North Dakota has released December production data for the Bakken and for all North Dakota. They were a little shocking.
Bakken production down 86,150 barrels per day 895,330 bpd. North Dakota production down 92,029 bpd to 942,455 bpd. It was noted that this the largest decline ever in North Dakota production. But it should not be overlooked that the October in crease in production was also the largest ever increase in North Dakota production.
From the Director’s Cut
Oil Production
November 31,034,520 barrels = 1,034,484 barrels/day
December 29,216,093 barrels = 942,455 barrels/day (preliminary)
(all-time high was Dec 2014 at 1,227,483 barrels/day
Gas Production
November 52,785,707 MCF = 1,759,524 MCF/day
December 47,679,872 MCF = 1,538,060 MCF/day (preliminary)
(all-time high was Nov 2016 at 1,759,524 MCF/day)
Producing Wells
November 13,520
December 13,337 (preliminary)
(all-time high was Nov 2016 at 13,520)
11,449 wells or 86% are now unconventional Bakken – Three forks wells
1,888 wells or 14% produce from legacy conventional pools
Permitting
November 76 drilling and 2 seismic
December 35 drilling and 0 seismic
January 81 drilling and 1 seismic (all time high was 370 in 10/2012)
ND Sweet Crude Price
November $34.58/barrel
December $39.93/barrel
January $40.75/barrel
Today $42.50/barrel (all-time high was $136.29 7/3/2008)
Rig Count
November 37
December 40
January 38
Today’s rig count is 38 (all-time high was 218 on 5/29/2012)
Comments:
The drilling rig count increased three from November to December, then decreased two from December to January, and is currently unchanged from January to today. Operators are shifting from running the minimum number of rigs to incremental increases throughout 2017, as long as oil prices remain between $50/barrel and $60/barrel WTI.
The number of well completions decreased slightly from 84(final) in November to 81(preliminary) in December.
Oil price weakness is anticipated to last into the second quarter of 2017.
There were three significant precipitation events, fifteen days with wind speeds in excess of 35 mph (too high for completion work), and nine days with temperatures below -10F. January 2017 will be more of the same.
Over 98% of drilling now targets the Bakken and Three Forks formations.Estimated wells waiting on completion2 is 807, down 32 from the end of November to the end of December. Estimated inactive well count3 is 1,573, up 54 from the end of November to the end of December.
Crude oil take away capacity remains dependent on rail deliveries to coastal refineries to remain adequate.
Low oil price associated with lifting of sanctions on Iran, a weak world economy, and capital movement to the Permian basin continued to depress drilling rig count.
Barrels per day per well continues to drop. In December it stood an 83 in the Bakken and 72 for all North Dakota.
This great chart was produced by Enno Peters. It warrants a closer look. The data is in barrels per day.
The two horizontal lines represent the 2015 peak and the 2015 peak production at the end of 2016.. And the difference is almost exactly one half million barrels per day.
But more important is the points I have placed in the ovals. Notice that production from 2016 wells in December changed very little from November 2016 wells. The decline was almost entirely from legacy production. That is from wells drilled prior to 2016.
If you look at Enno’s first chart you will notice that the decline was shared by a decline in production from every year prior to 2016.
According to the Director’s Cut, producing wells dropped by 183, from 13,520 to 13,337. 81 new wells were brought on line so that means 264 wells had to be shut down. the numbers from the North Dakota web site were different. They had the well count going from 13,201 to 13,013, a decline of 188. At any rate between 260 and 270 wells had to be shut down if either number is correct and 81 new wells were brought on line.
So we could conclude that the huge drop in legacy production was due to all those wells being shut down. But why were they shut down? Your first thought would be that they were shut down because of low production. But if that were the case, that they were mostly low producers, then the barrels per day per well should have risen. It did not. Barrels per day per well dropped by 6, from 78 bpd to 72 bpd.
Bruno Verwimp sends us the above chart. The accuracy of his prediction is uncanny.
And here is an amplification of his model with the actual data.
The EIA has a far more optimistic take on Bakken production. That is their reference case.
Here is their High Oil case and Low Oil case. The green is tight oil.
It is my opinion that the EIA is wildly over optimistic. More so concerning the Bakken but with other plays as well. Tight oil will be a complete bust. The Permian is performing well because it is mostly conventional production. But even the Permian will begin to decline by 2020 or shortly thereafter. All other shale plays are already in decline. But the idea that the Bakken will still be producing two million barrels per day in 2040 is ludicrous beyond belief.
Thanks for staying on top of this Ron. I wonder if the Bakken is really starting to head off a cliff now. They need to be drilling as fast as possible to steady production if that is the case. It will be interesting to see how much oil is being produced in the Bakken at the end of 2017. I’m thinking Bakken production may be under 750k per day for December 2017. What do you think?
I think that would be a little low. I would put December 2017 production closer to 800k for the Bakken, a bit more for North Dakota.
But right now everything is just a wild ass guess.
Well if my prediction is wrong I will say it was a wild ass guess. If it is spot on, I shall call it ‘sheer brillance’. 😉
This is some items about Bakken and more information about crude stocks trend:
http://en.angi.ru/news/604-CRUDE%20STOCKS%20TROUBLE%3A%20SOME%20ARE%20GROWING%2C%20OTHER%20COME%20SHORT/
EIA wildly optimistic in Bakken, Gulf and Texas. Their current numbers have to be way high in relation to what is actually happening. Even Texas RRC site is not predicting an upturn until current permits and completions get a lot higher. At $53 oil, it is not happening, or going to happen.
This is the official North Dakota stance.
North American Shale Magazine – Bakken has large production dip, but major frack activity starts: “But, starting in May, the Bakken will once again be bustling with truck activity. According to Helms, operators are enthusiastic about the current oil price and have already committed and planned to frack as many wells as possible this year. The expectation, Helms said, is that industry will complete roughly 700 wells in fiscal year 2017 and 1,000 wells in fiscal 18. ‘There is going to be a lot of truck traffic in May,’ he said. ‘Companies are going to add as many frack crews as they can this summer,’ he added.”
BoomerII,
700 to 1000 wells per year are not many wells per year. In its haydays Bakken had over 2000 wells per year. Given the current shutdowns of wells (264 wells in December alone), there might be not many net wells added in 2017 and 2018.
Most of those wells will come back on line when the weather warms up (probably already are now in fact), or there may been some some shut in for completion actions in the same section, they might take longer if the weather delays things. But 1000 isn’t much above last year: by my counts there were 550 net permits (new minus cancelled), 625 spuds and 723 completions in 2016. But if the completions do lead to bigger initial flows and higher recoveries, as some of the major players are promising, there would be a proportionally larger impact on production. Combine that with a higher proportion of legacy wells and the decline rate should at least ameliorate, even if production doesn’t increase. They could likely meet the target by clearing DUCs and without adding too many rigs – I think they need about 3 to 6 months inventory of DUCs to allow the rigs and completions crews to wok independently, so say 400.
“Most of those wells will come back on line when the weather warms up (probably already are now in fact)”
George,
Wells are not shut down in Canada (very similar weather to ND) due to cold weather ever. There are technical reasons, spills, flowline need to be replaced, cost of replacement too high so you shut down well, overproduction at the well and not enough tank trucks …etc but these are odd reason. Cold weather is not issue at all.
But seasonal impacts are big in ND – that’s why Verwimp’s sine wave imposed on the logistic comes out so well. The director’s cut pretty much states that weather was an impact, and one of the shale blogs specifically stated that some gas lines had frozen. I am not saying the shutdown was planned, and they would certainly have preferred not to do so, but they have very new infrastructure, it takes a bit of time to get it working, especially with stretched budgets as all the operators have had.
” But seasonal impacts are big in ND ”
Seasonal impacts are exactly the same as in Alberta, Saskatchewan in Canada where all conventional wells are located. I am telling you George nothing shuts down in terms of production in winter. Drilling is seasonal but has always been the case. But we are talking here about wells shut down. George, these shale wells in ND don’t have long term “mojo” and the most reasonable explanation would be what Heinrich says that this is simply the cost issue if a well goes from 100 barrels to 20 barrels per day.
I guess we’ll find out in a couple of months when the February figures come out.
George, I’m sure, DUC wells aren’t the best. All the best DUC wells were put into operations last summer. That’s why we watch no changes of DUC wells number from August 2016.
AK – The number has been coming down slowly, but although it is fairly constant the wells that make up the DUCs are constantly cycled through. DUCs cannot be left for more than two years (I think it is now – it used to be one but the rule was relaxed after the price crash). After that they have to be abandoned (temporary or permanent -either way they aren’t DUCs anymore) or have to get a non-completions waiver. Most of the DUCs are 6 to 12 months old. The rigs and completions crews work independently so a company probably contracts the completions once a pad has been fully drilled and they now what they are getting. Below is from last September but the shape doesn’t change much, although the wells split by company do.
I should have added – the date is when the well, now listed as NC or NCW (i.e. non complete or with a waiver), was originally spudded.
Looking at that chart might explain why CLR suddenly have to start doing a lot of completions as their block of oldest wells are getting to the two year mark.
George, thank you, it’s right. During two years any well should been completed. My point is that nobody leaves a good well for a long time. This being so, I expect some problems.
The problems can be technical: the well may not be connected to a pipeline, the separation units may not have enough capacity, there is also an important reason such as “no money”. Such well don’t stay idle long, because it is wasteful to have no payback from the millions buried in the earth. It’s worse when the reasons are geological: the well happened to penetrate a thinner layer, which has too much clay or too few fractures, so a good inflow is not guaranteed at all.
“nobody leaves a good well for a long time” – that might be right usually, but CLR definitely chose to defer completion on many of their wells last year, and this year they are clearing the backlog (131 new wells from DUCs but only 17 from new drills by their presentation). Whiting at one time planned the same and then changed their mind. If there are issues with infrastructure (e.g. access to pipelines) then you’d have to wonder why they drilled in the first place – but if their were unexpected issues, then eventually these will be cleared and the well completed.
I don’t know enough about the process to say, but is it known for sure that a well will be good or bad just from drilling, or does it need to be completed to tell?
GK, you are in the right way. I will try to explain.
Sometimes drilling and logging operations give you the exact reply, that the well will be good and such wells are completed immediately.
Sometimes drilling and logging operations give you the exact reply, that the well will be bad and such well is stored up for the abandonment.
But many times there are no exact reply after drilling and logging. Such wells became DUC. If new drilled wells are not better the operator will complete DUC wells.
My economic evaluation, done a couple of years ago, showed it could be worthwhile to delay completion for up to 3 years. I believe now is the window to go for it, because costs will be going back up by say 20 % from last year. More or less.
It would be better to complete the wells and start production when prices are higher, but companies need cash.
And I agree with you, oil services costs are already rising.
DAPL is expected to be fully operational (bout half million barrels a day) by summer.
Although figures vary, the additional netback for the operators may be in the $8/9 bbl range.
That’s a lot.
Winter weather and road restrictions may curtail near term completions, but May and June timeframe should show marked increase in production.
Hiring spree currently underway out of Williston, especially for CDL holders and frac crews.
Furthermore, several of the 1,500 +/- inactive wells may be brought back online with higher realized prices.
coffe,
Do you have any data on how much ($/bo) it will cost to ship through DAPL?
Normally pipeline transport comes with ship or pay obligations.
Rune
Good question that I don’t (and should) have the answer to.
ETP may be a source to get the transport fees, but my understanding is the various operators commit to both provide product and fixed payment, and those numbers vary by amounts contracted as well as how earlier in the process the commitments are made.
Further clouding the issue is cost of CBR by operator as well as final destination.
Export is also playing a larger role in all this.
Varying estimates that I’ve seen range from $5/$12 barrel.
Big spread.
Rune
Regarding the cost to ship via DAPL … some analyst just said it would vary between $1/$2 range per barrel.
So, depending upon how much CBR runs, netback increase could be in the $9/bbl range.
Somewhat surprisingly, some reports are now saying oil might flow through DAPL as early as March or April.
Should have significant impact on ND production numbers.
George Kaplan,
In my view there is simply a cost issue here. If a well goes from 100 barrels to 20 barrels per day, the mainenance, operating and transport costs go up fivefold per barrel, even if they are the same for the well. So, it might not pay off to send a crew there and pay for transport. Unless, the oil price does not go up, these wells and many more wells are likely to shut down for a while.
I saw a recent story about the rise in the cost of fracking to completion for these DUC wells. Costs are said to have risen to something like $3.2 million in some of the areas where wells need completion. I believe the Director’s Cut said last month there were 86o wells awaiting completion. If the story I read was true, then it will be around $2.8 billion to frack those 860 wells. I don’t know what the cost of getting a well to the DUC stage is, but it sure seems a lot of money to have sunk in the ground for wells that will be outputting just 100 barrel a day after their first 24 months.
Is my thinking fuzzy on this?
Bruno Verwimp wrote back in 2016, September 16th, “….Hold your breath for the next winter. It might bring severe decline in oil production in ND Bakken….”
I wrote at the same time: “…FWIW my ‘money’ is on Verwimp’s observation and model for the Bakken. … I for one will be interested to see your chart next spring!”
Another 3 months will be interesting. By the look of it, it might well be down to 700,000 bpd in a year if the uncanny accuracy continues. As I understand it, his chart has nothing in it derived from price.
That is correct. Verwimp’s model has no oil price input. This is a serious problem since everybody recognizes that oil price has been determinant in the current oil situation. Therefore one can only conclude that Verwimp’s model is accurate due to chance, and therefore has no predicting capability. It will continue to be accurate until it doesn’t. It probably represents oil production decay in the absence of sufficient economical incentive.
@Ron, Thanks for including my graphs. I like the label ‘uncanny’.
@Phil, as for now your ‘money’ appeared to be safe. Indeed oil price is not a parameter in the model. I just don’t need it. I don’t believe oil price makes any difference after all. Geology makes a difference in the first place and furthermore the expectation of earning money in the future. That expectation, strengthened by high oil prices, has triggered US shale to start booming. But that’s it. Why is Permian shale peaking so much later than Bakken or Eagle Ford? Same price environment, same political economy, same technology… that leaves only other geology?
Why did so many countries experience increase, and other countries decrease in oil production between 2005-2012? They operated in the same price environment those days. Difference in geology (and in field maturity) is the main factor.
But, I know, some people stick to their beliefs, even confronted with evidence that opposes these beliefs. As far as US shale is concerned, I presume the profound belief that higher prices will bring back the good old days of growing oil production and the salvation connected with energy independence, hinders the rational observation that ND Bakken is 2 years post peak now and US shale as a whole is 700k barrels per day post peak.
Hi Verwimp,
Geology absolutely plays a role, especially when oil prices are relatively high it is clear which fields are constrained by geology. When oil prices fall by a factor of 3 or 4 fields that are not constrained by geology will decline due to economic constraints (poor profitability.) The Bakken only increased in output due to high oil prices and a high well completion rate. Eventually geology will be the reason for Bakken decline, low oil prices clearly are the reason at present.
In Jan 2018 your model predicts about 680 kb/d for ND Bakken/TF output. My 61 well model predicts about 818 kb/d in Jan 2018 and the 85 well model predicts 900 kb/d in Jan 2018, I expect ND Bakken/Three Forks output will be around 825 to 900 kb/d in Jan 2018, with a best guess of 866 kb/d (847 kb/d in Dec 2018). This corresponds to a 75 well model, chart below.
Hi Dennis,
” I expect ND Bakken/Three Forks output will be around 825 to 900 kb/d in Jan 2018, with a best guess of 866 kb/d (847 kb/d in Dec 2018)”
Is that a prediction or a scenario? 😉
As I said on several occasions: Time will tell.
As I said on several occasions: I really appreciate your scenario’s, because they make clear, for example: “Even if from now on 75 new wells were to be added each month, still a (slow) production decline will occur.”
That being said, I think you may evaluate the opportunity to tinker the parameters of the input of your convolution. You may notice the later 2015 wells and the 2016 wells that were added, gave more oil than your model shows. I presume that is because their initial flow is higher than your average well (and their decline is steeper too).
Profitability sounds like the quintessence for an operator to add wells. According to what I understand of Rune Likverns analysis, none of the shale wells have turned out to be profitable yet. The sector as a whole is burning cash like they are flaring gas. Still 40 rigs are operational in the Bakken. In my humble opinion there is a gigantic discrepancy between drilling for oil and making money nowadays in the Bakken. So I see no need to count on the absent correlation between profitability (price) and production to make further projections about the future.
The latest NDIC data showed a large decrease in the total number of wells, for the first time in recent history. That is a new thing. It might turn out to be fatal. According to shaleprofile.com (Enno Peters) there are now more than 900 wells (and counting) producing zero! More than 600 wells (and counting) are producing on average 5 barrels per day. More than 1500 wells (and counting) are producing on average 18 barrels per day. A stunning 3200 wells (and counting) are producing on average 40 barrels per day!
