The Texas Railroad Commission (RRC of TX) updated its online database a few weeks ago. The best estimates I have seen for Texas C+C and natural gas output are produced by Dean. Thank you Dean for sharing your analysis with us.
The following 4 charts were produced directly by Dean, output for Oil + Condensate, Oil, and Condensate are in barrels per day, and Total Natural Gas is in thousands of cubic feet per day.
The chart above shows how Dean’s estimate for Texas Oil and Condensate has changed from August 2015 to Feb 2016, the most recent estimate is a dashed line.
The chart above shows how the RRC estimates have changed from Jan 2013 to April 2016, generally the data is incomplete for about 18 months prior to the most recent data point. Look closely at the May 2015 dataset (most recent data point in March 2015) and you will see that it does not get close to the April 2016 data until September 2013. Typically when considering RRC data from the Production Data Query (PDQ) System one has to go back 18 months to find data that is within 1% of actual output.
In the chart above the upper and lower bound are each 1 standard deviation (sigma) above and below the “CORRECTED” estimate, this is different from Dean’s chart where the usual 2 sigma upper and lower bound is used. If the probability distribution is normal, the 2 sigma bounds covers 95% of the probability (there is a 2.5% chance output is higher than this range and a 2.5% chance it is lower.) The 1 sigma upper and lower bounds should encompass 68% of the probability assuming a normal probability distribution, with a 16% probability that output might be below the lower bound.
The chart above shows an “Estimate” of Texas C+C output that is the average of the EIA estimate and Dean’s estimate. The dotted line is average output based on this estimate from Dec 2014 to Jan 2016.
Dean recently sent Ron and I the following e-mail:
I have sent you a couple of additional analyses of Texas oil data:
1) A plot of the time evolution of my correcting factors for the first 12 (corrected) months
Plot is below.
2) The EIA Texas data C+C vs three alternative corrected RRC data:
- my usual corrected data using the correcting factors averaged over the whole time sample available
- my corrected data using the correcting factors averaged with data up to November 2015
- my corrected data using the correcting factors averaged with data up to March 2015
The second plot was based on the evidence that some statistical tests highlighted a possible structural break in the dynamics of the correcting factors in April 2015, that is the correcting factors from April 2015 onward belong to a different statistical regime than the factors before April 2015.
I also added the case using the correcting factors averaged with data up to November 2015, because the data released by the RRC in the last 3 months are quite anomalous.
Thanks, Dean
(Second chart is below)
I asked Dean which of these 3 “corrected” estimates was “best” in his view.
From the limited data available he is not sure, but his “best guess” (my words) is that somewhere between “Corrected Break Dec15” and “Corrected Break Apr15” may be close to correct.
The Chart above shows the average of the “Break Dec15” and “BreakApr15” estimates from Dean’s recent analysis (previous chart) from Feb 2015 to Feb 2016 with exponential trend lines fit to different periods. The decline rate from the peak is 4.7%/year, for the whole range shown (blue dots) the decline rate is 4.4%/year, and from June 2015 to Feb 2015 the decline rate has slowed to 1.1%/year.
The future decline rate will depend on many factors including the price of oil, my guess is that it will be between 1.1%/year and 4.7%/year. At 4.7% output in Texas would fall 210 kb/d over the next 12 months, the Bakken may fall about 200 kb/d, the rest of the lower 48 onshore maybe 100 kb/d, for a total decrease in US L48 onshore C+C output of 500 kb/d in 2016.
An alternative estimate can be found by considering US lower 48 onshore (L48 OS) C+C annual decline rates.
The chart above replaces the EIA estimate for Texas C+C with Dean’s “best guess” for Texas C+C to estimate US L48 OS C+C output from Feb 2015 to Jan 2016, the decline rate is 7%/year, which would result in a 500 kb/d drop in US L48 OS C+C output in the next 12 months if the decline rate remains 7%/year and Dean’s estimate is correct for Texas.
The decline rate from the peak in March 2015 is about 8.1%, if that trend continues for all of 2016, L48 OS C+C output will fall by 560 kb/d in 2016, increases in output in the Gulf of Mexico may offset this decline by 100 kb/d, if so US C+C output would fall by 485 kb/d in 2016, assuming Alaska continues its 5%/year decline rate.
Dean/Dennis,
Thanks for the post. I was getting worried we were not going to get a close look at the Texas numbers. Just one thing, is there any chance of getting the graph of the Casing head gas? Otherwise know as associated gas.
Hi Toolpush,
As far as I know Dean does not analyze the associated gas and gas well gas separately. I also have not tracked natural gas very closely, so your best bet would be to look at EIA data, but they also combine the output. Are you looking for GOR?
Seems that Whiting and Hess saw a GOR increase.
COP and PXD did not, but that could be because PXD’s non Permian assets are primarily gas and completions in those areas have been suspended, while COP still has a world wide asset portfolio.
Thanks for the post!
I read COP conference call. Per call, COP is running three rigs total combined in Bakken and EFS, with no plans to add in 2016, which will cause a 10% BOE drop.
Gas production dropped due to Canadian gas divestments.
COP’s last GOM well is drilling now, no more after it.
Shallow,
The fix certainly seems to be in for a longer term down turn in oil production.
Once oil production does fall and the market re-balances, the interesting point will be who will be willing/capable of raising the cash to finance the drilling?
Hi Toolpush,
If the majors pick up assets from bankrupt companies, they will have no trouble with financing. Companies like XTO and Statoil will be fine along with some of the other strong players in the LTO sector.
As is always the case in capitalism the strong companies will take over the weaker ones. When oil prices rise to $70/b or more production will also rise within 12 to 18 months.
If the independents can’t operate these wells at a profit, the majors have little to no shot. The problem with these shale plays is not available capital. It is bad rock. And switching ownership is not going to change that.
As the recent history shows, even with “bad rock”, but with available capital, LTO production can be ramped up by 4 mb/d in just 5 years.
Alex,
But it can deflate in 3 years if there is no capital as we are watching it right now. And you are left just with debt on the end of cycle. For big majors to go into shale and do that kind of investment that is solely based on market timing it is equivalent of individual investors picking individual stocks based on market timing and going in and out. That is equivalent to suicide in long run and no one who even remotely understands how market works would do that kind of thing.
Which would require another 30,000 shale wells at an estimated total cost of 250 billion more dollars. The first 30,000 shale oil wells have not been paid for yet and short of 100 dollars a barrel, sustained, won’t. Besides, it looks like a game of Pixie Stix out there in sweet spots now, where might these other 30,000 wells get drilled? If off on the flanks, it will take 50,000 shale wells to get back to 4 MBOPD, and 400 billion more dollars. Much longer laterals, oodels more sand and horsepower, much poorer wells, you see.
By the time the shale oil industry admits it needs help and wants to sell assets to majors, or bigger companies, or anybody with new credit, it will be too late. Those “assets” will have already depleted 50% of their exaggerated EUR’s, the remaining 50% will take 20 more years to realize, maybe, and be nothing more than stripper wells. Buyers will not be paying a lot of money for ‘de-risked’ acreage and PUD’s when all the wells nearby have already proven themselves grossly unprofitable. There is a reason major integrated companies did not get into shale oil plays in the first place. They are not going to change their minds because the price of oil is now 40, instead of 100.
This M&A stuff is more shale oil hope. Like 50 dollar oil will supposedly put them all back cranking out the wells again and everything will be peachy.
Right.
Hi AlexS,
It is doubtful that another 4 Mb/d on top of the 4 Mb/d already accomplished is forth coming. That is, I doubt US LTO output will ever hit 8.7 Mb/d.
The “bad rock” looks much better at $80 or $90/b and at that price big oil companies might buy the better assets.
If there is adequate demand for oil and the price of oil rises to $80/b, more LTO wells might be completed.
“bad rock”, but with available capital
Shale fell out or favor for Wall Street if we look at which rates and on what terms credit lines are rotated. So this hypothesis about re-appearance of “available capital” with “proper” oil prices is weaker then it looks.
It might not be available before, say, $100 per bbl and before 2020. And even in this case amount will be less then in the past and conditions less favorable.
Loosing a couple of billion dollars provide (a temporary) lesson for a bank. Let’s say for three years (may be slightly longer — five years). After that they again are ready to break their neck running for better profits :-). So “reckless” capital might not be available for shale before 2020.
In other words, “carpet drilling” is a feat that is difficult to repeat unless something fundamentally changes in shale technologies or world oil production picture.
Looks like “Go to Iran my friend to drill” is the slogan now 🙂
Reno. I agree with you.
I have been studying the Spraberry horizontal wells in the Permian basin, which appear to be the most favored LTO well by Wall Street at the present time.
It appears to me that there is no magic, so to speak. The Spraberry was first developed on large scale in 1950-51. The vertical wells of that era came in with very high IP, but rapidly fell off.
There was tremendous activity in the Spraberry with vertical wells in the last ten years, when oil made its rapid climb.
Little paid attention to when PXD is discussed, is that they operate over 6,500 vertical Spraberry wells in the Permian Basin. Of those, almost 6,000 have attained “stripper well status” of 15 barrels of oil per day, or less. It appears the wells settle out in a range of 5-15 barrels per day, and produce around 2-3 barrels of water for every barrel of oil. The wells also tend to produce minor amounts of gas.
I have been discussing this play with Mike, he has knowledge of the area. He says that, despite the low volume, the vertical wells (which are 7-10,000′ deep) are profitable because of the low produced water volume.
Basically, it seems the vertical wells are only pumped a few days per month. I am not from the PB, but have been through Midland and Upton Co. TX, and have seen scores of very large (160K pound and greater) pump jacks, most of them idle.
When I look at the older (2+ years, so not really that old, but just in relative terms) hz Spraberry wells, I see the same thing, very low volumes. Almost none of PXD’s hz wells still produce 100+ bopd after two years, most are already below 50 bopd after two years.
I really think what is happening here is very simple, the hz wells just pull out a lot more oil up front, but likely by years 3 and on, they really do not produce much, if any, more than the vertical Spraberry wells.
Therefore, it appears to me the 1-1.25 million BOE EUR type curves are vastly overstated.
There are exceptions, PXD’s wells on the ET O’Connor and Donald Hutt leases are very strong. There are a few others. There are also exceptions with regard to the vertical wells, but, like the hz, those appear to be few and far between, less of those on a percentage basis than Parshall and Grail in the Bakken, for example.
One other interesting thing I noted. Summit Petroleum is a decent sized private company which has been drilling, completing and operating Spraberry wells for many years. I noticed that they have only drilled 3 horizontal Spraberry wells, or at least that is all I can find producing as of 1/16. It appears they continued to drill vertical wells in 2015, albeit at a much slower pace than prior years.
In summary, I question whether allowing tightly spaced horizontal wells in the Spraberry is in the best interests of both economics and conservation practices? I am not qualified to delve into that, but I think someone should.
I am concerned that Mike is exactly right, that the horizontal well boom, and the lack of spacing rules for those wells, is leading to significant waste, that is going to bite us in a few years.
Really surprising that the spacing rules are being ignored for short term gain? I guess that is what the US stock markets are all about, so no surprise at all. After all, who is going to get excited about $1 million vertical Spraberry wells that IP 150 bopd, cum. 75,000 barrels of oil in the first couple or three years, and then produce 1,500 – 7,500 barrels of oil for the next 40 years? 3,000 BOE IP’s and 1.25 million BOE EUR type curves sell so much better, I suppose.
Again, would be interested in comments on this from those who have better technical background than me. In particular, would like to hear from horizontal proponents, but seems coffee is the only one that lurks around here. Coffee, what do you think?
Thanks for information Shallow, and this is a bit off topic but you follow the financials of these companies.
I see these companies touting that they can make money with a 30-50% ROI drilling these wells. I assume this is for the first year. How in the hell are they making money on these wells that deplete at the rate they do, with only a 30% ROI in the first year.
In other words this is a new way of infill drilling
Shallow
With holding both you and your question in the greatest respect, and in light of the long running interactions you and I have had over the years, I no longer contribute info to this site as I’ve grown weary of playing the role of cyber pinata to the acolytes of Ra and Zephyr, disgruntled investors, Malthusians of all stripes, and people involved in conventional production who display a staggering degree of ignorance regarding the so called shale revolution.
The answers you seek, along with increasing GOR, private investment demonstrably pouring in tens of billions of dollars, bankrupt companies still producing, etc. are all ‘out there’ online to the diligent, open minded reader.
The Permian will continue to operate primarily due to its ‘lateness’ in entering the horizontal arena.
I told you a few months back that WTI would probably increase and still believe that.
Hang in there, shallow.
“People involved in conventional production who display a staggering degree of ignorance regarding the so called shale revolution. ” That’s directed at me, Shallow; not you. Sorry about that.
A lifetime of spending your own money, and shouldering 110% of the risk involved in exploring for and producing hydrocarbons, of having to make money or go hungry, does not lend itself to automatically believing everything you read on the internet. You know that as well as I do, Shallow. This business of oil often requires you separate from the herd and think for yourself.
But it is not fair for me to impose my real life experiences on internet driven analysis. I need to mosey on down the road again.
Make no mistake about it, however, we are now raping source beds in all of our producing basins in America and when that is gone there will be nothing left for our kids and grandkids. We are not efficiently able to produce these unconventional source beds yet in an economic, profitable manner. That is now pretty clear to everyone but the blindly devoted, the eternal optimists and those that really have nothing to lose.
Mike
Appreciate the straight talk in any case, guys.
This sociopoliticoeconomic climate/culture makes a piñata out of everyone and everything…
So maybe some straight talk is about the piñatas responding.
Shallow:
If we look at page 205 here
http://www.beg.utexas.edu/resprog/permianbasin/pdfs/PA_FinlRpt.pdf
And move down to Figure 68, the type log, we can see the target zone is thick, likely to be partially depleted by older wells, and has a fairly poor rock quality. The formation is areally heterogeneous.
This tells me the best option is a very cheap vertical well, 5 1/2 inch casing, completed with 600 to 700 ft of perforations and a beam pump with the tubing anchor placed near or below the bottom perf.
Is this what they do nowadays? I haven’t discussed this section with anybody since 1980-81.
Once subprime oil, always subprime oil. Labels are difficult to change.
Key word is If.
Dennis,
Yes, I was interested in how the GOR is running, compared to Bakken. With Ron’s graphs not being available, and the RCC raw data being more confusing than helpful, Dean’s data is should be able give us some guidance.
Hi Toolpush,
Are you looking for the RRC charts? I think the RRC data is not very useful, but if we assume the gas and oil data are incomplete by the same amount (no idea if this is true) I could do a GOR chart based on RRC data, I just wanted to make sure I did what you are looking for.
I would do associated gas divided by oil output in MCF (thousands of cubic feet) per bo. Let me know if my guess is right and when you do, I will produce the chart.
Hi Toolpush,
Using NDIC data I looked at GOR in MCF/bo from Jan 2005 to Feb 2016.
The GOR decreased until 2009 and has increased since then.
Note that in 2005 there was very little drilling and most of the wells were 10 years to 20 years old at that point.
I think we may be seeing the GOR increase as the rate of new wells added slows and the older wells (with higher GOR) cause the overall GOR to increase because the proportion of older wells will increase over time, even at a constant completion rate.
Hi Toolpush,
Using RRC data for statewide casinghead gas divided by oil (MCF/barrel), I found the GOR for Texas from Jan 2005 to Feb 2016. Be careful interpreting data for the last 18 months because the assumption that the level of incompleteness of oil data and casinghead gas data is similar (in percentage terms) may not be valid. The data up to August 2014 should be quite reliable and gets better as you go back further in time.
Note that the GOR in the Bakken remains below the GOR in Texas, so although GOR has increased in the Bakken it remains below the levels in Texas statewide.
I really appreciate Dean’s charts, especially since Texas is just so insane the way they track production.
But, Dennis, when you say “If the probability distribution is normal,” you open the statistical trap door. Is there any reason to believe the probability distribution is normal? Have you actually compared the probability distribution to a normal distribution? Just asking. Maybe you have. I know it’s convenient to assume a probability distribution is normal because it makes all kinds of statements about probability so much easier, but that doesn’t make the assumption right.
In any case, the take away I get from these charts is that Texas is holding it’s own — no growth, slight decline, but no dramatic drop — yet.
Hi Silicon Valley observer,
Dean is an economics professor specializing in econometrics (basically statistics applied to economic phenomena). His upper and lower bounds are 2 standard deviations above and below the corrected estimate, generally a normal probability distribution is assumed unless there is evidence that it is not the case. I will let Dean comment on whether the probability distribution looks normal as he is an expert and I am not.
It is only assumed if you are sloppy with your statistics. Sorry, don’t mean to be a downer, but that’s the truth. Most distributions are not normal.
And no disrespect intended towards Dean. He’s doing great work and I don’t know that he is assuming a normal distribution. I didn’t see him say that, it’s something you said and I don’t know if you were quoting him or not.
I recall my days studying finance and econometrics. Assuming as standard distribution is just too damn convenient. So people do it, even respected academics. Convenience usually wins out. Who listens to statisticians anyway?
Hi Silicon Valley Observer,
I said in the post:
If the probability distribution is normal, the 2 sigma bounds covers 95% of the probability …
Note the if, I do not have a probability distribution or the data, Dean has collected it, I assume he is not as sloppy as I am with the statistics, and that when he chooses 2 standard deviations for the upper and lower bounds he does so for a reason. He has not said what the distribution is, I am suggesting what proportion of the probability distribution would be contained by those bounds if it were a normal distribution, no more and no less.
In probability theory, the normal (or Gaussian) distribution is a very common continuous probability distribution. Normal distributions are important in statistics and are often used in the natural and social sciences to represent real-valued random variables whose distributions are not known.
https://en.wikipedia.org/wiki/Normal_distribution
Hi, when I compute the correcting factors for the latest 12 months the models’ residuals are normally distributed, while the residuals for the month from T-13 up to T-23 are not normally distributed.
That said, I compute the standard errors using the normal distribution for all correcting factors for simplicity, to have a quick rough ballpark idea of the uncertainty surrounding the estimates. Of course, I am perfectly aware that better methods can be used, starting from the bootstrap and the like. However, I am resorting (for now) to this simple approach for several reasons:
– I compute these RRC data corrections as a small hobby in my (few) free time
– the normality assumption is rejected for the oldest months with the smallest revisions, so that increasing the confidence intervals does not change much the outcome
– This is (quite) a long-term project: I am building a vintage dataset of Texas RRC data and several years of data will be needed to start developing a full robust methodology. More info here:
https://sites.google.com/site/deanfantazzini/nowcasting-texas-rrc-oil-and-gas-data-ongoing-project
Interestingly I am the only one together with Ron and Dennis building this vintage data set, since the Texas RRC does not save the old data (I had a long interesting discussion with them)
– Once the vintage data will be long enough (not earlier than 2020 – to say the least) and the effect of the data digitalization process ongoing at Texas RRC will be completed, my idea is to develop a full nowcasting method.
However, before that, I more than happy to gain experience with these data, to examine their dynamics with simple practical approaches.
Thanks Dean.
“For simplicity” — that says it all. No offense Dean, I’m happy to have your work and it’s valuable. And why should you be different from anyone else who uses the standard normal distribution for simplicity. But simplicity is not a valid statistical technique.
