hi Glenn,
Ok, look at the June Presentation from Pioneer, one of the largest producers of LTO in the Permian basin, well cost (capital spend divided by number of wells to be completed) is $10.86 million. Drilling info estimates $6 million. A pretty big difference don’t you think?
No royalties included in the Drilling info analysis, inflating revenue by 33%.
It only requires a brain to do the analysis.
Mike, shallow sand, and Fernando know plenty and they see these presentations for the hype that the are.
Your appeal to the market and that it must be rational may prove incorrect.
It was certainly the case in real estate in 2008. A lot of big players were wrong then, and a lot of investors in LTO are wrong now.
At $80/b it works, at $45/b you need to fudge things the way Drilling info and many others have.
At this point I am done because pointing out the actual holes in your arguments gets the response that the oil industry must be right.
That is not an argument, it is faith based.
A true believer cannot be convinced.
The type curves are bogus, well cost is underestimated, royalties are not included in the economic analysis.
But still those oil companies must be right, just look at all the money they are making (with the exception of those with substantial international oil operations, not very much in earnings per share).
Then you point to Tesla and say see they aren’t making money. That is true, but then I assume you don’t invest in Tesla.
Dennis,
It is true that Pioneer spends more to complete its average well than $6 million (but certainly not $10.86 million, unless one believes Pioneer managment lied in its 1Q2017 earnings release).
But there’s a reason for this. And the reason is that the average lateral length of a Pioneer well in 2016 was 9,100′, not 7500′.
And in the first quarter of 2017 the average lateral of a Pioneer well was even longer, somewhere between 9500′ and 10,000′.
This graph is from Pioneer’s 1Q2017 earnings release.
But here’s the thing: if one is going to use the cost to drill a 10,000′ well in an economic analysis, then one should also use the production history and EUR of a 10,000′ well, not that of a 7,500′ well.
Pioneer’s average 9,100′ well in 2016 had an EUR of 982,000 BOE, which far exceeds the 764,000 BOE that the average 7,500′ well in the “Area 1 – Wolfcamp A” had.
One should not use the cost to drill a 10,000′ lateral well and the production curve and EUR of a 7,500′ lateral well if one wants to do an economic analysis that has legitimacy.
Dennis,
And where did you come up with the nonsensical notion that “royalties are not included in the “Area 1 – Wolfcamp A” economic analysis”?
Talk about a zinger, that one is beyond the pale.
One cannot make fact-free claims like that if one wants to retain any credibility.
Hi Glenn,
I could not find the cost per well broken out in the 10Q from 2017Q1.
I used the June Investor presentation from PXD, 2.4 B capital spend for 2017 in Permian and 85% of 260 wells completed in 2017 in Permian (221 Permian wells).
Do the math. It’s 2400/221=10.86 million per well.
Yes the laterals are longer, and there is more proppant, that is the major reason why the well profiles have changed from 2015 to 2016.
Eventually the well profiles will reach a maximum, this concept is referred to as the law of diminishing returns in microeconomics.
On the no royalties included, it is based upon the stated assumptions by drilling info. Nowhere did it say what the assumption for royalties was.
So I assumed they were zero. I don’t have access to drilling info.
My breakeven calculations using 32% combined royalties and taxes, and $13.40/b combined G&A, interest, other costs, and lifting cost and a 10% annual discount rate at in the spreadsheet at the link below. Average first quarter 2016 well has an EUR of 304 kb and the break even oil price is $74.84/b with a well cost of $9.5 million. At a wellhead price of $55/b the well loses about $3 million over its life (NPV=negative 3 million)
https://www.dropbox.com/s/ebmwklapm5b2bpk/breakeven%20Permian2016.xlsx?dl=0
or
https://drive.google.com/file/d/0B4nArV09d398Yl9OaUZMUFVUSnc/view?usp=sharing
Hi Glenn,
We don’t know what the output of the longer lateral wells will be.
In 2016 from annual report for PXD the capital spent in the Permian was 2317 million and there were 242 successful wells or 2317/242=$9.57 million per well. So the breakeven price would be $57/b using a PXD specific well profile from Q1 of 2016 (later wells do not have enough monthly data for a good estimate). The well profile for the Pioneer wells is indeed higher than the average Permian basin well by a considerable margin. For the 585 total wells completed in quarter 1 of 2016 the EUR is roughly 305 kb, but for the 45 wells completed by Pioneer the EUR is 464 kb (oil only).
Also looking at the 2016 annual report for PXD about 83% of the value of the barrels of oil equivalent are oil for 2016 Permian output. (NGL assumed to sell at 50% of price of C+C and Natural gas at a value of 1/18th. The extra revenue from the NGL and Natural gas sales might allow the 2016 wells to break even.
Note however that the well profile is based on only 45 wells which started producing in the first quarter of 2016 and a well profile based on 11 months of output data and only 45 wells may be inaccurate.
I have considerably more confidence in the 305 kb well profile. If we reduce the well cost from 9.6 million to 8 million to reflect the shorter 7500 foot lateral (vs 9000 for PXD), then the average breakeven for the Permian basin for 2016Q1 wells is $65/b, if we assume the natural gas and NGL sales can cover the downhole maintenance costs that I have ignored.
Alternatively if we assume the value of NGL and natural gas sales is about 17% of the C+C sales and ignore any downhole maintenance cost (a shortcoming pointed out by shallow sand) then breakeven cost falls to $45/b, with an assumed 8 million dollar well cost and a 10% annual discount rate.
This may indeed explain why the Permian has been attractive to oil companies lately.
A mistake I was making was to ignore natural gas and NGL sales.
This estimate is very rough because I assumed PXD has typical natural gas and NGL to C+C ratios for all of the Permian basin. I do not know what typical values are for NGL to Natural Gas for all of the Permian basin. For PXD it was 0.21 b NGL per 1000 CF of natural gas produced in the Permian, anybody know if this is typical?
Hi Glenn,
I redid the breakeven using oil and natural gas well profiles from first quarter of 2016 (the gas profile is a new estimate which I had not done before). I still don’t have data for NGL for the Permian basin as a whole so have left that out for now.
Just using oil and natural gas the breakeven is $44.9/b for an 8 million dollar well and 10% annual discount rate.
If we assume NGL per 1000 CF natural gas produced by PXD in 2016 is typical for the Permian basin as a whole (.21 b NGL/MCF NG) and that NGL sells for half the price of a barrel of crude, then the breakeven oil price for an 8 million dollar well with 10% annual discount rate is $43.9/b (2017$).
Note that rising service costs and more expensive well designs might drive this price higher as well cost increases, though rising well productivity could offset this.
Hi Glenn,
I question if the assumption of a 7500 foot lateral is correct for the Permian basin wells that were completed in 2016. I do not have data on lateral lengths, I suspect the well productivity of the average well has improved due to longer lateral lengths, more frack stages and more proppant. All of these drive up the total cost of the well.
So the $7 million cost per well might have been correct in 2014 or 2015, but based on data from PXD it looks like well costs have increased.
A good well cost study by IHS for the EIA is at link below, with land costs included the average Midland Wolfcamp well cost about 9.5 million (see p 86, fig 8-3 for D+C cost and p. 90 fig 8-6 for land costs.)
https://www.eia.gov/analysis/studies/drilling/pdf/upstream.pdf
Should rename it after Glenn and forget about Baron Munchausen
https://en.wikipedia.org/wiki/M%C3%BCnchhausen_trilemma
Hi Glenn,
For where I got that Drilling info did not consider royalties see the article that you cited above at drilling info(at link below)
https://info.drillinginfo.com/permian-premium-are-high-prices-justified/
and the following quote from that article:
http://peakoilbarrel.com/open-thread-petroleum-june-7-2017/#comment-605087
[Table 3. Net Present Value (NPV) of Pioneer Wolfcamp B wells drilled in Martin County using 5 years of forecasted production (Arp’s model) and a 10% discount rate. Costs include reported drilling and completion cost ($7.5MM) and facilities cost ($0.4MM), and estimated land acquisition cost ($1.43MM). Taxes and royalty burden are not considered.]
Note that the well cost is $9.33 million=7.33+0.4+1.43
I had assumed you read the piece.
Hi all,
I rechecked my calculations to make sure everything was roughly correct.
Assuming natural gas sells at $3/MCF and NGL sells at half the price of crude and including natural gas and NGL output the breakeven price (NPV=zero) of the average Permian well at a well cost of $9 million per well (includes land and facilities) and a 10% discount rate is $51.82 at the well head and assuming $3/b of transport cost would be about $55/b at the refinery gate.
Payout is reached at 112 months (9.33 years) at $51.82/b. At $60/b payout is reached in 60 months. At $70/b payout is reached in 36 months. For an 18 month payout the wellhead price would need to be $91.70/b.
The $55/b oil price would correspond with an 85 month payout.
Hi Glenn,
My scenario for the Permian is similar to the Pioneer forecast through 2021and note that their forecast includes about 700 kb/d of conventional Permian oil output in 2016, my scenario includes LTO only (based on the EIA’s tight oil estimates for the Permian Basin [Texas and New Mexico]).
After 2021, I think it will be difficult to reach the 5 Mb/d that is forecast by Pioneer, LTO output in the Permian basin is likely to level off about 3 to 3.2 Mb/d from 2020 to 2025 and then start to decline. This only will happen if oil prices rise to $70/b by 2020 and continue to rise to $110/b by the end of 2025. Otherwise economics will reduce the drilling rate and even 3.2 Mb/d is unlikely to be reached.
You’re making my point. You and what is discussed here don’t influence decisions at the corporate level.