According to the NDIC the average Bakken well produced 83 barrels/day in dec 2016. But the median well produced only 50 barrels/day. 2 years ago the median well produced a little over 75 barrels/day. The ND Bakken has peaked, but it is in fact the production of productive wells that has peaked. There is an enormous and fast growing portfolio of wells that produce nothing or hardly anything. That makes the decline structural, I believe. That makes operators plugging wells, discarding the production from those promised “fat tails”.
So, again, time will tell. But I think I’ll stick to my model for another while.
“the median well produced only 50 barrels/day. 2 years ago the median well produced a little over 75 barrels/day.”
Less new wells – lower average output per well
Hi Verwimp,
In this case it is a prediction for Jan 2018 ND Bakken/Three Forks output and the prediction is based on the assumption that the average well will produce approximately the well profile I have been using for the past year (which has underestimated actual output) and that the number of new wells added will average between 61 and 85 new wells per month over the Jan 2017 to Jan 2018 period and that new well EUR will start to decrease in June 2017 and reach a maximum annual rate of decrease of 4% in June 2018.
The wells that get shut in temporarily is a big part of the “seasonal effect” that you attempt to model, the other part is slower completion rate due to poor weather. George Kaplan has suggested that it is likely that many of these shut in wells will be brought on line in spring.
George has forgotten more than I will ever know about the oil business, so I am assuming his guess would be far better than mine.
Hi Verwimp,
Why do you think fewer wells were completed in 2016 (729 wells) than in 2015 (1436 wells), and in 2015 compared to 2014 (2157 wells)?
Chart below compares Brent Annual Spot price (vertical axis) with Annual ND Bakken/Three Forks well completion rate for 2014 to 2016. Lower prices means lower profits and fewer wells are completed as a result.
Mike Shellman has suggested that oil prices and profits make a difference and he knows the business (I do not). I believe that Shallow sand and Fernando Leanme would also agree that the oil price will influence output (they also know far more than me).
I’m not sure if three data points prove correlation. Given that no shale company has turned a profit in the last five years, I agree that price/profit does not seem to have as much effect on shorter term production as geology.
Hi Yaman,
Then we could use monthly data from June 2014 to Jan 2016 for Brent spot prices and then compare with well completions from Dec 2015 to July 2016 due to the 6 month lag between decision to drill and well completion. This gives us 20 data points. The R squared is 0.785 which we would expect as oil prices alone do not determine the number of wells completed, there is weather, regulation changes, and plenty of other factors which affect the number of wells completed.
Hi Yaman.
Also see Rune Likvern’s post (link below) figure 2
https://fractionalflow.com/2016/04/06/the-bakken-lto-extraction-in-retrospect-and-a-forecast-of-near-future-developments/
Figure at link below
https://fractionalflow.files.wordpress.com/2016/04/figure-2-bakken-estimated-net-cash-flow-and-cumulative.png
Note the cumulative debt (in red) did not change much from Oct 2013 to Nov 2014, the acceleration in debt after Nov 2014 was due to the fall in oil prices which increased the level of negative cash flow.
A more recent chart at
https://fractionalflow.files.wordpress.com/2016/08/fig-3-bakken-monthly-ncf-vs-cumulative.png
shows that by the middle of 2016 debt had leveled again.
If oil prices eventually rise, perhaps the debt can be paid out of positive cash flow. EIA reference case has Brent at $75/b in 2020 in 2016$ and the high oil price case has Brent at $98/b (2016$) in 2017.
Hi Dennis,
Correlation doesn’t imply causation.
You may find a much lower R² in the Permian?
You will find, for sure, lower R² at some other place on Earth.
Why I think less wells were drilled in the ND Bakken post 2014 oil price collapse?
– Because there is less oil left to drill for.
– Because the drilling companies’ expectations of earning money in the future waned.
You refer to other people who may know better. I am ready to listen to their arguments, because I’m not an oil man and I will never pretend to be one. I live in Belgium 4.400 miles away from the Bakken. So who am I to make statements about Bakken oil production?
I’m an engineer in civil construction, I have a rather solid math background, I look at numbers with an open mind, I studied oil data both globally and in depth (and coal and gas), I recognise patterns, I detect wrong arguments when they appear to be wrong.
The ND Bakken dataset prior to december 2013 followed the pattern of a Hubbert curve almost exactly. Adding a sine wave to it, to correct for seasons, just did the job to match the dataset even more exactly. Given the origin of the Hubbert curve is Lower48, given ND Bakken is lower48 too, I just dared to publish my graphs here; the result of a purely mathematical approach, completely without any technical, technological or economical concern whatsoever.
Apparently, 37 months later my model is still spot on. Because I made a good guess? Because of chance? No, because Hubbert did a wonderfull job modelling finiteness in the Lower48. All credits to Hubbert.
‘But… The world is full of examples that contradict to Hubbert!’ I know, but I recognise the unlimited passion of inhabitants of the Lower48 to go for their goal. To get things done today instead of tomorrow, especially when it’s about making money. There are no constraints in the USA, unlike anywhere else. Therefore the purely theoretical Hubbert curve shows up so nicely in the USA today again.
And you know what? The Permian is my next target. Because of this graph (see below). You see what I did? This is my ND Bakken Model on top of Enno’s data collection of the Permian, shifted 1 1/2 years or so. You see the pattern? There’s more to come, Dennis. I promise.
Hi Verwimp,
I have shown before that when the Hubbert type of analysis is done too soon is severely underestimates URR. That is likely to be the case for your ND Bakken Hubbert curve which has a URR about half of proved reserves plus cumulative production (roughly 6 Gb). The USGS estimates a 95 % probability that the TRR will be more than 7.5 Gb (USGS analysis from April 2013), see
https://www.dropbox.com/s/evwtxgsuisewczk/2013_Bakken_ThreeForks_Assessment.pdf?dl=0
Note that the 7.4 Gb mean estimate is undiscovered TRR (UTRR) and is for ND and Montana, for ND Bakken/TF it is 5.8 Gb and we need to add proved reserves at the end of 2012 (3.4 Gb) and cumulative production of 0.6 Gb to find the mean TRR estimate of 9.8 Gb, for F95 UTRR=3.5 and TRR is 7.5 Gb.
Note that the USGS F95 estimate for Permian LTO resource (Wolfcamp only) is 11 Gb and the F50 estimate is 19 Gb. What is the URR of your Permian Hubbert curve, maybe 5 Gb?
See
https://www.usgs.gov/news/usgs-estimates-20-billion-barrels-oil-texas-wolfcamp-shale-formation
Oh on correlation and causation, there is a good theory (neoclassical economic theory) as to why supply will be affected by price, the correlation just supports the theory. Possibly it is coincidence just as your chosen URR for the Hubbert curve by chance coincided with oil prices dropping by a factor of 2 (or more).
I agree time will tell if your Hubbert estimate is correct, I believe your URR is too low by at least a factor of 2 and possibly 3. By 2019 it is likely to be clear, we will have to wait. If oil prices rise to $75/b by the end of 2017 as I would guess (and I never get price predictions correct), then we may know by Sept 2018.
That would be a hell of a situation with all the money that has been dumped into the Permian over the past year for it to be already at peak and be post peak within a year and a half from now.
I was an investment banker and in and around the finance industry for a decade. I know a bubble when I see one, and Permian is a bubble.
Classic indicators: zero historical economic profits financed by debt and asset sales and hyped up by bankers and media resulting in surging land prices. If this is not a bubble, I don’t know what is.
I cleaned up the graph for better insight. The ressemblance between Permian production (blue) and the Hubbert curve (red) is so unbelievably great it would be an astounding coincidence if the Permian would be following another curve.
And that would be a hell of a situation indeed.
Verwimp – How do you explain why Permian has not followed the Hubbert curve after 3Q16, which is where you ended your graph?
Permian LTO production in January 2017 was 1.6 mb/d instead of 1.05 mb/d in your chart.
Permian LTO production (mb/d)
source: EIA-Drillinginfo report
And production growth has actually re-accelerated in mid-2016 with the increase in well completions
Year-on-year growth in Permian LTO production (%)
Verwimp – How do you explain why Permian has not followed the Hubbert curve after 3Q16, which is where you cut it off in your graph?
Frenzied Betting, Sleeping Market: Something Must Give in Oil – Bloomberg: “Unfortunately for the bulls, the oil market itself has fallen asleep after an initial surge. As Standard Chartered analysts including Paul Horsnell pointed out this week, prices have been stuck around a dollar a barrel above or below $55.50 since mid-December. Meanwhile U.S. crude closed above $54 a barrel only once since OPEC’s Nov. 30 meeting, despite crossing that price level 14 times. ‘If crude prices are to break out of their recent range in the next few weeks, the risk is to the downside,’ JBC Energy GmbH in Vienna said Thursday.”
It’s going to go up to around $63.
Shale oil is called subprime oil for a reason.
We need to account for the fact that shale oil production was supported by junk bond issuance. The loss on shale oil junk bonds is not that big: the U.S. energy companies have defaulted on ~$40 billion in high-yield bonds in 2016, more then doubling the $15 billion for 2015 according to Fitch. But they do affect future junk bond issuance…
What is interesting is that MSM stopped talking about shale junk bonds in 2015 as if they got some order from above 🙂 Most warnings are from 2014, some from 2015:
http://www.econmatters.com/2014/11/subprime-crisis-in-shale-oil-junk-bonds.html
https://www.bloomberg.com/news/articles/2015-06-18/next-threat-to-u-s-shale-rising-interest-payments.
In this sense, even $ 63 might be too low, if loans became more expensive and well servicing costs continue t0 rise. Printing junk bonds is a necessary side effect of shale oil production and this is now definitely more expensive activity then before.
I think that the return to profitability for shale at oil prices below $70 bbl is very problematic.
The $63 justifies fracturing and completing DUCs, because the well drilling cost is already sunk. Waiting an extra year for $70 is a wash. Therefore if those companies have sense they will start getting contracts and permits to start completing now, in 2017. If they don’t have cash they can sell to those who do.
DUC levels are already normalized back to pre-crash levels in both bakken and eagle Ford. You can confirm using EIA duc supplement data. There is no more quality duc to complete.
The number of the DUCs is still well above 2014 levels in the Bakken, Eagle Ford and Niobrara. And rapidly rising in the Permian.
But a few years ago people saw a long future for both the Bakken and the Niobrara and look how much they have leveled off. I keep coming back to that point. If these areas have short production lives, then the great fracking miracle is going to take us only so far.
AlexS – your rhetoric in your post does not align with your graph. Bakken and Eagle Ford DUCs are clearly back to 2014 levels and largely off from their respective peaks. Permian DUCs are rising because it is uneconomical to “complete” these wells, and company debt levels are reaching their limit. The bubble is over.
The DUC numbers are rising because the more wells being drilled and completed the more DUCs are needed to maintain the same relative inventory (i.e. the time to complete all the DUCs at current completions rate is kept fairly constant), and so allow the rigs and completion crews to work independently. Nothing more complicated.
Yes, but the number of the DUCs was increasing in 2015 – early 2016 when the number of new wells was decreasing.
And despite a decline in the DUC inventory in the Bakken and Eagle Ford, the number of the DUC relative to new wells is still much higher than the “normal” levels in 2013-14.
Although the DUC numbers may be fairly staic the wells making up the numbers are not. A well is first a permit, then a spud, then a DUC (or, very occasionally now, a dry hole) then is completed. The time from spud to completion can be several months. All the wells on a pad are drilled, then the rig moves off, the completion crew moves in and they are all completed in turn. I don’t think there are any ‘bad’ DUCs. If they are known to be dry they are just P&A’d to avoid paying rental or minimum royalty charges. Some might be found not to be as good as expected once completed, but not man these days because drilling is only in the core areas and the good prospective zones have been fully delimited by previous wildcats and development wells.
Drilled but uncompleted (DUC) infers something positive awaiting a proper time, or price to complete. That is hardly the case. I venture to guess that half the drilled but uncompleted wells are actually drilled and temporarily abandoned (TA’d) wells . Reasons to TA a well could range from mechanical downhole problems, logging and lithology analysis of the lateral suggesting completion is not warranted, poor offsetting well results, faulting, well communication issues, deferring P&A costs, leasehold issues, turning bad looking wells into disposal wells, or injection wells, and wells awaiting sidetracks and/or plugbacks. Bad or sick Three Forks wells have Bakken behind pipe, Wolfcamp D wells have B and C behind pipe, even Eagle Ford wells have Austin Chalk behind pipe. Lots of TA’d wells in the Permian are awaiting sidetracks or deepening, I’ll betcha. There are actually all kinds of “bad” DUC’s. If they were good DUC’s they would have been completed and brought to bare; for those that think spending $4M dollars to drill a well, with borrowed money, then sitting on it for three years hoping for higher oil prices before completing it is smart business, I suggest tippy toeing thru some 10Q’s and K’s coming out right now. The newest being Whitting. These shale guys need every penny they can get their hands on and would sell their mothers for the right price.
Why drill and not complete a well? You can book the same PUD reserves based on SEC proximity rules without spending the $4M. Was it a good idea in 2013 and 2014, before the crash? Drilling costs went down 25-30% in 2015 and 2016 so, guess not.
No – temporary abandoned wells in ND are designated TA. No well can be NC for longer than two years and very few are longer than one year. Most are around 6 month.
Two years then, whatever. It is a mistake to assume all drilled but uncompleted wells are capable of being completed (in their current state) or that if completed they will be good wells. Min. royalty payments or rentals would apply to leases, not individual wells on a lease (ie slot/pad drilling). An operator is going to do everything it can to defer P&A in this price climate or to prematurely plug the vertical section of a HZ well where potential might exist within reach of that vertical well in another zone. There are ways to do that, even in N. Dakota. That from an operator; take it or leave it.
Hmmm whom to listen to someone who is almost never right or a billionaire.
mike VS Sam Zell…my money is on Zell, of course I was in 5 years before he was.
http://www.worldoil.com/news/2017/2/22/billionaire-sam-zell-joins-slew-of-investors-in-awesome-stack-shale-play
SS check out the May unit production in the out today CLR report. You may want to revisit your no oil meme in SCOOP. (page 31-32)
http://investors.clr.com/phoenix.zhtml?c=197380&p=irol-irhome
Alexs, you may recall i said two years ago the stats out of Okla are going to change. Like Trump said we are just gonna get tried of winning?
Wish I had more time but someone got work around here??
Seems like whatever increases oil production will just keep prices low. So it’s not going to be a good scenario for companies.
Never said no oil. Said oil seems to drop to near nothing in 12-24 months, except for Springer formation.
I looked up the May wells. I have production thru 10/31/16. Two wells with first production 3/16 are under 100 barrels of oil per day in 10/16. The remaining five have first production in August or September, so only 1-2 months where I am looking.
Lets look in a few months, see how they hold up.
Boomer, thanks for your comment; you don’t seem to get caught up in the data obsession and appear to be able to see the forest for the trees. In spite of a draw down this week, C+C inventory levels in the US are at an all time high and growing. There are issues with the quality of LTO in America that is not allowing significant drainage (use) from Cushing, for instance, south to the Gulf Coast for refining, and imports of heavier foreign crudes (for blending) into the US are rising. LTO is just not very good stuff; that is something seldom recognized by the general public. The production cuts that OPEC have promised and that have given the US LTO industry a 6-7 dollar per barrel pay raise recently are precarious, at best, and many OPEC countries have already said they will not renew those cuts.
If you are actually IN the business of producing oil in America, and paying bills associated with that production, whether a conventional producer, even an unconventional producer (with a square centimeter of cranial capacity*), you are deeply concerned about the near term price of oil. More production, lower prices. Trump Almighty can’t fix oil prices; its a world oil market, not an American oil market. The US LTO industry is out of control, again, and on a path of self-destruction. It cannot make itself aware of market conditions and self regulate itself. If there is money to borrow, it will borrow it.
Production is growing in the Permian and as you have already determined, so much so that takeaway is problematic. More so than people are aware. Permian production and the feeding frenzy there will stifle, or hurt the price of oil. What happens in the STACK/SCOOP play in OK will not. It is primarily a gas play, as Shallow points out, and a perfect example of how the BOE slight of hand the shale industry uses so effectively, confuses people (*with no cranial capacity).
STACK won’t help Marathon, who lost $2.14B in 2016 nor will it help Continental who reduced its losses in 2016 to a paltry $400M. OK shale plays are just like all shale plays. Ultimately they will prove grossly uneconomical to produce, particularly when borrowed money is necessary to develop the play. NATGAS prices have tanked nearly 30% or more in just the past few weeks.
There is no reason to be crowing about anything going on in the unconventional shale business at the moment.
Texas tea,
Oil production in Oklahoma peaked in March 2015 (like in Lower 48 states onshore in general).
Unconventional output from the SCOOP, STACK and Woodford shale has been slowly increasing, but is still below 90 kb/d. Two years ago it was about 70 kb/d. These are mainly gassy plays with some oily zones. It’s not a new Bakken, Eagle Ford or Permian in terms of C+C production potential.
Oil production in Oklahoma and Woodford shale (incl. SCOOP and STACK), kb/d
Source: EIA
CLR is a big player in SCOOP and STACK. Its oil production there was close to 23 kb/d in 2016, but more than 72% of total hydrocarbon output is natural gas.