Probably, I was not clear: I am doing this for fun in my free time while (slowly) collecting the vintage data for the time when a large dataset will allow me to build a statistically robust nowcasting model.
I do not have the time right now to do something more sophisticated than this + the vintage data built so far is really too small and plagued by several structural breaks due to the ongoing digitalization process and the fall in Texas oil production which has fastened the data submission process: If had a large dataset I would probably employ a multivariate model with time varying parameters estimated with Kalman filter, but this is not the case yet.
Given that the confidence bands seem to create such discomfort, starting next month I will only send Dennis the corrected data without bands.
Dean,
Thanks for sharing your great insight. To me, the bands make your analyses better and I hope you keep showing them.
Hi Dean,
I also would prefer the bands be included.
Silicon Valley Observer thinks he is very sophisticated with his statistics knowledge.
My guess is that his knowledge may be fairly limited.
While it is true that not every probability distribution is Gaussian, as a first approximation, this is often assumed when the data is very limited.
My understanding is that the central limit theorem suggests that in a large random sample the probability distribution will tend towards the Gaussian.
Generally errors tend to be random in nature so the Gaussian seems like a reasonable assumption.
In any case, with or without the bounds thank you for sharing your knowledge with us.
Silicon Valley Observer’s main contention was that my assumption that the probability distribution was Gaussian may not have been correct, and you have said that he was at least partially correct (months 13 to 24).
Frankly I think his complaints are much ado about nothing and hope you will ignore him.
Ha, Dennis. My knowledge is pretty limted huh? LMAO. The central limit therom applies to the distributions of means (averages) of samples, not the distribution of the data itself. Hey, but you already knew that right?
I already said that I appreciate what Dean does. It’s valuable. It was you who asserted the normla distribution, not him.
By the way, your response is pretty much the stock response I’ve heard from anyone who wants to use the standard normal distribution when it isn’t warranted. Attack the critic, not his criticism.
But frankly, your ad hominem (as well as uninformed) attack on me is totally uncalled for.
As far as my being sophisticated, I am currently sipping sherry while dressed in a tuxedo — SO THERE! ha
SVO,
Which sherry?
Hi svo
The most recent 12 months is where most of the error is.
Those errors have a normal distribution so my comments would only apply to those months.
Possibly the pareto distribution would be a better choice than gaussian. As I said before I don’t have the dataset.
Hi Silicon Valley Observer,
Nobody claimed simplicity was a statistical technique, did they?
Dean said his time is limited and he also has limited data, he tried to get this from the RRC, but they do not archive their data, or if they do they will not share it (I don’t know, it is unavailable).
I am grateful that Dean shares his excellent analysis with us, and I hope he ignores the potshots from the peanut gallery.
We would love to see your analysis. 🙂
I have already said multiple times that I appreciate what Dean does. How many more times do I have to repeat that?
I know what, I’ll just agree with you all the time. How about that? I imagine you won’t mind a bit.
Hi Silicon Valley Observer,
You don’t need to agree with me, offensive comments to Dean should be minimized however.
Or we can just rely on EIA estimates, because I don’t have the data or methods to replicate Dean’s analysis. The RRC data as published is only useful 12 to 24 months in the past, so without Dean’s analysis the EIA estimate would be the best freely available estimate.
If you are familiar with the principle of maximum entropy, for any continuous probability distribution that has a mean and a variance, the normal distribution will be the probability distribution with the maximum entropy.
In many cases we do not have information about the probability distribution due to limited data.
In that case, if we are dealing with some likely probability distribution that we believe is a continuous real valued function that has both a mean and a variance, the Gaussian distribution would be the maximum entropy probability distribution.
So in a situation where we have limited knowledge and data (and time), the assumption of a Gaussian seems reasonable to me.
You are absolutely correct about the cental limit theorem. Along with it applying to the mean, it also requires a large set of data. We do not have a large data set, maybe 18 months where we have the RRC data set saved, so the CLT does not apply.
Hi SVO,
One mistake you have made is in basic reading comprehension.
I said in the post:
If the probability distribution is normal, the 2 sigma bounds covers 95% of the probability (there is a 2.5% chance output is higher than this range and a 2.5% chance it is lower.) The 1 sigma upper and lower bounds should encompass 68% of the probability assuming a normal probability distribution, with a 16% probability that output might be below the lower bound.
Can you point out where I have assumed the probability distribution is in fact a normal probability distribution? I have said what the probability is that the data point might be between 1 sigma or 2 sigma limits if the probability distribution was normal.
Nowhere have I made the assertion that the probability distribution was normal for all 24 months where upper and lower bounds were presented by Dean.
Then you offer the stunning revelation that simplicity is not a statistical technique, very nice, I am sure that the Econometrics professor found that very enlightening.
Your statistical knowledge is indeed very impressive and no doubt we could all learn much from you.
As I have pointed out before driverless cars do not solve for anything, there is simply no real need for them.
The benefit if you can call it that is to further concentrate wealth. As with most automation it is the owners of production that prosper. Owners see labor as nothing but an expensive headache and the less there is the less headaches there are. What they never seem to grasp is that for every employee lost they also lose a customer, maybe not directly but over all that is the net effect, especially now that the global economy is stagnant or shrinking.
Reality proves that driverless cars will never be more than a microscopic part of the auto mix, a theme park ride if you will. There are millions of taxi drivers everywhere and now millions more uber drivers also all ready to take anyone anywhere anytime. Truck driving is one of the top jobs by % in much of the US.
Nobody except the technocopians who probably read too much sci-fi sees any advantage to driverless. Now if the techies could come up with a customerless product that generates profits then we might have something.
Truck driving is one of the top jobs by % in much of the US.
You are living in the past!
http://www.bitesizedincome.com/the-future-is-going-to-hit-us-like-a-ton-of-bricks/
There are around 3.5 million truck drivers in the US. Even if we assume that trucks will not be entirely driverless for quite a while, the ‘convoy mode’ can still wipe out 75% of all trucking jobs.
In about 10 years there is a very good chance that 2.6 million truck drivers will be laid off in the US
This is going to cause massive social and economic disruption.
What should we do?
The sad truth is that technology is now removing jobs at a faster rate than that they are replenished. My generation and those coming after me will have to get used to a world with a steadily shrinking pool of available jobs.
What does this have to do with April 2016 Texas production?
Dennis
Can you move this to the other thread started yesterday, before this post becomes cluttered with posts that have nothing to do with the original post?
Every thread has been treated as an open thread here. It’s the only thing that makes sense. Anyway, how much can you say about Texas production before it becomes really boring.
makes it hard to follow and the posts invariably turn into climate change pissing contests. Obviously there is demand for that, but it has its time and place.
Not entirely correct. Sometimes it turns into an EV pissing contest, or a renewable power pissing contest or, often enough, a when-is-the-peak-going-to-happen pissing contest. Good thing I drink a lot of beer! LOL
Last time I checked I’m living in the present. Let me check. Yep, April 29, 2016. 🙂 Sorry, couldn’t help myself!
As I have said on this subject, the issues are less technical (though the technical issues are significant) than they are political and legal. Google has already tried to push the responsibility for self-driving vehicles to the occupant of the car even though the occupant has no steering wheel, brakes or accelerator! If Google won’t accept the liability for their own technology, who will? Insurance companies? Besides, the Feds said no way. Who in the government is going to approve a technology that could have a career-ending result when things go wrong?
And referring to OFM’s example, who am I going to yell at when the driverless lumber truck parks in front of my driveway? “Hey you stupid jerk robotic driver thing, get out of my driveway!”
I will try to clarify and beef up my case for electric and self driving cars and trucks over in the new non oil thread.
See you there!
SVO,
Google wants the technology, and the company that runs it to be legally defined as the driver – and therefore the tech will be “at fault”.
They are quite literally trying to do the EXACT OPPOSITE of what you suggest. The set back in California recently was that the courts decided there has to be an actual driver who is responsible, which also means Google vehicles must have a steering wheel and pedals.
This legal decision was precisely the opposite of what Google wants. Google wants to be the legally responsible driver. It is the only way their autonomous vehicle taxi service model can work.
Please, do a little research before posting on these subjects.
Hey, I do as little research as possible! 🙂
There are two issues here — getting the government to allow driverless cars without steering wheels etc, and then determining liability. You are correct that Google wants to be considered the driver in order to avoid requirement for a steering wheel etc.
Google’s parent corporation, Alphabet, Inc., is pushing back against the government’s assessment by arguing that the company’s artificially intelligent self-driving system could be interpreted as a vehicle’s driver. “Developing a car that can shoulder the entire burden of driving is crucial to safety,” said Chris Urmson, director of Alphabet’s self-driving car project, during a Congressional hearing on Tuesday. “We saw in our own testing that the human drivers can’t always be trusted to dip in and out of the task of driving when the car is encouraging them to sit back and relax.”
http://www.scientificamerican.com/article/driverless-cars-must-have-steering-wheels-brake-pedals-feds-say/
But when they say driverless system, they don’t mean Google — they want to push the liability into some kind of weird definition of the system in the car that’s doing the driving, even though it is built and controlled by Google. They want it both ways.
So, those who are injured by a Google self driven vehicle would have to sue Google?
So the owners of Google driverless autos would not need liability insurance?
I imagine Google will have a tough time with the trial attorneys and the auto insurance companies.
Google’s parent corporation, Alphabet, Inc., is pushing back against the government’s assessment by arguing that the company’s artificially intelligent self-driving system could be interpreted as a vehicle’s driver.
A driverless car is a tool like any other. The software, computers and actuators that control it will be purchased or leased from a vendor, and then it will be a matter of what the license says. As soon as you do whatever sets the thing in motion (voice command, biometric sensor, phone app, whatever) you will be responsible for what the license says you are.
After all, no one will be holding a gun at your head. You could have bought a manual car.
Google is making an opening gambit here: this is about setting parameters. Google obviously has decided that they want no part of mixed liability (and on this point, I agree with them.) The way to avoid mixed liability is by not allowing you to drive. (I personally believe that the only safe way to transfer control from a computer to a human is to pull over and park, due to what in psychology are called “shifting costs”.)
Interestingly, forcing people in the US to accept sharing the road with self-driving cars could (very broadly) be considered a constitutional issue- the “liberty” portions of the Fifth Amendment.
(3-hour pause)
And then it struck me. If corporations can be people, why not cars? Gets around the constitutional problem.
Of course, I hope it won’t come to that. My guess is that Google will lease the first Google cars and they will self-insure them. Once the safety record is established (3 to 5 years) other companies will enter the market. It won’t actually matter who’s responsible or what it says on the license anymore…we’ll treat the boilerplate the same way we treat software acceptances.
Either that, or our robot overlords will start out life as Chevys with citizenship.
-Lloyd
This doesn’t belong here but its important only to demonstrate what is behind “renewables” vs oil.
Its obvious the entire “renewables” racket is a military operation. How else is “renewables” sustainable unless there is MASSIVE demand destruction? Of course there are less customers because thats the point of it. Put’em up in rabbit hutch apartment slums and keep them off the road unless its a trip to the soup line (Walmart) via the automated car. Look at Warren Buffets major stock holdings:
Warren Buffett’s largest [Poverty for everyone] holdings:
IBM, Coke, American Express, Phillips 66, Procter & Gamble, Walmart, Goldman Sachs, Wells Fargo
Locked up human sloth consuming coke, smoking, and consuming gruel and being tracked with computers and intimidated with A.I and lasers powered by advanced portable storage. All courtesy of God (Goldman Sachs). I guess Warren forgot about the pharma pills frying their brains.
Why is a battery favored over an ICE? Again for military purposes…controlling the herd requires a shock and awe weapon: cutting a person in half with a beam weapon every now and then. The herd will have a tougher time terrorizing a distributed electricity network rather than large centralized power plants. And harvesting electricity will require a one government world with all the interconnectors and what not.
Renewables (cables + batteries (crude for now but later more advanced devices beyond batteries) + solar cells) locks up the world like cattle in a pen. Feudal lords (Goldman Sachs) own all the land.
And the alternative to The Goldman Sachs Amusement World Park is Venezuela. The entire world is going Venezuela rotting its infrastructure toward collapse while consuming everything in sight…Slums vs Slums…its entirely your choice.
And I’ll be labelled a tin foiler no doubt. Nobody will believe what I said.
Rig count is out. Oil rigs down again.
Have read a few CC transcripts. Looks like almost no one intends to rush rigs back into the field in 2016.
I have read a lot of statements about needing to see $50+ stable for 90 days at a minimum.
Also, no word on who is putting up the $$ to complete Whiting’s wells in 2016. My guess is a service company.
shallow sand,
“no word on who is putting up the $$ to complete Whiting’s wells in 2016. My guess is a service company.”
My guess is a private equity fund.
US oil rigs: down 11
Eagle Ford: -4
Permian: -2
Cana Woodford: -2
Niobrara: -1
Bakken: unchanged
what about gas?
And how many vertical rigs running?
Gas rigs down 1 unit
Vertical rigs: 50 (- 1)
Directional: 46 (-2)
Horizontal: 324 (-8)
50 vertical rigs in the US.
unbelievable
http://www.bloomberg.com/news/articles/2016-04-27/top-oil-service-firms-mull-north-america-retreat-as-losses-mount
“HOUSTON (Bloomberg) — Two of the three largest oil rig operators and fracers are considering pulling back from the North American market as losses mount.
“Schlumberger—after posting its first North American operating loss since at least the turn of the century, according to Barclays Plc—is evaluating whether it’s worth temporarily shuttering its business in the region. Baker Hughes said Wednesday it has decided to limit its exposure to unprofitable onshore fracing work in North America because of the unsustainable pricing.
“It’s the first time in at least a decade that those companies and Halliburton Co., the big 3 in oil services, all lost money in the region during the first three months of the year, according to Bloomberg Intelligence.”
Has any upstream division of any operator so far reporting 1Q16 shown a profit? ExxonMobil, BP, and Statoil had profits overall but only because of downstream and marketing operations.
Thanks for the link George.
This indicates there will be no quick return to high volume horizontal fracking on a large scale in North America.
I am not aware on any company in the E & P upstream focused in North America that has positive earnings for Q1, 2016, but I have not made an exhaustive look.
Shallow,
I see the only bright spot in the rig count, is the long forgotten Barnett. It appears it is no longer a gas play, but is now seen as a oil play. There are 6 oil rigs working, increasing one per week all through April. It seems to be the only area that has more rigs drilling this year, than last.
I think the rigs per “play” is geography more than geology. There are not that many rigs drilling haynesille shale wells
Worth the time for those taking an interest
”DUC’s and wells that have been shut-in for at least 6 months allow capital providers or analysts to determine where a company stands on future drilling. If you look at a company’s 10’k report and determine that they are only going to bring online 20 wells in 2016 in the Bakken but have 18 DUCs that will hit their 2-year expiration limit in the same year it can be concluded that they will only be drilling 2 wells during 2016.”
http://info.drillinginfo.com/drilled-and-uncompleted-wells/
Posting down here to widen the view.
Based on what I can tell, here is a distribution for horizontal Spraberry wells with first production on or before 7/2014. There appear to be 715 active wells.
First, cumulative oil through 1/16:
2% 200,000 bo or more
7% 150,000-199,999 bo
26% 100,000-149,999 bo
41% 50,000-99,999 bo
17% 25,000-49,999 bo
7% 1-24,999 bo
Next, most recent monthly production (1/16) for these wells:
9% 3,100 bo or more
32% 1,530-3,099 bo
30% 775-1,529 bo
29% 1-774 bo
I assume that possibly there have been improvements (technological, etc.) that make newer vintage wells more productive?
Keep in mind these wells cost in the $7-9 million dollar ballpark to drill, complete and equip.
Enno has a post coming out soon on the Permian, interested to see what it reveals.
Some Central Valley Orchards Irrigated With Oilfield Wastewater
http://sanfrancisco.cbslocal.com/2016/04/28/california-farmer-says-orchards-irrigated-oilfield-wastewater/
The investment these farmers have in their trees is huge. Anyone who has driven through the central valley knows what I mean — orchards that extend as far as the eye can see, and beyond. If you can’t get clean water, you take what you can get or lose your investment. I just wonder what impact, if any, it has on the fruit. I don’t think we will ever know.
It is extremely unlikely there will any difference in the fruit, barring slightly smaller fruit maybe, if the trees are stressed above and beyond normal drought stress.
The long term health of the trees is another matter. If there is very much in the way of metal or reactive hydrocarbon contaminants in that water, the trees will probably gradually go into decline. It might take as little as four or five years, or as long as twenty or more for the contamination to build up to levels that obviously stress the trees.
I doubt if any body has actually done enough research on irrigating with this sort of water to really know how much trouble it will cause, or how long it will take it to show up, or how long it might take to correct it.
It might not cause any problems at all, if the rains return, and it is used in moderation afterward, or if it is used only a year or two or three and discontinued.
It seems rather unlikely it is going to be clean enough to use it indefinitely without some problems.
“I just wonder what impact, if any, it has on the fruit. I don’t think we will ever know.”
-makes me wonder about those “smoked” almonds.
There was this guy from some old ‘As Seen On TV’ infomercials– Ron Popeil– who would use ‘liquid smoke’ on the food, which I thought was kind of weird… Well, the whole infomercial was kind of weird…
Anyway, I spontaneously started calling him, Mr. Liquid Smoke… and he seemed to have a kind of smokey appearance too, so I thought at the time.
Correct, Ron, thanks!…
But getting back to the industrial food production system… Would you allow a sociopath to feed your baby? Because that’s kind of what we do everyday.
And if it’s a race to minimize costs and maximize profits, in the end game of this, isn’t our food going to suffer and increasingly come under this logic too?
So maybe we should start considering giving BAU in general a nice big Italian fuck you/off (vaffanculo) and start doing things for ourselves again.
The future doesn’t just happen. We make it happen.
Rude Italian Hand Gestures (with cute Italian-sounding music and natural girl)
The Midway Field in Kern County (4th largest in US) is water intensive.
I can see why it would be tempting. I drove through a while back- massive infrastructure.
I am a little late posting the rig count chart. Sorry.
Baker Hughes Rig Count
I can only imagine the pain that those employed in oil services are feeling. I wonder how many jobs each rig accounts for? And how many local businesses rely on those employees? I live far removed from those locations, but I can guess the devastation to lives and communities is pretty extensive.
I appreciate the time consuming un paid work every body is putting in to figure out where the domestic American oil industry is headed.
And I suppose that domestic production will soon fall off enough to make a significant difference in the price of oil, UNLESS foreign producers up production about as much or more as domestic producers cut back.
The thing I think every body is missing by concentrating on AMERICAN producers, who must respond to market conditions, later if not sooner, is that most of the oil in the world is owned by various sovereign governments, and governments don’t pay much attention, short term and medium term, to profits and losses. They seem to be more concerned with domestic employment, status in the international pecking order, maintenance of the local status quo in their respective countries, economic warfare with their real, potential, or imagined enemies, etc.
To put in a nutshell, national oil companies play by a different set of rules. Profits and losses absolutely do matter to them, but not very much in the short term, and not a whole lot in the medium term, not until the treasury cupboard is just about bare. It seems it is only in the long term that national oil companies are more or less COMPELLED to play by the rules of the market.