So no matter what you say about the Permian, it’s going to happen or it isn’t based on geology, the price of oil, and financing.
I came to this forum to see info about LTO decline rates and what I have seen has been very helpful.
The date of “peak oil” seems less important now since more companies are focusing on a less carbon future anyway. Some people think for environmental reasons fossil fuels should stay in the ground. But it may be that they stay in the ground for economic reasons.
Perception-wise, oil is falling out of favor as an investment. And if the money stops coming, most likely drilling will stop.
Perceptions are a problem right now for the oil industry. Talk of unlimited supplies just keeps the price of oil down. So those oil companies that want to talk about the boom in LTO reinforce the idea that oil prices will stay low because there is going to be so much oil.
Your main purpose in being here seems to be to refute the idea of Peak Oil. Fine. That means the market thinks all that oil should carry a low price. Can you get lenders and investors when the price stays low?
Hi Boomer,
It is not clear who you are addressing your comments to.
I was replying to Glenn.
Glenn, Exxon and Chevron were the MARKS. The shale oil promoters (scammers) were trying to sell their worthless oil fields to Exxon and Chevron. They succeeded.
And big oil bought those leases to appease their investors. It allows them to look like they are doing something while they are actually cutting back.
so all the previous shale acquisitions by majors made bundles for their shareholders?
NOT!
Mike,
Another classic from Seinfield would be appropriate for new term of “repackaged bankruptcies” ?
https://www.youtube.com/watch?v=rCZRqH7sRyA
A mistake in comment above
“A hyperbolic well profile is assumed until a 8%/year annual decline rate is reached”
should have been
“A hyperbolic well profile is assumed until a 5.8%/year annual decline rate is reached”
Hi Glenn,
Chart with data and hyperbolic well profile.
Arps hyperbolic coefficients
Q0….29318
b….1.1
D0….0.56187
This analysis appears to omit demand entirely — a fatal defect. It’s still cheaper to run an electric car than a gasoline car… so oil prices will be even lower than they think…
Hi Nathanael,
There is a World market for oil and World supply may fall faster than demand, in which case oil prices may remain high.
I don’t think it is easy to predict future demand, and I agree it is a major shortcoming of my analysis. The basic assumption is that oil prices will adjust to balance supply and demand and from 2020 to 2030 oil prices are likely to be relatively high (80 to 120 per barrel in 2016 $) in order to balance supply and demand. That assumption will be incorrect if the scenarios created by Tony Seba are correct, but I find those scenarios unrealistic. I hope that I am wrong on that score, but the realist in me suggests otherwise.
Well, you might be right about 2020-2030, which I think of as “short term”.
So, looking at the world,
(1) China is the largest market
(2) China is practicing aggressive export mercantilsm and strongly affecting the rest of the “third world” markets
(3) China is implementing domestic policies which are vastly accelerating their replacement of gasoline/diesel-powered vehicles with electric vehicles (such as the extreme difficulty of registering gasoline cars in major cities, while electric cars can all be registered)
(4) Many suspect that a large portion of Chinese oil “demand” in recent years was building up of a strategic reserve, not consumption.
GDP has already decoupled from oil usage, worldwide, as industrial facilities were shifted off of oil.
My conservative demand reduction scenario (meaning, quite likely that demand will fall faster than this) has demand falling faster than the natural decline rate of the oil wells by 2028. If electrification goes faster than my conservative model, or the distribution of gas vehicles replaced biases towards the high-miles-per-year vehicles, that’s a year or two earlier. Drops in demand due to phenomena other than electric vehicles will probably bring it back another year or so.
It looks like supply will not fall as fast as the natural decline rate of the oil wells thanks to silly money-losing frackers (etc.), which would bring the crossover point (for the permanent oil glut) back significantly; reducing the presumed decline rate would pull the crossover point back anywhere from 2 to 4 years. This gives me an earliest date of about 2021 for the crossover point, though I still think 2028 is more realistic. This wouldn’t affect the final result as by the time the “excess exploration” supply stopped we’d already be around 0% oil use.
It is possible that supply will fall faster than demand if supply falls really really fast, like the fracked gas wells running out very quickly, but it looks like almost all producers are pumping like mad, and many are drilling like mad even though they are doing so at a loss. This says to me that supply will stay high for quite a while, subsidized by “sucker financing”. By the time this process ends we’ll be running into that final glut which starts in 2021-2028.
The demand drop will first be visible in China due to their *aggressive* policy. But the rest of the world will follow for purely financial reasons.
is it because of these aggressive pro-EV policies that SUV sales in China have grown at 38% CAGR over the past 5 years?
It’s the government that wants electric cars, and the people who like SUVs as in the US TV series.
In China it could be the government wins this race.
But I think before this, the chinese oil usage will still grow. As long as the gas car fleet increases (it does), and air travel increases they will need more of this stuff.
But I think behind this is not only enviromental improvement, but the chinese government doesn’t want to join the game of thrones in the gulf to secure their share of oil.
They now invest only money, and want to get rid of this stuff. No oil – no need for aircraft carriers, military bases, puppet governments, terrorists and other stuff. Much less hassle and cheaper in the long run.
Hi Nathanael,
Your conservative scenario corresponds with my optimistic scenario for demand reduction. After 2023, LTO output may decline pretty quickly as the economics becomes unfavorable as the sweet spots run out in the LTO plays in the US.
I am skeptical that international LTO will ramp up just in time to mitigate the rapid US decline, I also don’t think extra heavy oil from Canada and Venezuela will be ramped up quickly.
Possibly OPEC might fill the gap, or deep water offshore, but this will need to offset decline from post peak fields which will be a challenge.
I would put the window at 2025 to 2035 for when demand may fall below supply and drive oil prices lower, with a higher probability of 2030 to 2035, so we are not far apart in our scenarios, roughly 5 years or so (2028 for you and 2033 for me). Though I realize you think 2028 will be the latest it would be and I think that is near the earliest that is likely.
It will be interesting to see how the next 10 years plays out and I hope you are right, but I think we should plan for 2033 (and possibly later).
In fact my expectation is that the slowness of the transition will result in a financial crisis around 2030+/-2 years, if that is correct demand falls below supply at that point and might never recover, depends on policy and the length of the recession.
Proper Keynesian policy might mean a short recession, but most economists don’t read Keynes anymore so the lessons of the past have been forgotten, Say’s Law seems to have become popular again.
The automotive industry's big data opportunity – inside a new book on our driverless future: “My research led me to the conclusion that there are five important challenges contributing to changes in personal mobility:
Urbanization is increasing and more megacities are being created.
Traffic congestion, particularly in megacities, is severely impacting individual productivity. Because our transportation infrastructures are inadequate or they are reaching their limit, building more infrastructure won’t solve the problem.
Pollution and climate change are impacting the quality of our life, particularly in cities.
The population of many developed countries is aging fast. These populations will require constant assistance of various forms, including transportation assistance, in order to continue functioning properly.
The socioeconomic conditions of certain population segments – particularly the Millennials – lead them to adopt the sharing economy to address many of their needs, including their transportation needs.”
ACE stands for Autonomous Connected and Electrified (ACE) vehicles.
Automotive disruption revisited – the shift from car ownership to "mobile experiences": “Simoudis: I feel that most incumbents have not yet fully appreciated that next-generation mobility will rely less on car ownership and more on car access. As I indicate in the book, these companies will need to transition from being in the manufacturing business to being in the insights business, and through those insights provide superior transportation experiences.
Some incumbents such as Ford, BMW, Mercedes, GM and a few others have established new companies to address on-demand mobility. I’m assessing how these efforts are progressing, the level of support they will continue to get from the parent company and the level of influence they will have in the parent company. For me that will be the best indication that something is really changing.
Reed: Do you still believe that fleets of cars will be the first to push the ACE envelope? How will this work?
Simoudis: Indeed I think that fleets, whether of passenger cars or trucks, will be the first broader adopters of ACE vehicles. The reason is because the business model of ridesharing companies – and of long-haul logistics companies – can be dramatically impacted by the use of ACE vehicles. This is why startups like Peloton are attracting so much interest, and ride hailing companies like Uber and Grab have active ACE vehicle programs.”
Looking at the articles on the future of transportation (which will greatly affect oil demand), I see that one way to research the subject is to Google “on demand mobility”. This page has some good graphics showing the inter-relatedness of several areas, which are potential research and investment opportunities.
Both companies and universities are doing research this area. Gas and oil, and fossil fuels in general, simply don’t provide as many entrepreneurial and growth opportunities as disruptive transportation technology. If you are a millionaire or a billionaire and want to have a lasting impact on the world, new transportation /energy technology is more intriguing than putting your money into LTO.
Changing Places – Mobility-on-Demand
Delphi and Transdev to develop global on-demand driverless transportation | TechCrunch: “Dance cards are filling up for the coming autonomous driving revolution: The newest partners are Delphi and Transdev, who are joining forces to create an automated, on-demand mobility systems, with a service offering set to make its debut via pilot projects in France, and then to eventually expand eventually to global reach.”
Delphi, Transdev Partner Up for On-Demand Autonomous Mobility Service – Motor Trend: “Earlier this year, Transdev, a French company, launched a fleet of self-driving taxis in Normandy for the public. With Delphi now on board, both groups can test the new service together and develop the next phase, a commercial service. In Paris-Saclay, Delphi and Transdev will develop an on-demand transportation shuttle between railway stations and the Paris-Saclay campus.”
cool, a person can stand and wait for the bus, er, I mean the “pod” or “car”.
Maybe autonomous EVs will become the least costly way to provide “taxi” service in urban areas.