CLR oil and natural gas production in SCOOP and STACK plays
BP Oil production and consumption
We have now graphed the whole of BP oil production and consumption and calculated the net export balance which is not in decline but it has been flat since 2005.
Nice, Thanks!
The net exports available on the global oil markets are some 60% of the total production. In the case of dropping global oil production it will take a while for the markets to dry out. If you make this same exercise on coal and gas, you get different numbers. Only a tiny fraction of global coal and gas production is available on the global markets. Dwindling global production will result in disappearing global markets in a very short time frame.
Verwimp – What is the best way to reach you?
A big contributor to the legacy oil decline is the unrelenting physics of fluid phase behavior, with gas becoming more prevalent in the production stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells will be worse (i.e. the newer wells dampen the effect, which have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a “gas” well or field.
Most of these LTO fields will eventually be abandoned as gas fields.
note – I tried to post a *.png graph, but the reply tool failed.
Probably too big – convert to gif or jpeg below 45 KB.
the original was 54kb. here is a 25 kb *.gif. Well count is on the right-hand y-axis, all others on the left.
Seems like this would be a very important chart when it comes to predicting the future of the Bakken.
I would think that the rising GOR at the field level may be due in part to the fact that the completion rate has fallen from about 1800 new wells per year in 2014 to about 750 new wells per year in 2016, the newer wells tend to have lower GOR, so as their proportion decreases the average GOR for the field increases.
”…has fallen from about 1800 new wells per year in 2014 to about 750 new wells per year in 2016, the newer wells tend to have lower GOR,..”
Interesting, as this is exactly the opposite of what actual data shows.
FreddyW posted a chart on Bakken GOR in the previous oil thread:
http://peakoilbarrel.com/opec-january-production-data/#comment-595923
Hi,
I missed to take into account the number of days in the month for total producing days in my last post. I wanted to investigate this more. So I did a bit of programing and adjusted each individual well for the number of days it was in production in December to see what the production would have been if it produced as many days as it did in November (adjusted for number of days in that month). I looked at wells that started production in 2014 and wells that started production in 2010. In short, both groups looked very similar and it turned out that about 86% of the increase in decline rate, for both 2014 and 2010, were because of fewer producing days and the rest for other reasons. However there is more to it than that. First of all, adjusted for number of producing days, the decline rate should stay the same or decrease a little every month, not increase. Secondly wells that are of the same age as the 2014 wells have historically had a monthly decline rate of around 3%. The decline rate in November (days adjusted) was 6,9% and in December 8,1. For the 2010 wells, monthly decline rates should have been around 1,5% but were 5,6% in November and 6,9% in December. So the decline rates are currently very very high. The huge drop in December could not have been that huge if the underlying decline rates would not have been that large.
I think the decline in GOR has something to do with it. If the reason for the increase in decline rates are that they are choking the wells, then I expect these high decline rates to be rather temporary, because I would guess that they adjust the choke only once per well. It may take some time to adjust all wells they have planned to adjust, but when that is done then decline rates should normalize. So if that is the reason then maybe it will take a few months to normalize. If the decline rates are still very high in a few months, then it doesn´t look good for Bakken..
I found a bug in my code. For 2014 about 100% of the increase in decline rates from November to December was because of fewer production days and decline rate in November was 6,43% and December 6,35% (a bit conservative). For 2010 the numbers are 86%, 4,16% and 5,16%. So lower underlying decline rates, but still very high. Sorry about that.
Try plotting real oil rate (what the well produced when it was turned on) versus (cumulative oil production plus cumulative gas in BOE) and see if that sort of normalizes everything.
If you plot the natural log of the oil rate I described above the decline curve straightens out, but in this type of well it will remain concave upwards. Take a dimensionless form (rate as a function of peak rate) and that gives you a decent type curve.
If you plot those type curves over the years you will probably see that recovery per well isn’t that different as long as they have similar reservoir contact.
So you want to see if initial oil production is correlated to cumulative oil plus gas production? Not sure though what is has to do with decline rate.
Hi FreddyW,
Are the GOR charts ok though?
The bug was that I missed to handle the scenario were there was zero production in the “after” month. It looked like this (for each well):
afterprod_adjusted = adjustmentfactor * afterprod
So afterprod_adjusted would in this case still be zero.
I don´t adjust the production for number of production days in any of my other graphs. So they should be ok.
I did some more investigation to find out if choking the wells is behind some of the decline in production. I took my data where number of producing days were adjusted to match previous month in order to remove the effect of fewer producing days. Then I grouped them into two groups, one were GOR increased and one were GOR decreased compared to previous month. Here is a summary of the results (wells with no oil or gas production have been excluded):
2014 wells in 2016, Oct to Nov:
Nbr of wells inc GOR: 1220 60,5%
Nbr of wells dec GOR: 798 39,5%
Increase for wells with increased GOR (%): -8,1
Increase for wells with decreased GOR (%): -3,7
Total production before 178465
Total production after 166997
Total decline (%) 6,43
2014 wells in 2016, Nov to Dec
Nbr of wells inc GOR: 863 43,1%
Nbr of wells dec GOR: 1139 56,9%
Increase for wells with increased GOR (%): -9,2
Increase for wells with decreased GOR (%): -4,5
Total production before 171216
Total production after 160341
Total decline 6,35
First of all, I was surprised to see that here and also historically, the group with declining GOR has a lower decline rate than the group with increasing GOR. I can only guess why that is. For wells that are 2 years old the group with declining GOR typically declines with 0-2% and the group with increasing GOR typically declines with 3-7%. So both groups for the 2014 wells declined more than usual. We can see in the data above that there was a massive movement of wells from the increasing GOR to the declining GOR group from November to December (Nbr of wells dec GOR went from 39,5% to 56,9%). We can also see that the decline rate for that group increased a bit from 3,7% to 4,5%. However total decline rate remained about the same (6,43% to 6,35%). So it did not have any affect on decline rate. It looks more like wells with higher decline rate in the increasing GOR group were just moved to the decreasing GOR group. Or in other words, they may be cheating with gas production data (flared gas) which I also suspected a few months ago.
Just a quick look at the 2010 wells:
2010 wells in 2016, Oct to Nov
Nbr of wells inc GOR: 413 58,0%
Nbr of wells dec GOR: 299 42,0%
Increase for wells with increased GOR (%): -7,1
Increase for wells with decreased GOR (%): 0,7
Total production before 33307
Total production after 31923
Total decline 4,16
2010 wells in 2016, Nov to Dec
Nbr of wells inc GOR: 318 45,5%
Nbr of wells dec GOR: 381 54,5%
Increase for wells with increased GOR (%): -9,6
Increase for wells with decreased GOR (%): -1,0
Total production before 32864
Total production after 31169
Total decline 5,16
They look similar to the 2014 well data. The group with declining GOR also increased a lot (Nbr of wells dec GOR went from 42% to 54,5%) and both total decline rate and the decreasing GOR group decline rate increased a bit. But the decline in the declining GOR group was much lower than the decline in the increaseing GOR group (1% compared to 9,6%). So if there are any wells that are choked, then they didn´t contribute much to total decline.
Why are wells with increasing GOR declining so fast? It could be that GOR is so high that gas supresses oil production. This would result in pressure being depleted quickly and eventually cause a lot of oil to be left behind as I understand it. Or any other ideas?
FreddyW, thanks for sharing!
Hi FreddyW,
Thanks. I would also love to hear from the pros what this may mean.
Hi FreddyW,
I would think the higher GOR might be due to too much fracking such that the pressure levels in the reservoir gets depleted too quickly and doesn’t give the oil time to migrate to the well so more gas is produced relative oil and the reduced pressure needed to drive the oil to the well results in less oil produced per day.
The geophysicists, geologists, and engineers can correct this as I would love to learn.
I have never had anything to do with an LTO well, or in fact with a well on solution gas drive, but a falling GOR ratio will happen only with older wells: those close to exhaustion, with low flows, and probably entirely reliant on artificial lift (possibly with some mixed drive from water as well, but I wouldn’t swear to that). In the early operation the gas comes out of solution of all the oil in the formation and is more labile than the oil so moves easily to the well bore, and the GOR rises as the pressure declines. The easy gas gets exhausted – i.e. the methane and ethane goes first, then the propane, then butane etc. At some point a condition is reached where the gas won’t be evolved unless the pressure declines, effectively the oil is ‘dead’ at the reservoir pressure. The oil has to be pumped out with, for example, an ESP but the more you pump, and the lower the pressure, the less gas you actually produce as the oil gets continuously heavier.
Freddy, this should fix you up; it is a good explanation of gas to oil ratio behavior before and after bubble point in pressure depletion environments like unconventional shale: http://petrowiki.org/Solution_gas_drive_reservoirs. Increasing GOR is indicative of depletion. Combine this with your produced water work and you can decide for yourself what is happening in the Bakken.
Thanks Mike. I will take a look.
Thats interesting. So GOR should not start to decline until it reaches 6 mcf/barrel or so the earliest and the well may reach the economic limit before that. So declining GOR should not be expected for some time then (unless they are cheating with flared gas reporting).
Thank you George and Mike.
Just two more tables. It looks like oil and gas production goes up and down a bit for a well. When gas production drops then oil production goes up and vice versa. This could explain some of the big difference in decline rate for the decreasing GOR and increasing GOR groups above. Using a longer time period should remove this effect, which I have done in the tables bellow. They show 6 months differences instead of 1 month. I have also excluded wells with < 5 days of production to improve data.
2014 wells in 2016, Jun to dec
Nbr of wells inc GOR: 987 51,3%
Nbr of wells dec GOR: 936 48,7%
Increase for wells with increased GOR (%): -22,02
Increase for wells with decreased GOR (%): -17,39
Total before 187216
Total after 150277
Total decline (%) 19,73
2011 wells in 2013, Jun to dec
Nbr of wells inc GOR: 511 46,2%
Nbr of wells dec GOR: 595 53,8%
Increase for wells with increased GOR (%): -18,33
Increase for wells with decreased GOR (%): -13,48
Total before 115051
Total after 97109
Total decline (%) 15,59
We can see that there difference in decline rate between declining and decreasing GOR is now much lower. But wells with increasing GOR still decline faster. The average per well production is about the same in each group for both tables, but that is not visible in the tables above. The 2014 wells decline faster than 2011 wells did in 2013, however much less difference than in the 1 month tables. The decline rate has increased a lot the last few months. It will be interesting to see the coming months if it was only temporary or if this will continue.
Try this if you have $10 to spare:
https://www.onepetro.org/journal-paper/SPE-184397-PA
From the abstract it looks like tight oil behaviour is very different from conventional wells, especially if there is a lot of dynamic changes (i.e. non steady state behaviour), which would certainly have been the case in December with a lot of wells going off line and then coming back on again. I doubt if looking at the GOR in anything but large aggregates of wells will indicate much.
Mr. Kaplan
I thank you for that link and plan on reading the whole paper.
From just the abstract, however, one might glimpse how different characteristics are from conventional and unconventional sources, most specifically regarding bottomhole pressure and conductivity.
As these Bakken wells have been relatively ‘confined’ to the core areas these past several months, they have ALL been drilled on existing pads with older, producing wells closely offset to the new ones.
It is the lengthy shut in period, combined with elevated bottomhole pressure from frac fluids (hundreds of thousands of barrels per new completion), that is promoting both non linear oil/gas production as well as varying GOR in these older wells.
For all
Should anyone glance at the link from Mr. Kaplan and skim through the summary, one might see the incredible amount of brainpower that is being applied to this field.
Additionally, the 17 listed references display, line by line, how extensive the commitment of resources are being put forth by the O&G industry.
Thank you George. There is a lot of information in the summary. 2008 could fit into the stages explained in the summary. However all years started to see increasing GOR in 2014 and all years has seen it level out in 2016. So it doesn´t quite make sence.
Hi Freddy W,
I can’t tell on your GOR chart which line is which between 2012 and 2014, one rises to the level of the 2015 GOR and the other is lower, but the color is similar and they come together and then separate and it is hard to figure, in the future if you change the y axis to a scale of 0.5 to 2.0, it might be a little easier to read, dashed lines when two curves are the same color and are near each other also helps (so either 2012 or 2014 could be a dashed line). Thanks.
Dennis,
Gas-to-oil ratio in North Dakota, the Bakken and by 4 key oil-producting ND counties (kcf per barrel), 2007-2016
Similar chart for 2010-2016
As I understand, FreddyW’s charts show GOR for the wells that started production in a particular year.
My charts show GOR for total production.
GOR is different in different parts of North Dakota. So changing share of different counties, as well as increasing share of sweet spots in total production may also affect GOR numbers.
This is an explanation given by Lynn Helms in 2016:
“Helms attributes the increasing gas production as oil production drops to the fact that low prices have forced producers to focus only on the Bakken core area or sweet spot for all 27 rigs still operating.
“That area has the highest gas-to-oil ratio,” Helms said. “The wells there also are the most productive [3,000 b/d], and the gas-to-oil ratios are two to four times what they are in other areas.”
http://www.naturalgasintel.com/articles/106414-bakkens-1-million-bd-production-unlikely-to-hold
Though I think this can’t fully explain increasing GOR in the Bakken, as it is rising in all parts of ND.
2012 and 2014 have different colors. So not sure what you mean. 2014 and 2015 have the highest GOR.
Here it is zoomed in.
Ok now I see. I had to reduce number of colors to fit into 50kB. 2012 has red dots in it.
Hi Freddy W,
Thanks my old eyes cannot make out the red dots, question answered, 2014 and 2015 are highest and 2016 is probably lower because the wells are so new. I still think the greater number of frack stages has something to do with it, maybe there was a change in the average number of frack stages from 2012 to 2013.
Is the 2000 GOR a North Dakota convention? There’s no reservoir engineering reason to designate a depleted well as a gas well when GOR increases to 2000 scf/bo. Depleted oil wells under depletion drive do experience very high GORs, but they remain oil wells.
Here’s a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.
http://fuelfix.com/blog/2016/11/22/pioneer-denied-request-to-reclassify-oil-wells/
My recall is there’s a regulation in Texas that classifies liquids from a gas well as condensate vs oil from an oil well. Almost certainly has some tax consequence.
Hi Fernando,
What are typical values for GOR when a well reaches its economic limit, assume the volume of produced water is equal to the volume of oil produced at the economic limit (or if that is not realistic please let me know what the “average well” might be would the ratio be 2:1 (water:oil), I have no idea what is typical and I realize every well is different.
Can any of you professional fellows explain the upsurge in “Legacy Oil Well” production shown in the monthly EIA Drilling Productivity Reports? The major fields, except. Permian, show that the legacy wells are rising after having been on seemingly steady downslopes for the years leading up to about early 2015. Are they reworking old wells? What’s the industry practice that has reversed the declines.
for example, this page–
http://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf
The legacy well production graph represents the monthly expected change in production.
In the example you referenced monthly legacy decline was about 140,000 bopd at the beginning of 2015. This legacy decline represents the decline of wells producing in the prior month. This decline was large because there were many recently drilled legacy wells, and the recently drilled wells decline more than wells which have produced for a longer period.
By the beginning of 2017 the legacy decline had decreased to about 80,000 bopd per month because there hadn’t been as many wells drilled recently.
To dclonghorn:
Right. Another point is that more and more wells became idle so they aren’t calculated in the legacy well production.
Thanks. That helps clarify things for me.
Some of y’all are newishcomers and cannot remember how very many times monthly production reports would report completely inconsistent with new completions totals and weather and more or less 15 gazillion other factors we’d throw in.
Point being, don’t think you have why the big recent increase or why this big decrease understood. Your odds on this are poor.
Reminder from last thread:. That Enno chart color coded by year — look at how shallow the post Peak descent slope 2010, 2011, 2012 is vs 2014. Damn near vertical. That would be the last non price smash year.
This speaks to EUR, but not loudly because of . . . Wait, do we have proof these recompletions are happening? Or is this presumption.
Also suggest a read thru of the new rule making paras of the directors cut.
I can remember months when new completions and new wells operating numbers completely failed to explain a change in quoted oil production that month . . . and I embarked on chasing down traffic reports and stop light failures at intersections because trucks hauling oil having been slowed down could conceivably have been the explanation for the numbers. Nada.
What we DID conclude was negative — zero explanation for oil output quotes from the number of wells completed in a month. Number of days of bad weather preventing completions also failed to explain. Bad weather slowing down trucks remained a maybe, but for trucks hauling oil, not trucks hauling proppant.
A blast from those early days:
http://static1.businessinsider.com/image/4f5681fd69bedd0f60000048-1200/here-is-a-load-of-proppant-from-china-used-to-frac-a-well-sitting-at-the-rail-head.jpg
Ceramic proppant for Bakken. From China. Soon after this it was magically discovered that special sand from the US was “superior” (meaning cheaper, but didn’t hold the fractures open as well).
This has been my philosophy for decades. Preserve our own resources and use up everyone else’s until they run out.