If the name of the game is to figure out when the price of oil is going up and staying up enough for domestic producers to make a living, the focus will probably have to be on national oil companies.
OFM, agree with you about the differences between the Nationals and the privates in the U.S. However, I think the main thing that has brought prices as low as they have been is the marginal production the U.S. added in the last four years. If North Dakota didn’t exist I think oil prices would still be way up there — at least above $80. As Ron has pointed out many times, it is only the U.S. and Canada that have prevented world oil production from declining in the past four or five years.
So, as the LTO production crashes, as I expect it will even beyond current expectations, the foreign nationals will not fill the gap and price will rise. All my opinion of course. But for me, the focus on what is driving price will be U.S. production decline. The nationals will just keep doing what they’ve been doing and reap the reward of higher prices.
Iraq did a pretty good job increasing production.
It seems Saudi “Vision for 2030” is mostly smoke and mirrors
http://oilprice.com/Latest-Energy-News/World-News/The-2-Trillion-Gamble-That-Saudi-Arabia-Cannot-Win.html
“…off its oil dependence in only 4 years, by 2020”
Meaning thats all they have left…4 years worth because the ChinaSuperPonzi is going to go vertical and everyone else will have to follow suit or be left out on the grab of the remaining resources. Its now a big race to consume it all in 4 years and buy up the world because….
Its gonna blow.
Venezuela, Saud, Egypt, Brazil, Greece, Italy, China, etc etc etc…literally every place on Earth is
GONNA BLOW in the next 4 years.
A massive WorldSuper”Renewables”Ponzi, the biggest Ponzi in the history of mankind, will accelerate oil consumption and fry whats left of Sauds remaining big oil fields in 4 years.
Then comes the Big Turkey Shoot with the automated EV’s turned military vehicles zapping the hordes because the “realizable net value” of the remaining fossil fuel inventory is negative and everyone is broke.
Then the automated EV’s will turn on each other in a massive robot war between the car manufacturers because there is massive overcapacity in manufacturing.
Then probably a massive nuclear war.
50 years till day of reckoning? Gradual decline? Forget it, the cats out of the bag on this doom thing.
Based on OPEC figures Saudi had produced 136.5 billion through 2014, so about 142 to date and, assuming no decline, 160 by the end of 2020. Obviously their reserves are unknown outside a select few, but news does get out including upgrades on existing fields, some new non-associated gas fields coming on line, development of shale gas, offshore exploration and some minor discoveries. But never reported is a major new oil field discovery or development. Pretty much all onshore areas have been fully explored, only deep sea remains, which appears to have been a disappointment from initial results.
From wiki and other places the URR for their giant fields (Ghawar, Safaniya, Shaybah, Abqaiq, Berri, Manifa, Abu-Sa’fah, Khurais, Neutral Zone) is 190 billion barrels; if true they could be up to 75% through, and should be well past peak, but are managing to retain a plateau. I think that Matt Simmons got things mostly right that there would be a collapse, but missed their ability (technically and economically with oil at $100 plus) and need to keep pushing the peak out.
So for Ghawar that would involve continuing with multilateral, intelligent wells, re-completions, possibly tertiary EOR methods, and new drilling up-dip where needed etc. Assume Ghawar is 90% depleted and its infrastructure suddenly disappeared, there would still be 7 to 10 billion barrels left, probably still representing one of the more attractive development opportunities around.
For Safaniyah there was a major upgrade project in 2012 with a new platform, wellhead upgrades, ESPs etc. Manifa is a complicated reservoir bought fully on line a few years ago. All the reservoirs have the best available models to allow optimum management.
There may be minor declines in their main fields, but not what would be expected given their age and depletion. They are expanding al Shaybah and Khurais by a total of 550,000 bpd over 4 to 5 years to 2018, which would compensate for 1 to 1.5% overall decline; to compensate for the rest would have to come from field management (e.g. using the intelligent wells) and in fill drilling. Between 2005 and 2014 they averaged 434 well completions per year, compared to 280 the previous 10 years, which is probably connected with this. (Note Kuwait went from 120 in 2000 through 2010 to 560 average since 2010, I’m not sure what that represents).
Eventually they are going to run out of options, the more they push things out the faster the crash is going to be. The signals seem to be that 2020 might be it.
I was thinking along these lines.
Let’s assume the original oil in place was around 260 GB.
Under ideal production conditions, the peak would be reached at approximately 50%. KSA is now just beyond that point. Over the decades there was over- and underproduction, depending on the situation. I don’t know if they have a small reserve left in terms of oil not pumped like Russia (artificially low production in the 90s).
Since they have very good reservoir conditions, they might be able to postpone serious decline to 60% or more but I don’t think that 90% is possible.
2020 might be the year their engineers told them, the serious decline will be inevitable.
Hi Florien,
The URR for Saudi Arabia C+C is about 310 Gb based on a Hubbert Linearzation, which would suggest about 168 Gb of 2P reserves are left to produce if the HL estimate is reliable. Often the HL tends to underestimate the URR. Cumulative production to the end of 2015 is about 142 Gb. If the HL gives a correct URR estimate, production continues at around 3.5 Gb per year and the peak is reached at 50% of the URR, then the peak might be in 2019 or 2020 for Saudi Arabia.
To illustrate how the HL tends to increase over time, I show two Hubbert Linearizations (HL) on the chart that follows. One uses data from 1991 to 2002 (gray crosses cumulative output to 98 Gb on horizontal axis) with a URR of 160 Gb. The second is my best guess using data from 1999 to 2015 (red diamonds) with a URR of roughly 310 Gb. It is for this reason the HL method only gives a very rough indication of the URR and in most cases tends to underestimate the URR.
A similar analysis for US lower 48 output shows a 1970-1979 HL pointing to a URR of 160 Gb and a more recent 1989 to 2008 HL suggesting a URR of 235 Gb. Note that 2015 cumulative lower 48 C+C output is 198 Gb, so clearly the 160 Gb URR estimate was too low.
Coffee. Moved down here again to widen it out.
I know Mike has blasted you some, but I sure hope you are not saying he is ignorant when it comes to oil and gas production, and in particular the most important part — the dollars and cents part. I have consistently found him to know his stuff. I think that is where both he and I have our disconnect with you, we know the high tech is not the be all end all, the buck stops at the P & L and balance sheet.
I am biased, I have admitted it. That is why I focus on the production records and company financial reports. Those tell the truth.
I guess I look at it this way. Above, George Kaplan linked an article wherein HAL and SLB are thinking of pulling out of North America, because they are losing too much money. That is a very bad sign.
The reason I posted the Spraberry stuff here is I have yet to see anyone take actual well data, outside of 90 day IP, and explain where the 1-1.25 million BOE type curves come from. Looking at it in simple terms, it appears a hz Spraberry well produces about 70% of its BOE in oil. So a 1.25 million BOE well is expected to make 875,000 barrels of oil in its lifetime. It appears from Enno Peters’ site that we should expect around 130K BO in the first 60 months. At that point we settle out at 5-15 BO per day.
At the rate of 15 barrels per day, it takes 136 years to reach 875K BO, or 141 total, including the initial five years. 141 years ago was 1875.
Contrary to what you posted, I can’t find any explanation as to how we credibly get to 1.25 million BOE, or even 1 million, other than maybe the top 1% of wells.
Hi ShallowS,
Where Coffee saw “the acolytes of Ra and Zephyr, disgruntled investors, Malthusians of all stripes, and people involved in conventional production who display a staggering degree of ignorance regarding the so called shale revolution” I see concerned citizens that try to understand complex situation with the generous help of specialists like you. There are many aspects of shale boom & bust that were almost criminal in nature. So there is nothing wrong in criticizing those aspects of shale boom & bust, and that does not exclude valuing some of its technological contributions.
Was it a real revolution or not, is a more complex question. As Chinese premier Zhou Enlai famously said about the implications of the French revolution “it’s too early to tell”. When in, say, ten-twenty years dust settles, we will have a more complete picture which parts of it were revolution, and which parts were financial scam.
I, personally, am inclined to believe in Art Berman view: “Shale is not a revolution–it’s a retirement party. Shale plays were not some great new idea. They became important only as more attractive plays were exhausted.”
Kudos to you for all your valuable contributions to the forum. They are greatly appreciated !!!
Dennis & Dean,
Thanks for the post.
@Dean : I may have been too quick to suggest that your projected uptick in January seemed out of order. Looking at the detailed lease data for the Permian and Eagle Ford, I also get the impression that January production may be higher than December. I’m very curious to see how it turns out, as I didn’t expect this.
I have also an update on the Permian, here.
Enno. Thanks for the update!
Clearly PXD’s wells are improving by year. They are spending more on completions, which does appear to cause significantly more oil to be recovered early on (first 12-24 months).
Thanks for the info. I also think that the production went up in Jan16. Unfortunately, we will know it for certain only in 6-12 months
Enno & Shallow,
OXY held its annual stockholders meeting in Midland yesterday which is summarized in the article published by the local newspaper. What is interesting is that Oxy’s new CEO said that the Permian Basin is the foundation of the company. In 2015, Oxy produced 255,000 BOEPD from the Permian. Oxy’s only domestic operations are in the Permian Basin.
The Permian Basin is organized into 2 team units: 1) Permian Resource which is dedicated to unconventional resources which is a growth oriented team; and 2) Permain Enhanced Oil Recovery which is a CO2 tertiary oil
And water flood team.
The article link is found here :http://www.mrt.com/business/oil/top_stories/article_92a77854-0e30-11e6-a799-5f2b3ae247dc.html
What is not discussed in the MRT article is OXY’s recent acquisition of SandRidge Energy’s Piñon field and Big Canyon Ranch, plus pipelines. The Piñon field sources OXY’s Century Plant in Pecos County, Texas and it is the largest CO2 processing plant of its type in the world.
Oxy agreed to fund Century Plant about 8 years ago at a cost of about $1.5 billion. In return, SandRidge committed to deliver around 3 trillion cubic feet of CO2 over a 30 Year period in return for processing Piñon field gas. Failure to deliver the CO2 triggered annual cash penalties of about $40 MM/year that SandRidge could not afford to pay and SandRidge could no longer drill wells in the Piñon Field because of the low gas prices.
When Oxy agreed to fund the Century Plant in 2007 or 2008, it said in its annual report that when the plant went on line it would immediately increase its Permian oil production by 50,000 bbls / day and book 500,000,000 barrels of proven producing reserves!
That, my friends, is an incredible amount of reserves! I don’t think any other company is capable of this in the lower 48. Tertiary reserves are high cost reserves but the reservoir rock is conventional and oil is IN PLACE and RECOVERABLE!
John S. I do not doubt OXY has significant reserves that will be produced through tertiary recovery.
Any ideas on costs per barrel? I suspect they can make strong returns at $60 WTI from those assets.
Regarding OXY unconventional, looks like they primarily are drilling Bone Spring wells. My impression of those are:
A. Results vary quite a bit.
B. Quite a bit more gas than Spraberry Wolfcamp, which may really help well economics if we can get gas back above $3.
As I have stated, OXY unloaded a ton of debt on CRC when they spun it off. What is your opinion of that? I think CRC has good assets, I assume the regulatory environment is the issue there?
Also, still wonder about whether Whiting is trying to sell North Ward Estes CO2 flood.
10Q says production there fell 3% from Q1. Assume they have not spent any CAPEX there.
I think you are absolutely right on CRC. Oxy got rid of that at just the right time and with the right strategy. Wall Street bailed them out and stuck it to the common stockholders. Wasn’t it sold to the investment community as a Montery shale company. I do remember them announcing a 100 MM bbl conventional discovery in CA about 3 years ago, so I may be completely wrong about CRC.
We talked to Whiting last year about a CO2 lease. The discussion didn’t go anywhere. The Denver management will not let them spend any money in the Permian. Some employees have been let go. I think NW Estes is for sale. In my opinion, There are better CO2 candidates available in the Permian Basin if that is the business you want to get into.
I don’t think there is any more Co2 supply available in the Pemian unless Oxy makes some available. If the low prices continue and $45 is a low price for a tertiary flood, some operators might consider throwing in the towel at the least economic floods and blowing off the CO2 to sell to other parties.
I believe that Kinder Morgan cancelled plans last year to build a pipeline from St John’s Arizona to bring CO2 to the Permian. I think there might have been some expansion going on in the Cortez area before prices collapsed. Don’t know the status now.
The resident expert consultant in the Permian Basin is Steve Melzer. His website is :
http://melzerconsulting.com.
I think he probably knows the answers to many of your questions about CO2. He is a good guy with a good reputation. You should talk with him. I think he might give you a lot of back of the envelop numbers.
Thanks for the info.
CO2 is out of our $$ range, but it is interesting to me.
I understand there are better areas for CO2 than NW Estes, but premium properties always bring premium prices. Just curious, have you heard what Whiting is asking? Dennis can give you my email.
CO2 availability issues are a concern, for sure and prices have not been good, for sure. But CO2 floods seem to me a better bet than LTO in the Permian.
I see Chevron has a big block of Permian conventional for sale on the internet auction, and some others are starting to be listed. Would be interested to know what the asking prices are for conventional oil down that way.
http://www.economiccalendar.com/2016/04/29/a-new-record-russian-crude-oil-production-at-1091-million-bpd-in-march/
“analysts at Goldman Sachs believe that in 2017 Russia could reach higher and come close to the oil production record of the USSR – 11.4 million bpd.”
analysts at Goldman Sachs believe
Come on. That’s nonsense. How after slushing capex to bones in 2015-2016 Russian companies suddenly can reach a new high in production? That’s on the level “pigs can fly”. They can but only with enough thrust and it’s dangerous to stand where they are going to land :-). Like in Russian translation of French The Internationale (https://en.wikipedia.org/wiki/The_Internationale)
“Nobody can liberate us. Neither God, not Tzar, not some hero. We can secure our freedom only with our own hands”. Same for the oil production.
To grow it you need increased capex. Substantially increased. Which is very difficult to impossible in current circumstances. So the natural path of Russian production from the current peak is down not up.
What arguments those suckers from GS have to support their wild forecast? This is just a hot air. In reality analysts at Goldman Sachs believe only in talking their books. That’s their job description.
“How after slushing capex to bones in 2015-2016 Russian companies suddenly can reach a new high in production?”
Russian upstream capex has actually significantly increased in rouble terms. Drilling activity last year was up almost 10%.
And if you are following Russian oil production numbers, you should know that it was up 1.5% in 2015 and more than 2% in 1Q16
Rystad Energy’s forecast for North America shale liquids production.
The numbers include Canada, NGLs.
NORTH AMERICAN LIQUIDS PRODUCTION LIKELY TO DECREASE THIS YEAR
April 29, 2016
http://www.rystadenergy.com/NewsEvents/PressReleases/decline-na-liquids-prod
Rystad Energy’s latest research shows that 2016 will be the first year in which we see a decline in liquids production from North American shale oil and tight liquids plays. Some key plays will face a net decrease in liquids production year-over-year. 2016 production from Eagle Ford and Bakken is estimated to drop by 12% and 9%, respectively, compared to 2015. From 2010 to 2015, the top four shale liquids plays have grown by 860 kboe/d on average, with the highest increase coming from the Eagle Ford Shale.
Their projected growth in the out years seems optimistic with all the troubles the service and rig companies are going through right now.
Rystad is projecting global shale gas+liquids production to increase by 10% annually in 2017-2020.
Projected growth in liquids production is apparently even higher, to ~10 mboe/d in 2020.
This compares with only 1.8% annual average growth for offshore projects.
Rystad expects a sharp rebound in capex for shale projects:
“Both offshore and shale projects have a large reduction in investments for 2016, due to continuing heavy reductions in capital budgets from oil and gas companies, in an effort to cope with low oil prices. For the offshore projects, Rystad Energy estimates the year-over-year reduction in investments to be 18% in 2016 and 17% in 2015. On the shale side, many shale companies have projected their 2016 capital budgets based on a 30 $/bbl oil price scenario, which resulted in an extremely low investment level for the year. The year-over-year capital investment change for shale is -40% for 2015 and -42% for 2016.
We believe that as the oil prices begin to recover, the investment levels for both sources will start to increase. From 2017 to 2020, Rystad Energy estimates that the capital investment for offshore projects will increase at an average annual growth rate of 11%, whereas shale projects will grow at a much higher rate of 33%. ”
http://www.rystadenergy.com/NewsEvents/Newsletters/UsArchive/shale-newsletter-april-2016
Rystad claims that shale projects are cost competitive compared with the offshore and most other oil and gas projects.
From the report:
“Based on breakeven oil price analysis for unsanctioned projects, shale is still a competitive source of supply. Figure 3 shows the average breakeven oil prices for unsanctioned projects. The average Brent breakeven price for shale projects is approximately 71 $/bbl. For offshore projects, only the offshore shelf has a lower breakeven price than shale. Oil sands have the highest breakeven price of around 98 $/bbl.
It is clear that compared to offshore projects, shale projects have a great advantage by having a lower breakeven oil price and the ability to make swift adjustments in response to fluctuations in oil prices. This means that when oil prices start to increase, operators that have both offshore and shale projects would prefer to ramp up the activity in their shale projects first.”
Rystad’s projection for shale oil and gas production has always been more optimistic than forecasts made by the EIA, IEA and OPEC.
Rystad’s current upbeat outlook can be partially explained by their oil price forecast.
From an article in “Straits Times”:
http://www.straitstimes.com/business/oil-tipped-to-rebound-to-us60-this-year
Oil could rebound to US$60 to US$70 a barrel by the end of this year as increasing demand starts to cut into the supply glut for the first time in years, according to an industry analyst.
Mr Jarand Rystad told a forum yesterday that with oil companies cutting back heavily on investments, the crude oversupply will quickly turn into shortage and, in turn, drive prices up.
In his keynote speech at the Offshore Marine Forum yesterday, Mr Rystad, managing director of Norwegian-based energy consulting firm Rystad Energy, added that oil could reach US$105 a barrel by 2020.
“This is just a classic commodity cycle… not a structural shift,” he said, noting that global oil consumption is still robust, while alternatives such as liquefied natural gas will likely have a visible impact on energy demand patterns only decades later.
But the bigger worry, he warned, is that the massive investment cutbacks could lead to another period of cost inflation. “It is very dangerous to start to scale the industry,” he said, citing how oil companies are adjusting their capacity to only a quarter of what it needs to be on a sustainable basis.
“Oil companies and oil service companies are laying off too many people. If you’re starting to scale, you will end up with far too low a capacity. Then you’ll have to hire new people (when the industry recovers) and then you’re back to the problem of cost inflation.”
“It is very dangerous to start to scale the industry,” he said, citing how oil companies are adjusting their capacity to only a quarter of what it needs to be on a sustainable basis.”
If I read this correctly, this analyst is saying the oil industry as a whole needs to be spending four times as much as it is, currently, in order to maintain the present level of production, or maybe increase it slightly.
Am I interpreting this correctly?
And if any body has an estimate of the total amount of upstream investment the oil industry has been making, as a percent of upstream revenue , on a historical basis, I would love to have a link or the chart or the estimate in any form.
Thanks in advance!.