But I see ownership of a personal EV as such a convenience ie there it is in the driveway whenever it’s needed like instantly in an emergency etc.
As long as EVs become affordable to the middle class, I don’t see “sharing” becoming more popular than owning and driving.
The two groups I see most likely to initially avoid car ownership are those who have never owned a car and don’t want the burden of having one, and those who are no longer able to drive.
Also, there may be families who decide they only want one vehicle and can car share for those times they need two vehicles or a different type of vehicle.
The rest will follow if it becomes both easier and cheaper to get transportation on demand rather than own one: No parking, no need for designated drivers, more flexibility in getting exactly the vehicle you need for any occasion, and so on.
Insurance is also a burden for young drivers. Even if they want to own a vehicle or drive the family car, the insurance rates for some categories of drivers can be prohibitive.
Where will the cobalt come from?
This might be a better commodity speculation play than oil.
Electric carmakers on battery alert after funds stockpile cobalt: “In a bold wager on higher prices, half a dozen funds, including Swiss-based Pala Investments and China’s Shanghai Chaos, have purchased and stored an estimated 6,000 tonnes of cobalt, worth as much as $280m, according to the investors, traders and analysts.”
I’ve been looking for the answer. These seem to be the options:
1. Develop batteries that don’t need cobalt.
2. Recycle batteries for the cobalt.
3. Pay enough for the cobalt that more mining of the mineral is done. Cobalt isn’t a rare mineral, and the primary reason that there isn’t more is that it is mostly obtained as a by-product from mining copper and nickel. If the demand for cobalt goes up and the price rises as well, there may be more incentive to seek out cobalt directly.
Right now it seems like a lot of stories about the potential scarcity of cobalt are coming from investment sites touting it as the next hot commodity. So it is difficult to sort out hype from reality.
This seems to be a pretty good source of info.
“Matching global cobalt demand under different scenarios for co-production and mining attractiveness”
https://journalofeconomicstructures.springeropen.com/articles/10.1186/s40008-016-0035-x
Right now it seems like a lot of stories about the potential scarcity of cobalt are coming from investment sites touting it as the next hot commodity. So it is difficult to sort out hype from reality.
http://www.nytimes.com/1978/12/18/archives/scarcity-of-cobalt-spurs-conservation.html
The price of cobalt has varied significantly from that time. And because the price is high right now, there is talk of doing more mining in North America and Australia.
From what I can tell, the biggest concern right now isn’t scarcity so much as concern that the Congo is the main source. And China is buying up what it can.
Probably the best long-term solution is to make batteries without coal.
This is a good look at both price and production of cobalt going back to 1900.
Cobalt: A Precarious Supply Chain
Without cobalt, I mean. I can’t seem to edit my comments today.
China plays long game on cobalt and electric batteries: “‘Though we don’t believe the narrative that there is a cobalt crisis,’ said Chris Berry, an analyst at House Mountain Partners in New York. ‘We do see higher looming cobalt prices as China plays the “long game” to dominate the cobalt supply chain.’”
As I mentioned, a lot of the info online about cobalt comes from sites promoting speculation in cobalt. I’m trying to sort out the hype from the reality.
Cobalt’s meteoric rise at risk from Congo’s Katanga: “The operation has the potential to add as much 22,000 tonnes of cobalt to a market with annual output of around 100,000 tonnes.
That could bring the price of cobalt, which has surged 135 per cent this year, back to earth with a bump. Goldman Sachs analysts say the resumption of production at Katanga ‘will significantly change the supply dynamics’ for cobalt and ensure the market is well supplied up to the end of 2019.”
I probably shouldn’t keep posting about cobalt here even though Watcher raised the issue, which affects EVs, which impact future petroleum use.
Recycling is likely to play an increasing role in maximizing the metals we have minded through out history.
I found this collection of articles that someone put together concerning the potential of reclaiming metals from scrap. I only looked at the first link, but it is very informative.
Scroll to the bottom of this page to see what I have copied and pasted here.
How high is the recovery rate of cobalt, iridium, neodymium etc. when recycling electronic waste?
Many thanks for all your inputs. I did some further research myself and found the following valuable resources and insights I would like to share here:
EASAC (2016): Priorities for critical materials for a circular economy. Online available under: http://www.easac.eu/fileadmin/PDF_s/reports_statements/Circular_Economy/EASAC_Critical_Materials_web_complete.pdf [Accessed March 30, 2017].
Graedel T. E., Allwood J., Birat J.-P., Reck B. K., Sibley S. F., Sonnemann G., Buchert M., & Hagelüken C. (2011): Recycling rates of metals – A Status Report, a Report of the Working Group on the Global Metal Flows to the international Resource Panel. Online available under: http://www.easac.eu/fileadmin/PDF_s/reports_statements/Circular_Economy/EASAC_Critical_Materials_web_complete.pdf [Accessed March 30, 2017].
Reuter M. A., Hudson C., van Schaik A., Heiskanen K., Meskers C., & Hagelüken C. (2013): Metal Recycling: Opportunities, Limits, Infrastructure, A Report of the Working Group on the Global Metal Flows to the Inter- national Resource Panel. Online available under: https://www.wrforum.org/wp-content/uploads/2015/03/Metal-Recycling-Opportunities-Limits-Infrastructure-2013Metal_recycling.pdf [Accessed March 30, 2017].
In the latter references I found the attached graph (p. 125), which was the most comprehensive information I found about recycling efficiencies (here between a common formal system in Europe and the informal sector in India for the gold yield from printed wire boards). So the smelter does seem to be very effective in central Europe, however separation and take-back systems perform poorly. Globaly less than 1% recycling rate for many metals (i.e. Neodymium) are reported. However, for other metals, the rates are considerably higher (Iridium 25-50% and Cobalt >50%) (Graedel et al. 2011). Indicating that it highly depends on waste streams. EE-waste-streem seem to show lower recovery rates than other streams (EASAC 2016).
I appreciate the cobalt links. Thanks a lot! Very good food for thought.
Glad you’ve found them of interest. Until Watcher raised the issue, I never thought about cobalt.
What I am seeing is the extent to which speculators can manipulate the market, and how country of origin influences the perception and availability of the product.
I think the Congo (its citizens, not those in power) needs that money so I don’t want to see a boycott. Rather, this should be used as a opportunity to improve working conditions for the miners, especially child labor.
Here’s my personal take on the Permian. If the amount of oil coming out of the Permian lowers the price of oil enough to kill other projects, I’m glad. I don’t want drilling expanded in either my area or the Arctic. If Glenn’s posts contribute to the idea that we have more oil than we know what to do with, well, great.
First shale test well on the north slope Alaska gets fracked this week. See my post above.
Hi Boomer,
The problem is oil price volatility. Sharp spikes in the oil price due to a lack of investment can send the economy into a severe tail spin. Generally the suffering that ensues is not a good thing. Smart economic growth coupled with good government policy can have many benefits including reduced human population growth as the average World citizen becomes more prosperous, more educated, and demands more equal rights (especially for women).
But maybe that investment will go to different energy-related projects. I think we are seeing a decline in oil even if that isn’t clear to everyone. I am basing this on what I am seeing from the big oil companies. The industry seems to be permanently changing and maybe that price volatility is part of the process to change how we view and invest in energy.
Hi Boomer,
That is a good point, but if oil supply is not adequate it might precipitate an economic crisis. Oil markets require regulation due to the long lead time for many of the projects, that is the reason why the RRC regulated output from 1935 to 1970 and OPEC has attempted to do so from 1985 to the present.
LTO may be messing this up and it would be better if the RRC stepped in to regulate output, maybe other oil states would follow or the Federal government could try to coordinate the various State Energy Agencies through the EIA.
Volatile oil prices help only the speculators.
I definitely would prefer regulation. Right now we seem to be getting low prices, excess production, and the usual wasteful consumption. I’d prefer judicious production, pricing that reflects costs, and more emphasis on conservation.
+1
Better accounting would go a long, long way towards accomplishing those goals.
1st, proper taxation to internalize costs like pollution and security. That would reduce excess consumption.
2nd, proper reporting of all costs by oil companies, to ensure that investors know exactly what they’re getting.
May drilling summary from Richmond EP:
WGEG recorded 19 E&A well completions in May, up from 16 in April. There were 6 high impact well completions. Ayame-1 in the Eastern Tano offshore Cote d’Ivoire encountered oil shows only; Yakaar-1 offshore MSGBC encountered 45m of net pay within a 120m gas column and is estimated by the operator at ~15 tcf; Karamah-1 offshore Oman encountered hydrocarbon shows; Stordal in the deep water of the Norwegian Sea encountered gas shows; Thalin-1B appraisal well successfully flowed from both the upper and lower reservoir zones; and Gohta-3 in the Barents Sea encountered oil shows in a poor reservoir quality section.
Also summary of 2016 exploration report:
Commercial oil and gas volumes discovered fell to a nine-year low in 2016, as the ‘lower for longer’ oil price scenario caused companies to reduce exploration programmes further, with less exposure to frontier, especially deep water, and emerging play drilling.
The diminished 19 well frontier programme delivered only one commercial success, a modest sized gas discovery offshore India. Frontier oil exploration continues to fail to replenish the emerging play prospect inventory, which is acting as a break on future oil exploration performance.
The commercial success rate was the highest in nine years at 35 per cent, eight percentage points higher than 2015, with success rates improved on the lower well count in proven plays and proportionally fewer high risk frontier wells.
Overall drilling finding costs increased to $2.0/boe in 2016 from $1.6/boe in 2015 due to the lack of large frontier and emerging play discoveries and much smaller average discovery sizes. Oil prospect finding costs averaged $3.1/bbl in 2016 – slightly down on the $3.4/bbl recorded in 2015.