Berkshire's Charlie Munger Has A Much Different Energy Plan For America Than Donald Trump | Seeking Alpha: “Munger believes that the United States should have an energy strategy that involves preserving these shale resources until some point in the future when they are much more valuable. This would be a point in time after the OPEC nations have exhausted their oil and gas reserves.
Munger would have us import oil and gas now from OPEC so that we can save our oil and gas for the future when the world is going to have major shortages.”
Sigh.
People Are Not Stupid.
The day comes when a firebrand is in control and dares to rock the societal systemic boat by declaring the price of oil will be non monetary. You want oil from Russia, America? Disarm. You want oil from KSA, America? Convert to Islam.
“We have enough of your dollars created from thin air. Let’s have something of real value to us before we send you oil. The price is described above.”
But if we haven’t wasted our own oil, we’ll still have it. And then if other countries want to give us terms we won’t accept, then we don’t use their oil.
Of course, without imports, we won’t have enough to run our country business as usual. But we’re going to head that way anyway, as global supplies become more scarce and/or expensive.
When the shit is well and truly in the fan, in terms of oil available for import to the USA, which will probably come to pass within the next couple of decades, barring the technocopians being right in predicting electricity displacing oil, well……
We have both economic and military muscle enough , assuming we wise up about globalization , and don’t export the rest of our industrial base, to INSIST on oil being sold to us , although getting it for dollars will be harder from year to year.
Saudia Arabia will never be self sufficient in food until the population there falls by what, eighty percent or better? If anybody will have the capacity to export food on the grand scale, it will be the USA.
And if anybody has a military umbrella under which smaller and less powerful countries can shelter at relatively low risk of the people there being treated like convicts, it will be the USA.
This is not to say we have been or are altogether NICE about the way we treat our allies, but compared to other countries, we stack up pretty well in this respect.
Nothing will move on the world ocean for quite some time if Uncle Sam finds himself in a corner where in his own interests indicate that nothing moves.
Of course considering that ninety percent of the leadership in China consists of engineers and scientists, where as ninety percent plus of western leadership consists of lawyers and other mostly parasitic types, it ‘s only a question of WHEN, rather than IF China will be a military superpower, and maybe the SOLE super power.
Maybe you should look up the numbers on USA food exports and imports. We’re not really the agricultural export powerhouse most people think we are.
Jimmy Carter said exactly that when he was President. Smart, but the industry didn’t like it.
And that is exactly when I started to think about this. During Jimmy Carter’s term. Had we done something starting then, we would have had decades to prepare for a time of declining oil supplies and higher prices. We could have had a relatively smooth transition. But we did nothing, so it is likely that when oil gets really expensive, it’s going to be an economic shock and we will have to make a rapid transition.
Sir Ronnie The Lessor continued the mythology (however, he tripled the national debt).
He perfected the Electronic Nuremberg Rally, and the Charge and Loot profit model.
It was a New Time in ‘Merika!
The North Slope was flowing, and SA had oil, as I remember, at $10 a barrel.
The Stock Market was depressed, and had nowhere to go but up, the Casino was open and they could make the rules, interest rates were 16% with nowhere to go but down,.
None of these are in place for Cheeto Boy.
The Soviets were being bled to death.
They are currently doing quite well.
California Resources Corporation (NYSE:CRC), an independent California-based oil and gas exploration and production company, today reported a net loss of $77 million or $1.83 per diluted share for the fourth quarter of 2016.
Highlights Include:
Received sixth bank amendment removing capital investment limitations and allowing additional joint ventures, among other changes
Initial 2017 capital investment plan of $300 million
2016 capital investment of $75 million with only $31 million of drilling and workover capital
Quarterly production of 135,000 BOE per day
A 2.2% sequential decline
A 10% year-over-year decline, excluding PSC effects
Annual production of 140,000 BOE per day
Annual production costs down 16% from prior year
Annual operating cash flow of $130 million
2016 Annual free cash flow2 after working capital of $49 million
2016 Organic reserve replacement ratio of 71% with minimal drilling and workover capital
2016 Adjusted Organic F&D costs of $3.42 per BOE3 excluding price adjustments
“Our planned 2017 capital budget of about $300 million should allow us to increase activity, enhance margins and return to a growth profile beginning in the second half of the year. Additionally, we expect to further expand our actionable inventory. We are pleased to have received our sixth bank amendment which removed capital investment limitations. We will continue to align our investments with our cash flow.”
CRC expects to align our capital investment with our operational cash flow, and adjust our capital plan accordingly. Based on the current market conditions, CRC will begin the year with a capital investment plan of $300 million, consisting of approximately $150 million for drilling and completions, $50 million for capital work-overs, $50 million for facilities, $25 million for exploration and $25 million primarily for mechanical integrity projects.
http://www.businesswire.com/news/home/20170216006267/en/California-Resources-Corporation-Announces-Fourth-Quarter-2016
CRC has been bleeding red ink for over 2 years. I don’t see anything less than $60 per barrel stopping that. Do they know something about the future price of oil most don’t ??
RRC production numbers for December and drilling numbers for January are out today. Production is steeply down and this will not change very soon as more wells are shut then permit in January (see below chart).
I just went looking for more info about this online and don’t see any. I can find info about the number of permits issued, but no one is mentioning plugged wells or net wells. Are people overlooking this or just choosing not to write about it?
boomerII,
To get the newest production (also individual wells ) from RRC Texas go to:
http://webapps.rrc.state.tx.us/PDQ/changePageViewAction.do?pager.offset=20
– click on: general production query
– you get a new site : general query criteria
– in the open form click on: initial view: lease
– choose the data range
– choose one : both
– district : statewide
– all other four : none selected
– click submit: you get a new site
– click on monthly totals and you get the production data for the months you have selected the data range; it is important to note that the latest four months get revised substantially; so a frequent check is necessary
for data on drilling go to:
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/
The RRC data is incomplete for at least 12 months, so a better estimate is the EIA data.
Baker Hughes rig count is out, US overall up 6 oil, 4 gas; but the drop in offshore rigs of 3 would likely have a bigger impact than the increase in onshore rigs.
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsoverview
Canada has started the spring decline and is down 21. See below.
Canada has to reduce rig count once the thaw sets in because there are restrictions to moving heavy loads on some roads, as they can get damaged when not solid. It looks like the thaw week might be getting gradually earlier in the year. Even this year when there has been some cold weather pushed south by the hotter air in the Arctic it is pretty early to start, but the prevailing weather pattern has just reversed with the Arctic now cold and warmer air moving to lower latitudes.
Canadian Oil Sands – Wall Street Journal – 2017-02-17
Oil sands projects can require billions of dollars in upfront investment and seven to 10 years, or more, to bring returns. Instead, companies are increasingly focusing on new sources of crude oil, such as shale, that don’t require the same massive investment and that can get from development to production much more quickly.
To be sure, oil output isn’t expected to fall in Canada as it has in the U.S., and some projects for which money has already been spent may go forward, a sign of the resilience of oil sands investments once money has been spent. That is because the cash cost of producing barrels once projects are up and running is low.
https://www.wsj.com/articles/energy-companies-face-crude-reality-better-to-leave-it-in-the-ground-1487327406
And what does that mean for pipeline construction?
I can’t see the original article since it is behind a paywall.
But this appears to be the text of the article without the above graph.
Energy Companies Face Crude Reality: Better to Leave It in the Ground | Fox Business: “Once considered a safe bet, Canada’s vast deposits are emerging as among the first and most visible reserves at risk of being stranded by a combination of high costs, low prices and tough new environmental rules.”
Hi all,
The sharp downturn puts Bakken output closer to my model based on average new well output profile (based on data shared by Enno Peters) and the number of completed wells each month (also based on data from Enno Peters). The model output has been lower than actual output for about a year, with this month’s data point the model is fairly close to actual output (model is 1.6% too low) . This “uncanny accuracy” is likely a matter of chance as the actual new well output varies from month to month.
Three future scenarios are presented with a constant number of new wells completed each month from Aug 2016 to Jan 2022 of 85 wells, and 125 wells, the 61 well model has 61 wells from Jan 2017 to Jan 2022.
Note that the most recent 12 months the average was 61 new wells per month and in Dec 2017 82 new wells were added. Also from April 2012 to Nov 2015 there were more than 125 new wells per month for the trailing 12 month average, the peak was about 186 new wells per month for the 12 months ending in March 2015.
We have no idea how many new wells will be added in the future.
Dennis, one thing you are forgetting…. geology. Your model looks very accurate if wells of the future are as productive as wells of the past. They will not be. Wells of the future will not be nearly as productive as wells of the past. All the sweet spots have already been drilled. We are now drilling the fringes, more and more water with less and less oil.
Hi Ron,
Model assumes new well EUR decreases over time.
Hi Ron,
The 61 well model would have about a 7.7 Gb URR if 61 new wells per month were added until March 2040 (28,500 total wells in Bakken/Three Forks from 1951 to 2040).
This assumes about a 4% annual decrease in new well EUR from June 2019, note that the USGS estimates a 95% probability that 2P reserves will be more than 7.7 Gb and 2P reserves at the end of 2012 were about 5.7 Gb. At the end of 2015, 2P reserves were about 7.2 Gb in the North Dakota Bakken/Three Forks. My guess is that the 61 well model is pretty conservative and the USGS F95 estimate (from April 2013) is likely to be the minimum output from the ND Bakken/Three Forks.
This assumes about a 4% annual decrease in new well EUR from June 2019,
Really now? 4% annual decrease in EUR? Dennis! Oh my God, Dennis, surely you see the absurdity in such an absurd estimate of annual decrease in EUR! And what about the period the period between now and June 2019? Are you assuming 0% decrease between now and then?
note that the USGS estimates a 95% probability that 2P reserves will be more than 7.7 Gb and 2P reserves at the end of 2012 were about 5.7 Gb.
Dennis, the EIA has lost all credibility with their prediction that the Backken will be producing 2 million barrels per day in 2040. That number is absurd beyond belief. If you are going to make some prediction about Bakken future production you need to find some source of data other than the EIA.
Hi Ron,
The USGS is not the EIA. It is the United States Geological Survey (USGS).
So far the EUR has been stable (or increasing) from 2008 to 2016, perhaps it will decrease before June 2018. My model has a gradual decrease in new well EUR from June 2018 to June 2019 from 0% per year in June 2018 to 4% per year in June 2019 if the rate that new wells are added is only 61 new wells per month.
If the rate that new wells are added is higher then new well EUR will decrease more rapidly.
The rate is consistent with the USGS estimate which is also consistent with proved reserves.
My estimates are based on the data.
Dennis, the EIA gets their “proven reserves” data from the USGS. The USGS does not, to my knowledge, make predictions about the future production of oil. They leave that chore up to the EIA.
It does not make one whit of difference where the data comes from. The idea that the Bakken will be producing 2 million barrels per day in 2040 is just downright stupid, stupid beyond belief. And whether that very stupid prediction is based on the USGS estimate of Bakken reserves or the EIA’s estimate of future Bakken production makes not one whit of difference.
Question: Do you believe that the Bakken will be producing 2 million barrels per day in 2040.
Hi Ron,
No I don’t think the EIA’s output estimates are very good.
Short answer is 125 well model would have 250 kb/d in 2040.
I use the USGS TRR estimate (10 Gb at least) as well as the past well profiles to model future output. My EUR for the average Bakken well is about 320 kb over a 22 year life and the rate of decrease in new well EUR depends on the rate that new wells are drilled. If we assume 40,000 total wells are drilled, a 5% annual EUR decrease with 125 new wells per month added results in a 10 Gb URR, but profitability issues would result in only 33,000 wells and a URR of 9.2 Gb. Output in June 2040 would be about 200 kb/d and the secondary peak would be 1090 kb/d in 2020.
Well I must say 200,000 bpd sounds a lot closer to what the Bakken will be producing in 2040 than does the 2,000,000 that the EIA is predicting.
But we will just have to wait and see. After all I will only be 102 in 2040. No problem, I’ll make it. 😉
Hi Ron,
I hope so. 🙂 Of course my prediction will be wrong, but I think it will be closer to reality than the EIAs prediction a more realistic guess would be 200 kb/d+/-200 kb/d (0 to 400 kb/d for ND Bakken/Three Forks output in 2040).
“This assumes about a 4% annual decrease in new well EUR from June 2019”
I agree with Ron, 2019 is not realistic. I think 2012 or maybe even earlier. No later than 2013 at least. Later production profiles may look similar now, but they have higher GOR and water cut and also higher decline rates.
The EUR you are talking about is for the core area only. I think there may only be about 3000 locations still available there, which means drilling there will probably stop sometime in late 2019. The rest is non-core, the EUR per acre for most of that might well be zero no matter what the oil price.
Hi George,
If we assume 14,400 wells are drilled URR would be 4.7 Gb. Cumulative production and proved reserves at the end of 2015 were 6.2 Gb for the ND Bakken.
I think there are likely to be more than 14,400 wells drilled, probably 25,000 to 30,000 total wells which would result in a 7 Gb URR. USGS thinks the TRR has a 95% probability of being 10 Gb or more, but high oil prices would be needed (over 120/b) imo.
There are over 15,000 wells listed in the ND DMR production page, so I’m a bit unclear what your 14400 represent. Assuming a core of 50 km radius would give one well every 134 acres for those wells – I don’t think there is anywhere that can support that.
Hi George,
I am only counting Bakken or Three Forks wells, based on the data gathered by Enno Peters there were 11,452 of these wells that had been completed from 1951 to Dec 2016 with all but 189 of the wells completed since Dec 2004. I added 3000 wells to this estimate to come up with 14,452 wells. If that is too many for the “core” area, then there are some wells that have been drilled outside of the core area. My average well profile is based on all the wells drilled from Jan 2008 to Dec 2015 (a little more than 10,000 wells), I do not know how many wells there are in the core area, but in some cases there are multiple layers that are accessed in the core areas.
Do you believe oil prices will remain below $60/b until 2020? The oil price will have some influence on output, non-core areas may be profitable at $90/b or above and at some point World oil output will plateau and oil prices are likely to rise. Also proved reserves and cumulative production for the ND Bakken/Three Forks are higher than a model that limits total wells in the ND Bakken/Three Forks to 14,450. I assume that you doubt the proved reserve estimates reported by the EIA. Cumulative output at the end of 2015 was 1.6 Gb. Proved reserves about 4.8 Gb. Even an assumption of no probable reserves (which is a little conservative) gives a URR of 6.4 Gb. USGS F95 TRR estimate at the end of 2012 was 10 Gb.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RCRR01SND_1&f=A
There might be 4.8 Gb left, there might be more, it’s probabilistic. But however much is beyond what can be achieved with another 3000 wells in the core will have to come from the non-core. The wells will be different and inevitably new production will come on line with much more effort (and money) and be much slower to arrive than the core wells developed immediately before. You might be right with 30000 wells – but they won’t be anything like the ones we are seeing now.
I don’t believe there are segregated sweet spots. There is the core, which is approximately a 50 km circle with a couple of bulges in and out, there is a strip around the core of 5 to 15 km which might have some reasonable oil reserve, there are smaller producing areas to the north and south, and there is a whole stretch of non prospective area surrounding these. The USGS and EIA seem to think there is oil in this last area (actually huge amounts of it by some of the EIA scenarios), despite the fact that the E&Ps drilled a lot of wildcat wells dispersed through it (generally in a ring just outside the periphery of the producing areas) up until 2012. These came in dry and then, despite still rising oil prices but as would be expected, they stopped drilling there, and they won’t be going back.
Hi George,
I don’t pay any attention to the EIA estimates, but I think the USGS knows what it is doing. I misremembered the USGS F95 ND Bakken/Three Forks estimate, it is 7.4 Gb not 10 Gb as I stated earlier, so only about 1.2 Gb more than proved reserves plus cumulative production. In conventional reservoirs typically (or on average for the fields of large oil province such as the North Sea or US) probable reserves are about 50% of proved reserves. At the end of 2015 there were about 4.6 Gb of Bakken/Three Forks proved reserves in North Dakota, if probable reserves were 1.2 Gb, this would be only 26% of proved reserves for a total 2P reserve of 5.8 Gb. The mean USGS estimate for ND Bakken TRR is 9.8 Gb which may be optimistic. Based on Drilling Deeper, probably 24,000 to 28,000 total wells in the Bakken/ Three Forks may be realistic if oil prices are high enough. Using my model with 26,000 total wells drilled and EUR decrease starting in Dec 2016 and reaching a maximum annual rate of decrease of 2.5%/year and 85 new wells per month added until 26,000 total wells are completed in 2031, the cumulative output is about 7.4 Gb by Dec 2040. Output reaches a secondary peak of 892 kb/d in 2017 and output falls to 851 kb/d in Jan 2023 and to 728 kb/d in Jan 2031, in Dec 2040 output is 98 kb/d in this scenario.
The USGS report used data given to them by the E&Ps, which was probably generated in 2010 and 2011 when they were still drilling wildcats all over the place (i.e. they didn’t then know what was out there). The drilling deeper report is a review of the USGS report, it has no knew data. The only thing clever the USGS did was apply probability functions (almost certainly based on conventional field examples rather than shale) to the data and then run Monte Carlo, which they seem very fond of. It is not accurate.