By upstream I mean everthing done previous to actually getting paid by a refinery or shipping company that buys the oil. I hope that is reasonably close to the usual definition of upstream as the word is used by producers. If there is a more precise accepted definition of the term, I would like to hear it.
I read it as when companies begin to ramp up again, the HHP, rigs and personnel needed to increase production will not be there and it will take more time to ramp up. Those rigs and crews that are in the field will be in high demand. i.e. Cost inflation.
I do not think there will a shortage of rigs and fracking equipment, as spare capacity in those sectors is very high.
Manpower may be an issue, as people who were laid off have found jobs in other industries and are not willing to return into the oil business
Rigs and equipment can be built. That takes time. As for existing equipment surplus The rigs in use are getting serviced by existing rigs that are stacked. And those that are stacked, the longer they are out of service, the more that needs to be replaced and or serviced. The longer this downturn lasts the harder it will be to ramp up with surplus equipment.
There is no need to build new rigs and equipment, as current capacity utilization is 30% at best.
Some older rigs were scrapped or cannibalized, but there is enough new equipment, as capacity was actively expanded in the previous years.
And there will be no return to 2012-14 record rig counts, due to (1) slower production growth rates; (2) more efficient equipment, pad drilling, etc.
He says that, if demand for drilling, fracking and other oil services sharply rebounds, that would result in a rapid rise in rates for those services (cost inflation).
AlexS. All of the service companies indicate that rates now are at unsustainable levels.
George Kaplan has a good link re this above.
shallow sand,
rates are indeed down 30-35%, in some cases 40%. This fact, rather than technological improvements, largely explains lower upstream costs.
And current rates are indeed unsustainable, so further cost cuts are very unlikely.
But rates are down because of weak demand from the E&Ps. If demand surges, so will the drilling/fracking rates.
I personally think that upstream capex and drilling activity will increase rather slowly and will not reach 2013-14 levels any time soon. Therefore, drilling/services rates will remain well below previous peak levels in the next few years.
And I agree that Rystad’s LTO production forecast seems too optimistic.
Alex,
I personally think that upstream capex and drilling activity will increase rather slowly and will not reach 2013-14 levels any time soon. Therefore, drilling/services rates will remain well below previous peak levels in the next few years.
I agree. Decisions to cut the US presence were made by some service companies and probably will not be reversed “on the spot”
Oil price recovery will be gradual and probably slow. There are powerful forces behind “low oil price forever” regime and they will counterattack sooner or later. This loss of control of oil price by “paper oil” producers that we saw recently might be temporary. Any reversal will increase uncertainty and slow down recovery of drilling.
Please look at Art presentation — he predicts a leg down for oil prices “soon” (not that I subscribe to his opinion):
http://www.artberman.com/wp-content/uploads/Buffalo-CFA-Presentation-26-APR-2016-1.pdf
Surge of rates alone might well make $80 instead of $70 to be the minimum realistic price at which mass drilling can be resumed for LTO. Now everybody is scared as hell (which is visible from rigs dynamics).
And remember that LTO producers milked their best spots at a loss for more then a year now. Those spots are gone. So to make modest profits they need higher prices. As somebody said here that reminds Toll Brothers strategy after subprime crisis.
Alex,
That is what he is saying but he does not explain or does not recognize where the problem is.
Mr Jarand Rystad : “Then you’ll have to hire new people (when the industry recovers) and then you’re back to the problem of cost inflation.””
Mr Jarand Rystad, cost inflation is not specific problem of oil industry. Cost inflation is “built in” into financial system because of simple flaw: A (salary) + B (costs of doing business) > A (salary) so there is always constant loss of purchasing power in this case from the oil consumer side. When there is a shock to the economic system (this time because majority of oil producers (OPEC & non-OPEC) did not agree to regulate the production the current economic system is in full display how unstable it is. So the oil consumers get very small & temporary relief in terms of their increase of purchasing power due to low oil prices. And then the system resets again and the race is off towards illusionary “recovery”. Rinse-Repeat until there is a structural jam.
Ves,
Like most other commodity industries, the oil industry has always been highly cyclical, which implies wild fluctuations in the price of oil, as well as in upstream costs (cost inflation in 2004-14, cost deflation in 2015-16).
There are also structural factors (gradual depletion of the large low-cost fields and lower quality of the new resource base, partially offset by technological improvements), which result in a long-term rising trend in costs and prices.
Alex,
Your “highly cyclical” characterization is a misnomer. No other industry experienced 400% decline in prices (if we count from $28 400% will be $112) . This is a completely new territory. So survivors will behave super-cautiously fearing to get into the trap of yet another boom-bust cycle again.
Banks for at least three years will still remember losses from shale. After that reckless behavior might resume.
So the pace and the trajectory of recovery this time will be different and most probably unique. Several new factors will also affect the recovery such as:
— exhaustion of sweet spots,
— difficulties of getting credit lines,
— hostile attitude toward shale from environmentalists.
I think that to ramp up LTO production this time will be considerably more difficult.
Alex,
Oil industry does not operate on it’s own and outside of the economic system so it is naturally that oil industry inherits the flaws of economic system.
And I am speculating here but current economic system could absorb these resets until now even tough it was wasteful thing to do but it could be argued that Mr. Jarand Rystad is wrong and we have structural jam this time as shale oil economics would clearly tell us.
“400% decline” is an oxymoron.
The peak to trough decline in monthly-average oil price (WTI and Brent), from June 2014 to February 2016, was 71%.
Such declines are not unusual for some metals and soft commodity prices.
“I think that to ramp up LTO production this time will be considerably more difficult”
I agree. I have always been saying that the recovery in LTO production will be much slower than growth during the shale boom of 2011-2014.
Ves,
I agree that shale oil economics (and later depletion of the sweet spots) will considerably slow the recovery in LTO output.
It seems that Rystad is underestimating both factors. That is why I believe their forecast is overly optimistic.
To their credit, I should note that Rystad’s estimate of the average LTO breakeven price ($71/bbl) looks more realistic than many other estimates ranging from $25 to $45. And with potential resumed cost inflation and the need to develop peripheral areas of the shale plays, LTO breakeven is more likely to increase rather than decline.
that’s to make a point :-).
http://money.cnn.com/2014/06/12/news/oil-prices-iraq/index.html
$106/4 = 26.5.
Which is the same as
(106-26.5)/106=75% # your calculation
so all depends on the denominator used 🙂
The increase from the price 26.5 to 106 would be 400%
4-times decline is 75% decline, not 400% decline. Nothing can decline more than 100%.
Looking at daily prices when considering industry economics does not make sense.
Monthly average is the minimum time frame.
Monthly average spot WTI was $105.79 in June 2014 and $30.32 in February 2016, which represents a 71.3% decline.
Alex,
OK, I stand corrected.
Hi AlexS,
My guess is that the Bakken and Eagle Ford may return to their previous peaks at most, we might see another 500 kb/d from the Permian basin above current levels, the rest of the US liquids plays will at best be flat with increases in GOM output possibly offsetting non LTO declines in the US C+C output. I do think Canada may see some growth by 2030 of maybe 1 or 2 Mb/d if oil prices remain high enough to make oil sands development profitable. There may be some growth in NGL output as well.
So the increase of roughly 3.2 Mb/d from 2016 to 2020, I would put at 1.5 Mb/d at most with 1 Mb/d coming from Canada under the most optimistic of assumptions (oil prices reach $80/b by Sept 2018 and rise to $100/b or more by 2020.)
Hi AlexS.
On reading through the comments I se you agree that Rystad may be a little optimistic about the recovery in LTO output. I think even with their optimistic oil price forecast, depletion of the sweet spots and possibly some difficulty obtaining financing in 2018 and 2019 may limit how much LTO output will increase. I think it may reach 5.2 Mb/d for US LTO output at most around 2020, if financing is not too much of an issue.
I agree with Rune Likvern that would be a big if.
Dennis,
Contrary to what Rystad is projecting, I think that a rapid recovery in oil prices is incompatible with a sharp rebound in US LTO production. That would require a sharp drop in output outside the US or a very strong growth in global demand.
Any sharp increase in LTO production – even if possible – would limit the recovery in oil prices.
I agree with the EIA and IEA that it will take up to 1 year for tight oil production to start to recover. So far only Pioneer indicated that they may increase rig count if prices reach $50. Others are not yet ready to ramp up spending.
And even if shale players take decision to increase capex, it will take several months to see a real increase in production.
Hi AlexS,
I think oil prices will recover when the CAPEX downturn starts to be felt in 2018,until that time LTO output will decline about 500 kb/d and then maybe flatten if oil prices gradually rise to $60/b, by mid 2017. When oil prices reach $80/b or higher (mid to late 2018 is my WAG), LTO output will recover gradually, possibly reaching as much as 5.2 Mb/d by 2020.
I think this roughly coincides with your view (or my interpretation of your view.)
I am not a chart person, but I would love to see a chart of what oil-producing countries say they are going to produce versus what they actually do produce. Same for big companies (like PXD).
Open Question.
Do any of the Oil guys think that the new shale play discovered on Alaska’s north slope will ever be developed?
Maybe. I doubt it. Probably not. North slope costs are really high, regulations and permit requirements are very strict. The Rock and fluid basics remain the same as in other shale plays.
Thanks Fernando,
I agree, but if I didn’t, smart people would pay attention to you and the other oil experts (those who work in the oil industry). 🙂
Thanks thats sort of what I suspected also given the lack of connective infrastructure to ship the oil out. As a side issue does such a thing as a winterised fraccing pump exist.
South Dakota is pretty cold. From my experience in other countries, we keep the tanks and piping from freezing, the pump isn’t a big deal. Getting a water supply is a hassle, when the ground is permafrost. Your concerns are valid, but Western Siberia has already given us the training ground.
Dennis: please give my e-mail address to shallow sand and I would like to get Shallow’s e-mail address.
Hi JohnS,
I will send your e-mail address to him, if he would like you to have his he will respond.
(Similar) outlooks for the global oil market by the EIA and IEA chiefs:
U.S. Energy Secretary sees oil supply, demand rebalancing in a year
http://www.reuters.com/article/us-g7-japan-energy-usa-idUSKCN0XT0E5
U.S. Energy Secretary Ernest Moniz said he expects global oil supply and demand to rebalance in about a year’s time.
Benchmark crude oil prices, which hit almost 13-year lows earlier in 2016, surged nearly 20 percent in April on a softer dollar and lower U.S. production. However, market participants remain skeptical about the sustainability of the rally given a persistent global supply overhang.
“The recent rise in prices is not something I think that the companies are willing to reverse their investment trends on,” Moniz told reporters on Monday after the G7 energy ministers’ meeting in Kitakyushu, southwestern Japan.
“Rig counts in the United States are quite low … a rebalancing of global supply and demand looks to be quite credible, roughly speaking on a one-year time scale.
“That may change the dynamic but structurally we clearly continue to have a very very large inventory of oil,” he added.
“We are still unbalanced.”
U.S. oil output is expected to drop by 600,000 barrels per day (bpd) this year from a year ago as producers respond to low crude prices, Moniz said, citing U.S. Department of Energy projections.
========================================
IEA chief says oil price bottoming depends on global growth
http://www.reuters.com/article/us-energy-g7-iea-idUSKCN0XS0U4
International Energy Agency (IEA) chief Fatih Birol said on Sunday that oil prices may have bottomed out, providing that the health of the global economy does not pose a concern.
Oil prices hit 2016 highs on Friday with Brent crude reaching $48.50 a barrel on optimism that a global oil glut will ease. That, coupled with a weaker dollar, has helped lift crude futures by more than $20 a barrel since prices plumbed 12-year lows below $30 in the first quarter.
A decline in non-OPEC production amounting to more than 700,000 barrels per day this year, and production outages such as in Nigeria and Kuwait, have driven the rally, Birol told Reuters on the sidelines of the Group of Seven energy ministers’ meeting in Kitakyushu, southwestern Japan.
Asked if oil prices had bottomed out, he said: “It may well be the case, but it will depend on how the global economy looks like. In a normal economic environment, we will see the price direction is rather upwards than downwards.”
“We believe under normal conditions towards the end of this year, second half of this year but latest 2017, markets will rebalance.”
Birol said he hopes to see a rebound in upstream oil investments next year, following a 40 percent curb in investments over two years. Non-OPEC output is set to fall by more than 700,000 barrels per day this year, the biggest decline in around 20 years, he said.
“What we would like to see is, after a big decline in 2015 and 2016, there will be a rebound in investments (in 2017), and bringing (investments) to the level of $600 billion once again,” he said.
Birol said a third year of decline in investments would be problematic for oil markets as it could cause oil price spikes and increase volatility, which would not be good for consumers.
With global oil demand seen growing by 1.2 million bpd this year, the draw in global oil stockpiles will start soon, which will help push up oil prices, he said.
“I think the trend is that there’s a decline of stocks worldwide and the stock building rate is slowing down considerably, and we expect towards the end of this year stock draw will start to kick in,” he said.
Birol said that despite the recent rally in oil prices, it will take a while to change the direction of falling U.S. oil production.
“It will depend on how high the price recovery will go and how long the level of prices will stay,” he said.
“Our analysis shows we need $60-$65 of oil prices in order to reverse the trends in shale oil and this would require also some time for shale oil to come back because there’s a lot of work to be done. We think up to one year is needed in order for shale oil production to change the trends.”
===============================================
Both the EIA and IEA project a gradual recovery in oil prices, but they do not expect a rapid rebound in LTO production.
“Crude oil ended the month of April with the strongest monthly gain in 7 years, adding 22% to the price. The low price caused “production destruction” and strong demand put the market on a trajectory of market balance.”
“We have said that oil prices have bottomed and the chief of the International Energy Agency (IEA) agrees. “In a normal economic environment, we will see the price direction is rather upwards than downwards,” IEA Executive Director Fatih Birol said on Sunday during a G7 meeting of energy ministers in Japan as reported by Reuters. He took the words right out of my mouth. Barring any unforeseen economic catastrophes, the global oil market is at the low end of the cycle. We have said for some time that now is the time to start positioning for a long term bullish move. The low price that we saw in crude oil earlier this year may be the last time we see that for over a decade. ”
“Even as some shale operators say that they may actually bring on rigs after we hit $50 a barrel, the truth is that many of the smaller operators will find it hard to bring rigs back on.”
http://www.321energy.com/reports/flynn/current.html
The low price that we saw in crude oil earlier this year may be the last time we see that for over a decade
Although never say never, it may well be that the low price which oil reached early this year will never be reached again in the future boom&bust cycles. Kind of absolute minimum for all future price movements.
A monument to triumph of financial engineering over common sense 🙂
Two more US Drillers Just Filed For Bankruptcy
http://oilprice.com/Latest-Energy-News/World-News/These-Two-US-Drillers-Just-Filed-For-Bankruptcy.html
It’s not just hitting the fan in the USA. In addition to the sad situations in Venezuela, Nigeria and Iraq, they are now rioting in Saudi Arabia.
http://money.cnn.com/2016/05/02/investing/saudi-workers-protest-binladin-oil/
The Saudi Bin Laden group has laid off around 50,000 mostly foreign workers. The workers have torched 7 buses and are rioting.
Maybe they got automated.
Can a bankruptcy court discharge plugging and abandonment liability in the same manner that it can discharge debts or other contractual obligations? What about foreign entities operating in the USA such as EnCana? What if they simply gypsy on home with their operational skeletons left behind? Makes me thing of the Texaco Ecuador environmental lawsuits that have dragged on for the last 15 years or so.
That was today’s morning conversation at the coffee table.
In a liquidation, there is a presumption that a buyer will step in and acquire assets at a small % of the bankrupt party’s cost of the assets.
A banker said that the average overhead cost to operate a well today is about $6,000/ month and the cost to plug and abandon a horizontal well is about $100,000 each.
100,000 X 1,000 wells is $100,000,000!
There is more and more skepticism in people’s minds about the value of the long, fat tails of stripper production that will keep the party going. I am not very comfortable with the assurances that there will be buyers for these LTO bastards.
In Oklahoma, every well will be properly plugged. For years, the industry has paid a portion of every barrel sold into a state fund that takes care of situations where no one with any money is around and responsible. They have cleaned up thousands of sites dating back much more than 50 years. I assume that other states have similar provisions since Oklahoma is so backward.
It works like the FDIC that insures bank deposits, or the federal Pension Benefit Guaranty Fund.
John,
What is the P&A regime for these LTO wells?
Do they need to put cement across all of the fracs down to 20,000 ft of MD on the horizontal, or do they just need to cement the vertical section for 500ft? and then cement across any casing cuts?
A 10,000ft horizontal cement job sounds like it could present a few challenges, especially when you are trying to achieve it for less than $100,000 for the whole P&A.
JohnS.
After the 1986 crash many leases were abandoned in our area. Operators simply disappeared, most of the abandoned leases were operated by non-local companies.
Hundreds of wells ended up being plugged by state tax dollars, although equipment salvage recouped some $$. I’d say there won’t be buyers of wells that wont cash flow near the strip.
When you mention overhead, are you talking LOE? I’d say $6000 LOE for a 10,000 well with a hz lateral is light. I have reviewed a lot of LOS and for the Bakken I came up with about $14K per month average for 100% GWI on a JIB statement. So this includes some G & A also. This assumes no down hole or other major repairs. I came up with about $100K annually assuming two down hole failures per well per year, again in the ND Bakken.
You figure, back last fall the midpoint Bakken well was at about 100 bopd gross oil, 80 bopd after royalty. So assume total LOE of $256K and net annual BO of 29,200, you come up with $9.18 per BO LOE (plus a little G & A) Take out some G & A, add a little gas BOE, you are around $8, and then go look at WLL and OAS LOE per BOE. I feel I’m pretty close.
Now look at a 2010 well when it is producing just 25 BOPD. Our LOE will be less as we have slowed down the pump jack and are hauling less water. So say we drop to $9,000 per month, plus say we spend $50K on down hole repairs. LOE is now $21.64 per barrel. Say we are at $44 WTI, so $35 in the Bakken. We only have $255K of gross oil, knock off $25.5K for severance and extraction taxes (the 10% tax is very onerous for ND, IMO) and then $158K LOE. We are now down to just $71,500 cash flow on a well that was, say D & C in 2010 for $11 million. Of course, we spent the early cash flow from our 2010 well on more wells, so that $11 million is still owed at say 5%, so annual interest of $550K! Not to mention the indirect G & A we need to cover, like employee benefits, new corporate and regional headquarters, etc.
The profitable at $50 is total horse bleep. So we ignore past well production histories, of which there are tens of thousands? Ignore all have Billions of Debt?
Geez, getting tired of them thinking we are that dumb.
Lotsa computations of likely breakeven price for LTO.
One presumes that’s average . . . as in the average well.
Anyone got a standard deviation?
I hear from a fairly good source that Venezuela’s oil production is now below 2.2 million BOPD. They are having problems buying diluent and getting service providers to work for them.
I’m trying to track information on the Guri dam status, I have an unconfirmed report that several hydro turbines are starting to vibrate. On the other hand a report from a few minutes ago says the water level has increased slightly at the turbine intakes.
More Venezuela info: the Guri water level increased a bit, then it stopped raining. Yesterday morning they had divers checking the water intakes to the turbines. The country continues to have power cuts, quite a few are unplanned.