88 per cent of the gross 17.4 bnboe discovered by the REP40 peer group companies since the start of 2013 is still at an appraisal stage, reflecting a marked slowdown in resource progression to production due to the oil price fall.
Exploration drilling plans for 2017 would suggest a slightly higher (~10 per cent) drilling count than in 2016. Plans are still fluid, however, and the number of wells drilled in the first quarter of 2017 was down 35 per cent on the same period in 2016, with a record high average commercial success rate of ~60 per cent.
62 high impact wells are planned globally for 2017, targeting 19.5 bnboe (unrisked), 37 per cent of which is oil. 24 of these wells are targeting frontier plays, 11 of which are in the Atlantic margins and the Norwegian Barents Sea.
REPORTING OIL COMPANIES’ PROVED RESERVES IN 2016 DECLINE FOR SECOND CONSECUTIVE YEAR
https://www.eia.gov/todayinenergy/detail.php?id=31592
Annual reports of 68 publicly traded oil companies indicated that their aggregate proved liquids reserves declined in 2016 for the second consecutive year. The decline in proved reserves was heavily concentrated in a few companies that reduced their estimated reserves from Canadian oil sands projects. Downward revisions of existing resources, relatively low extensions and discoveries, and relatively high production also contributed to a decline in proved reserves.
All areas dropped in reserves, Canada the most, but looks like a high relative loss in Europe.
Also:
So far in 2017, capital expenditures remain lower than for the same period in 2016. Generally, larger companies with more production are reducing expenditures, while relatively smaller companies are increasing their capital expenditures.
So not likely to get significantly better next year unless saved by a sudden price rise, Be interesting to see how Bloomberg, Reuters and all the oil industry blogs like FuelFix, OilPro etc. pick up on this.
If you’re small and have nothing to lose, you borrow money.
If you’re large, you aren’t that casual. You might borrow to return capital to shareholders, but that is money they would not see otherwise.
Ohio just released production figures for the Utica for the first quarter, 2017.
87 wells produced over 1 Bcf with 33 or those over 1.4 Bcf over 90 days.
Expressed in terms of energy in oil equivalence, 1.4 Billion cubic feet of natgas equals almost a quarter million barrels of oil … in three month’s production.
For the first time, a well has surpassed 2 Bcf in a quarter, the Pittman 3H from Eclipse, 2.211,694 cubic feet, a flow rate over 25 MMcfd.
This area is on the cusp of re-writing gas production on a global scale.
So much for coal.
Eclipse is another example of big wells, little to zero profits.
Look at a chart since their IPO.
But, shares are higher than managements previous company, Rex Energy, which after a 1 for 10 reverse split is $3 (split adjusted 30 cents).
Shallow
I wouldn’t be at all surprised if a lot of these guys got bought up by bigger fish with a lot of capital backing. I think EQT has 1 billion cash in the bank.
There is so much gas, so much area, but the realized price is in the toilet.
That said, Cabot turned a hundred million profit 1 Qtr 2017 and talked a lot on CC of options with expected quarter billion profit for FY 2017.
A lot of volatility still, but there is a growing market for both gas and NGLs.
They should be able to export this gas to Europe – lot’s of expensive russian gas here, and the Netherlands start running dry.
Eul
First two US LNG shipments arrived the other day in Poland and the Netherlands.
My limited understanding is the flexibility of destination delivery is a big plus for the players involved.
According to the EIA, the Utica is now experiencing a 185 mcf/d Legacy Decline rate. Here are the approximate legacy decline rates for shale gas in the Utica:
Jan 2014 = 20 mcf/d
Jan 2015 = 40 mcf/d
Jan 2016 = 100 mcf/d
Jul 2017 = 185 mcf/d
So… while Eclipse might be pumping in GOBS of sand and fracking fluids and god knows what else to produce these large shale gas wells, they are also dealing with very high legacy decline rates.
I don’t see anything new here. At some point, these decline rates are going to gut these energy companies.
steve
I realize I can be a little slow sometimes, but I never did quite “get” the concern with legacy decline rates … all the more so in an explosive growth environment such as the Ohio Utica.
2014 – 839 wells – 479 Bcf production
2015 – 1,282 wells – 1,015 Bcf
2016 – 1,562 wells – 1,465 Bcf
2017 – 1,614 wells – 372 Bcf (90 days only)
So, to go from 839 up to1,614 wells would, I s’pose, incur a growing decline from a larger base. No?
Now, if one also realizes that the per day production from 2014 to 2017 increased from 570 MMcfd to 4.1 BILLION cubic feet/day, one might ask “What’s the fuss”?
There is a demand for gas and it gets used (disappears) every year.
As we use more and more gas, more and more people/industries now require the gas to survive. Chemical plants, homeowners, pipelines, LNG export fracilities, power plants, etc. If we ever reach the point where we cannot keep up with the growth plus the decline, some of these current users will have to go without.
As long as we can keep up, “there is no fuss.”
But, realize the power of compounding. If the growth rate in gas usage is between 3-4% year, then after 100 years, we need to produce 32 times as much gas – with NO decline rate factored in. With a 2% growth rate, about 8 times as much, again without factoring in a decline rate.
Gawd, I get so tired of this abundance bullshit. It never ends. The US has been, is now, and will be a net importer of natural gas. How anybody in their right mind cannot consider the enormous decline of these AP wells a “fuss” is beyond me. And exporting this shale gas in the form of LNG is shortsighted, made without regard whatsoever for America’s energy future, greedy, and stupid.
If one focuses on the bottom 95% of these gas wells, and the financial condition of the producers in that region, the picture being “framed” is entirely different. Take Cabot for instance, good grief: http://financials.morningstar.com/ratios/r.html?t=COG
Its fascinating to me to observe. There are essentially 2 1/2 commenters on POB that never give up; link, after link after investor presentation slide after link. Always the top 5% of all shale well performers, never the bottom 95%, never the actual meat of the resource play. And NEVER with actual financial data of the companies in their portfolio. They are refuted every which way but Sunday, time after time with realized production data, from people that can think for themselves, yet they keep coming back with the same tired message…hydrocarbon abundance on a peak oil and gas production blog. Go figger.
There are simple solutions to excess production.
1st, taxes to properly account for external costs like pollution and security.
2nd, proper reporting by operators of all costs and relevant assumptions, projections and field history to investors.
3rd, hefty excise taxes to repay local areas for the loss of one-time resources.
Well, as always, the key economic concept is substitution.
Right now, NG has a large market due to overproduction. Overproduction makes it cheap. When the price rises for whatever reason, people will (eventually) switch to substitutes:
— electric heat pumps for space heating
— electric stoves & ovens for cooking
— electric furnaces for industrial process heat
— solar power and wind power for power plants
— batteries for power plants at night
Chemical plants genuinely cannot do without gas, but thankfully they use very small quantities and will pay premium prices for it.
Chemical plants can use a variety of sources for hydrocarbons: coal, plants, electrolytic H2 & environmental carbon, etc.
OTOH, If petrochemical feedstocks are the only use for FFs, they’ll last a very, very long time, and this use doesn’t involve burning them, so why not?
coffeeguyzz,
The eye-popping initial production rates are great.
But an achievement just as important, if not more so, is the flattening out of the decline curves that has been achieved with the newer fracking techniques. Slower decline rates equate to much greater EURs.
Much of this technological breakthrough has been very recent.
Pioneer Resources, for instance, didn’t begin experimenting with Version 2.0 completions until mid-year 2015, and with Version 3.0 completions not until the first quater of 2016. One of the changes in completion techniques has been the rapid increase in the amount of proppant being used. This rapid increase YOY can be seen in this graph between 2014 to 2015, and even more so between 2015 and 2016.
The amounts of water being used and then produced per well in PB are greatly increasing also.
What is water costing per barrel in PB, both to purchase for fracking and to dispose of? There are some there that say water handling is the most important issue in PB unconventional plays.
The results being achieved with more advanced completion techniques have been one of the great success stories of the shale industry.
The greatly enhanced well productivity can be seen on this graph from Enno Peter’s website, Visulaizing US shale oil production. As completion techniques have improved through the years, decline curves have flattened out.
Because Verson 2.0 and Version 3.0 completions are so new there is little production history for these wells. But for the most recnet months (when Verson 2.0 and Version 3.0 completions were becoming more widely used), what can be see from Enno Peter’s graph is a continued flattening out of the decline curves. The multi-year trend is accellerating.
The Texas Railroad Commission data which Enno Peters uses is notoriously slow to be posted. drillinginfo’s data, however, since it comes directly from the operators, would be more current.
You once observed that “The shale industry is a work in progress.” The data bears this out.
The results of the constantly improving drilling and completion techniques being used in the shale industry is striking.
It can be seen in Pennsylvania.
This Pennsylvania EIA chart has absolutely NOTHING to do with improving completion techniques and everything to do with the shear number of 5BCF wells drilled in that state since 2010, many of which were drilled by Ultra, who is now belly-up and/or on Ultra Edition 3.0.
The shaleprofile.com to DI graph, with a line drawn on it, is high school stuff. I don’t send production data to DI, no operator in Texas does. DI provides services to the oil and gas industry for fees.
Mr. Stehle, respectfully, are you a PE and still a member of the the SPE?
Nah.
The number of unconventional wells completed in Pennsylvania in 2016 was only a fraction of what it was in prior years.
The production gains in statewide production are being achieved with much greater well productivity, not an increase in the number of wells being drilled and completed.