There have already been over 33000 real or potential wells in ND, most around the Bakken core. over 6000 are dry, over 5000 have been abandoned and nearly 4000 have had their permits cancelled – thats almost as mnny as there are producing wells. None of those areas have any more oil.
Hi George,
I only count Bakken/Three Forks wells, not the wells in other formations. I also don’t count the dry holes, just wells that have produced oil. So far it has been about 11,500 wells. I don’t know how many will be drilled, but if we assume that oil prices won’t be low forever and that the oil companies proved reserves are conservative estimates (F90 is typical), and further assume it is unlikely that probable reserves are zero, then 7 to 7.5 Gb seems a pretty reasonable estimate to me.
What is your URR estimate if oil prices rise to $100/b and remain above that level from 2020 to 2030? Are you thinking 4 Gb?
That is about what we get if there are 14,500 wells total drilled in the Bakken/Three Forks and the average EUR is 275 kb. That is quite a bit lower than cumulative production plus proved reserves. About 22,000 wells would be needed to reach 6.2 Gb (proved plus cumulative) if we assume the average well produces 275 kb in the ND Bakken/Three Forks.
Hi Freddy W,
We do not know the future output of recent wells, but so far the well profiles look very similar to the past. I am assuming the USGS f95 TRR estimate is about right (10 Gb) and that along with what we know about past well profiles is the basis for the model. So far it has done pretty well, but if the well profile changes drastically as you seem to assume, then output will be lower in the future than my model.
No need for it change drastically. A 4% change in decline rate would not be noticable until after several years. Especially when there is noise in the data.
Hi Freddy W,
So far the changes are speculative in my opinion, we do not know what the future well output will be, we can look back at well profiles over several years and assume future wells will look like older wells or speculate on how they might change in the future. It is a guess either way. For 2009 to 2014 Bakken wells from 50 months to 89 months I get about a 10% annual decline rate based on data from shaleprofile.com.
For my well profile for 2015 and later the decline rate from 50 to 89 months is steeper at 18%.
Hi Freddy W,
You are correct that a change in EUR will only be apparent after several years, it is possible that such a change has already started but just cannot yet be seen in the data.
Hi Ron,
Actually I misstated the EUR assumptions, the decrease in new well EUR is assumed to begin in June 2017 and the rate of decrease increases by 0.33% (annual rate) each month until June 2018 when the maximum annual rate of decrease of 4% per year is reached. Through June 2016 there has been no apparent decrease in new well EUR since Jan 2009, in fact EUR looks like it has been increasing over much of this period.
The fact is we do not know what the output of these wells will be in the future, I have assumed the future output of wells drilled in 2015 will look much like the wells that had been drilled from 2008 to 2014, that assumption may be incorrect, but so far that assumption has resulted in an underestimate of actual output, perhaps the model will overestimate future output because more recent wells will have lower cumulative output than older wells, we can only guess at the future well profile.
Dennis, I don’t doubt that drillers have figured out how to get more oil per well by longer laterals and more fracked stages. So it is only natural that production per well should increase until… until… all the sweet spots have been drilled up. So as they move from the sweet spots out to the fringes, there can be no doubt that EUR will fall off quite dramatically.
Of course they could still drill more wells in the sweet spots, in between the wells that have already been drilled. The below chart is from just over thee years ago. At that time well production in the sweet spots was already starting to drop off due to closer spacing.
WELL INTERFERENCE IN THE BAKKEN
Hi Ron,
I also expect the new well EUR will decrease, but so far the data does not show this. My model assumes EUR will decrease starting in June 2017 and at 75 new wells per month the annual rate of decrease will be 3% per year from June 2018 on (with a gradual increase from 0%/year to 3%/year over a 12 month period. Also note that a higher completion rate would increase the rate that the new well EUR would fall, for example if 113 new wells were added each month the EUR would decrease at a maximum rate of 4.5%/year.
Chart below from Enno Peters website
https://shaleprofile.com/index.php/2017/02/15/north-dakota-update-through-december-2016/
It is cumulative production grouped by year of first flow from 2005 to 2016.
Dennis,
To stay with the truth, see below chart, which was your prediction. You did not foresee the long price decline and you did not foresee the Bakken production decline. And you still do not foresee the further declines of Bakken and you still do not understand the reasoning behind it.
Verwimp is spot on with his model, yet you cannot claim that your model is right. You have been backpedalling and adjusting your huge errors to reality all the time.
ha
Hi Heinrich,
Yep that model assumed a lot more new wells would be added and was wrong.
The model assumes 150 new wells would be added each month. Note that from Jan 2012 to Dec 2015 the average number of new wells added per month was 153.
If oil prices rise to $100/b in 2015 US $, it may be that the number of new wells per month rises to 150 per month.
At present I expect somewhere between 61 and 125 new wells per month may be added in the future and the path in actual Bakken output will fall between these two scenarios.
If you tell me future oil prices accurately, I will give you a better estimate of future Bakken output. Verwimp’s model will require very low future oil prices, less than $30/b from 2018-2021, does that sound about right?
Verwimp’s model will require very low future oil prices, less than $30/b from 2018-2021, does that sound about right?
No, I don’t think that is right at all.
Bruno says his model is based on geology, not economics, (price). Apparently you disagree. Could you elaborate on why you disagree? That is, do you believe that there is plenty of oil in the ground and that only the price determines what oil production will be in the future.
Remember we saw oil in over half of the world’s producing countries decline when oil was was around the $100 a barrel range for over three years. Price did not increase their production levels. The real arbitrator of oil production is geology. Price is important but that comes in second to geology.
Geology will determin the future oil production of the Bakken, not price.
Hi Ron,
Price and geology determine oil output.
Are you of the opinion that the price of oil has no influence on oil output?
If so I strongly disagree.
I also disagree with the proposition that only the price of oil determines output. It depends on many factors, including demand for oil.
Oh and the geologists and geophysicists at the USGS think the URR of the Bakken Three Forks (of North Dakota and Montana) is likely (greater than 95% probability) to be more than 7.7 Gb.
The estimates of Bruno and Laherrere are based on Hubbert Linearization which does not tend to give very accurate estimates. It might give a minimum URR, but tends to underestimate actual URR. Geology alone does not determine output, ask Mike and Shallow sand, the oil price matters and so does geology.
I wrote: Price is important but that comes in second to geology.
You replied: Are you of the opinion that the price of oil has no influence on oil output?
Errrrr…. Dennis, I think you have a problem…. Please try to comprehend exactly what I wrote before disputing something that I did not say at all.
Thank you!
Hi Ron,
I focused on your concluding statement which contradicts what was written before.
Geology will determin the future oil production of the Bakken, not price.
The statement above implies the reverse of your earlier statement.
Generally people focus on the conclusion.
You conclude that geology determines output, not price.
I repeat that both are important, and suggest that geology and the price of oil will determine output.
If the price of oil is too low, geology will not be important, the oil that could be produced profitably at higher prices will be left in the ground. In that case geology determines very little. In the case of a high oil price scenario geology will determine output and your concluding statement would be correct in my opinion. There is no a priori reason that oil prices will be high over the long term, eventually high oil prices will lead to substitution of other forms of energy for oil for many uses and oil demand may fall to a level that leads to low oil prices where a lot of expensive oil may be left in the ground.
Dennis,
If price is so central to future production, how do you explain the uncanny success of a price-independent model for 42 months including pinpointing a 180-degree reversal point?
Also, consider that profits, not price (i.e. Revenue), is what should determine capital decisions, in theory. If full-cycle profits are below zero both at $50 oil or $100 oil, which they have been for shale companies for the last five years, then why should price matter
A better explanation is: shale companies are clearly pumping at all price/profit level to generate cash for debt and dividend payments, AND THEN plugging any difference with more debt and equity raises. Not the other way around.
Hi Yaman,
When oil prices were high in 2014, the debt had stopped increasing and Bakken focused oil companies were mostly funding capital expenditures with cash flow rather than more debt, a slight cut back on the rate of well completion would have allowed them to pay back debt. The model was a lucky guess which coincided with an oversupply of oil and a price crash.
You do see that lower prices will translate lower profits, I hope.
Let’s say at $100/b a company was barely profitable (or losses were $0.01/share), now let’s assume ceteris paribus that the oil price drops to $50/b, what do you think happens to the companies profitability?
My guess is that it would be lower and capital expenditures would be reduced as much as possible such that fewer wells would be completed.
It turns out that this guess was correct, though to be honest I expected there would be even less drilling than has been the case, notice my 3 Gb scenario at an oil price of $71/b that I did in December 2014, my scenarios were too pessimistic, for output even though I was too optimistic on the oil price.
I did not account for the momentum of drilling that had already begun and the fall in costs that would occur as well completion ramped down, or the continued access to credit for these companies that were continuing to bleed cash.
Perhaps oil prices will remain low long term in which case the LTO sector will become bankrupt eventually. The wells already completed may be picked up by independent oil companies if the price of the wells is cheap enough and the oil will be produced from existing wells.
I expect more wells will be drilled if oil prices rise to more than $90/b, which might occur by 2018, depending on output from OPEC and Russia.
The past success of a model says nothing about its real capacity to predict the future. Two factors are at play:
– There is an unlimited number of different models. It is a given that some will approximate future reality.
– After fact you will only get information about successful models.
I think nearly 100% of people here will believe that both geology and oil price play a role in oil production. I think nearly 100% of people here will believe that the coincidence in US tight oil decline after many years of increase, and the oil price crisis is not due to chance, and both are related.
Then, why some people are ready to believe that a model that leaves out an important factor as oil price will accurately predict future oil production? Is it a question of believing your lying eyes instead of your thinking mind?
We know that one of the problems in the present oil crisis was that too much oil was produced by US tight oil industry for what was demanded, creating an inventory surplus. Too much oil is not exactly what a depleting geology predicts, and that was the reason Peak Oil got toasted in 2010. It is an indication that a model that predicted the present crisis based only on geology simply cannot be right.
As in science we learn from models when they fail to reproduce reality. If they reproduce reality we don’t know why and therefore we don’t learn. If anybody believes he understands oil production enough to accurately model it he should not be here. He should be elsewhere expending his many millions.
“I think nearly 100% of people here will believe that both geology and oil price play a role in oil production. I think nearly 100% of people here will believe that the coincidence in US tight oil decline after many years of increase, and the oil price crisis is not due to chance, and both are related.”
Exactly. It is impossible to ignore the price factor.
“Then, why some people are ready to believe that a model that leaves out an important factor as oil price will accurately predict future oil production?”
I will be willing to admit that this model works only when and if oil prices reach $70-80 and Bakken production continues to decline. Current Bakken well head price is only $40, a $12-13 discount to WTI.
Javier,
There is very simple reason why model should leave out the oil price. It is because you can’t model stupidity. You just can’t model stupidity of human mind. Shale, as marginal player, should not be drilling for the last 3 years. But they were drilling. And in Permian it is full steam ahead, pedal to the metal. So you got that backwards about lying eyes and thinking mind. Eyes are not lying but thinking mind is telling you stories.
You should drop thinking mind and you will clearly see that there is less and less oil to support this kind of capitalism and financial markets. Too much debt is issued and oil is losing its mojo to service it. So the wheels are coming off. And also if you observe fake political class infighting you will also clearly see that only question for them is how to break the truth to the public.
AlexS,
” Exactly. It is impossible to ignore the price factor.”
Really? People do it every day and ignore the price factor in their daily lives. If that is not the case than who made their personal debt?
Oil Companies, Governments are no different. They are made of people.
Ves,
After the sharp drop in oil prices, oil companies have cut their capex 2 to 3 times; a lot of projects were postponed or canceled.
Ves,
I might agree with you on everything and I would still not believe the predictions from a model that ignores oil price, since it is known to be an important factor.
This is the same as making a model of personal weight loss taking into account calories intake, but not exercise. If that model accurately describes weight loss by a person, you can assume that said person does not exercise at all, or other factors compensate for the effect of exercise (genetics, disease). What you don’t do is to think that the model works correctly. When that person changes its level of exercise, the model will stop “working.”
AlexS,
Capex is imaginary figure in FUTURE and not reality in the PRESENT. Capex is irrelevant number, it is just some written $ figures on power point. It takes 3 seconds to cut Capex. You cut production if you want to balance the market. But that is hard in current hamster wheel financial system. So what do you do? Well there is always so called re-packaged bankruptcy where you shed the debt, pretend and continue to drill sweet spots until there is no more. So low prices continue.
Ves,
Lower imaginary capex leads to less imaginary rigs drilling less imaginary wells.
That results in less imaginary production of imaginary oil, which imaginary refineries process into imaginary gasoline, imaginary diesel and other imaginary products.
Then imaginary people pay imaginary $$ to fill imaginary tanks of their imaginary cars with imaginary gasoline. Finally they get their imaginary homes and see their imaginary families.
AlexS,
But they are still imaginary capex and $ because they are in the future. And future is always a hope, a dream. Reality is that oil industry is bankrupt today like the rest of the economy. But it is very hard for humans to live in present so they always live in future. So oil industry is waiting for that $120 in future because present is very ugly and disturbing. But in the meantime debts are piling, production is decreasing, cost inflation is increasing and when future becomes today it is still ugly so they move to future again.
Ves,
Oil companies have spent much less in 2015 than in 2014; and much less in 2016 than in 2015.
That resulted in less drilling and completion activity, and hence – lower production.
I do not undestand why are you talking about the future.
My interpretation would be that yes, companies have cut back on capex recently. And there is perhaps no reason to assume they will ever increase capex again. If economically and geologically it no longer makes sense to continue to look for new discoveries and to try to coax more oil out of the ground, then it might make sense to plan for a future where you divest and get money out of your company as you can rather than waiting until the money runs out and no one wants to buy your assets.
“…according to Barclays’ latest E&P spending survey, North America spending will increase 27% in 2017, after a decline of 38% in 2016”
http://www.ogj.com/articles/2017/01/barclays-global-e-p-spending-expected-up-7-in-2017.html
That Barclay’s article doesn’t tell us anything we don’t already know. People are throwing money at the Permian, but not so much in the rest of the world. It could just be another short-term boost like we saw with the Bakken.
“North America spending will increase 27% in 2017, after a decline of 38% in 2016. …
International spending will increase 2% in 2017 after falling 18% in 2016.”
Upstream capex in general, and North American capex, in particular, is highly cyclical.
During the oil price downturns cuts in NA spending normally begin earlier and are deeper than in international spending.
When oil prices rebound, US E&Ps are the first to increase capex and these increases are steeper than outside the US.
International capex will rebound in 2018.
“When oil prices rebound, US E&Ps are the first to increase capex and these increases are steeper than outside the US.
International capex will rebound in 2018.”
That’s been your response to everything. We’ll have to wait and see. I think the major companies will not be expanding capex. I think they are doing more to keep their stock prices high and paying out dividends than investing in the future. And I think the smaller US companies are drilling as long as the money holds out.
Again the future of the Bakken seems to me to be important in terms of predicting how any LTO field will do. If these are short-lived and there aren’t any new major discoveries, I don’t think additional capex investment is going to result in significant production. And if not, why do it?
“Oil companies have spent much less in 2015 than in 2014; and much less in 2016 than in 2015.”
AlexS,
So what that tells you? Higher production would create more debt and lower production will just create less debt if we look at just NA production. Look the situation in the rest of the world is not pretty either but in NA we can see extreme paradox. Oil customers/consumers are 1 trillion in debt in outstanding car loans and oil producers are also in debt by pumping oil at loss so that 1 trillion debt can be serviced by enabling these same customers to drive around in circles with their “no added value” jobs. And that is just car loans debt.
Also, if the reason capex was reduced was oil prices, then increased production in the US will continue to likely keep oil prices low, which will continue to keep capex at a reduced level.
Hi Heinrich,
You seem to not understand the difference between a prediction and a scenario.
A scenario asks a question such as: “If the EUR of the average new ND Bakken/Three Forks well starts to decrease in June 2017 and reaches a maximum annual rate of decrease of 5.5% in Jun 2018 and 150 new wells per month are added until 40,000 total wells are completed (from 1951 to 2033), then what would the output profile look like.
The chart is from the comment below
http://peakoilbarrel.com/bakken-december-data-big-decline/#comment-560046
The scenario above suggested if the oil price had only fallen to $80/b rather than $50/b or less we might have seen more wells completed. It was simply a “what if” question and not meant to be a prediction.
Taking the chart out of context is a cheap shot.
Hi Heinrich,
Another chart from that thread is explained in link below (2/17/2016 at 6:15 PM)
http://peakoilbarrel.com/bakken-december-data-big-decline/#comment-560046
Hi Heinrich,
At the comment below is a scenario from December 1, 2014 at 2:03 PM
http://peakoilbarrel.com/peak-oil-2014/#comment-460454
A chart with 3 different price scenarios, low, medium and high. The low and medium are the same price scenarios as my previous chart and the high price scenario has real oil prices rising at 4.9% per year from $70/b in Jan 2015 to about $140/b in Jan 2030 about twice as fast a rate of increase as the medium price scenario. Reality will be somewhere between the low and high scenarios, but my guess is that between the medium and high scenarios is more likely than below the medium scenario.