On the political front the Maduro regime is marching towards full fledged dictatorship. This in turn will increase brain drain, and I suspect there will be more violence. Two days ago there was a large firefight near downtown Caracas (Cota 905), security forces versus armed gangs.
USA policy towards the Castro family dictatorship has definitely given Maduro a path forward to turn into a much more dangerous character. Bush had his huge blunder in Iraq, and it looks like Obama collects smaller fiascos: Libya, Syria, and Venecuba.
http://www.pv-magazine.com/news/details/beitrag/third-phase-of-dubais-dewa-solar-project-attracts-record-low-bid-of-us-299-cents-kwh_100024383/#axzz47atViz00
Middle Eastern oil producers are going to have more oil to sell later on than might be predicted by big fans of the Export Land Model. I am one of those fans.
But with oil prices inevitably going up, sooner or later, unless oil becomes obsolete, burning any more of it than necessary for electricity is going to be a money foolish proposition. Folks with lots of sun can generate most of their electricity with solar power cheap enough to sell oil saved at a substantial profit.
If electrified cars get to be competitive on a cash purchase price basis with conventional cars, these countries can sell an even larger portion of their total production.
I don’t have a clear idea how big an impact this might have on oil prices, but it might mean there will be a few million more barrels on the market over the next few decades, starting five or ten years down the road. It will take that five or ten for solar farms to be built on the grand scale, assuming they do get built.
Watcher,
What’s your take?
THERE’S A BIG REASON THE US DOLLAR HAS BEEN GETTING DESTROYED
“The dollar index is down about 7.5% since its peak in mid-January, trading near 92.50 and at its lowest level in almost 16 months. There have a bunch of theories about what’s causing the greenback’s drop — including a rumored secret G-20 meeting to “take down” the dollar. But Credit Suisse’s foreign-exchange strategy team led by Shahab Jalinoos attributes much of the dollar’s weakness to something much simpler: the rebound in oil prices and the subsequent rebound in currencies of oil exporters. Oil exporter currencies are the main drivers of broad USD weakness, the team wrote in a research note to clients. Oil exporter currencies CAD and MXN, the Canadian dollar and the Mexican peso, have contributed greatly to USD weakness, much more than ‘policy divergence’ currencies such as EUR and JPY, the euro and the Japanese yen, they added…”
https://ca.finance.yahoo.com/news/theres-big-reason-why-us-090000556.html
There’s no reason for anything outside of the behavior of international central banks.
The Fed desperately wants to tighten. The ECB, BOJ and anyone else you can think of want to loosen.
Now, in days of yore when capitalism had a function, this would mean the Fed would drive rates up and the others drive rates down. But now it’s . . . the Fed won’t do QE for now and the others are flowing printed paper from their computers like water from a cleft rock.
The underlying motivation — everyone wants to be an exporter of stuff. If your currency is strong, the weaker currency country making stuff that competes against your stuff does so with a lower price on it. That’s the stuff people buy, the lower price. So no one wants other currencies to get weaker than their own, which also is somewhat inverted from historical norms.
Behold the meaninglessness of things measured by a whimsically created substance, when the visibility of that whimsy becomes profound.
Hi Watcher,
The money printing doesn’t matter very much, but interest rates do. If inflation approaches zero (if we assume deflation is avoided) and interest rates also approach zero for most countries, then the exchange rates will simply be determined by supply and demand for capital and goods. There are no large economies that do not let there currency float (value is determined by the market).
On the money supply in the US, if we consider the M2 money supply from 1996 to 2015, it has increased by 6% annually while M2 velocity has decreased at 2% per year, for a net increase in transactions of 4% per year on average, this is consistent with the average growth rate of nominal GDP for the US of 4%/year from 1996 to 2015.
Links to relevant FRED pages:
https://research.stlouisfed.org/fred2/series/GDP
https://research.stlouisfed.org/fred2/series/M2V
https://research.stlouisfed.org/fred2/series/M2
Bottom line, for the US the money supply has grown just as it should, the Fed has been doing a good job over the 1996 to 2015 period.
Inflation at link below:
https://research.stlouisfed.org/fred2/series/PCETRIM12M159SFRBDAL
From 1996 to 2015 (except for GFC peak in 2010) the annual inflation rate has been 1.5% to 2.6%, so inflation has been well controlled. Interest rates have been low because the economy has been operating well below capacity and the demand for liquidity has been low. Data in chart below used annual data from last link above (from FRED).
M2 wrong parameter.
Hi Watcher,
Doesn’t really matter, money supply has been rising while the velocity of money has been falling. Inflation has been well controlled, which is the Fed’s main mission. Better economic growth cannot be accomplished with monetary policy. Increased money supply is simply offset by lower money velocity when interest rates are very low.
The demand for money is determined by economic activity, once interest rates approach the zero lower bound, monetary policy is ineffective. Fiscal policy is what is needed under these circumstances if private spending does not get the job done. Government spending increases or tax cuts for the middle class (those with income between 25k and 75k) would increase aggregate demand and though counterintuitive, the increased economic activity might reduce budget deficits as GDP increases.
How low oil price can go again ?
http://www.bloomberg.com/news/videos/2016-05-01/why-oil-prices-aren-t-headed-back-to-30-a-barrel
OK, Bloomberg presstitutes were pretty predictable (a part of “low oil price forever” crowd) , but the guy they are interviewing made several good points.
“Logistics have mass and momentum. The current mass and momentum — debt, stacked drilling rigs, and depleting oil wells — will ratchet the price of oil higher for at least a year. I completely agree with the Saudis that the “Post-Oil Era” is at hand. Life requires energy. Less affordable oil energy will dramatically affect long-term investing.”
http://seekingalpha.com/article/3970216-peak-fracking-perpetually-higher-oil-prices
I was sort of surprised to see this blog post at Scientific American, but they do allow their bloggers to run free, with the usual boiler plate about the author’s views not necessarily being the same as the magazines.
Oil all the way out the ying yang forever ?
http://blogs.scientificamerican.com/guest-blog/the-age-of-cheap-oil-and-natural-gas-is-just-beginning/
I am willing to believe there is a lot of oil that can be had by fracking, if we pay a high enough price for it, but methinks this guy is maybe a little on the optimistic side, lol.
He also mentions fracking old conventional fields. There has not been much discussion of this possibility here in this forum.
Do any of you hands on guys have anything to say about fracking old conventional fields? How much more oil might be gotten out of such fields by fracking them?
Hi Old Farmer Mac,
I would not use optimistic to describe this author, delusional might be better. 🙂
Hi OFM,
I can’t quantify an answer for you with hard data but here is something to consider. First fracking is a tool or technique that is used with a specific purpose in mind. It is not a stand alone panacea but combined with horizontal drilling there is a lot of new conventional oil yet to be produced in the lower 48.
I recently saw a geological interpretation work around an old San Andres field on the central basin platform. The San Andres is a great reservoir with super porosity and permeability and has produced billions of barrels of conventional oil on primary production , secondary (water flood) and tertiary (CO2) production.
This was a low relief anticlinal structure delineated by dry holes and uneconomic wells with very thin pay zones (less than 20′ thick). Think of an upside down soup bowl with conventional vertical wells drilled around the rim of the bowl through the thin pay sections.
Now horizontal wells are being drilled around the rim within the < 20' thick pay zone. Now the operator is dealing with hundreds of feet of virginal San Andres pay. Those wells are being drilled and fracked and are very economic at $30 oil.
JohnS. I took a look at hz San Andres, it appears Forge Energy LLC has had some very good wells. A few duds too, but looks like most are pretty good. Some other private companies doing this, but only Apache when it comes to public companies, outside a stray one by OXY.
What is D & C cost? Looks like these do not decline as badly as LTO Permian do?
Scientific American has lost a lot of quality in recent years.
Fracturing old reservoirs isn’t a big deal. For example, fracturing can be carried out to get around damaged zones in the near well area. These damaged zones are seen in old wells and water floods. But this fracturing is low volume and costs much less.
I can see improved mega fracturing jobs helping out in some low permeability reservoirs. But if the reservoir is old this isn’t really going to help that much.
As regards the USA having or not having good candidate reservoirs, it’s evident they are the best. This horizontal well plus large scale multistage frac technology requires reservoirs with light, low viscosity oil – fracturing a heavy viscous oil is a waste of money. And this is the problem I can see in many areas around the world. The stuff is there but the pressure is too low, the viscosity is too high, the surface is hellish, or the costs are too high.
So yes, our professor living in Sweden has a disconnect. Reminds me of the Swedes drilling for meteorite oil at Siljan Crater.
Hey OFM, your link no longer points to the post but after a little digging I found it.
Meh, It’s author is another one of those energy specialists and he is an economist to boot…
Marian Radetzki is Professor of Economics at Luleå University of Technology, Sweden
He co-authored a book with Roberto F. Aguilera, titled the ‘Price of Oil’. Looks like he might be plugging it on the Sciam Blog.
https://goo.gl/lcsk1u
He seems to think fracking is a new revolutionary technology!
I wonder if anyone ever told this genius [Radetzki] that the US LTO guys lost their ass at $80 oil. And, the US had the advantage of millions of miles of pipelines and railroads; mineral ownership by individual citizens; more refining capacity than anyone in the world; more storage than anyone in the world; better individual worker mobility; a favorable tax environment; thousands of service industries to handle the glut.; the world’s best currency, etc., etc. But somehow, now the people of Iraq, Nigeria, Afghanistan, Liberia, Sudan, Poland, or wherever the shale oil is, are going to make it happen for a fraction of the US?
I cannot stop laughing. I think that I need to go to the hospital.
“Professor of Economics” those days usually means a member of neoliberal academic mafia. It’s a dirty word now ;-). Being a Polish guy working in Sweden of course he tries to be a better catholic then Roman Pope. Outdoing US neoliberals.
As for the book whether this guy intended to milk the low oil price situation or not, the timing of his book is impressive.
http://www.amazon.com/Price-Oil-Roberto-F-Aguilera/dp/1107525624
It looks like the content is not.
As any neoliberal he defends the concept of “Four Cheaps”: labor, food, energy, and raw materials that dominates neoliberal thinking and which are crucial for overcoming bottlenecks of capital accumulation. The neoliberal boom that commenced after 1980 was based on significant decline of prices in food, energy, and other commodities. Commodity prices for metals fell by nearly half between 1975 and 1989; for food by around 40 percent.
Now we got “end of cheap oil” which threatens economic growth (this is what secular stagnation is about). In a way, rising ERoEI spells troubles to both neoliberal globalization and neoliberalism as a social system. To what extend additional supply of electricity via renewables is able to compensate for exhaustion of oil reserves remain to be seen.
As for his thesis “LTO oil is a revolation”, sure horizontal drilling is applicable to high porosity reservoirs, but to what extend it is different and more efficient then infill drilling in such environment remains to be seen. If analogy holds, this is just a method of the acceleration reservoir decline by increasing the initial volume of production via additional investment. That might be true for LTO too.
Labor might be close to exhaustion too. Not in the sense of imminent physical breakdown; it is exhausted in its capacity to deliver a rising volume of unpaid work to capital (what is usually presented as rising productivity). The neoliberal extension of the workweek provides a good reason to think that American workers cannot work much more or much harder. That suggests that the key reserve for increase of productivity is further automatization and computerization of everything (as in computers eat people).
BTW it you looks at author publication list it looks like the author does not have and specific extraction industries background. He is more of a trader. Take for example his another book (April 1990) “A Guide to Primary Commodities in the World Economy”
Thanks every body,
I figured this guy for a cornucopian, which is why I said “Methinks this guy is maybe a little on the optimistic side, lol”.
But sometimes such people do bring up valid points that have not yet gotten any attention here in this forum.
For all I know, it might be possible to get some more oil out of a some old conventional oil fields by fracking.
The mere fact that I haven’t heard about it is no indication at all that it can’t be done.Somebody somewhere might even be doing it already.
If this link hadn’t been on the Scientific American website, I probably wouldn’t even have mentioned it. I have back issue around someplace from way back there, the one with the cover story being about the END of cheap oil, lol.
I forgot to mention that in my original comment.
The editors at SA might not be QUITE as objective as one could wish when it comes to business as usual questions, considering a science oriented magazine should be objective about questions such as peak oil. Sarc light ON on this time instead of lol, so there will be no mistaking my opinion.
Scientific American has an ax to grind. I have been attacking the IPCC oil production forecasts on a fairly consistent basis, and I’m starting to get traction. This may be part of a defensive maneuver by the global warming panic Mafia to build a fake “consensus” that oil supplies are plentiful. At this time they are drafting the next set of emissions projections (for AR6), so I expect “peer reviewed” garbage being published in Nature saying that oil, gas, and coal resources do back their bullshit emissions forecasts.
Hi Fernando,
The following assumptions are not realistic, but let’s assume that LTO resources (except in the Arctic and Antarctic) worldwide are extracted at similar rates to what the US has experienced from 2010 to 2015, from 2020 until they are no longer profitable. We will assume real oil prices in 2015$ remain between $100/b and $150/b (though I think they will remain mostly under $120/b). How much LTO would we expect for a URR? My guess would be 100 Gb, though your WAG would be far better than mine.
Thanks. I do not agree with your explanation for this piece, it is just the usual thinking by economists that have no real clue about the real world technology and geology, it should be ignored, maybe you should publish something here (minus the IPCC plot to take over the world 🙂 ).
Dennis, 100 to 150 would appear reasonable. My problem is the lack of information on the thermal maturity, liquid viscosity, and over pressure conditions of the Bazhenov and Vaca Muerta they are testing at this time.
Hi Fernando Thanks.
I assume you mean 100 to 150 Gb for World LTO URR (a guess based on very limited information) if oil prices are relatively high (over $100/b in 2016$).
http://www.marketwatch.com/story/watch-saudi-arabia-shrink-as-america-works-to-wean-itself-from-middle-east-oil-2016-05-03#:P2hFfq0jr14sXA
Oil importing gif.
http://in.reuters.com/article/us-canada-wildfire-fortmcmurray-idINKCN0XU2D8
LTO companies debt and energy junk bonds problem can’t be swiped under the carpet. It is just too big for that. We are talking about around 350 billion of debt with half on them in junk bonds. That’s probably half of the gain of the US economy from oil prices crash (and, of course, not all this debt will convert into direct losses; recovery in the range of 20% is still possible).
What form the day of reckoning will take is very difficult to predict. Much depends on debt repayment schedule and bond maturity dates. But this level of debt completely undermines chances of quick revival of LTO production in case oil prices jump up, as new capital to finance drilling will not be here. So any talk about quick revival of the US LTO production as a reaction on higher oil prices does not take into account the fact that that it will be very difficult to finance new mass drilling this time. And drilling 1000 wells is around 6 billion. 1500 — 9 billions.
https://finance.yahoo.com/news/u-oil-industry-bankruptcy-wave-040735270.html
likbez,
So what that tells you that last paragraph that you have boded. It tells me that “money” suddenly stopped working on macro level sometime when this shale thing started. There shouldn’t be that MANY rigs anywhere in shale plays in 2009-2014 and no one should be drilling AT ALL today in shale plays or any play for that matter either. So “money” stopped working on macro level. Yes, on micro level you will get kicked out if you don’t pay rent but some disruption will trickle down eventually.
So what that tells you that last paragraph that you have boded. It tells me that “money” suddenly stopped working on macro level sometime when this shale thing started.
A very good point. Thank you !
But not that, although it is true the banks needed to blow a new bubble.
It also tells me that in Garner Hype Cycle of innovations shale in 2016 is close to reaching or already reached “the trough of disillusionment” http://www.gartner.com/newsroom/id/3114217
I’ll let folks go see the disaster that is Nissan Leaf sales themselves. Freefall. April sales 787. Not 787K. 787.
Ford’s F series pickups sold 70,000 units last month. Not 70. 70K.
Gasoline powered cars like the Chevrolet Volt (odd name for a gasoline car) are doing okay.
Stock market prefers TSLA.
Gasoline powered cars like the Chevrolet Volt (odd name for a gasoline car) are doing okay.
Watch’ welcome aboard the EV bandwagon. 🙂
You might appreciate the image of a Tesla burning to the ground at a ‘supercharger’ station earlier this year. (I guess it really was supercharged.)
I posted it, after some words about car fatalities (and links to some horrific images of fatalities still at the scene).
If some are going to fetishize the deathmobile, whether electric or not, for the sake of journalistic, etc. integrity, we might as well cover all angles– straight and crumply, alike.
(I guess the taxpayers as usual are responsible for car-crash-cleanups, etc., whether they drive or not.)
I’ll let folks go see the disaster that is Nissan Leaf sales themselves. Freefall. April sales 787. Not 787K. 787.
The curse of rapidly advancing technology. The Chevy Bolt, and Tesla 3 are likely making prospective EV buyers keep their powder dry or put it towards a 2017 Chevy Volt.
Chevrolet Sets New Yearly High For Volt Sales In April
Hi aws,
It is interesting that Watcher dismisses the Volt as a gasoline powered car. It has a range of 53 miles on battery when fully charged. As the charging network improves the effective range for a round trip becomes 106 miles. It may be “gas powered”, but for a lot of people the fuel economy (for gasoline only) may be about 1100 miles per gallon (that would be about one 10 gallon tank of gas per 11,000 miles driven). For longer trips people will use their F150 🙂 .
Needs a cheaper lighter battery.
Hi Fernando,
Battery cost has been falling by 15%/year, so cheaper is coming, lighter, probably not so much, though there is research on better battery technology and as demand increases energy density may increase as well with further technological improvements.
Dennis,
Those expectations of progress in car batteries are somewhat similar to LTO dreams.
There are limits of battery technology in the energy per unit of weight metric that can principally achieved and IMHO lithium batteries are close to this limit: that’s why they are so dangerous if overheated — a lot of energy is stored in a relatively small volume/weight. That also means that going further this path increases the danger of fire.
The technology is 25 years old. “First lithium-ion battery prototype was produced in 1985, a rechargeable and more stable version of the lithium battery; Sony commercialized the lithium-ion battery in 1991. [37]”
Cost of production plants and cost of the pack as well as variables involved are well researched. Including by US government. See for example:
http://www.cse.anl.gov/batpac/files/BatPaC%20ANL-12_55.pdf
Look at Table 5.9. Summary of results for cost of baseline battery and that of similar batteries with
double the power and double the capacity of the baseline battery to understand limits of efficiency of production.
I think that the economy of scale is already fully in, so further reductions of costs at the rate of 15% per year (45% in three years) are unrealistic. Where did you got those forecasts? Price might even increase if components cost increase.
This is already a mature production so further reductions of costs are problematic.
Hi Likbez,
A youtube video that Fred posted had battery research, it does not have to be lithium ion, but it looks like continued improvements are possible. Over the past 10 years of so costs have been reduced at 14%/year. Economies of scale as battery production ramps up further for EVs will lead to further reductions in cost, possibly this rate will slow, but recently the rate of decrease in cost has increased to 16% (past 3 years), we could use some lower future rate of decrease, but for another 10 years I would expect at least a 10%/year decrease in battery costs. Elon Musk is confident that battery pack costs can be reduced by 30% when the Gigafactory is fully operational in 2019 (that is only a 9%/year decrease). If we assume a 9%/year drop in battery costs, then the cost falls by 75% by 2030.