Believe it or not, Mike, some of us prefer to live in the reality-based community, not in the fact-free and logic-free zone where the only argument seems to be to personally attack one’s opponent.
So, increased Marcellus production is not a cumulative result of the number of wells drilled since 2009 and corresponding legacy production?
Yeow !
I withdraw my question regarding your status as a PE, or whatever type of engineer you are, and wish to downgrade my comment regarding high school level stuff to grade school level stuff.
Like I said, ad hominem seems to be the only weapon you have left.
I assume drilling info data comes from crude oil purchasers. It is my understanding that is where IHS US Data online comes from.
For our leases, the IHS data always matches our run statements, which makes sense as they buy the information directly from the crude purchaser. There is about a 1-2 month lag between the time we receive our run statements (around the 10th of the following month) and when the data is updated on IHS.
Hi shallow sand,
I have read that drilling info just aggregates the data from state reporting agencies, but I don’t know.
I would think your state agency might have data on your wells as taxes must be paid, but it may not be at the individual well level, as is the case for North Dakota for example, but not for Texas which reports at the lease level.
It can be seen in Ohio.
And it can be seen in the Permian Basin.
Hi Glenn,
Chart below uses Permian Basin Tight oil data from the EIA. The DPR includes about 700 kb/d of conventional output from the Permian Basin region. In the past 12 months Permian basin output has increased by 280 kb/d (May 2016 to April 2017).
https://www.eia.gov/petroleum/data.php#crude
click on tight oil estimates
Glenn. The increase im legacy declone rates and drop in prouction increase per rig does not tell the same story
And it can be seen in the prices of natural gas and crude oil, which has been an enormous boon for consumers and for American businesses.
If it were not for the shale revolution, natural gas prices would most likely still be above $12/mcf, and oil prices above $100/bbl.
This of course is anathema to the non-shale sectors of the fossil fuel industry, as well as the renewables industry, which are in competition with the shale producers.
Hi Glenn,
The only question is how long these companies can continue running while losing money. I agree the low prices may have helped some people, but spending on oil and natural gas is a pretty small proportion of total income. The lack of investment due to low oil prices may result in a price spike later.
It will be interesting to see how fast LTO output rises. I have read that there are a lot of wells that have been spud, but there are not enough fracking crews to complete the wells. This will probably drive completion costs up as firms compete for scarce fracking crews and service costs increase.
At least through April completions have not gone up by very much on the Texas side of the Permian, though improving well productivity may still lead to increased output.
Dennis Coyne says:
I sure hope so. I’m ready for that creative destruction to kick in, and for all those projects and wells that need $80 to $100/bbl oil in order to be economical to begin to wither away.
But I’m not holding my breath.
And as you say, “It will be interesting to see how fast LTO output rises,” since this could have an enormous impact on future oil prices too.
And future oil prices will in turn be a major determinent of future activity levels in the shale industry. With sub-$50 oil, we could see rig activity in the Permian Basin level off, and it could even decline.
But if oil rebounds above $50 per barrel again, we’ll probably see the shale producers hedge up again, and the shale operators will party on.
My current demand-based assessment is that sub-$50 oil will be here *forever*. The demand is drying up faster than the supply.
Hi Nathanael,
If the Cornucopians (on oil) are correct, then that may be right.
They are not correct and supply will fall faster than demand, especially if you price forecast of $50/b or less were correct. Supply is very constrained at $50/b. LTO loses money, deep water drilling is very constrained and many OPEC nations will not be able to balance their fiscal budgets at that price. We will see $75/b or more by 2020.
Hi Glenn,
That chart is pretty funny.
So we extend that line based on 3 data points. Seriously?
You should do late night TV 🙂
Dennis,
Two things:
1) drillinginfo’s analysis is probably based in part on the success of improved completion techniques in the past, and the calculation that that trend will continue.
2) drillinginfo, just like the oil and gas producers who drill and operate shale wells and have rushed into the Permian Basin in such a big way, have a few more months of production history than what Enno Peters is privy to. They also have a wealth of other information.
I know from your previous comments that you think the teams of engineers and scientists who work for these companies are just stone dead stupid, or dishonest, and that you are the only person in the world who knows anything. But hey, that’s your prerogative. The shale revolution proceeds regardless of your opinions.
Hi Glenn,
No not stupid, I just don’t understand where in the Article talking about whether the high land costs in the Permian are justified, that they would do an analysis which clearly stated that they left out royalties and taxes.
I ignore the conclusions of such analyses.
So drilling info is speculating about the future?
Who would do such a thing? One cannot assume that because well productivity has improved in the past that it will continue in the future.
The chart I referred to is your adjustment of the graphic from Enno Peter’s site. The fact is that based on the past data a well profile for over 700 kb of oil cannot be justified for the average Permian well.
Just out of curiosity does drilling info do an analysis for the entire Permian Midland formation?
Do you remember the Bakken operators touting a “typical” Bakken well with an EUR of 600 kb?
Those analyses were off by roughly a factor of two (the correct EUR is about 320 kb).
You are correct, that I do not have access to the proprietary data and Enno uses public data. Note that the Texas data which is available is accurate, but you are correct that it is incomplete. The drilling info data is also not complete, but it is better.
Mike and shallow sand know plenty and shallow sand has access to IHS data, but is unable to share it.
Yes the shale “revolution” proceeds. Here is what I thought would happen in Dec 2012 for future Bakken output.
http://oilpeakclimate.blogspot.com/2012/12/quick-update-to-tight-oil-models.html
I just think LTO resources are more in line with what the geologists at the USGS think rather than the economists at the EIA.
Oh, my mistake in analysis in late 2012 was that the scenario was too optimistic (partly because of the unanticipated crash in oil prices).
Dennis
Whoa, whoa, whoa.
Please, if you sincerely make the comment that a ‘typical’ Bakken EUR is 320k, you are grossly misinformed.
Grossly, and I say that with no aspersions whatsoever.
I would caution you and others when using Enno’s site as his data and methodology are at variance with other sources.
This is not to say there is a scintilla of inaccuracy or nefariousness on Enno’s part. Quite the opposite, in fact.
But, as one example, the 9/21/2016 DMR presentation specifically shows a ‘typical’ Bakken well producing 110 barrels a day at the 5 year mark and hitting 50 bpd after 16 years online.
There are numerous factors behind the glaring divergence between Enno’s work and the ND DMR’s, but – once again – quoting a 320k Bakken EUR is wildly misplaced.
Coffee. What are the factors for DMR and shaleprofile.com divergence?
Enno would be in a better position than I to discuss this, ss.
But his inadvertent inclusion of some Red River wells would be an example.
Hi Coffeeguyz,
The fact is that using that for an average well profile and the wells completed, matches output quite well. It is possible with high grading it has increased a bit, but not likely to be more than 350 kb of oil. Natural gas is not included, but Natural gas adds very little value relative to crude ( 3 times less in value for a boe of natural gas vs crude so any such “barrels” should be discounted by a factor of 3 at $55/b oil and $3/MCF Nat gas.
The NDIC “typical” wells suffer from the same kind hype as investor presentations.
I don’t worry about single wells, for every monster well there are many more dogs that bring the average down.
Hi Shallow sand,
My estimate is correct.
The typical well presented at the NDIC has 11 b/d at year 45.
My guess is they are using an exponent with b=1.5 or more, not credible at all.
We don’t know what happens beyond year 10 or so, but they have the “typical” well producing 68 b/d at year 10, based on the data you have seen does that seem reasonable?
The average 2010 well (based on data from 814 wells) produces about 45 b/d at 6 years, where the “typical” well in that presentation produces twice this amount (94 b/d).
Have you seen a big difference between Enno Peters data and IHS?
Igor Sechin, just like Mike, shallow sand and the renewables producers, is caught up in a competitive struggle with the shale producers. And has every bit as great an interest in seeing it fail as they do. But this hasn’t sent him into an orgy of denial and wishful thinking.
I would very much like to see US shale make money, contrary to what you assert. However, that is not looking likely.
Is a company like PXD, which has among the best acreage, going to have EPS of $8.00 per share at $45 or lower oil and $3 or lower gas, which would justify a $160+ share price? Or is it more likely that it will take $65+ WTI and 4+ HH to see that happen?
Shallow, am I to infer from Mr. Stehle’s comment above that you are I are a.) not as smart as this Russian, or that b.) we are as un-American as this Russian for not embracing investor presentation induced analysis, c.) both the above ?
Nostrovia !
Mike. For some reason you and I are looked at with a lot of disdain by a few here. I guess those who own an interest in stripper well production in the US are the lowest of the low, and it is very fun for the fans of large corporate firms to lump us in with the rest of the “non-shale” rabble.
I try really hard to not get personal and stick to facts. If I get facts wrong or go off on the wrong tangent, I try to correct it. I fully accept the fact that shale tanked the price and that 99% of USA loves it.
I think shale is kind of like Tesla. Money keeps getting thrown at it because people love the idea of low gas or no gas. Doesn’t matter if it makes money. In fact, I read some comments a guy wrote about Tesla on SA. He wrote Tesla is the largest crowd funding project in the history of crowd funding. People want it to work so bad they don’t care at all about the economics. I suppose shale is the same deal.
My family actually has more invested in US Ag than we do in oil. Those prices are low too. I guess US Farmers are just not “competing”. Same as US conventional oil and gas producers are not “competing.”
It will be just our luck that Wall Street’s next big racket will be diverting pension money to miles and miles of unprofitable greenhouses that will flood world grain markets and drive corn to $1, wheat to .75 and soybeans to $3. Then the Glenn’s and TT’s can laugh at us again and shout to high heaven that we just need to compete.