My guess from Dec 1, 2014 for output was pretty good as output from Oct 2014 to Dec 2016 did indeed fall between the medium and high scenarios, though my oil price predictions were far from the mark, as usual.
If you follow the thread, Ron thought the low scenario was far too pessimistic and said,
I doubt there will be any real decrease in wells completions until the middle of 2015…
see link below for full comment
http://peakoilbarrel.com/peak-oil-2014/#comment-462037
if we consider the centered 12 month average of well completions the completion rate fell from 183 to 120 from Oct 2014 to June 2015.
My guess on oil prices was wrong, as usual 🙂
Watcher also asked about my scenario from 6 months earlier (June 2014), which is at link below:
http://peakoilbarrel.com/peak-oil-2014/#comment-463047
In June 2014 my “low oil price” scenario was $80/b, the EIA’s AEO reference scenario had oil prices much higher than this at the time, the low ERR and low price scenario (dashed orange line) with ERR of 4.3 Gb was based on oil prices fixed at $80/b in 2013 US$ and the USGS F95 TRR estimate for the ND Bakken/Three Forks from April 2013.
Less flow = less revenue. More debt being taking on, on top of all the current debt that is, in order to keep it going. So your trying to service and ever increasing amount of debt with less revenue. This is going to break at some point. Those red dots on Verwimp’s model will suddenly fall well below the green line they have been tracking so close to. Verwimp’s model might be best case scenario. With the possibility of it being much worse. Due to unpayable debt.
Hi HHH,
If oil prices remain low you may be correct, if oil becomes scarce, what do you think will happen to the price of oil?
Let’s assume oil scarcity results in higher oil prices, what do you think will happen to oil company profits when oil is $100/b? My guess is that they will increase and debt will be paid.
I don’t believe $100/b will dig them out of the hole they dug themselves drilling wells while price has remained low. I don’t believe they can get a high enough price to make them whole again. They might all be bought for pennies on the dollar then possibly someone could make money there. Those debt will never be paid. To drill outside the sweet spots in the Bakken they really need closer to $120/b maybe just maybe one day oil reaches $120/b and companies go in and get what is left. That won’t change a thing about the fate for current operators in the Bakken. Only thing i see that could possibly offset some of this is revenue coming outside the Bakken say from the Permian might keep some of them afloat a little longer.
Well said, HHH; that pretty much sums it up. Most people analyzing LTO well economics, and the financial ability of America’s LTO companies to contribute to our energy needs in the future, conveniently leave out debt and the ramifications of debt.
Much higher GOR in the Bakken, a sure sign of depletion, is creating an opportunity to fabricate much higher EUR’s and make shale oil companies look better than they actually are. Nevertheless, Enno Peter’s data does NOT suggest to me, or others, that 2014, 15 and 16 wells will have 500-600K BOE UR’s. Regardless, at oil prices below 40 dollars in the Bakken, that is barely sufficient UR to even reach well payout ! I therefore concur with Shallow that 95% of Bakken wells drilled since 2014, or anywhere else in the country, is simply a waste of our country’s remaining hydrocarbon resources.
Some of us are tracking water production in the Bakken, and the reasons for its increase, and find that alarming. That is also a sign of depletion and produced water, the albatross around the neck of ALL oil production, will cause economic limits to occur sooner and shorten decline curve tails. Given so much of the great Bakken production came from just a few counties in N. Dakota, and sweet spots in those counties, I personally believe the Bakken is dying a slow, ugly death now and production there will never exceed its previous highs, as Mr. Patterson suggests, not without throwing a half trillion foolish dollars at it. Moving off those depleting sweet spots into flank areas will result in higher costs, and much lower well quality. He is correct about that, also.
Geology, rather the current state of the resource place, is not all there is to it, no. Product prices DO matter, also, as to how much of predicted TRR will actually be recovered, but not so much in these unconventional shale oil plays, not in my opinion. Costs are too high, decline is too great and borrowing money to develop these plays (the only way it can be done, short of a Watcher fix) simply does NOT work at less that 85-100 dollars a barrel. Anybody denying that has been on holiday on Mars the past eight years.
Lastly, about this incredulous need to predict and model the future of shale oil production in America: geology matters (see above), costs of extraction matter, product prices matter, profitability matters; the FED, politics, currency values, taxes, available water, anti-frac’ing sentiment, the age and experience of the work force in the industry, corporate finances, alternatives, a millennial generation fast becoming urbanites, demand(!), recessionary trends, recessions, inflation, debt, debt deflation and more debt… all those things affect the future of hydrocarbons. It is not sufficient to simply say oil will become scarce and prices will go up. That’s an old perspective and its a new world.
The only “DATA” to be used in the oil business effectively is realized production data, like that in which Enno Peters provides. The EIA, the USGS, the IEA, PETA and the NCAA; they are ALL just guessing about reserves and the future. The E in EUR stands for estimated and the T in TRR is for technically.
What a refreshing dose of reality (for a change). Thanks Mike. Oops, when I say “for a change” I don’t mean a change from your other comments. I mean a change from the prattle of so-called oil analysts who wouldn’t know rod grease from the Vaseline they use to lubricate their girlfriends.
Mike: There are a load of non-operated Bakken WI presently for sale on energy net.com.
I don’t know if I will have time to summarize 8/8 costs, but there are some eye popping expenses. On many wells, water hauling alone is running $6-8,000 per month.
Zavanna seems to have the lowest per well charges, with WLL, CLR, EOG, Hunt and Triangle all being represented as operators of wells that those non-operated owners are trying to sell out of. Two Parshall wells of EOG on there, they have tremendous cumulative oil, but now not so good and LOE really high.
Looks like they all become stripper wells eventually.
Hi Mike,
The EUR that I use is based on Enno Peters data. It is 321 kb over the life of the average well. Yes $85/b is needed to make a reasonable profit on an average Bakken/Three Forks well that is completed today. Proved reserves in the ND Bakken Three Forks were 4.8 Gb at the end of 2015, cumulative output was about 1.1 Gb at the end of 2015, probable reserves are likely to be another 2.4 Gb, so a very conservative URR estimate would be 8.3 Gb. The USGS F95 TRR estimate for the North Dakota Bakken/Three Forks is about 10 Gb and by that estimate there is about a 5% probability it will be less than 10 Gb.
I suppose it is possible oil prices will remain low for the long term, but I think that is unlikely.
Lots of factors affect oil output, everything is interconnected, but a theory of everything is a little beyond my ability.
Models are simplifications of reality, they focus on the most important aspects of the problem.
Clearly the future is unknown, we just do our best to frame the likely possibilities so we can prepare for what may come to pass.
Thanks, Doug; very much. A quite famous oil man told me one time the only thing to count on in the oil business is what just happened, and sometimes even that is hard to digest. You’ve been there, seen that; I trust you understand what I mean, as does anyone with any experience whatsoever in actually trying to make money in the oil production business.
I hope you are well, sir.
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require the addition of an average of about 95 wells/month (61 wells/month were added through 2016).
In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent. This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus a steeper decline in production.
Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16).
To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17.
To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI).
To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return.
Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B.
Write downs/impairments shrinks the affected companies’ assets/equities and thus debt carrying capacities.
Some make forecasts about future developments without considering the companies’ balance sheets.
At present oil pries (low/mid 50’s) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and “new” wells.
For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations.
Rune, thank you for this post.
Rune-
Thank you as well.
Your work product is excellent. When Rune talks, people should listen.
Brook
Hi Rune,
Thanks.
My number of wells added was based on the previous 12 months (61 wells per month), the recent rise to 82 wells per month, and then an optimistic scenario where oil prices rise to $85/b.
You are correct my analysis does not consider company balance sheets, but only considers profitability on a point forward basis.
In this case the model was simplified to only consider what output would look like if oil prices rose to a level that would induce companies to drill 61, 85, or 125 new wells per month. I think it likely the path of output will fall between the 61 and 125 well cases unless there is a severe recession which may lead to lower oil prices.
One item which I consider important is debt redemption profiles. It is possible to estimate what it takes for a company to retire its debts in an orderly way. This is one item whereby creditors may be able to influence both what a company has available for funding for the manufacturing of wells and thus influence the production profile.
As the debt nears maturity the company is in reality faced with 2 alternatives:
1) Retire its debts, that is put away money from operations.
2) Full or partial roll over the debt, that is, replacing existing/portion of debt with a new debt with later maturity. This may be a hard one if production (rather revenues/net cash flow) is in decline and it comes with a higher interest cost.
Anyone know if we can say … The US was a NET IMPORTER of NG for 2016?
Looks like it’s close to net zero, but perhaps imports will rise now with strong demand and production plateau [??}
http://fingfx.thomsonreuters.com/gfx/ce/3/500/500/US%20NATURAL%20GAS%20MARKET%20–%20SELECTED%20INDICATORS.pdf
I notice that this blog post, “Is The Bakken a Bust?” has been picked up by a number of websites.
And then when you have the WSJ saying that maybe Canadian oil sands should stay in the ground, I wonder if there is now finally an awareness among at least some members of the business media that oil won’t continue to flow indefinitely.
There are still articles being written about how great the Permian is, but I am not seeing articles about how the Permian is going to solve all of our petroleum issues, which you did see when the Bakken was booming.
“Land Rush in Permian Basin, Where Oil Is Stacked Like a Layer Cake”
https://www.nytimes.com/2017/01/17/business/energy-environment/exxon-mobil-permian-basin-oil.html
“The Permian, in production for almost a century, is so bounteous that it fueled the Allied forces battling Germany and Japan during World War II. In recent years, though, the basin had been in decline, and big oil companies like Exxon Mobil sold assets to small independents that were willing to scrape the remaining barrels of old wells by flooding them with water and carbon dioxide.
The article does tout the Permian, but it still doesn’t promise decades of oil like articles were once saying about the Bakken.
This is what the article says about the Permian. It doesn’t say that the field is going to decline, but it doesn’t present the area in quite the same way as people used to write about the Bakken.
Tiny steps, perhaps, in how business writers are starting to view oil, but maybe they are starting to get more realistic.
“The geological virtues of the Permian, along with an existing robust array of pipelines, have made the basin the cheapest to develop of any shale oil field in the country.”
Okay. This is relevant to what I am saying.
If most of the trades are being done by machines, and if those machines are being influenced by business articles, then if those articles turn negative, the market could come crashing down.
Why Is Smart Money So Long In Oil? | OilPrice.com: “Jonathan Kinlay, PhD, Head of Research & Trading at Systematic Strategies LLC JonathanAlgorithmic Trading, provided a plain-English explanation of machine-driven trading and in particular how computers can be taught to ‘read’ the financial press just as we normal humans do. …
The key point is that financial journalistic verbiage is stripped down to key words or sentiment indicators, words or phrases like ‘successful,’ ‘market discipline,’ ‘supply reduction,’ ‘exceeding targets,’ etc. , and the so-called news-trading algorithm is based on the distribution curve of such sentiment. Orders to the futures pits follow. …
If machines really are the new market-makers in the crude oil futures market, then the prices they are spewing out may be as much a mirage as that found when travelling in the OPEC desert of misinformation and fake news.”
As Ron’s article gives deep insight what happens in the Bakken just a few additional thoughts. It looks like that the staunch performance of new wells comes at the expense of production when wells are getting older. So the decline in the field of 2015 looks especially steep. And 2015 was a year when new wells were very productive. So, there seems to be a trade off.
Secondly, the Bakken legacy decline in 2016 of more than 500 kb/d – this is the decline if no wells would have been drilled – is exactly what is documented in the EIA drilling report. In the drilling report the legacy decline is around 50 k per month, which is annualized 600kb/d. In my view, most people are not aware how big the annual decline in the shale patch has become. Total legacy decline for the Big Three (Bakken, Eagle Ford, Permian) stands at around 240kb/d which is annualized 3mill b/d. In other words, the industry has to stem the decline of 3 mill b/d at a cost of at least USD 75 bn with new drilling without adding any growth.
So, these USD 75 bn cannot be classified as capital expense, as capital expense implies investment in new capacity, yet it must be classified as operating expense or sunk cost. The same is the case for shale natgas production which has an annualized legacy decline of roughly 20 bcf/d or 3mill boe/d at a similar cost. So, USD 150 bn are sunk cost every year. And most investors think they have made an ‘investment’ for the future.
I am just wondering how this will be resolved when investors are weakening up to the fact that their ‘investment money’ has already been spent and they cannot expect any return and must fret to get the principal back at all.
Asked the other day if we have proof of recompletions being a frequently done thing.
EURs of wells can be corrupted in reporting by a recompletion. All kinds of definitional things can be done to obfuscate.
Let’s say you have an oil well and it starts dying. Then you do some kind of water flooding or CO2 stuff (ya I know this may not refer to shale) and you get more oil out. And declare it to be part of the original flow for Estimated Ultimate Recovery measurement.
Or you bring in the fracking pump and haul another 10 million pounds of proppant to the site, and get more oil and declare it to be the same well and the new oil adds to the old oil for EUR measurement.
But wait, suppose you ALSO bring in a drill rig and resnake that well out to “clean out stuff” and refrack and new oil flows presto, the executives add it to their presentations for 900K EUR barrels from wells.
And well, hell, lets drill another hole maybe 100 feet from the previous one and frack it and declare it all part of the same well and son of a gun if we don’t get 900K barrels out of wells now.
An awful lot of data of all kinds is bogus nowadays.
Watcher
Apparently that is already starting to happen, at least with some operators (Marathon/Oasis) in the Bakken.
I’ve not done much checking, but the FracFocus site should show that wells have been refrac’d.
The advances made with diverter material and techniques is encouraging some operators to refrac older wells on the same pad that new ones are being originally completed.
If it works, it could boost output significantly.
We do bring a rig to a well site, enter a well, plug the lower part of the wellbore, and drill another section out of the upper section of the hole.
If the new well section is relatively close to the abandoned well section, it’s usually called a redrill, but in some areas they call it a sidetrack (it depends on the regulations).
If the new well section is drilled to tap a different “spacing unit” it’s usually called a sidetrack, and the well name is changed by adding an X to the previous name. In some cases the operator requests a different API number, but I’ve seen areas where the number stays the same.
In conclusion, for general purposes it’s better to say it’s a sidetrack. Most people realize the actual legal and regulatory details for that particular site depend on the regulatory environment.
Can you explain how you arrived at $75 billion for NG drilling cost?
I hope by now most here have looked at shaleprofile.com. I took the following off of there. Hopefully I have the numbers right.
In December, 2014, North Dakota produced its highest oil output. In December, 2014, 9,892 wells with first flow in the years 2005-2014 produced 1,187,797 barrels of oil per day, an average of 120.08 barrels per day per well.
In December, 2016, those same 9,892 wells produced 491,531 barrels of oil per day, an average of 49.69 barrels per day per well.
2014 first flow wells produced 594,635 bopd in 12/14 and produced 157,309 barrels per day in 2016, just 69.09 per day per well.
If 2016 wells follow 2014 wells perfectly, in 12/18 they will produce 51,541 bopd.
Now, let’s look at economics on those 2,227 wells as a group. Assume 80% net revenue interest and $45 well head oil price in 12/16. So, 1,713 BO in 12/16 x $45 oil = $77,101 gross oil revenue. Severance taxes are $7,710. LOE is $14,000. G & A is $5,100. So net, excluding any CAPEX that may be required for down hole failures and excluding interest expenses is $50,291. Add in about $6,000 in natural gas income, after severance, and we are at $56-57,000 of income in 12/16 on wells that, in 2014, cost about $10 million each.
Per Enno’s shaleprofile.com, it looks like wells settle out in the 35 BOPD range. Those will generate about $20-25,000 per month of net income from $45 oil, $23-28,000 including gas. This, of course, excludes down hole failures. If we assume $100K annually of CAPEX for those, we are now down to $15-20,000 per month.
If the wells haven’t gotten close to payout in the first 24 months, they will struggle to make it at current oil and natural gas prices.
It appears to have been a serious financial mistake to put new Bakken wells on production since late 2014, in hindsight. Economically, the wells are weaker generally than our conventional wells. We have added zero since the 3rd quarter of 2014. The price is still too low to economically add new wells in our field, absent getting lucky with an outlier on the high side.
Didn’t you and Mike have a discussion of a downhole pump of some kind that priced at what, $100K?
shallow sand – I know better than to question your math, but I got lost.
You have 2 consecutive posts. The first one ends with: “If 2016 wells follow 2014 wells perfectly, in 12/18 they will produce 51,541 bopd.”
The second post starts with: “Now, let’s look at economics on those 2,227 wells as a group.”
So, I divided 51,541 by 2,227 and got 23.14 bopd. Later I read: “Per Enno’s shaleprofile.com, it looks like wells settle out in the 35 BOPD range.”
In between those two I read: “So, 1,713 BO in 12/16” So, I divided that by 31 days and got 55.25.
So I was mixed up: I seemed to read that 2014 wells are producing 55.25 bopd in 12/16, but 2016 wells will be producing 23.14 bopd by 12/18.