See
http://www.hybridcars.com/gm-ev-battery-cells-down-to-145kwh-and-still-falling/
http://www.computerworld.com/article/2977655/sustainable-it/as-energy-push-accelerates-battery-costs-set-to-plunge-60.html
http://www.mckinsey.com/business-functions/sustainability-and-resource-productivity/our-insights/battery-technology-charges-ahead
Generally the cost of Li ion batteries have been falling faster than projected. The 2012 McKinsey report projected a cost of $160 per kWhr by 2025, but GM claims in October 2015 to have already achieved $145 per kWhr (for cells rather than the battery pack).
See
http://www.greencarreports.com/news/1103667_electric-car-battery-costs-tesla-190-per-kwh-for-pack-gm-145-for-cells
The McKinsey piece was likely using pack cost rather than Cell cost. GM’s pack cost is currently estimated at about $220 per kWhr and Tesla claims its pack cost is currently $190 per kWhr. If Musk’s estimate of a 30% reduction in cost by 2019 is correct then the pack cost drops to $133 per kWhr by 2019.
The McKinsey report suggests that an EV is competitive with the ICEV at $2/gallon gasoline with a battery cost of $150 per kWhr.
I do not foresee gasoline dropping under $2/gallon long term, but battery cost are likely to continue falling.
That study is pretty old and cost reductions below suggested by that paper have already been achieved.
The 14-16% annual cost reductions are what have been achieved over the past 15 years or so.
I agree future rates will be lower, but thinking that costs will not fall further is unlikely.
The Tesla Giga factory is expected to reach full capacity in 2020 and battery costs are expected to decrease 30% by 2020 (only 7%/year). Pack costs would fall by 52% from 2015 to 2015 if a 7%/year cost reduction is achieved. Pack cost would be under $100 per kWhr by 2025.
Dennis,
That Tesla business model probably won’t work out that way. I can’t find the link, but recently read that the lithium won’t be cheap enough.
The lithium miners so far have refused to sell their product at the low prices “demanded by Tesla.”
If those miners continue to be unreasonable by refusing to sell cheap (below their cost of production), our whole dream of cheap, long range electric cars for the masses to continue BAU will turn out to be a pipe dream.
Someone better open a new super high quality lithium mine ASAP. Surely there is a high grade ore deposit with all necessary infrastructure just waiting for the price of lithium to drop so low that only the new mine can sell at Tesla’s demanded price and make profit. Once the new mine opens, it should be able to put the higher cost miners out of business, create a shortage, and raise the price beyond Tesla’s reach. Or have we high-graded lithium, just like oil, so new mines will work lower grade ore in tougher places, while magically and dramatically reducing their costs? (Sarcasm intended).
Those projections of 30% price reductions are probably ignoring the geology, similar to projections of perpetual oil abundance.
It seems that global population is in overshoot and that BAU probably can’t continue for the masses, or grow to include lots more masses in developing countries. Then there is climate change and degradation of environmental systems that we depend on for life services.
So why do we think electric cars are so great for our future? Can’t figure that one out. Disconnect in thinking? Hopium?
Thanks for your optimism. It is a stark contrast to many unpleasant alternatives that, frankly, seem more likely. I doubt that much of what you foresee will turn out the way you think, but I do hope you are at least partly right:-)
Jim
Hi Cracker,
The reduced price of the battery is not based on falling lithium prices, it is based on lower cost of production due to economies of scale.
The cost of lithium ion battery packs have been falling at 11.3% per year for the past 15 years. From $1150 per kWhr in 2000 to $190 per kWhr in 2015 (battery pack cost).
For Tesla to achieve a 30% reduction in battery pack cost from 2015 to 2020 will require an annual rate of decrease of 6.9%. I think it likely this goal will be met even if Lithium prices don’t decrease just due to efficiencies in large scale manufacturing in the Gigafactory (a joint venture between Tesla and Panasonic).
See
http://dukespace.lib.duke.edu/dspace/bitstream/handle/10161/1007/Li-Ion%20Battery%20Costs%20-%20Anderson%20-%20MP%20Final.pdf?sequence=1
Dennis said:
The reduced price of the battery is not based on falling lithium prices, it is based on lower cost of production due to economies of scale.
Correct, as a matter of fact even if lithium prices increase the overall price of a battery pack would still continue to fall.
The projected increase in energy density and lower production costs combined would still allow for continued price drops.
BTW, there’s a lot of lithium in the ocean and I’ll bet that there will be people farming genetically modified marine algae that concentrate lithium.
Granted that might turn out to be the cause of number of real environmental nightmares but I’m pretty sure somebody somewhere is already working on that…
In the mean time there is plenty of easily mined lithium available, kinda like when there was lots of easily available cheap oil 🙂
Lithium prices
source: http://oilprice.com/Energy/Energy-General/Tesla-And-Other-Tech-Giants-Scramble-For-Lithium-As-Prices-Double.html
So prices are basically unchanged since Tesla built their first car. They can afford quite a substantial price increase.
This is already a mature production so further reductions of costs are problematic.
I very highly doubt that is even remotely true. I recently posted a link about the current state of the art and where the research is heading. Here it is again.
https://goo.gl/B3qBEW
This is also an interesting article:
http://insideevs.com/falling-gas-prices-vs-falling-battery-prices-wins/
Batteries
A lithium-ion battery’s chemistry and electricity storage are governed by four key components – the anode, cathode, separator and electrolyte. Lithium-ion battery cells are then combined into larger modules that are packaged in housings, often referred to as the battery pack, which utilize cooling systems, electronic interfaces and controls.
EVs can be the cost catalyst for energy storage. EV sales perpetuate lower battery costs, leading to more cars sold, leading to lower batteries, and so on.
UBS lists the following as the key drivers for a reduction in total cost of the lithium-ion battery:
(1) Increasing manufacturing scale and productivity;
(2) Reducing the cost of battery materials and components;
(3) Increasing battery energy density and lifespan (minimising battery fade/maximising the number of charge cycles).
baterry costs
Where the cost go
Cell manufacturing alone contributes to nearly a third of the battery cost. Economies of scale will begin to take a heavy bite from this slice of the pie reducing significantly the cost. Cathode material developments are the second largest cost and for that reason have been a key area of focus. Still, cost savings in all areas of the battery are being optimised which contributes to the continuing falling price of the battery. Lithium-ion battery costs for automotive applications have already come down aggressively in the past three years, with pack costs having fallen from US$500/kWh in 2013 to US$360/kWh today. Umicore believes that this total pack cost will fall to below US$200/kWh by 2020. Tesla sees a pack cost of less than US$100/kWh within 10 years
http://spectrum.ieee.org/at-work/innovation/the-search-for-a-better-battery
LG Quoted an amazing price to GM for the Bolt. IIRC Under $200 / kWh
As I said : Needs a cheaper lighter battery technology.
Hi Fernando,
The battery packs have been getting cheaper, they have decreased from $1150 per kWhr in 2000 to $190 per kWhr in 2015, so slightly more than a factor of 5, costs will continue to fall as production of larger battery packs for cars ramps up due to economies of scale. They may not be able to increase the specific energy much further as we don’t want to break any physical laws. 🙂
Hi Watcher,
For 2015 the Mercedes S class sold 21,934 vehicles in the US, the Tesla Model S sold 25,202 cars in the US. The best selling Mercedes is the C class with 89,080 cars sold in the US in 2015. It will be interesting to see how long it will be before Tesla beats the C class with the model 3, maybe in 2018 unless there are delays in the release of the Model 3. It will be interesting to see the sales of the Chevy Bolt in 2017, that car is the reason the Nissan Leaf is not selling, people are waiting for the Bolt.
http://fortune.com/2016/02/11/tesla-best-selling-luxury-sedan/
“For 2015 the Mercedes S class sold 21,934 vehicles in the US”
“The best selling Mercedes is the C class with 89,080 cars sold in the US in 2015”
An interesting observation: 21K rich people concerned about their status vs 90K of status obsessed middle class wannabes 🙂
Hi Likbez,
I don’t judge, people can spend their money as they choose. The average selling price of a new light duty vehicle in the US is $33,000. The $80,000 Tesla Model S might last a very long time, if it lasted 3 times as long as the average $33,000 car and saves $27,000 in fuel costs over its 450,000 mile life, then with no discounting we would come out $47,000 ahead with the 30 year old Tesla, and for the first 15 years or so you would have a very nice car, it might get a little old from year 16 to 30 though.
Wildfires at the beginning of May in Northern Alberta.
This could have gone in either thread, I chose this one.
‘Worst of the fire is not over’: Wildfire rages in Fort McMurray after devastating day
‘We’re still faced with very high temperatures, low relative humidity and some strong winds’: Alberta official
CBC News Posted: May 04, 2016 3:28 AM MT
‘Catastrophic’ Fort McMurray wildfire prompts state of emergency
http://cci-reanalyzer.org/DailySummary/index_ds.php#
None of that matters.
Only oil flow from the oil sands matters.
It snowed in the mountains of North Carolina today.
http://www.wyff4.com/news/Temperatures-drop-rapidly-snow-flurries-reported-in-mountains/39399438
Omega block behind searing heat inflaming Fort McMurray wildfire
Omega block
Does that look more ‘systemically-chaotic’ to you?
Because naturally, that’s a prediction of climate change.
If we overlayed historical maps like that, I wonder what differences we might see.
As Tesla Motors was frequently mentioned in this thread, I decided to look at the company’s financials.
I know that this is a new, high-growth industry, so net losses, negative cash flows and rising debt should be viewed as something normal.
Still, the numbers remind me of the shale industry, also a new, high-growth segment of the oil industry.
Brief summary of Tesla Motors financials (from 10-k report 2015)
In million dollars, except per share
Note (from Stockopedia):
Net Debt to Equity-
Also known as Net Gearing, this is a measure of a company’s financial leverage calculated by dividing its net liabilities by stockholders’ equity. The formula is : (Total Debt – Cash) / Book Value of Equity (incl. goodwill and intangibles)
It uses the book value of equity, not market value as it indicates what proportion of equity and debt the company has been using to finance its assets.
The gearing ratio shows how encumbered a company is with debt. Depending on the industry, a gearing ratio of 15% might be considered prudent, while anything over 100% would certainly be considered risky or ‘highly geared’. As a general rule, net gearing of 50% + merits further investigation, particularly if it is mostly short-term debt. A highly-geared company is more vulnerable to a sudden bump in the road, either operationally or due a change in the economy (e.g. a recession or an increase in interest rates).
http://www.stockopedia.com/ratios/net-debt-to-equity-trailing-12m-495/
Thanks for your report Alex, very interesting. I understood that the financial situation of Tesla is not likely to improve in 2016 & 2017.
Enno,
As Tesla’s sales increase, so are the company’s losses, negative cashflows and debt.
What should change this situation and when can Tesla become profitable?
How many years a company can be loss-making before the market recognizes that it is in financial trouble?
Alex,
“Money” suddenly stopped working and that is what market will realize. It is no coincidence that same thing is happening at the same time to oil, gas, nuclear (it was article about that on 35 billion Hinckley plant) or Tesla. We are running on fumes 🙂
Ves,
In many “old” industries, “money” is still working.
Companies are sticking to prudent financial policies.
BTW, this refers to most conventional oil producers.
Alex,
Conventional is only losing less than shale per barrel. If they don’t replace reserves as even the most majors didn’t last year than that it is just race to the bottom.
AlexS. In the US, all producers are feeling pain to varying degrees at Q1 prices, less so but still pain at current prices.
There are a lot of US industries that are showing good earnings. These are across a wide variety of industries. Also, many of the smaller banks are also showing good results. I do not own large banks, but have shares in some smaller regional banks, all posted record earnings.
For some reason investors are very accepting of US oil and gas losses, and only seem to get worried when there are signs that bank lines will be slashed below present balances and/or interest cannot be paid.
shallow sand,
It is not surprising that oil producers, both in and outside the U.S., “are feeling pain to varying degrees” at the bottom of the cycle.
But most of conventional producers have much more affordable debt levels than the shale guys.
Alex,
Very true. And this is a big, I would say, decisive difference.
Great to see someone in here adress this. I know it’s a bit OT.
Here is a great link on the subject.
http://www.wsj.com/articles/elon-musk-supports-his-business-empire-with-unusual-financial-moves-1461781962#:vkAg_GglMeb6NA google if its locked.
Listened to a great podcast, in Swedish unfortunately, with a comparison of BMW and Tesla on the stock value. Let say theres a lot of air in the Tesla. Don’t get me wrong I’m a fan off Tesla but not so much the stock. And among my friends to criticize Tesla is like cursing in church.
Amatoori,
Thanks for the link.
Interesting, what is Elon Musk’s source of finance for his loss-making projects?
The product may be great, but financial model is flawed.
Similarly, shale oil and gas companies are producing a commodity, which is in demand (and will remain for decades). But their financial model is flawed.
They are drilling great wells with long laterals and are using superfracs, but remain loss-making and are burning cash.
Alex,
The product may be great, but financial model is flawed.
With great product produced at loss it is still always possible to accumulate huge debt as long as you are on the upside or slightly downside of the initial bell curve of Gartner Hype Cycle for a new technology.
As soon as Tesla reaches “Through of disillusionment” all bets are off.
http://www.gartner.com/newsroom/id/3114217
After that your mileage may vary 🙂
Hi AlexS,
As a company ramps up output in a capital intensive industry, debt will accumulate as the money spent on plant and equipment will exceed revenue. Eventually the ramp up in output will slow down and profit margins will increase as the rate of new investment slows down.
Anybody that thinks an investment in a small company taking on giants like GM, Ford, Mercedes, Toyota, Honda, and Hyundai is not a risky investment, would have bet on David against a half dozen Goliaths. Not a really smart bet.
David won that fight according to legend, but it was a one on one battle. Luckily the 6 giants are not working as a team so it is not really David against 6 Goliaths, the 6 giants are battling each other and may ignore David which might improve the odds, hard to say, but still high risk imo.
Dennis,
As I said above, “I know that this is a new, high-growth industry, so net losses, negative cash flows and rising debt should be viewed as something normal.”
I understand that economies of scale may lower unit costs, improve financials and allow paying down of debt.
Or may not.
In real life, not all Davids win a fight againsts Goliaths.
My question is: how many years a company in a new industry can remain loss-making before the market recognizes that it is in financial trouble?
5 years, 10 years, 15 years?
Meanwhile, Tesla’s plans are becoming even more ambitious
Tesla’s projected sales growth
source: http://www.bloomberg.com/news/articles/2016-05-04/tesla-s-wild-new-forecast-changes-the-trajectory-of-an-entire-industry
AlexS says “I know that this is a new, high-growth industry, so net losses, negative cash flows and rising debt should be viewed as something normal.”
In my opinion, the world is now just full of financial BS artists. I believe that in the not too distant past, when Carnegie started the new steel industry, or Rockefeller with oil, or the railroads with Vanderbilt, or Henry Ford with the auto, or Bill Gates with computers, or Steve Jobs with computers, or any number of thousands of people – that their view, nor that of their backers was -“net losses, negative cash flows and rising debt” was NOT viewed as NORMAL. But, today’s BS artists seem to think so.
I am not criticizing AlexS, although he may have been influenced by such propaganda. The NORMAL would be for a new industry to have windfall profits, protected by patents, that would eventually wane away as other competitors, and new technology came onto the scene. Think – Xerox, Polaroid, Eastman Kodak, Alcoa, Gateway Computer, Bomar Brain, etc.
Remember, normal is an average, so there are examples on both ends of the spectrum.
Seems like after hearing Musk on the CC today, even some of the believers are starting to waiver.
The one that got me was that they took all of these $1000 REFUNDABLE deposits and applied them to their line.
Has anyone there ever heard of escrow or trust account?
” applied them to their line.”
It’s free money 🙂 almost like QE from the Fed 🙂
Henry Ford had net losses, negative cash flows and rising debt. His first two companies failed. He was, of course, not listed on the stock market.
Here is Tesla’s major, major problem – well, one of them.
Their production division is a train wreck. They are having huge problems even rolling out 50K per year. They only shipped 800 vehicles in March. The current excuse given is “supplier problems” And they think they can ramp up this broken production unit to roll out 10x more – 500K per year – in just two years? With cash problems? With product engineering problems? (elsewhere in the earnings comments, the Model X is noted as the most difficult-to-build vehicle in the world. That is an engineering problem- not production or parts.)
They are desperate for cash flow. You’d think job 1 would to to keep their inventory/parts ordering/production processes all tightly linked so every single vehicle that is ordered is shipped ASAP. You don’t get paid until you ship. Even one-man businesses understand that.
Below is an actual excerpt from Musk’s comments about the Model 3 delivery date (nominally 7/1/17 and why he already says it will slip), vehicle assembly complexity, and Tesla’s parts supplier problems. Pathetic. If a CEO at GM/Ford/BMW/Kia/everyone else ever said their production/inventory control was this out of control, their board would immediately fire them for incompetence. Oh, wait, Elon is the largest stockholder and controls the board.
“The date, I’m sure this will leak, it’s hard to keep a secret really, the date we are setting with suppliers to get to volume production capability with the Model 3 is July 1 next year. Now, will we actually be able to achieve volume production on July 1 next year? Of course not. The reason is that even if 99% of the internally produced items and supplier items are available on July 1, we still cannot produce the car because you cannot produce a car that is missing 1% of its components. Nonetheless, we need to, both internally and with suppliers, take that date seriously, and there need to be some penalties for anyone, internally or externally, who does not meet that timeframe. This has to be the case because there’s just no way that you have several thousand components, all of whom make it on a particular date.”
http://www.thestreet.com/story/13559022/2/tesla-motors-tsla-earnings-report-q1-2016-conference-call-transcript.html
FYI, even with a well-oiled-mass-market vehicle production machine like GM, it takes about 8-9 months of pre-production assembly line runs to get the product tweaks and the line up to full retail production capacity. GM started pre-production on the Bolt about 2 months ago. For Tesla to be hitting 7/1/17 mass production, they need have the line re-tooled for their high-volume and doing pre-production runs by this October. Yeah, right.
Tesla doesn’t really do “pre production runs”. They can’t afford to. The early customers are the beta testers. This time, however, they’ve dedicated that role to their employees…
Hi AlexS,
As far as David and Goliath, I said it was not a good bet, that is, the odds are very low that David wins. So I agree that David usually loses such fights.
As far as how long can they remain unprofitable? Amazon took about 10 years to reach significant profits, I would think when the Model 3 reaches 500,000 vehicles per year (probably not until 2020), Tesla would become profitable the following year (2021).
Dennis,
Of course, we may give Tesla the benefit of the doubt. But I wouldn’t be so sure that ultimately the company will become profitable.
from Bloomberg:
Tesla Falls on Cash Concerns, Doubt About Manufacturing Goals
http://www.bloomberg.com/news/articles/2016-05-05/tesla-falls-on-cash-concerns-doubt-about-manufacturing-goals
Tesla Motors Inc. fell Thursday after the company, aiming to dramatically boost production, withdrew its projection to generate more cash than it uses this year and said it will probably need to raise capital.