I am just fortunate that these are investments for me, not the livelihood that it is for Mike and others. I have friends in our field that are hurting, trying to put kids through college and whatnot. One laid off his only hand and has taken on all the work he can. He hasn’t had a day off in over three years. He and I have discussed this stuff a couple times across the fence row. He is about as conservative politically as they come, big NRA and the whole 9 yards. He doesn’t have time to read this crap, so he asks me sometimes about what shale is doing in terms of production. Recently, after I tell him about the gains, his usual response is, “Oh piss!” Then he asks if they are making any money, and I google some earnings and read them to him. The usual response is, “WTF!” We now have a running joke, when the price drops I get a text asking why the hell I am flooding the market with my suit and tie wearing cronies.
I assume this post will get some derisive comment. Oh well. I don’t get too concerned about that. I will say, however, that stripper wells operators are generally small business owners. They are probably about as similar to the US farmer as any other industry. Compared to shale, very small footprint. Operating wells that have been there in some cases over 100 years. I guess tough times for that is something to crow about.
I don’t consider you and I, or thousands like us, the lowest of the low. I am fiercely proud of the contribution I have made to providing hydrocarbons to my country over the past half century, keeping nine or so good men and women employed all these years. Yourself, the same. We have nothing to be ashamed of.
I detest people who con other people out of money, or that borrows money they knowingly cannot pay back. It is akin to stealing. If you embrace the concept, and promote it, you are no different. In my mind you are actually… worse.
Adios, pardnor !
I like your comment.
I have to say, though, the economics of shale are dreadful compared to the economics of Tesla. Michael Liebreich described the key point: manufacturing economics gets cheaper as time goes on due to the learning curve and economies of scale, while resource economics gets more expensive due to depletion and as the big economies-of-scale deposits are used up. While every industry has elements of both, shale oil is basically resource economics, and Tesla is basically manufacturing economics.
Hi shallow sand and Mike,
You guys (and George Kaplan and Alex S) and a few others are the main reason this blog is worth reading.
Please ignore the clowns (like me) that probably don’t know squat about producing oil. Most of us have never put our hands anywhere near a drilling rig, the closest I have come to this was watching a water well being drilled on my property (all of 400 feet deep). 🙂
Glenn,
There is no question of denial (from conventional producers wherever they are located), but the question is can anyone help shale industry.
If shale decides not to listen to, not to change, then shale decides for committing suicide. What can you do? What OPEC or Russians, Mike, Shallow can do? There were 2 rounds of production cuts talks and US (along Canada, UK, Norway) stubbornly refused to participate. It is almost that West is so eager on self destroying itself.
Madness is rich elite diseases. Poor countries cannot afford it.
Bigger frac’s, more money. $9M dollar well costs, minimum.
And the incredible amount of fresh, potable water to achieve those frac’s is stunning. At typical 30% produced water dilution rates, over 9.5M gallons of fresh water per well, 18B gallons of fresh water per year at 160 wells per month. Enough fresh water in one year to serve the people of Odessa for 4 1/2 years, all this in arid W. Texas where water is life: https://rbnenergy.com/wipe-out-how-will-permian-eandps-dispose-of-all-that-produced-water. If you don’t care about the water these wells use you are brain dead.
Anybody that has ever actually operated an oil well that produces 8BW per 1BO knows it is impossible, an outright fabrication, to declare OPEX of $2.33 per incremental BO (PDX) when dealing with scale, corrosion, produced water, oil and water treating and pumping wells on rod lift from 8,000 feet. A CT wash out for frac sand, an ever occurring event in shale operations: $110K per event. Lift costs at year 2 are more like $6.50 a barrel and they go up as the well ages. Concho says $5.50. 7% severance and ad valorem tax on $53 dollar hedged oil is $3.71 per barrel, it is a lie by omission to leave out G&A costs ($3.35 per incremental BO for Concho) and interest expense (about $2.20 per incremental BO for Concho; twice that for Devon working in the Permian and dragging all of its debt around like an anchor).
Hi Mike,
Thanks. I use $13.4/b for combined G&A, interest costs, and lifting costs and $9 million for well cost for Permian Basin wells, royalties and taxes of 32%, and an annual discount rate of 10%. EUR is about 304 kb over 18 years well is assumed to become uneconomic at 10 b/d. Note that adding the 27 kboe of natural gas and NGL for the total EUR of 327 kboe reduces the breakeven price a bit. I assume NGL sells at about 50% the price of crude and NG at $3/MCF. The EUR breaks out at 304 kbo, 12.5 kb NGL, and 10 kboe of Natural gas (60,000 MCF NG) for the average 2016Q1 Permian well.
Mike says:
That certainly isn’t what the IHS Global study commissioned by the EIA that Dennis linked above concluded.
Trends in U.S. Oil and Natural Gas Upstream Costs
https://www.eia.gov/analysis/studies/drilling/pdf/upstream.pdf
Even after considering the cost of longer laterals and bigger fracs, actual average well cost in the Midland Basin declined from $10 million in 2012 to below $7 million in 2015 and 2016. IHS predicts the average horizontal D&C well cost in the Midland Basin to rise to only $7.5 million by 2018.
Hi Glenn,
And when land cost is included the well cost goes up to $ 9.3 million in 2014.
Mike,
IHS, however, did come up with some very high operating costs for Permian Basin wells that should please you. These were for FY2014. But one can discern from the report neither exactly what they include nor if they are for a combination of vertical wells and horizontal wells, or horizontal wells alone.
Hi Glenn,
How do we know the decline curve has flattened if we only have 12 months of output data?
Using info from shaleprofile.com, and considering only Pioneer wells in the Permian Basin I get an oil well profile of about 441 kb for wells completed in the first quarter of 2016. This data set is very small (only 45 wells) and may just reflect a sweet spot acquired by Pioneer. What the well profile will look like beyond 12 months is very much a guess. Well profiles with very large EURs can be created using exponents on the hyperbolic of above 1, but such well profiles have proven unrealistic in the Bakken (with projected EURs of 600 kb, when reality was about half that).
You are speculating about future output and the oil guys here know those inflated type curves are 2 to 3 times higher than reality. So far the estimate by Enno Peters for 2016 Permian wells (300 kb EUR) looks very realistic. The 750 kb EUR estimates from drilling info, not so much.
Dennis Coyne said:
And you aren’t?
But even more than that, it is not me who is doing the speculating. I am merely citing the work of others who’s speculations disagree with your speculations.
And it should be obvious whose speculations the decison makers favor. And trust me, it isn’t yours.
Hi Glenn,
I am speculating, but you complained about it, now you are quoting the speculation of drilling info. There are many reasons why the well profile might be wrong, but if you talk to producers, most of the error is estimates that are too high.
Even my estimates, if anything, are likely to be too optimistic.
Hi Glenn,
The data suggests my well profiles are correct and the model using these well profiles and number of wells completed matches output quite well.
The model is not perfect, but does a fairly good job considering its simplicity.
Interview with David Stockman.
Feds/Central/Mega Banks QE Malfeasance Drove Billions into High Cost Shale Junk in desperation for yield. … such malinvestment and disorder creates massive economic waste. Now we are in the Crackup phase.
https://youtu.be/QBIXAsZcIvY
Interesting article about why peak oil did not happen when some thought it would.
https://ourfiniteworld.com/2017/06/12/falling-interest-rates-have-postponed-peak-oil/
Peak conventional oil already happened 2005. The cheap stuff already runs dry, no more drill a hole and pump happily for 30 years.
We now wait for peak very compilicated and expensive oil(deep sea, tar sand and fracking). Here peak oil mostly depends on the financial side – there is lots of stuff with declining EROI, but with the right price it will be extracted. The question here is how long we can afford this.
First the oil for just burning it will be phased out, that already happens.
Secondly, the oil for land transport will be phased out. It’s on the horizont.
Third, the oil for air transport will be phased out – still science fiction.
And finally, oil for chemical usage will be phased out – that’s in a far future. And oil for chemical usage can be pumped with an EROI < 1 with no problem, since it's a raw material like iron or sand and not an energy source.
Using oil for sea travel is more of a waste disposal – it will be phased out when land transport is phased out. Use liquid gas instead, later hydrogen from solar or fusion energy – ships are big enough to support this.
If this phasing out isn't fast enough, there will be a global crisis – as with a growing asia unconentional oil can't keep up with growing demand and declining cheap oil for more than 10 or 20 years, according to all studies.
For example, when Ghawar finally gives up, all hyped US fracking oil growth is needed to replace this one giant field, with no capacity to supply demand growth.
Hi Eulenspiegel,
Conventional only peaked in 2005 if it is defined very narrowly (Colin Campbell’s definition). If conventional C+C is defined as all C+C except extra heavy (API gravity less than 10 degrees) oil and LTO, then a new peak was reached in 2016.
I agree that by 2030, and possibly by 2020 that peak conventional (as I have defined it) will have been reached. It is doubtful that NGL, LTO, and extra heavy oil will be able to fill the gap as conventional output declines. Oil prices will rise and we will try to transition to other means of transportation while using the output as efficiently as possible. Hybrids, plugin hybrids, EVs, and more public transportation, as well as electrified rail for long haul transport will help along with overhead wires on major routes for short haul trucks and buses with batteries used for the last few miles.
Completely omitted form Tverberg’s study is the fact that oil and gas prices have gone down, not up.
This is not to say that loose monetary policy cannot, under the right conditions, cause oil demand to increase. What it does say is that Gail’s blinkered analysis is based on incomplete truths, not the whole truth.