So, I backed up to [ in the 1st post]: “2014 first flow wells produced 594,635 bopd in 12/14 and produced 157,309 barrels per day in 2016, just 69.09 per day per well.” Dividing, I got 2,227.
So then I decided that the 2227 wells from 2014 were at 55.25 in 12/16.
So, then I divided 51,541 by 55.25 and got 933. So, I guess that there are 933 wells from 2016 in Enno’s shaleprofile.
So, I am going to reward myself with a 3rd Bloody Mary, before you can tell me that I am wrong.
Clueless. Sorry for being confusing, which admittedly my posts are.
There are 2227 2014 wells and 746 2016 wells.
The 2014 wells averaged 69.09 bopd per well. There are 746 2016 wells. If they average 69.09 bopd in 12/18 they will produce 51,541 bopd
I am assuming the working interest owners get 80% and royalty get 20%.
69.09 x .80= 55.3 bopd to the working interest owners.
Clueless, I am going to go over the numbers on the above posts and check them. Was interrupted a few times when I posted previously.
Ok, I messed up some numbers, sorry about that.
Again, from shaleprofile.com.
In December, 2014 there were 2,277 wells with first flow in 2014 that produced 594,635 barrels of oil per day. 261.15 barrels of oil per day per well.
In December, 2016, those 2,277 wells produced 157,309 bopd or 69.09 bopd per well.
In December, 2016, there were 736 wells with first flow in 2016 and those produced 244,953 bopd or 332.82 bopd per well.
If those wells produce an average of 69.09 bopd in 12/18, like the 2014 wells did in 12/16, the total bopd would be 50,850.
Will refrain from posting numbers without double checking first.
Hi Shallow sand,
I agree. Do you think when oil supply is too low to meet oil demand that oil prices will remain low? I do not.
If as I suspect oil supply (C+C output) remains below 82 Mb/d, oil prices are likely to rise well above $75/b. When this occurs, I do not know. My WAG is before 2019.
Dennis. There seems to be more things than just actual supply and demand that affect oil prices. Currency fluctuations seem to matter quite a bit. QE after 2008 seemed to drive oil prices back up quickly, in combination with a large OPEC cut, followed by sanctioning Iran.
There is far from perfect supply/demand correlation in my opinion. For example, the US industry is focused on way too much IMO. US inventories seem to matter much more than inventories elsewhere. Same with US rig count. Same with US production numbers.
I may be wrong, but other than 2009 and 2010, hasn’t worldwide supply and demand trended upward at a relatively even pace? Yet we have had periods of extreme price volatility. $10 WTI in 1999, then over $30 in 2000, back below $20 in 2001, followed by steady up in 2002, 2003, 2004-2007, super spike in late 2007 to mid 2008, over $100 drop from July, 2008 to December 2008. Rapid recovery starting in mid 2009. Very high prices 2011-mid-2014, followed by a drop all the way back to $26 in early 2016.
We have actually had pretty stable prices the last few months, low $50s on WTI. I have no clue where we go from here. It does appear OPEC and Russia desire higher prices. I think they figured out US financial markets are so deep that only $30s and lower for WTI really curtails US shale right now, an $30s and lower are not only too low for OPEC and Russia, but they start a deflationary cycle in world markets which compounds problems.
If OPEC and Russia are playing the long game, it would seem that they would shoot for price stability and let shale run its course. Let the US use up the shale as quickly as possible, even if it means giving up some market share for a few years.
Of course the peak demand theory runs counter to this. I am not convinced that peak demand is here yet. It will be some day, but that could be a few years or decades, I have no idea.
“If OPEC and Russia are playing the long game, it would seem that they would shoot for price stability and let shale run its course. Let the US use up the shale as quickly as possible, even if it means giving up some market share for a few years.”
That’s what I have thought we should do.
So it becomes a matter of who is more focused on the short term and who is more focused on the long term.
If they do see that the US shale areas will play out pretty quickly, they decide they can wait it out.
Also, they probably have more control over oil producers than the US does. We don’t have a coordinated strategy other than what investors are willing to do.
Currency fluctuations seem to matter quite a bit.
SS, the price of oil is listed in a currency. So if the currency fluctuates then the price fluctuates. That is like saying that if the price fluctuates then the price fluctuates.
QE after 2008 seemed to drive oil prices back up quickly,…
More money available to buy oil means more demand for oil. And if QE boosts the economy then you would naturally boost the demand for oil.
in combination with a large OPEC cut, followed by sanctioning Iran.
And of course that is supply. Inventories in the USA largely affects WTI while OECD inventories affect Brent more. That is one reason Brent is higher. But one often affects the other because both tend to follow world supply.
Day to day swings are called volatility for a reason. These swings sometimes last for only a few hours and sometimes for days or even weeks. Volatility swings are caused by traders trying to guess which way supply and demand will pull prices. Sometimes they are right and sometimes they are wrong. Short term swings are caused by traders guesses but long term trends are always determined by supply and demand.
Ron, I do not disagree with you. I assumed Dennis was referring to the oil price in terms of US dollars. Which I agree is US centric of me.
Note in the beginning I say I feel things affect the price (US) in ADDITION to supply and demand.
Another thing that affects prices that are most relevant (well head) are competition, both producers and crude purchasers. This, of course, can also be referred to as supply and demand. Our local basis has fluctuated quite a bit over the years, and most recently we are getting a better price because a new crude purchaser entered the area. Previously we were hurt on basis because a refiner didn’t want our grade of crude for awhile. Those are just local matters, but they are relevant issues, just like lack of ND pipe line access hurts ND prices.
Do you contend that supply and demand is the only reason US prices have been so volatile the last 20 years?
We sold oil for $8 in early 1999, for $140 in July, 2008, for $28 in February, 2009, for $99 in June, 2014 and $25 February, 2016. Last month we received $48.
Is the above volatility due to traders views of future supply and demand, in addition to actual supply and demand?
Is the above volatility due to traders views of future supply and demand, in addition to actual supply and demand?
No, not at all. Volatility swings are only a few bucks above and below the long term trend line. Those very huge long term price swings, lasting for months or years at a time, are due entirely to changes is supply and demand.
Shallow — The way I look at “traders views” is this: You and I can bet as much as we want to on the Super Bowl football game. We can try as hard as we want to, bet hundreds of millions of dollars, and I just do not think that we will have an effect on the results of the game itself.
Our bets do not matter to the players playing the game, nor the officials, unless they are on the take.
So the current and futures prices for oil likewise do not make any difference to the amount of oil supplied or demanded?
Or am I missing what you are getting at?
Shallow
Above, your comment regarding more than supply/demand affecting prices …
Exactly.
While Watcher’s ominous comments may frequently prompt some bemused collective response, make NO mistake, the very lives of the thousands of individuals from the House of Saud hang in the balance of a sustainable revenue stream from their hydrocarbons.
Driving down WTI below 27 bucks did not kill LTO.
Demonstrably, validating Nietzsche, the unconventional industry is coming back stronger.
The future may provide a great deal more volatility for all of us, far beyond the O&G arena.
Right. The traders might as well be locked in a room playing poker.
But, the media publishing what they do can have short term effects. If spec long positions rise, and people read that, they might think that prices are going to go up.
The real movement is caused by fundamentals – like 2 mile long fracs in shale and drilling in 10,000 feet of water. Both relatively recent events. The fact that you cannot drill in 10,000 feet of water, or start a new tar sands project, or drill in shale when the price is under $50 will eventually raise the price. Unless Boomer and Nathaniel are right and we stop using most oil by 2030.
We seem to be going back and forth about whether higher oil prices will increase production or whether production is already at the point where it can’t be increased.
That’s why the numbers from the Bakken are so important. We know that production slowed at the same time oil prices dropped. But if the Bakken has already given its best, then adding more money to that drilling there won’t help.
If all that is accomplished is that more production speeds up decline, and production increases with oil prices, investment money, and loans, then money more just speeds up the problems.
That’s what this forum is about. To what extent is production tied to oil prices and to what extent is geology not going to give up anymore oil.
Hi Shallow sand,
No supply and demand do not always balance which is why there is price volatility. Note I am defining quantity supplied and quantity demanded separately from inventory build or draw, when there is an imbalance there is a change in the stocks of petroleum.
My point is just that eventually demand will out run supply at current oil prices, stocks will decrease and eventually oil prices will increase.
My WAG is that in mid 2018 oil prices will be higher, but I always guess wrong on the price level so will not bother to do so.
@coffeeguyzz
Where OPEC went wrong in driving down the price of oil to hurt/kill LTO was not in whether or not it was profitable at $27. It is not. And I think Enno’s site and input from actual producers has proven that is not profitable at $47 or even $57. Where OPEC miscalculated was the strength behind the financing of LTO. And their ability to suspend the laws of economics regarding LTO.
And what is going on in the Permian is the biggest bubble I have seen in this business, but if the banks, wall street and Private Equity are willing to disregard actual numbers, then it will continue to inflate. Until they don’t.
It’s the same bubble as behind sub prime housing and now city appartment prices going skywards.
You only need the story going on and enough dumb investors. There is no shortage of both.
Hedge fond managers will be happy to buy all of this crap, because they speculate with OPM (other peoples money), and if these companies go boom they have already pocketed their big bonus checks.
Here capitalism works like good old socialism – you create ineffective projects and continue them.
The chart below shows well availability for the Bakken wells (i.e. total days on line divided by total available stream days. The drop in availability in December is obvious and the main reason for the drop in production. The effect is actually bigger than shown because there are about 1600 wells that don’t produce for all three months shown, but in December another 300 were added. In October and November about 9500 wells stayed on line throughout the month, but this dropped by over 3000 in December. The effect is over the whole area but strongest in Mckenzie and Williams, which are two of the biggest producers. For the wells on line there was also a drop in streamday production of 3%, but this might be related to bringing them on line after a shutdown. The confidential wells don’t have data for analysis for days on stream so they are not included. The wells that went offline in December but flowed in November averaged 40 bpd in November (higher on a streamday basis).
This can only be weather related. I couldn’t find a particular area that showed up with a lot of down time but there have ben reports of major gas lines hydrating off which would have a large local impact. But equally there may just be individual wells with local freezing or maintenance problems and the snow makes it difficult for quick resolution.
More of the same is likely to have happened in January, but availability should climb again in February.
Those numbers are really low. I guess the wells buildup enough pressure to justify what one would consider sloppy operating practice?
I know this is way off topic, and any discussion of it should go to the other thread, but some regulars here don’t read the non petroleum thread. Something tells me we’re mostly middle aged or older already, and peak oil won’t matter to us once we’re GONE.
This is not junk science.
https://www.scientificamerican.com/article/the-hunger-gains-extreme-calorie-restriction-diet-shows-anti-aging-results/
Beleive it or not, there have been reports of this starting years and years ago. The first ones were with rats. I know, because I started something similar in 1975. I eat no breakfast, no lunch, just supper. Sopmetimes I will eat supper at 6 pm, and the next day at 9 pm. During the day, I drink sugar free soft drinks. And, lately, some wine. I think that it works.
I have read some articles that say you can accomplish this by once a week going 24 hours without food. There is some cell function in the body that regenerates if there has been no food for 24 hours.
Clueless,
You can make wrong conclusion reading that article. It is not the hunger that makes you feel healthier. Hunger is just polar opposite of stuffing the food at any time. Mind can trick you very easily that you are hungry. If you have worked in corporate world you know the drill and that at certain time is a lunch break let’s say 12 noon. But did you listen to your body to see if it is hungry or not? Not really, because mind takes control and decides for the body and says “Let’s go and stuff some food because everyone in the office is doing it and who knows maybe I will get hungry later in a day when I will not be able to eat”
So we are on the way stuffing food in the restaurant at 12’00 clock when our body are not really hungry. After so many years of conditioning the mind can get you salivating about food by just looking at the clock on a wall. Dog will only salivate when sees the bone. We do not even have to look at the food we will be salivating. Looking at clock at noon will do it. So that fasting that they are talking about is just forceful technique of listening to the body. It is right amount the food that satisfies the body that makes you healthier but not the fasting. Only benefit of fasting is to forcefully make you aware to listen to your body when it gets hungry. There is no other benefit in fasting.
Let’s see what the papers at Nature say.
http://www.nature.com/nature/journal/v457/n7230/edsumm/e090205-11.html
Could you explain with YOUR knowledge or experience or you are just trying to explain something with “BORROWED” knowledge with that link?
BTW you remind me of shale guys that have their blogs and magazines (I am not sure maybe they even have TV channel and TV guide) but still cannot explain why they are dying.
So the internet links, blogs, magazines, books are useless if you don’t know yourself from you own experience.
Nature is the top publisher of peer review science papers and research on Earth.
I take their data seriously.
” I take their data seriously”
Don’t take anything seriously. Life is cosmic joke so if you take it seriously you would not understand it. 🙂
Listen I will try very simple, all I am saying fasting is just technique. It’s like horizontal drilling is just technique. You just have to eat when you body ask for it in moderation and not when your mind tells it. So if someone says Superbowl your mind immediately tells you pizza & beer but body is already content and does not need pizza & beer 🙂 So mind is disease.
Don’t have a tee vee, never eat pizza, didn’t see the Super Bowl, and spend time fighting for calories in the back country.
I think you are still wading in the shallow end of the pool.
Science is actually your doorway into knowledge.
” Science is actually your doorway into knowledge.”
This is just human – to think about questions and to try to find out the answers. Science comes ONLY to certain answers. For example how you don’t realize that science of oil fracking does not give satisfactory answer to certain geology formation? No? Yes? I mean you are reading this site? Where is your doorway into knowledge? It is nowhere to be found.
I believe the discussion was about caloric restriction and longevity.
But, if you want to change the goal posts, it is a typical tactic for someone who is losing a data driven observation.
Truthfully, I come to this sight to learn about energy and oil from people much more literate and experienced than me (although my father was in oil).
I find it incredibly valuable and enlightening.
hightrekker23,
A profound concept error here. It is not Nature’s data. Each article has to be judged on its own merits, and Nature has published incredible rubbish before.
The water memory article comes to mind:
“Water memory defies conventional scientific understanding of physical chemistry knowledge and is not accepted by the scientific community. In 1988, Jacques Benveniste published a study supporting a water memory effect amid controversy in Nature, accompanied by an editorial by Nature’s editor John Maddox urging readers to “suspend judgement” until the results could be replicated. In the years following publication, multiple supervised experiments were run by Benveniste’s team, the United States Department of Defense, BBC’s Horizon programme, and other researchers, but no team has ever reproduced Benveniste’s results in controlled conditions.”
https://en.wikipedia.org/wiki/Water_memory
We already commented at the lab, at the time the Water memory article was published, that it was impossible that it could be correct. Since then I have seen enough rubbish papers in Nature to have your faith in “Nature’s data”. Each article has to be judged on its own merits. There is no Nature’s seal of quality.
More challenging geology may be overcome with technology, that is higher specific costs.
To the best of my knowledge, there is not a technical constraint to extract oil from wells at a cost of $200/bo or more
The challenge is the demand side, many consumers would not be able to sustain their present oil consumption with $200/bo.
The global debt has grown and continue to grow, meaning that with even sustained low interest rates, the debt service continues to grow.
An earlier post here at POB (and other media) showed that OPEC compliance with recent cuts so far had been good. There have been/is strong build in US stocks. US has a big portion of global stock capacities.
US total demand (consumption + stock build) flattened (YoY changes) since late summer 2015 and recently US consumption went flat (since Oct-16). This may be a temporary thing.
The oil price has been moving within the band of $50-$55/bo in recent months and the dollar has remained strong, that is several other currencies has depreciated versus dollar.
To me this suggests something may be going on with demand/consumption at present prices.
My present working theory is that the affordability limit has come down, that is I expect now to see demand/consumption respond negatively to say oil price growths towards $70/bo.
Oil sold outside the US depending on where you are talking in dollar terms is more expensive. Governments/Central Banks that have trashed their currencies with QE and interest rate cuts outside the US are waking up to the fact their currencies don’t buy as much oil as they used to when it comes to having to import oil. Rest of the world needs a weak dollar. The stronger the dollar becomes the less affordable oil is to the rest of the world. Back when FED QE was at full throttle this wasn’t an issue because dollar was weakening faster than most currencies. Which allowed rest of world to import more oil with less money. Affordability outside US has lower ceiling on price now than does the US itself. Which is why while i believe that in the US $70/bo could be handled. Outside the US that affordability is pretty much in the $50-$55/bo range that price has been in. Maybe $60/bo being the upper limit for the rest of the world. Further dollar strengthening would only push this affordability number down. Unless rest of the world started allowing their currencies to rise from where they currently are. Ending QE and raising interest rates themselves. I’m not so sure actual oil scarcity would equal higher prices under the current circumstance as Dennis was suggesting.
Think about what affordability would be for say the European Union if say the Euro currency fell below parity with the dollar. I’m going to throw a what if scenario in here. What if France decides to leave currency block. Euro currency falls well below parity with the dollar. I’m thinking all of Europe’s affordability number drops to maybe $40-$45/bo
Now someone remind me of how much oil all of Europe imports every year. Because it’s a lot and even if Euro Union stay intact this year. Their affordability ceiling isn’t going to be rising anytime soon.