Shares in the electric-car maker fell 4.9 percent to $211.71. The shares had surged late Wednesday and early Thursday after Tesla moved ahead by two years its target date for reaching annual production of 500,000 vehicles before sinking on skepticism about the ambitious assembly goals and concerns about cash.
Tesla said in a letter to shareholders Wednesday that to meet the new production target, capital expenditures this year will probably be about $750 million more than the $1.5 billion originally planned. A capital raise of about $2 billion would dilute current owners by about 7 percent, UBS analyst Colin Langan wrote in a note.
“Ultimately, we see the new volume targets as too aggressive, setting up investors for disappointment,” he wrote.
Some investors may even view the move cynically as a “perfect rationale for a large equity capital raise which might have otherwise been needed or at any rate desired, due to ongoing free cash burn and liquidity comfort levels,” Ryan Brinkman of JPMorgan Chase & Co. wrote in a note.
Tesla plans to begin production of the Model 3, its more affordable electric car, in July 2017. Though Tesla has taken in roughly $400 million from customers pre-ordering the Model 3 at $1,000 each, cash is still king, and the company will need more of it.
“I don’t think we want to rely too much on customer reservation money as a source of capital,” said Chief Executive Officer Elon Musk on a conference call with analysts Wednesday. “Maybe there is a buffer or something, but it’s not as a primary source of capital. I think it’s going to make sense for us to raise some amount of money, some combination of equity and debt and make sure the company has a good buffer of cash on hand. I think it’s important for de-risking the company.”
Hi AlexS,
The speculation by me that they would be profitable in 2021 was an optimistic assessment. There is much that could go wrong.
If (a very big if) Tesla reaches 500,000 cars sold in 2020, they may be profitable by 2021. Note that in the conference call Musk guessed that they might get to 1 million cars sold in 2020 (500,000 more cars sold than I have guessed). Note that this is cars sold from Jan 1, 2020 to Dec 31, 2020, Tesla’s goal is 500,000 cars sold (S, X and 3 combined) in 2018. I doubt they will hit this number. Tesla expects to sell 85,000 cars this year, so the goal is very ambitious.
Lets say they double sales in 2017 to 170,000 vehicles and double again in 2018 to 340,000 vehicles, if they manage that they will be doing very well and they could hit the 500,000 number by 2019. I still like their chances better for hitting 500,000 in 2020.
It will be interesting to watch.
Next round of N.D. oil production figures ‘going to be bad,’ Helms says
WILLISTON – Early March oil production numbers show that North Dakota will likely drop below 1.1 million barrels per day for the first time since June 2014, the state’s top oil regulator said.
An official update will be released next week, but Director of Mineral Resources Lynn Helms told an oil industry group in Williston he expects to see a “severe” production drop.
“It’s going to be bad,” Helms told the Williston Basin chapter of the American Petroleum Institute Tuesday night.
North Dakota saw a smaller than expected drop in oil production in February as more companies put fracking crews to work to complete wells and maintain cash flow.
The state produced an average of 1,118,333 barrels of oil per day in February, a 0.4 percent drop from January, according to preliminary figures released in April.
But March figures, scheduled to be released May 12, are reflecting the more significant production drop Helms had been anticipating.
“I think that’s a significant milestone,” Helms told the oil industry group.
The declining North Dakota oil production – down from the record 1,227,483 barrels per day set in December 2014 – is prompting Helms to reevaluate an earlier projection he made that the state could one day produce 2 million barrels of oil per day.
“It’s kind of taken away hope of getting to 2 million barrels per day,” Helms said.
Low oil prices are forcing operators to focus drilling activity only in the core areas of the Bakken where wells have the greatest production. As oil prices recover and drilling expands to other areas of the Bakken, those high-producing wells will be declining, Helms said.
I had a look at some of the drilling history based on the ND statistics. Below represents the wild cats drilled and the success rate (dry wells’ ratio). They took a few years to get going but between 2006 and 2012 drilled successfully but then seemed to run out of options. The ratio of dry wells started to increase and the number of wild cats drilled was rapidly reduced and is this year zero.
I also looked by county. They drilled in 24 counties all together, but only five are really productive. Below show development and wild cat total drilling length (producing and dry wells). The development tends to follow the wild cat successes. Several of the counties came up dry on most wild cats and were never visited again. These are wild cat results:
These are development results (I didn’t include extension wells). These results down say to me that there is going to be a big production increase once prices rise.
George,
Interesting.
Could you please explain “that there is going to be a big production increase once prices rise” in more detail?
Maybe I misunderstood you. The dry wells (unproductive wells) are increasing to a level of about 50%. And the developments seems to have peaked.
Thanks.
“Down” should have been “don’t” (spell checker alert) – i.e. I think all the places that have seen good exploration results have been or are being exploited, and the likelihood of getting to 40,000 wells is low (note that net producing wells actually appear to be on a plateau or now declining 13212 in October 2015, 13010 in February 2016).
Hi George,
If we focus on the Bakken/Three Forks there has been an increase of 105 producing wells from October 2015 to Feb 2016. There have been very few wells completed lately (only about 70 in Feb 2016), this is due to low oil prices.
So far there is little evidence that the average productivity of new wells has decreased, though we may reach that point soon.
I looked at 9354 ND Bakken/Three Forks wells which started producing between Jan 2010 and Nov 2015 and considered their 3 month cumulative output. I sorted by month of first production and then randomly within the month and took the 123 well running average of the first 3 months cumulative output. I chose 123 months because this was the average number of wells completed from Jan 2015 to Nov 2015.
The average 3 month cumulative for all 9354 wells was 30,296 barrels of oil. At well number 8000 (starts from well 123) the date is Jan 2015.
The trend in new well productivity through Nov 2015 is up. Nov 2015 is the last month in the data set with 3 month cumulative (I used the Jan 2016 data set).
Dennis, I didn’t look at well productivity, which is what you seem to be discussing. My points were: 1) that there is no exploration drilling being conducted at present and that it declined quickly after 2012 when prices were high, implying that there aren’t any areas left worth looking at, 2) that 5 counties had high exploration success and these are the ones now responsible for almost all production (and actually all in decline) and that the development in each county quickly followed the exploration, suggesting core areas are key for overall production rates, 3) that other counties have been explored without success and are likely to be unproductive, 4) that ND general stats show 13012 wells producing in Feb 2016 and 13212 in Oct 2016 (this is net i.e. wells added minus wells shut in), and 5) that taken together these do not indicate that there is any potential for a large production increase in the near or far future. If you think productivity increase is going to compensate for overall depletion and lack of new exploration success then I think you are wrong.
Hi George,
They know where the oil is, there is not much need for exploration. I do not expect well productivity to continue to increase, the chart was intended to show that there has been no productivity decrease so far. I agree that at some point the sweet spots will be fully drilled and drilling will need to move to less productive areas.
When that point is reached we will see new well productivity decrease.
Older low output wells from the non-Bakken formations have been shut in at faster rates due to low prices, though some may be reactivated as oil prices rise. The NDIC seems to think there are another 30,000 potential well locations, perhaps they are mistaken, the USGS also thinks there are that many potential well sites and they could also be wrong.
I think we will have to see what happens when oil prices rise to $75/b or so, my expectation is that there will be at least 15,000 more wells completed in the Bakken/Three Forks in the next 10 years or so if oil prices rise to $75/b and remain at that level or higher.
I also agree there won’t be a large production increase (though we have not defined large).
I expect ND Bakken/Three Forks output will increase gradually to maybe 1.22 Mb/d (only 60 kb/d above the previous peak) by about 2022 and then will gradually decline. This is under a scenario where the completion rate increases to 155 new wells per month and then gradually declines along with output. Total ERR of about 8.4 Gb and 27k total Bakken/Three Forks wells completed. The scenario requires high oil prices ($155/b in 2015$) by 2020, lower oil prices will mean less output.
George,
Exploration drilling in shale plays is important only in early stages of development. The geology of the Bakken, Eagle Ford and the Permian is already very well known, and there is no need for additional exploration. The fact that activity is currently concentrated in the sweet spots does not mean lack of exploration success in the periphery. Resources are there, but they are too costly to produce at current oil prices.
They know where it is because they searched heavily up to 2012. They didn’t stop searching because of the price, or because they had so much acreage they didn’t need any more. They stopped because they were hitting dry holes and ran out of places to look. That definitely does mean lack of success at the periphery.
The picture is shale basins is completely different from conventional fields. Drilling
in established plays is almost risk-free, as
the share of dry holes in the past few years was ~ 1%.
Companies were drilling development wells in the periphery, and those wells are still producing. But they stopped drilling new wells outside of sweet spots as it is uneconomic at current prices.
If it’s risk free why even drill wild cats, and why have five counties had pretty much only dry wild cats drilled and nothing else. Development wells are drilled once the wild cats have delimited the play that is why they have high success. My comments are on wild cat wells. There is no such thing as risk free development as all the companies going bankrupt are funding out, and the only way to know for sure what is in any play is to drill.
Interesting, thanks Ron.
I have several times made a prediction what the oil production in ND would look like in March 2016:
1) 2015-11 here on POB : “I forecast that the whole of ND produces between 1.0 and 1.15 mb/d.”
2) 2016-01 on my site : “I estimate March production in ND to be very close (+-0.03 mbo/d) to 1.10 mbo/d.”
3) 2016-02 on my site : “I therefore expect oil production in ND to decline by another 60 kbo/d to about 1090 kbo/d (+-30kbo/d) in March.”
4) 2016-03 here on POB : “So ND (as a whole) will drop below 1.1 mbo/d in Feb or March.”
Based on these remarks from Helms, it looks like these 4 predictions may hit the mark. And they were not obvious to all (Helms predicted 1.2 mb/d by year end 2016, some time late last year)
In the Webinar from April Helms said he expects about 1 Mb/d by the end of the year and maybe 900 kb/d by mid 2017 before things start to gradually recover. I believe he expects oil prices to turn around by mid 2017 to the point that drilling may gradually pick up by that point.
The Weekly Petroleum Status Report showed US C+C production down 113,000 barrels per day for the week. Most of it was Alaska which was down 83,000 barrels per day but US lower 48 was down 30,000 barrels per day. That is a huge one week drop.
Ron. Thanks for the updates!
Did you see products supplied is back up over 20 million barrels per day? That is pre financial crisis levels.
I do not think the US has been there on an annual basis since 2003-2007, could be an outside chance US hits that average in 2016 if summer and fall are strong.
I do wonder if this is a part of the OPEC strategy that has been little discussed. I assume if US demand has taken off, places like India and China are likewise on a big increase. Maybe 1.2 million bopd demand increase will be revised upward?
The initial estimate for 2016 was 1.4 Mb/d. It might be closer to reality.
Alaska drop was big but is there a sesonal change as well in their production? Couldn’t find a detailed chart. Had a quick look at EIA statistics and saw some lower seasonal numbers during June–August. Maybe someone can confirm this and if this drop is larger then usual. I know weekly EIA number are unrelible but a 83.000/day drop this week is like a 20% drop from the week before. Alaska was on a slope before but is this the edge of the cliff?
Thanks.
ANCHORAGE, Alaska — BP has announced it will reduce the active rig count at Prudhoe Bay on Alaska’s North Slope, a move expected to cut oil production and more than 200 jobs.
.
http://fuelfix.com/blog/2016/03/09/bp-to-decrease-number-of-rigs-working-at-prudhoe-bay/
They will cut rigs from five to two. I had no idea there were any rigs still drilling in Prudhoe Bay.
Yes, there is maintenance every summer. They pig the pipeline. I don’t know how long that takes but I am sure it is several days. And of course there is other summer maintenance also. But I have never seen it this early but it is likely there is some maintenance reason for it.
They actually now pig the pipeline (with cleaner pigs) weekly, to keep the wax low enough for the smart pigs, increasing the frequency when they’re just about to send a smart pig South. Even so, the wax is now so severe (due to low flow and cooler oil) that ultrasonic pigs no longer work well enough, they have to use magnetic flux leakage pigs.
A great read about pigging the Trans Alaska Pipeline is chapter 9 of the book “Rust” by Jonathan Waldman.
http://www.goodreads.com/book/show/22609454-rust
He follows a smart pig, which takes 26 days to make the journey (though it took 8 days off at pump station 4 for cleaning, data download, battery change and some sensor replacement).
He covers pigging in general and the start of smart pigs in TAPS, starting with old style caliper pigs and low resolution ultrasonic pigs that couldn’t find anything, even though when sections of the pipe were cut out to fix leaks the crews found corrosion inside.
Then came a high-resolution ultrasonic pig from NKK in 1989.
“… NKK had five engineers on its crew, and they brought gifts for Alyeska employees. They lived at Pump 1 for a month, and did calisthenics in the manifold building. They wore matching green helmets and uniforms, bloused where they entered their boots, and communicated by hand signals. Before loading their pig, they rolled up a Shinto prayer, put it in the tool, then got on their hands and knees and prayed to it. The Alyeska guys should have prayed too.
NKK’s pig also found hundreds of anomalies. …”
Capex cuts (billions):
Deepwater ……………….. $87.65
LNG …………………………$63.10
Onshore …………………….$44.61
Oil sands……………………$28.50
Shallow water…………….$23.30
Offshore gas……………….$13.90
Heavy oil ………………….. $7.97
Source: Rystad Energy
Note: Data through March 2016
What with EV’s getting their fuel in other ways than ICE’s, how does, or might, this ‘fuel transference’ affect who pays, and where, how and when?
The attached image is a little tongue-in-cheek, but by how much? (Pardon its size. Otherwise-small images apparently get expanded to fill the area to the margins.)
In other news…
Coral reefs are straight-up dissolving now
That’s the buffering effect. But 6 million tons of calcium carbonate isn’t that much. I bet it amounts to increasing the reef porosity by a tiny fraction of 1%.
I have another update on the oil production from the 4 major shale basins in the US,
here.
Not bad. I left you a comment.
Higher oil prices will likely accelerate completion of the DUCs, but that will not stop the decline in U.S. oil production this year.
excerpts from an article in Reuters:
DUCs in a row: Oilfield servicers to gain as more wells completed
Wed May 4, 2016
http://www.reuters.com/article/us-oilfieldservices-spending-idUSKCN0XV2DT
U.S. shale producers are returning to unfinished business – completing previously drilled wells – offering a ray of hope for oilfield service providers battered by the oil slump.
Halliburton Co and Baker Hughes Inc, the world’s second and third-largest oilfield services companies, indicated on Tuesday that they expected a drop in the large number of drilled-but-uncompleted wells (DUCs) as crude oil prices steady.
Oil is hovering above the $40/barrel mark after having rallied 20 percent in the past month.
This has been enough for several producers to return to the thousands of unfinished wells that dot shale fields across the United States – essentially to ready them for production.
Devon Energy Corp, Diamondback Energy Inc and SM Energy Co all said on post-earnings calls on Wednesday that they were completing more wells.
There were 1,732 “abnormal” DUC wells in March – those that hadn’t been completed within three months of drilling – in the top five U.S. shale fields, including Eagle Ford in Texas and Bakken in North Dakota, according to Alex Beeker, an analyst at energy consultant Wood Mackenzie.
That number is expected to consistently fall through the year.
Next month, for example, Beeker expects the number of such wells to drop by about 400.
“We don’t see that volume (of DUCs) continuing to build; and in fact, it’s being worked off in the stream of work that’s out there today,” Halliburton President Jeff Miller said on Tuesday.
Baker Hughes said it expected oil producers to complete several hundred wells every month as oil prices climb back into the mid-$50s.
………………………….
To be sure, the fledgling recovery in spending won’t mean the end of troubles for these [oil services – AlexS] companies.
“Even if DUCs come online, U.S. production will continue to fall, and until output stops declining, it’s going to be a challenging market for oilfield service companies,” said Rob Thummel, a portfolio manager at Tortoise Capital Advisors LLC.
“The number of new wells drilled in the United States has halved from 40,000, and the addition of a thousand or two thousand wells will not do much to arrest steep declines in shale production.”
Thanks Alex,
The title of the article is misleading: “as more wells completed” => no, there will be less wells completed compared with 2015, only more than are being drilled.
I just made an update on shale production in the US. What I found interesting to see is that the legacy decline of wells > 1 year was about 50%, each year in the past few years (wells in the non-Bakken basins decline much faster). For example, wells starting production before 2015, dropped in total output from around 3.2 in Dec 2014, to 1.6 mbo/d by Dec 2015.
We could make a simple approximation of how much the decline will be in 2016:
– Production from wells starting in year 1, typically decline somewhere around 59% the next year.
– Older wells decline in total about 45%.
Based on this I estimate that the wells in my dataset will do about ( 1400 * 41% + 1617 * 55% = ) 1463 kbo/d by Dec 2016. Add a little extra due to revisions, improved initial production, and maybe a somewhat slower drop in older production, and I would say that 1600-1800 is a close call, or a drop of about 1.4 mbo/d (not counting the output of any new completions in 2016).
Last year, by December, total output from wells starting in 2015 was about that size (1.4 mbo/d). But the rate of completions is probably half (very roughly) the size this year, so the drop till 2016 Dec could be in the order of 700 kbo/d, just from the areas I’m looking at.
This is not a prediction, just a rough guess at what might be in store.
Enno: Also interesting is if we go back to wells starting production before 2014, which shows as of 12/15 those are contributing slightly less than 800K bopd.
I assume the records for wells starting production before 2014 are complete, or at least very close, even for TX.
This has been my focus with regard to the most favored area, TX Permian Spraberry Wolfcamp. Horizontal wells 2 or more years old contribute a small percentage. It is true that many more wells have been completed there in 0-2 year range, but looking at individual well data for the 2+ year old wells reveals much.
Will the improved completion practices cause the wells to decline less steeply?
Shallow,
“Will the improved completion practices cause the wells to decline less steeply?”
More data is needed to answer this, so let’s see in the coming months. In the past improvements have mostly lead to higher initial gains, so it would be quite a big achievement if it’s more than that.
Has anybody tried to drill fish bones instead of fractured horizontals in the Spraberry?
You won’t be able to know.
Choke variable.
Hi Watcher,
The choke can only reduce flow, if we assume these wells are run as fast as they can go, the choke is no longer part of the equation.
Since Jan 2015 the wells have been run wide open. Prior to that maybe the choke is a bit of an issue, but more flow now means more money now and there is a tendency to run these wells close to their maximum rate.
So no chokes are not really a big issue.
Suppose we don’t assume that. Then once more that text is worthless.
Dennis,
The choke does not run full open, or otherwise it would not be a “choke”.
The idea behind choking back flow, is to maintain reservoir pressure above “bubble point”. Bubble point is where the gas is allowed to liberate itself for the oil. Matt Simmons described it very well in his Twilight book, as a bottle of coke, and when the bottle is opened, the gas is allowed to escape the liquid.
If the choke it opened too far, to obtain increased oil flow and allowing drop in reservoir pressure below bubble point, we will see an initial increase in oil flow, along with an increasing Gas Oil Ratio, GOR. Once sufficient gas has be liberated from the oil, and the oil has lost it natural drive, oil production will fall, until we you have a pure gas well.
Choking back the well, will have lower initial flows, but ensure the greatest URR. A company desperate for cash flow, has the temptation to open the choke a little too far for their own long term health.