Hi Glenn,
In an earlier comment you said,
Dennis,
And where did you come up with the nonsensical notion that “royalties are not included in the “Area 1 – Wolfcamp A” economic analysis”?
Talk about a zinger, that one is beyond the pale.
One cannot make fact-free claims like that if one wants to retain any credibility.
http://peakoilbarrel.com/open-thread-petroleum-june-7-2017/#comment-605220
I respond:
For where I got that Drilling info did not consider royalties see the article that you cited above at drilling info(at link below)
https://info.drillinginfo.com/permian-premium-are-high-prices-justified/
From the article linked above we have:
[Table 3. Net Present Value (NPV) of Pioneer Wolfcamp B wells drilled in Martin County using 5 years of forecasted production (Arp’s model) and a 10% discount rate. Costs include reported drilling and completion cost ($7.5MM) and facilities cost ($0.4MM), and estimated land acquisition cost ($1.43MM). Taxes and royalty burden are not considered.]
Note that the well cost is $9.33 million=7.5+0.4+1.43
http://peakoilbarrel.com/open-thread-petroleum-june-7-2017/#comment-605358
Note that the original comment had “7.33+0.4+1.43” which was mistyped, I corrected this above to “7.5+0.4+1.43”
So the source of my suggestion that royalties are not considered was the article you cited. (In bold above).
I do not have access to the proprietary Drilling info data, but the other information that you provided from drilling info gave no information on the royalty assumptions.
You provided that after the fact.
Hi Glenn,
On the Wolfcamp A area 1 analysis you gave the economic assumptions below:
Can you point me to the royalty assumptions there?
http://peakoilbarrel.com/open-thread-petroleum-june-7-2017/#comment-605155
Given that earlier Drilling info had excluded the royalties, I assumed that was their standard practice, so far you have claimed that it is included, perhaps it is true.
Dennis,
I cited two distinct, different analyses.
And even though they were made by persons who work for the same company, the areas of investigation and the assumptons that went into the first analysis are not the same as those that went into the second analysis, which specifically zeroes in on “Area 1 – Wolfcamp A.”
The first study was authored by Lindsey Artman and can be found here:
https://info.drillinginfo.com/permian-premium-are-high-prices-justified/
The other study is proprietary and was probably made by a team of engineers and scientists. Below I’ve included the heading for the second report.
Granted, it is true that no specific mention was made of the NRI used in the February Midland Basin Report. But just because it was not mentioned does not necessarily mean the royalty burden wasn’t taken into account, as was your assumption. There are other explanations of why it wasn’t mentioned.
It’s pretty easy to attack and discredit someone else’s work, especially where there is a strong desire to do so and when that other person is not present to explain and defend their work, to provide the reasons why they did what they did.
Glenn,
The royalty assumptions were not stated, as I don’t have access to the proprietary data I cannot check.
In any case the well cost is too low and the well profile is too high, and that criticism stands.
Glenn
I don not think she missed it out. I think she said, oil prices have fallen, making thing more complex.
My take on things is, low interest rates allowed companies to spend money drilling in places that were previously too expensive. After drilling for a few years they got very good at it. Producing too much oil. That is what drove prices down.
Once this excess capacity has been used up by increasing consumption prices will start to gradually increase.
The Canadian Association of Petroleum Producers
2017 CAPP’s annual Crude Oil Forecast, Markets and Transportation report provides the association’s latest long-term outlook (2017 to 2030) for total Canadian crude oil production and western Canadian crude oil supply.
http://www.capp.ca/publications-and-statistics/publications/303440
BP Statistical Review of World Energy
http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.htm
June 2017, pdf file, direct link: http://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review-2017/bp-statistical-review-of-world-energy-2017-full-report.pdf
Thanks Energy news.
The Canadian Association of Petroleum Producers (CAPP) forecasts an increase in Canadian oil output of 1.25 Mb/d from 2015 to 2030. According to EIA’s AEO 2017 US C+C will increase about 1.1 Mb/d from 2015 levels by 2030. So that is 2.35 Mb/d higher output over 15 years from Canada and the US if both forecasts prove correct. For many years World average C+C consumption has grown by about 1 Mb/d, if that continues we will need another 12.65 Mb/d of C+C output from somewhere or consumption will need to grow more slowly. I am doubtful that OPEC will manage to increase output from 35 Mb/d to 48 Mb/d from 2016 to 2030. This would also require the rest of World C+C output (excluding OPEC, Canada, and US) to remain on plateau for 15 years.
The OPEC increase and flat production from non-OPEC minus US+Canada seems very optimistic, some might say unrealistic.
THE BP BIBLE FOR 2016 IS OUT
http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html
Here are the important points:
1) Global oil consumption increased as it has relentlessly, now 96.6 mbpd
2) Global oil production 92.2 mbpd — that’s less than consumption, and Yes, price is down tra la tra la
3) China’s oil consumption continued its relentless rise — now 12.4 mbpd
4) KSA is neck and neck with Japan for #4 consumer of oil at about 4 mbpd, didn’t quite catch up.
5) India’s consumption continues its relentless rise now at 4.5 mbpd, #3 in the world and surging.
6) US consumption also continued its rise now at 19.6 mbpd. US production lists a decline to 12.3 mbpd. (this is all liquids, remember). So consumption up, production down, price down.
7) Iran (18%) and Iraq (10%) both list strong increases in production
Isn’t it amazing how all those EVs have killed off increases in oil consumption?
Hi Doug,
Yep all 2 million of them (out of about 1.2 billion personal vehicles).
Doug, you understand.
Spend a bit of time on cobalt.
Ok. If the most pessimistic scenario is right, then what does it matter to you guys if some of us experiment with alternative energy plans?
If there’s nothing any of us can do to change the course of anything, why do you bother to post here? Isn’t it just wasting what time you have left?
What is your purpose it telling us the world is doomed? At least the Christians warning of the Apocalypse offer the hope that conversion will bring salvation.
I don’t understand your thinking. What difference does it make to you what we believe?
“What difference does it make to you what we believe?”
So it all boils down to belief? Isn’t that what Jehovah Witnesses tell us? Frankly I could give a rat’s ass what you “believe”.
And if there is a message in what you are posting, I don’t get it. Can you clarify?
We’re all going to die. Should we not bother to live in the meantime, knowing the inevitable outcome?
Some of us just get tired of the cornucopian crap. No hard feelings.
Doug, You mean you don’t enjoy all of the clips from US shale industry power points? LOL
Hi Boomer.
Some reasons why hardcore doomers still come here:
1. Misery loves company.
2. If you’re smart enough to reach the conclusion that we’re all doomed (and likely sooner rather than later), you’re also smart enough to know you could be wrong.
3. We need something to do while we wait for the end of the world- we bore easily. 🙂
-Lloyd
I fall somewhere in the middle. I expect major changes ahead, with no growth or de-growth likely.
I see a combination of declining fossil fuel use, increased renewable use, AND decreased consumption for economic reasons.
I don’t believe current lifestyles are sustainable and changes will happen, either by choice or necessity.
Will all of that bring climate change under control? I don’t speculate about that.
Do I think the coming changes are good or bad? Good more than bad. I think the world will be better off without so much consumption.
Can it happen with a rising population? It can if consumption per capital goes down. That could bring unwanted changes to some people but I think it will happen. And if the changes are severe enough, the population in some areas will likely decline because the economics and resources can’t support them.
I anticipate major changes, but I don’t consider myself a doomer because I think some percentage of people and life on Earth will survive.
Maybe I should put it this way. You point out that populations will increase and renewables will be inadequate.
What if my response is, “So what?”
Does the conversation go anywhere after that?
Let’s just say God will provide and leave it there.
Or the universe will provide.
Why would it matter what is believed if he’ll be dead soon?
haha
Cobalt: too depressing. Everyone knows the Democratic Republic of Congo (DR Congo) has the largest reserves of cobalt: current population 82,081,422 — 6 births per woman. Maybe someone will volunteer to teach them about birth control. Ha ha.
I posted a lot of links about cobalt. Between opening new mines, recycling cobalt, and building batteries without cobalt, there are some possible work arounds.
BTW Cobalt made the short list of four metals that the EU chose to name as representative of the 40 metals it classifies as “critical.”
From what I’ve read in the last few days, the concern seems to be who controls the supply more than how much there is. China appears to be moving aggressively in that direction.
I hope workable batteries can be built without it. I read about some using iron.
And perhaps another solution is to massively reduce the number of vehicles, both ICE and EVs. I’m not sure we need to replace all the ICE vehicles with ones using batteries. How about more trains, buses, and human powered transportation?
Pfft, we’re a long way from peak cobalt. It’s extremely recyclable.
Remember, people were claiming wind power would never be significant… until it was significant
But if price is down and production is down, there is likely to be a transition away from oil. It may not be a smooth transition, but if production doesn’t keep up with consumption, and fewer investors/lenders want to fund production, then consumption will go down as supplies dwindle.
All those alternative transportation plans may not be the direct reason oil demand goes down, but they are likely to be useful as an alternative WHEN oil declines.
It’s good to have something else in place. That facilitates a smoother transition when it becomes necessary.
Yeah, I’m sure adding a couple of billion people to the planet will also help facilitate a smooth transition to earth’s energy balance as well.
Hi Doug,
No doubt that would make it more difficult, the 2 billion estimate has a pretty wide confidence interval, so we don’t really know what it will be.
No doubt the transition to other forms of energy will be difficult, perhaps impossible, but I am a little more optimistic than you. 🙂
I said “smoother” not smooth. Change will occur and it will be disruptive. And populations will likely change as a result. But Homo Sapiens will likely survive if any mammals survive because we are one of the more adaptable species.
There’s no reason humans have to keep living the lifestyles we have now.
Oil demand doesn’t go down.
It rises with population and GDP.
Oil consumption may go down, involuntarily.
That’s what I expect. I think economics will force people, companies, and countries to use less.
Hi Watcher,
Population growth can slow, GDP growth can slow and Oil intensity can decrease, all of these together will lead to oil demand peaking and falling as it must.
Oil demand is going straight through the floor. It has barely started but it will become obvious after a while.
Because who wants dirty black goo? Useless toxic crap. As soon as there’s a cheaper substitute people will use the substitute, because the substitute will be superior.
That’s what’s happening and it’s basic microeconomics of substitution. The speed of the drop in oil demand is determined by the speed at which the production of the substitutes (electric cars, etc.) can be ramped up. This is increasing at about 50% per year and it probably isn’t socially feasible to increase it any faster. In 2028 or so, there will be no gasoline cars sold; well before that, the decrease in oil demand will be visible.
Where’s the extra coming from?
Pretty good question. The differential is big.
If you believe the storage narrative you could look there, but the differential . . . probably too big.
Lots of crapola about. Particularly in the world of assays. Ever since during the railcar explosion spasm when Marathon pulled one assay saying there were volatiles and replaced it with another, we should have realized.
Part of the problem is different weights. It is better to use mass rather than volume, still not perfect but better. Also some of consumption is biofuels, GTL, CTL, etc. and there is storage.
In fact if we deduct the biofuels produced (assuming all of it is consumed) from liquids consumption then there were 47 million tonnes more oil produced than consumed (I am ignoring CTL and GTL because I have no data and I assume these are negligible).
So multiplying by 7.33 b/tonne that is 344 million barrels of oil added to stocks in 2016, or 0.94 Mboe/d of excess liquids production in 2016.
some energy news
The Asia-Pacific Economic Cooperation – Energy Overview is an annual publication that has a chapter discussing the current energy situation in each APEC economy, including energy supply and demand, key energy policies, notable energy developments, useful links, and further references.
http://aperc.ieej.or.jp/publications/reports/energy_overview.php
Venezuela and China agree on $2.8b in financing for oil boost: Planning Minister Ricardo Menendez
India’s consumption of petroleum products is recovering following the demonetisation shock
Chart on twitter: https://pbs.twimg.com/media/DB4B4KgXkAAI3FQ.jpg
Oil production per rig in top 3 shale basins according to EIA Drilling Productivity Report (in bbl/day)
Chart on twitter: https://pbs.twimg.com/media/DCJQeF8XsAE5bX9.jpg
OPEC MOMR June 2017 was released today, IEA tomorrow
http://www.opec.org/opec_web/en/publications/338.htm
I hadn’t heard of CAPP before now. Here are their annual stats for completions
http://www.capp.ca/publications-and-statistics/statistics/statistical-handbook
http://mobile.reuters.com/article/idUSKBN1940IL
US shale firms more exposed to falling oil prices as hedges expire
Reuters – 9h ago
According to a Reuters analysis of hedging disclosures by the 30 largest U.S. shale firms, most stayed on the sidelines in the first three months of 2017, a stark contrast from a year ago when firms rushed to lock in prices, even though oil was trading …
BTW per the Bible
Russian oil production 11.2 mbpd
KSA production 12.3 mbpd
Up 2% and 3% respectively. Quite the cut agreement they have.
Though you know what, sports fans, this is all liquids and I am coming to suspect fast and loose is the order of the day with all things assay.
Oh and BTW rev 1.0, boy didn’t that price reduction since 2014 hurt KSA and Russian production!
If you have to have it, and YOU DO HAVE TO HAVE IT, a substance created from thin air by central banks will say nothing about getting it.
I don’t use petroleum.
There’s a bizarrely common delusion among both oilmen and “peak oil” people that petroleum is essential. It isn’t. There are plenty of substitutes. For all applications except airplanes and rockets, the substitutes are now strictly superior qualitatively, which makes petroleum an *inferior good* — rich people now use less of it (except for airplanes and rockets).
For a long time, the substitutes were more expensive. Critically, for the most important applications, the substitutes are now *less* expensive. This marks the beginning of the end of the oil age.
The end happens after production capacity of substitutes is ramped up, which takes a while; my current projections converge around 2025 – 2030.
The unavoidable permanent oil glut (where demand is decreasing faster than the natural decline rate) starts several years before that. With overoptimistic exploration, the permanent glut will actually happen even a few years before that. Given that the short-term glut from the market-share war is clearly going to last well into 2018 and probably 2019, there’s a slim chance for one last shortage between this glut and the last glut, but I think it’s more likely we’re in the final glut already.
so if you drive an EV then you are not using petroleum. you are using smth that is at least 30-40% coal and 30-40% nat gas.
Unless he uses solar PV.
Yo, Watcher.
If you have to have it, and YOU DO HAVE TO HAVE IT,
I think the other side of this is “If you have to sell it, YOU HAVE TO SELL IT.”
If the developed world goes electric, that extra oil will go to generators, chain saws and mopeds in the third world.
Commerce, like water, seeks it’s own level.
-Lloyd
That’s OK Loyd, I figure that much of the US will be third world in the near future if we don’t reverse the trends occurring now.
Hi Watcher,
The cuts were in 2017, this is 2016 data.
Bakken update is out. 24,000 barrels per day increase.
Three consecutive months of large and growing discrepancy between my earlier assumptions and reality!
Veriwimp
Thanks for the heads up.
Seems a comment on this site a few weeks back referring to massive decline and ‘running for cover’ for claiming ongoing productive strength was, unsurprisingly, inaccurate.
I’m not sure how accurate Lynn Helms has been in the past, but he has just said that without big price drop and/or harsh winter North Dakota output expected to stay above 1 million b/d for foreseeable future.
At API 42, maybe it’s not oil anymore coming out.
EN
Helms actually said something similar about 18 months ago and Mr. Patterson made note, along with expressing some skepticism.
I chimed in saying, with some variation – mainly WTI related – that a million barrels of oil a day would not be an unreasonable expectation.
Well, suffice to say there were several commentators who were aligned with Mr. Patterson’s view.
Fact is, there’s almost 12,000 Bakken producers, new ones are much more productive, and declines are less than many have anticipated.
Hi Verwimp,
My model is also underestimating output, the assumption has been that well productivity would be flat or declining, but well productivity (at least the early months) may be increasing, based on Enno Peter’s data that looks to be the case.
Looking at US oil production, the descent from 1970 had many upward blips that never panned out. What we are seeing now could just be an upward blip due to economics and new technology. The same geological constraints are in play as before and the increasing amount of effort needed to extract is still present. No giant gushers and easy pickings, just sheer effort economically and technologically are keeping the flow going.
World crude oil production is actually descending lately.
Douglas Westwood indicating undersupply after 2019 – to find out more costs almost three thousand pounds. I’ve seen a couple of DW reports, they are big, but don’t always contain much new – it’s more about having your assumptions confirmed sometimes. Here it would be interesting to know where the supply comes from in 2019 and later and how much decline they are assuming. If anyone sees it please let us know.
http://www.douglas-westwood.com/report/market-briefings/upstream-investment-outlook-2017/
Where does a million b/d of offshore come from in 2018? Maybe that’s new projects but I can not see how they get that amount net of declines.
There are a lot of offshore projects due late this year and through 2018, I’d say at least 3 mmbpd nameplate. After that it drops to around 900 kbpd in each of 2019 and 2020 and then below 500 and down to nothing planned for 2023.
To come for 2017 and 2018 there are 7 or 8 150 kbpd FPSOs in Brazil; Egina, Kaombo Norte, Sonam (Africa); Atlantis North, Constellation, Hebron, Stampede and Big Foot in GoM and Canada; Kashagan, Abu Dhabi and Qatar expansions; and Greater Catcher
Clair Ridge, Kraken, Maria, Mariner, WIDP in the North Sea area. Plus about 15 smaller tie backs and gas condensate streams. After those all finish there are going to be a lot of installation, commissioning and start-up teams with nothing to do for at least five years, and most of them won’t be around then even if required.
This year so far looks worse than 2014/15/16 for discoveries and offshore FIDs so the ‘gap’ (which may of course end up a permanent drop) for offshore projects now looks like it’s going to be out from late 2018 to at least 2022/2023.Ramp up times will have some impact as well so it might be 2024 before big projects initiated (say) in the first half of 2019 can reach plateau
http://www.opec.org/opec_web/en/publications/338.htm
OPEC MOMR out today
Libya and Nigeria each up approx 175,000 barrels per day.
Iraq up 44,400.
Venezuela down approx 7,000.
UAE down 18,000.
Angola down approx 54,000.
Total OPEC up 336,100
US shale oil production forecasts from the EIA’s Drilling Productivity Report, June 12th
https://www.eia.gov/petroleum/drilling/#tabs-summary-2
IEA Oil Market Report – Highlights (14 June 2017)
Although global demand growth was only 0.9 mb/d in 1Q17, it is forecast to accelerate in 2H17 and for the year as a whole our outlook remains unchanged at 1.3 mb/d.
Global oil supply rose by 585 kb/d in May to 96.69 mb/d as both OPEC and non-OPEC countries produced more (total liquids including NGLs).
OECD commercial stocks rose in April by 18.6 mb (620 kb/d) on higher refinery output and imports.
https://www.iea.org/oilmarketreport/omrpublic/
The new one..
OPEC May Production Data
http://peakoilbarrel.com/opec-may-production-data/