The only time the choke gets fully opened is in a drill stem test, DST. When drilling exploration wells. During these initial tests, which are mainly to test the permeability of the formation, a series of flows are conducted.
1/A clean up flow, to rid the formation any drilling mud and completion fluids. The well is them shut to normalize pressures, usually 1 1/2 time the time of the flow.
2/ Several flow tests are performed on various sized chokes, ranging from 8 to 24 hours, interspersed by resting shut ins of 1 1/2 times the flow time. Down hole pressures are recorded, and recovery times are plotted and timed. These flows are where most of the important information is recorded.
3/When all the serious work has been done. A final is made. The final flow, is where the headline number which gets announced to the stock markets is recorded. The choke is opened for maximum flow, which is usually 2″ fully open. This flow rate doesn’t usually mean much to the Petroleum Engineers, as there is no guarantee that this rate can be maintained for any time, but great for the stock price.
And while we are on this point of chokes, most of these LTO wells only stay on natural flow for 6 months or so, then a pump is installed. Either a beam pump, or an ESP, Electrical Submerged Pump. The ESP is easily controlled adjusting the amps to control the flow. Once again, if the operator gets too greedy, and reservoir pressure drops, and we end up with a gas well and with the oil left behind. Beam pumps will just be run faster by changing the gearing or run more often for the same result.
So “opening the choke” on an older well, in fact is, speeding up the pump, for all intensive purposes, it means the same thing, or at least has the same result.
Thanks for the clear lesson Toolpush.
Hi Toolpush.
By wide open, I simply mean with the largest choke that makes sense. For any company that does a discounted net cash flow analysis, they will choose the choke that maximizes the discounted net cash flow from operating the well at the discount rate that makes sense for that firm.
Based on the 36 month payout rule used by Mike, the discount rate for an average Bakken well would need to be over 20%. Shallow sand uses a more aggressive 60 month payout rule which for an average Bakken well would correspond with a 15% discount rate.
So the basic idea is that different firms would use different discount rates and it will affect the choke size they use for their wells, if they bother to do a discounted cash flow analysis (many don’t bother with this in smaller companies).
Let’s assume that there are 2000 DUC wells 3 million each to complete. That’s 6 billion dollars. And where companies get those money from ?
Actually the completion cost is about 66% of the total cost, so more like $5 million to complete each DUC, money is probably loans from banks and private equity.
Just in the last 24 hours.
Canada: Taken together this amounts to some 0.5 million [barrels a day] of capacity that is currently offline. Infrastructure is being affected too, with the 560,000 b/d Corridor pipeline shut down and movement along the 140,000 b/d Polaris pipeline significantly curtailed.
Lybia: An official at the port told the news agency that tanks at Hariga were 7-10 days away from hitting their full capacity. This means, Reuters reported, that with no tankers loading oil at the port, Libya will be forced to shut in about 120,000 bpd of output, which is the export capacity of the port.
Iraq: Production at an oilfield near Kirkuk, in northern Iraq, has been stopped after unidentified gunmen set at least two wells on fire on Tuesday night.
US: An official update will be released next week, but Director of Mineral Resources Lynn Helms told an oil industry group in Williston he expects to see a “severe” production drop.
And all of that is worth a $1.17 of increase on WTI/Brent in the last 24h!!! Really? 🙂
Militants attack Chevron platform in Niger Delta: navy spokesman
Thu May 5, 2016
http://www.reuters.com/article/us-nigeria-oil-delta-idUSKCN0XW1PL
——————————————-
Venezuela 2016 oil output seen down at 2.35 million bpd: consultancy
Tue May 3, 2016
http://www.reuters.com/article/us-venezuela-oil-output-idUSKCN0XU22R
Venezuela’s oil output may fall to average some 2.35 million barrels-per-day this year, as the South American OPEC country’s cash crunch and shortages weigh on production, according to energy consulting firm IPD Latin America.
IPD’s prediction comes on the heels of its quarterly sector survey, which estimated Venezuela’s oil output tumbled 6.8 percent to 2.59 million bpd in the first quarter compared with the same period of 2015, due to drilling delays, insufficient maintenance, theft, and diluent shortfalls.
That estimate is a whisker above the 2.53 million bpd Venezuela produced in the first quarter, according to OPEC numbers. But it marks the first time since the third quarter of 2008 that production fell in all districts, including the extra-heavy crude Orinoco Belt, IPD added.
I had information it was down to 2.2 mmbopd. The problem everybody has is accounting for the imported oil diluents. The OPEC figure is 2.32 mmbopd.
The reason I go over the Guri hydropower status is the link between electricity supply and ability to keep operating. If Guri has a partial shutdown the grid will go unstable.
Nigerian Oil Output Plunges to 20-Year Low as Attacks Mount
http://www.bloomberg.com/news/articles/2016-05-06/nigerian-oil-output-plunges-to-20-year-low-as-attacks-escalate
• Strike on Chevron platform cuts output by about 90,000 b/d
• Crude output fell in April to lowest in more than two decades
Nigeria is suffering a worsening bout of oil disruption that has pushed production to the lowest in 20 years, as attacks against facilities in the energy-rich but impoverished nation increase in number and audacity.
Chevron Corp. shut down about 90,000 barrels a day of output following an attack on a joint-venture offshore platform that serves as a gathering point for production from several fields. Even before that strike on Wednesday night, Nigerian oil production had fallen below 1.7 million barrels a day for the first time since 1994, according to data compiled by Bloomberg.
and Alberta oil sands outage are now in range of 650k bpd and up 150k from yesterdays numbers.
The price is agreed between producer and refiner. If the producer wants less than the refiner bids . . . .
The goal is victory, not paper wealth.
But the thing that most overlook is that struggle between paper and physical assets are foremost and primarily within US. Producer in Kazakhstan does not wake up every morning looking at price in Cushing. That is why every analysis that you have read in paper and on TV does not make any sense.
Well, it doesn’t make sense, but there could be other reasons.
Or none. Maybe some reporter knows editors can’t understand the details so he makes no effort to present coherency.
The reason why it does not make sense when we read articles is twofold: msm are primarily in business of making simplistic narratives (bad/good, black/white) and because “nobody knows anything” including us.
Many things influence why something is happening around us. In the case of oil there is lot’s geology, lots of how debt based economic system functions, lot’s of geopolitics, lot’s of struggle between paper and physical assets among the elites, lot’s of irrational human behaviour, and lot’s of natural law how world and nature evolves day by day.
Haliburton following Schlumberger in pulling out of Venezuela:
http://www.worldoil.com/news/2016/5/6/halliburton-joins-schlumberger-in-cutting-venezuelan-activity
Extra heavy oil needs a lot of wells, so this should show up in production numbers fairly quickly.
500,000 Barrels And $1 Billion In Losses The True Cost Of Canada’s Wildfire OilPrice.com
Is This The Biggest Red Herring In Oil Markets OilPrice.com by Arthur E. Berman
I ASSUME these figures are accurate. It’s hard to say just how all that driving breaks out between new and older vehicles, larger new vehicles etc.
Sometimes things are not as they intuitively seem. We are told that new cars are driven more than older ones, and I am confident this is true as a general rule.
But with the economy picking up somewhat, a lot of folks may be driving older less fuel efficient cars to work, maybe a long way to work, and plumbers and roofers may be using their work trucks more than usual, etc.
But it seems very likely to me that three percent more driving on only two percent more gasoline indicates that the average fleet fuel economy is picking up quite rapidly since in fact most cars ARE older cars. Even forty or fifty million new cars put on the road over the last few years is still only less than a quarter of the fleet.
I haven’t yet run across a site that lists the number of cars and light trucks registered by model year.
But it’s OBVIOUS that ten million late eighties early nineties cars and trucks replaced by twenty fifteen or sixteen models means a lot less gasoline burned per mile per vehicle.
If any body knows of such a site, I would really appreciate a link. Researching a book, and it’s slow going. Thanks anybody and every body. All the regulars here will get be listed as treasured mentors in the foreword, if it is ever finished.
And if I wind up giving it away, which seems likely, I will give an autographed cd copy to any regular who wants one , free of charge, not even postage, lol.
When lightning strikes way up North and starts a fahr, there ain’t nobody there to fight the good fight. It is gonna burn to beat hell.
I’ve been burning gas and oil for a few days. Gotta get that stuff done, you know, hey. You go incommunicado because you’re out there burning up that precious fuel to make it all go like it’s supposed to go and it’s gonna go.
If you don’t yure a gonna starve.
Of course, it is a lot of work, but oil and gas can get ‘er done. Without that oil and gas, it will be a tough row to hoe.
All-in-all, Texas does the same and the numbers are the proof, all in the pudding. Texas refuses to give up, throw in the towel, no way.
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/production-data/historical-production-data/crude-oil-production-and-well-counts-since-1935/
It takes a lot of beer!
there ain’t nobody there to fight the good fight
Judging from price action today there are efforts to kill oil rally. I think if banks profits from oil trading can drop like a stone, we collectively will be better off. They desperately try to preserve the unnatural and ultimately destructive level of rent extraction from the oil industry they’ve managed to create.
Looks like the whole Wall Street is now in “apres moi, le deluge”(after me deluge, https://en.wikipedia.org/wiki/Apr%C3%A8s_nous_le_d%C3%A9luge) mode.
All these disruptions and oil is still trading down. Don’t make no sense.
Greenbub. I can only give a sarcastic response.
First: Tesla is going to sell so many electric cars so soon, based on their CC from yesterday.
Second: Continental Resources announced a wonderful quarter, and apparently $30 oil and $1.75 natural gas is no big deal.
I need to stop reading conference call transcripts. Never have I seen so much happy talk from two companies who are in debt up to their eyeballs and posting losses quarter after quarter.
Oh, I forgot, both are changing the world.
Even with the dollar down, oil is still down. What gives?
Don’t be so silly. Oil price below the cost of production is an anomaly and normalization is inevitable despite all efforts by Wall Street, the US government and EU to slow down this process to preserve neoliberal globalization, which is threatened by high oil prices.
They might have a year to run of fumes, but I doubt that more then that. And as a result of their valiant efforts the normalization might happen at the level above $80/bbl. Then what?
It is very easy to destroy an industry. And neoliberals proved to be pretty adept in this task while fattening their valets. In this case the USA oil industry. Generally destruction is a much easier task that building/rebuilding something. Nothing new here, move on.
“After me deluge” mentality might eventually lead to some neoliberals hanging from the lamp posts. they consider themselves to be an aristocracy, so that will be pretty fitting.
“Let them eat cakes” did not work too well in the past. Same with oil shortages. “History Does Not Repeat Itself, But It Rhymes” — Mark Twain.
Hi Shallow Sand,
Amazon lost money for years and they aren’t even in a capital intensive industry.
Continental is nothing new, but if lithium ion battery costs fall to under $150 per kWhr (pack level cost) EVs become competitive with ICEV even at $2/gallon gasoline (2015$) and Tesla might be a big deal when they reach 500,000 Model 3 vehicles per year (maybe in 2019, but more likely 2020).
I imagine gasoline will be at $3/gallon in 2019, though if EVs take off oil prices may never reach $100/b due to lack of demand.
Interesting times.
Dennis,
EV will never became competitive with ICEV at $2/gallon. First of all Tesla might be bankrupt sooner then 2019. Mask’s aura might some point disappear, but debts remain. Remember that Tesla S is $70K car and as such this is no go for mass market. So this guy might build the factory but people will not buy his cars. Adventurism can’t always be compensated by slick marketing. Then what?
If oil price rise substantially, lithium battery costs might also rise because mining costs will rise. And reserves of improving technology and cutting price are not that great, far less then your super bold (and pretty unrealistic) 15% a year estimate (45% in three years).
Also at below $4/gallon gasoline the incentives to buy EV other then status symbol are minimal. You need oil at or above $5/gallon for any substantial volume of sales increase.
Hi Likbez,
The model 3 will be $35,000 with no incentive. Range will be 215 miles.
Go test drive a Tesla. You’ll figure out why people want to buy EVs. They are simply superior as an experience over worthless, rattletrap gasmobiles like Rolls Royces. And I’m dead serious.
Some of you oil guys have spent too much time in a commodity market: one barrel of black sludge is much like another. But driving an electric car is a *nicer experience* than driving a gasoline car.
I am 100% convinced that gasmobiles will quickly be relegated to inferior goods, which are only bought if the buyer can’t afford an electric car. The question regarding Tesla is simply one of whether they will mass produce these electric cars succesfully, or whether some other competitor will do so. The effect for the *oil industry* is the same regardless of whether Tesla goes bust.
Hi Shallow Sand,
Massive debt is now like the sword of Damocles hanging over the whole shale industry. And that created qualitatively new situation with reaction of the industry on rising oil prices delayed and more muted then at times of “carpet drilling”. Even money to complete DUCs are now a scarce commodity. Everything goes to debt repayment. In addition many companies will be forced to sell assets like Chesapeake:
http://oilprice.com/Energy/Natural-Gas/Beleaguered-Chesapeake-to-Sell-Off-More-Assets-to-Reduce-9B-Debt.html
Here are thoughts from
http://oilprice.com/Energy/Oil-Prices/Why-Oil-Prices-Will-Rise-And-Many-Pundits-Will-Be-Caught-By-Surprise.html
that pretty well resonate with your line of thinking about the problem.
This seems a tad optimistic even for a true believer cornucopian.
http://www.cnbc.com/2016/05/06/could-oil-really-fall-to-less-than-10-per-barrel.html
Here’s a question for any of you hands on guys, or numbers crunchers.
The SO CALLED ” price of oil” is quoted at various trading hubs, right?
Is there any oil company in the USA that can deliver oil after paying mandatory taxes, etc, and shipping costs that can DELIVER oil to Cushing without spending at least twenty bucks a barrel in direct or variable costs? This would include taxes, wages, waste water disposal, parts, equipment leases, other maintenance expenses, etc.
I believe the hands on guys refer to these costs as “lifting costs” most of the time, and to lifting costs we must also add the shipping costs.
I read some years ago that most people in the industry believe even the Saudis have to spend twenty bucks at least PER BARREL to cover ALL their costs. That was probably ten years ago. Their lifting costs would be only a minor fraction of that, but their shipping costs are obviously significant. They have to get the oil to the coast to load it, and pay to transport it, and then pay to unload it, before THEY get paid for it.
A quick glance at the vlcc shipping industry seems to indicate it costs at least a dollar a barrel to move crude on a super tanker, under ” normal ” market conditions.
Hi Old Farmer Mac,
Pipeline shipping is pretty cheap once the pipes are built. Often people look at wellhead costs and these are quite low in Saudi Arabia compared to most other places, shipping costs may be high.
You can get an idea about these by looking at price differentials for different types of crude, maybe in the OPEC oil market monthly report.
http://www.opec.org/opec_web/en/publications/338.htm
Looks like about a 3 to 4 dollar per barrel differential between Brent and the OPEC reference basket.
So how much does a producer typically pay to move a barrel from the field to a refinery via pipeline? My guess is that the pipeline owners manage to charge anywhere from maybe a dollar to maybe as much as five dollars or more a barrel, depending on the distance, etc.
I remember this fact (?) from the early 1970’s with the oil embargo. [No internet back then, so no way to verify at the time.] But, it was said that the Saudi oil fields were “uphill” from the loading facilities on the coast, such that their pipelines were “gravity” fed – no pumping needed [thus, virtually no transportation costs].
Maybe some other old fart, like Ron, can confirm (or deny) such reports.
BHI rig count:
Oil 328 -4
Gas 86 -1
Directional 44 -2
Horizontal 318 -6
Vertical 53 +3
oil rig count by basin:
Hi Alex,
Do you think this is a bottom point or decline will continue for the rest of the year ?
likbez,
As I was saying earlier, in my view, the US oil rig count will bottom by mid-2016, but the rebound will be relatively slow. Companies will focus on completing the DUCs.
This comment is off topic. But it does pass on some very useful information.
When on any internet blog, many times it is tempting to start using foul language with respect to some posters. However, this is not necessary. There is a word that can be a good description to use for such a person, in most cases, without resorting to cursing. You do not see it very much, so I am going to share it with everyone, even though many may already be familiar with the term. Just refer to the person as an “ignoranus.” Nobody seems to use that term anymore. It is a very useful word.
Just a second – now everyone thinks that I cannot spell? Well, I can! Ignoranus refers to a person who is both stupid and an asshole.
Some of us need a laugh before we head home for the weekend. At the risk of making a self-assessment, luckily not very many on this site.
Can also be divided into IGNO:
Definition Urban Dictionary: igno
http://www.urbandictionary.com/define.php?term=igno
Urban Dictionary
Ignorant, in the Irish sense/usage: disgusting, horrible, mean, ugly, unwanted, repulsive.
And RANUS:
Certain species of frogs such as Ranus sylvatica or Ranus palustris
https://www.wpclipart.com/animals/F/frogs/frog_4/Wood_frog__Ranus_sylvatica_young.jpg.html
Igno ranus could therefore be a disgusting, mean, ugly, repulsive frog, or a prince for that matter…
All you have to do is kiss it to find out 🙂
Yair . . .
Nope CLUELESS you got it wrong . . . that word is spelt with an “m” i.e. “you fucking ignoramus”.
Cheers
Ignoranus was the winner of the “adulterated words” contest.
One of the other entries was “Sarchasm” – The gulf between the author of sarcastic wit, and the person who doesn’t get it.
“Sarchasm”
LOL! on this site it can be quite a bit deeper than your typical well and much much wider than your average church door!
With my sincerest apologies to the Bard.
The Baker Hughes Rig Count.
Wildfire could cut oilsands production in half
It will take a long time to replace the housing and other infrastructure lost to the fire- infrastructure that indirectly supports the local oil industry.
Local production recovery may take at least a year, even if the key people move into campers so they can get back to work.
Never been that far north, but winter in a camper in Alberta is probably not much fun.
To the extent that they have decent business interruption insurance, I would expect them to be very deliberate in getting back to full production. No need to rush it at these prices.
“Increasingly efficient extraction techniques, improvements in clean energy production and battery storage will push crude prices to near-zero ”
http://www.cnbc.com/2016/05/06/could-oil-really-fall-to-less-than-10-per-barrel.html
Wow, Cnbc is really showing their hand here.
Someone should ask the CEO of Ford why they even make gasoline powered cars anymore, EVs are about to take over. Any day now.
From SF Gate
“On Friday and Saturday, Ultra Petroleum and Midstates Petroleum respectively filed for bankruptcy protection. And according to Fitch Ratings, they pushed the energy high-yield default rate to 13%, topping the previous record of 9.7% set in 1999.”
The default rate will probably go a lot higher yet.
It appears that a lot of deals are being made to convert debt into equity.
That’s probably a good strategy based on betting oil prices will be going up.
International Oil Companies: The Death of the Old Business Model
Professor Paul Stevens, Distinguished Fellow, Energy, Environment and Resources
Chatham House, May 5 2016
I think things are just going to get worse and worse for that old business model they are simply going to be unable to compete with renewables…
Steven Chu: Mexico’s Energy Auction Reveals True Price Of U.S. Renewables
http://www.forbes.com/sites/jeffmcmahon/2016/05/08/steven-chu-mexicos-energy-auction-reveals-true-price-of-u-s-renewables/#1524892275d2