“Outside the US that affordability is pretty much in the $50-$55/bo range that price has been in.”
In Europe, Japan and some other countries the impact of oil price fluctuations on retail prices on gasoline and diesel is largely mitigated by high fuel taxes.
When it takes 1.15 yen to equal 1 dollar as oppose to a few years back when it took .80 yen to equal 1 dollar in dollar terms it takes you 44% more yen to import the same amount of oil to Japan. Affordability has a lot to do with the purchasing power of a currency.
Ditto with the Euro currency but not quiet to the same extent, not yet atleast. But if the Euro currency fell below parity with the dollar. That affordability number would fall from whatever it actually is say $60/bo to maybe half that or just above half that say $40/bo
If France or Italy does decide to leave the European Union the euro currency will fall well below parity with the dollar. Bring down that affordability number for the entire European Union with it.
Someone remind me of the exact amount of oil the entire European Union imports every year. It’s a lot. Even if they do stay intact together after this years election the affordability number isn’t likely going up anytime soon. Oil price will be what people can pay for it and not a penny more. IMO
Despite the depreciation of some currencies vs. the dollar, retail prices for oil products remain lower than in 2014
Gasoline prices in national currencies (per liter), 2014 – January 2017
source: IEA
Japan is a good case study.
Japan’s oil (petroleum) consumption has been in general decline since private debt had a high in the mid 90’s and its petroleum consumption declined as private sector began to deleverage (local currency).
From 2014 to 2015 Japan’s petroleum consumption continued to decline and this may have been due to a weakening of the Yen vs US dollar.
For the Euro area much of the oil price decline was offset by a weaker Euro (and also GBP).
Several nations (also some states in the US) have increased taxes furthering weakening the effects of lower oil prices.
Affordability (lowered households disposable income) will continue to be an issue going forward.
China is struggling to keep up the Yuan and many expect that the Yuan will weaken which is likely to affect Chinese oil consumption.
India has seen good growth in its petroleum consumption, but also here it remains to be seen if a higher oil price will affect consumption. India and Indonesia a while back cut/reduced subsidies (when oil prices crashed) for some petroleum products, thus a higher oil price will make itself felt earlier.
There is nothing now that suggests India is going to pick up speed a la China in its energy consumption.
“There is nothing now that suggests India is going to pick up speed a la China in its energy consumption.”
From Platts:
Outlook 2017: India’s oil demand growth rate to eclipse China’s yet again
Singapore (Platts)–12 Jan 2017
http://www.platts.com/latest-news/oil/singapore/outlook-2017-indias-oil-demand-growth-rate-to-27748998
• Demonetization impact on oil demand to be short-lived
• LPG and transport fuels demand to rise
• New petrochemical projects a boon for naphtha demand
The dramatic rise in India’s oil demand shows no signs of faltering, leading analysts to say that the country will remain a driver of Asian growth in 2017.
Consumption is expected to rise 7-8% this year, outpacing China’s demand growth for the third consecutive year.
The cash crunch following New Delhi’s move in early November to demonetize more than 80% of its currency is expected to temporarily dampen the country’s appetite for oil products in the first quarter, or maybe a little longer.
But gains in oil demand that the country is set to achieve from the “Make in India” initiative — which aims to raise the share of manufacturing in GDP over the next few years — will more than offset the negative effects of demonetization, analysts said.
The government’s clean fuel drive, sharp anticipated growth in transport demand and air travel, and the country’s insatiable growth for petrochemicals will act as a boon for gasoline, jet fuel, LPG and naphtha, helping oil products to post close to double-digit growth in 2017 — similar to that seen last year — if not higher.
“For the third year in a row, India’s oil demand growth will outpace China’s demand growth,” Platts Analytics said in a note, adding that it was expected to grow at about 7% to 4.13 million b/d in 2017, compared with 3% in Chinese oil demand to 11.5 million b/d.
India’s demand for oil products in November rose 12% year on year to 16.6 million mt, or 4.35 million b/d, data from the Petroleum Planning and Analysis Cell showed.
Over January-November, oil products demand rose around 9% year on year to 176.36 million mt, or 4.1 million b/d.
While growth fundamentals for oil in India remain high, slower growth in the initial months of 2017 because of demonetization might pull down the overall oil demand growth in 2017 to a shade below 2016 levels, according to analysts.
“If successful, the effects of demonetization are expected to be temporary, and indexes are expected to bounce back,” said Amrita Sen, chief oil analyst at Energy Aspects.
I should have been more specific.
I cannot see that India will see sustained growth in its petroleum consumption a la China over several years.
The key for India is monetary policies.
India, at least from 2014 to 2015 saw strong growth in petroleum consumption. Lower price helps and in 2016 the average price was even lower than in 2015.
2017, too early to call.
India has a rapidly growing middle class, which is a key factor for a long-term growth in oil/energy demand
I’m not confident that any country will see rapid economic growth in the future. I think we are hitting some walls: labor competition, scarce resources, political turmoil, income inequality, etc.
And we all gonna die someday …
What causes this growth in the middle class?
Look at the articles I just posted about economic growth in China and the world.
I don’t think India’s middle class will be in a position to significantly boost world economic consumption.
From 2014 to 2015 India’s petroleum consumption grew with 0.31 Mb/d (BP) while the oil price dropped almost by half.
China’s petroleum consumption grew by 0.77 Mb/d in the same period.
For India like for any other economic growth is about growth in debt (access to credit).
There is growth in debt in India, but the debt to GDP ratio has not moved much and total debts (market value) in India is about 15% of China’s.
Hi Rune,
The fact that the debt to GDP ratio is not changing in India suggests they are on a sustainable growth path. As long as high growth rates are maintained without an increase in the debt to GDP ratio suggests the growth may continue especially if it is based on growing income and consumption within India. Potentially oil prices might be limited to $75/b as you suggest, but only if decline in consumption in slow growth economies offsets the increased consumption of rapidly growing economies such as India and China and $75/b is high enough to keep output on a plateau. If oil output starts to decline, I think we will see the oil price rise above $80/b. Perhaps this will lead to a World wide recession or perhaps needed investment in non-fossil fuel energy will lead to higher growth.
Debt to GDP ratio says nothing about the ability to service debts. That is what matters.
To grow income may be through increased exports and/or growth in total debt.
Since year end 2016 OPEC (and maybe some other exporters) has reduced their supply with about 1 Mb/d (ref also previous post on POB.
There is nothing that suggest other suppliers has fully filled this gap, rather it may be that the others are stagnant or in slight decline.
US stocks (total complex) have in the same period grown with about 1 Mb/d.
US consumption has remained stagnant during the same period.
The price has remained range bound in the $50-$55/bo band.
This suggests to me that someone may have reduced their consumption and that while the oil price is “low”.
Hi Rune,
For the most part national income tracks GDP very closely, so typically higher income will enable a higher debt level. That is typically what a lender looks at, the value of assets and income. If Debt to GDP does not matter why does the Bank for International Settlements bother to track it?
Debt to GDP is a convenient metric. GDP or GNP says nothing about the abilities to service debts.
Countries do not service their debts based on GDP figures.
There is no law that says GDP will grow forever.
Hi Rune,
Generally higher income makes debt easier to service. I did not say GDP will grow forever and did not mean to imply that it would. The point was that if debt grows at the same rate as GDP as you suggested was the case for India (I didn’t check the data), then debt is unlikely to become a problem.
It seems the monetary reforms in India were to try to reduce tax evasion so it is possible that income may be under reported in India as some people may have hoarded cash to avoid taxes.
The data for India may not be very good, and the same is probably true for China and many other emerging economies as well.
What if GDP declines?
Hi Rune,
In many cases the amount of debt decreases as well because there is less demand for new loans as the economy contracts. In some cases this is offset by more public debt and in that case Debt to GDP would rise, such countercyclical government spending to reduce the severity of recessions needs to be balanced by a reduction in government budget deficits when the economy recovers.
One possible reason for increased debt levels is a structural change in the economy where consumers and small businesses have greater access to credit. Generally OECD nations have higher debt to GDP than emerging economies, as emerging economies grow their debt levels may approach the average of OECD nations and the World debt to GDP level would be expected to rise.
It may be that the optimal level of debt to GDP at the World level may change over time.
Rising personal income, at least for a part of population (tens, and in future hundreds of millions people).
India simply follows the path of China and east Asian countries.
Of course China and India will never reach average per capita levels of oil and energy consumption achieved in the U.S. or Europe. But given their huge population, even an increase from 5-10% to 20-25% of western per capita consumption will have a significant impact on global demand.
There are no signs that now shows that India is on a similar growth path as China.
India is about 2 decades behind China in terms of per capita income; its economic model is different. But its GDP growth is similar or even exceeds China’s.
GDP growth in China and India (%)
2015 2016 2017 2018
China 6.9 6.7 6.5 6.0
India 7.6 6.6 7.2 7.7
source: IMF WORLD ECONOMIC OUTLOOK UPDATE, JANUARY 2017
http://www.imf.org/external/pubs/ft/weo/2017/update/01/
India’s GDP is about 20% of China’s as per 2015.
Re India.
India has been/is running a trade deficit and is also a net oil importer. A higher oil price weighs on their import bill. This can of course be negated for some time through the use of more (private) debt.
Re China
A major portion of the strong growth in Chinese energy (oil) consumption was the construction sector (investments). A structural change of the economy from less investment to more consumption may not necessarily lead to an increase in total energy consumption. The energy consumption shifts from one sector to another sector of the economy.
India was able to reduce its current account deficit as % of GDP even in the period of high oil prices in 2013-14
India’s current account deficit as % of GDP
source: IMF World Economic Outlook Database
Interesting that their relative trade deficit increases with a decrease in the oil price.
Most likely this is not related with oil imports.
Although global oil demand growth is expected to decelerate this year, it remains well above long-term average for 2000-2014.
Important to note, that estimates for 2015-16 and demand projections for 2017 have been constantly revised upwards.
Global oil demand growth (mb/d)
source: IEA
2017 too early to call.
Look at the article I posted about China and economic growth. I’ll repost this part of it.
“Simply put, China of ’85-’00 grew on population and demographic trends. China of ’00-’15 grew despite decelerating population growth but on accelerating debt growth…this growth in China kept global growth alive. China of ’15-’30 will not grow, will not drive the global economy and absent Chinese growth…the world economy is set to begin an indefinite period of secular contraction (big picture outlined HERE).”
So growth was drive by an expanding population from 1985 10 2000. Growth was driven by debt growth from 2000-2025. And moving forward, neither one of those will likely drive growth.
So it’s quite possible that we’ll see similar patterns in oil consumption. It has gone up in the past due to population growth and then debt growth. Remove those and oil demand goes down.
Projections based on what has happened in the past may no longer hold because global economics are changing.
”Projections based on what has happened in the past may no longer hold because global economics are changing.”
Exactly my view also, at some point extrapolations loses their predictive powers and nonlinear dynamics takes over.
“Embrace uncertainties!”
There is a limit to how much debt any country can take on to stimulate economic growth.
Several countries in Europe hit this limit whereby deleveraging started and with deleveraging came also decline in energy (also oil) consumption. Oil consumption came up a little with the collapse in the oil price.
China together with USA has been the prime drivers of the global economy since GFC. These economies will also at some point reach their limits.
Then there is no one left to continue meaningful growth in global debt.
If China and India were growing like the reported numbers say they are or have. Would they not have absorbed the glut in petroleum products that are currently piling up in storage? I’m thinking if those numbers are anywhere close to real we don’t have a glut or petroleum products piling up in places.
China all liquids consumption growth 2015 was 5%. India 7%.
GM recently reported 2016 car sales in China up 7.3% over 2015. Useful to understand 1st or 2nd derivatives on this. As long as they sell cars there it would be oil consumption growth.
Growth in sales would be oil consumption — not just growth, but acceleration of consumption growth.
Oh and btw, the Cadillac division for the first time ever recently sold more cars in China than the US. Nice, big gas guzzling Cadillacs.
HHH,
Global supply has exceeded global demand since the beginning of 2014 until mid-2016 and again in 4Q16. We have been discussing this for the past 3 years. It is also easy to find the data about supply/demand balance in monthly reports by the IEA, EIA and OPEC.
AlexS, I realize all that. Been following oil discussion a lot longer than three years. China/India have claimed high growth rates for years. All i’m say is if those numbers were accurate they should be absorbing this glut in oil products. They are not absorbing this glut in oil products. Maybe just maybe their growth figures are inflated just a bit to give the illusion of growth.
Ya, we’re back to all those 2014 oil collectors buying oil just to store it with no intention of selling it. They have gone on doing this for 2+ yrs now.
a chart from the IEA OMR February 2017
Thanks AlexS.
It seems that a 1 % growth rate would be a reasonable guess.
What do you think?
Sometimes you present data that you do not agree with.
Rune is certainly correct that a better estimate of 2017 oil demand could be made in 2018. For now the IEA estimate does not look unreasonable, especially if we assume oil prices will remain under $70/b.
Higher oil prices (over $80/b) might reduce consumption to some degree.
Since year end 2016 OPEC (and maybe some other exporters) has reduced their supply with about 1 Mb/d (ref also previous post on POB.
There is nothing that suggest other suppliers has fully filled this gap, rather it may be that the others are stagnant or in slight decline.
US stocks (total complex) have in the same period grown with about 1 Mb/d.
US consumption has remained stagnant during the same period.
The price has remained range bound in the $50-$55/bo band.
This suggests to me that someone may have reduced their consumption.
Dennis,
If you mean 1% annual growth in global oil demand in 2017, this is too low. Demand growth has exceeded 1% in the past years (except during the 2008-09 recession) and it will remain higher this year.
Below are recent estimates from the 3 key forecasting agencies (the IEA OMR for February is not yet available for non-subscribers). The absolute numbers and growth estimates are different, but all are well above 1% growth for 2017.
Hi Alex S,
I tend to be on the optimistic side so I was tempering my estimate to account for possible downside risks (such as an increase in oil prices due to increased demand with perhaps lower supply if OPEC and Russia do not increase supply as the rest of the World output falls due to depletion.)
I should have said at least 1% growth in World oil demand, often these estimates are too optimistic as well.
There was a lot of talk about imminent demand destruction at least since 2008-09, but actual demand growth continues to defy these projections, and forecasts are being revised upwards.
I’m not saying that this trend will continue. Global demand growth will likely decelerate, but not as dramatically as some people in the POB are suggesting.
IEA global oil demand projections (mb/d)
sources; Medium-Term Oil Market reports January 2015 and January 2016; Oil Market Report January 2017
Hi Alex S,
Keep in mind that the oil price forecasts have also changed from 2015 to 2017 and this is reflected in the demand forecast.
I think in 2015 the IEA was forecasting oil prices that in hindsight were too high and resulted in a demand forecast that was too low. Perhaps in Jan 2017 the IEA is forecasting oil prices that are too low and in Jan 2018 it may look like the IEA overestimated demand growth in 2017.
My 1% oil demand growth guess may even turn out to be too high, if oil prices increase more than my guess (around $80/b in 2016US$ in Jan 2018.) Note that my oil price predictions always seem to be too high so it is pretty likely that oil demand growth will be at least 1% and maybe even 1.5%.
Rune is quite astute and he disagrees, based in part on too much debt and slower economic growth (I think.) I believe he thinks oil demand growth will be much less than 1% and that oil prices will remain low due to stagnant oil demand.
Dennis,
1% growth is slightly less than 1 mb/d.
Even in 2011-2014, when average Brent oil price was close to $100 or even higher, global demand was increasing at a higher rate.
For this year, I expect average oil price at $55-60, this is certainly not an “unsustainable” oil price.
The IMF expects global GDP growth to accelerate to 3.4% this year from 3.1% in 2016. No signs of global recession.
What should cause such a sharp slowdown in oil demand this year?
Hi AlexS,
It is always difficult to predict in advance what would cause an economic downturn.
If oil prices remain at the level you predict, then perhaps we might see the oil demand growth forecast by OPEC (1.26% for 2017).
My expectation is that oil prices will rise more than you predict, especially if OPEC and Russia maintain the production cuts past June 2017. I believe petroleum stocks will be reduced and supply from non-OPEC producers as a group is unlikely to increase much at current price levels (less than 500 kb/d would be my WAG through the end of 2017.)
For this reason I expect oil prices will rise to about $75/b by Jan 2018, $85/b by Jan 2019, and $100/b by Jan 2020 (all in Jan 2017 US$). The increase in oil prices would be the reason for slower demand growth of roughly 1% per year.
If we consider C+C output and a 1% demand increase for C+C for each year from 2017-2020, then demand would be about 84 Mb/d in 2020. I think the World will struggle to reach that level of C+C output even at an average oil price level of $117/b (Jan2017 US$). In fact output is likely to decline (if it even reaches 84 Mb/d in 2020) so that higher oil prices may be needed if demand destruction does not occur at $117/b. I doubt World C+C output will exceed 84 Mb/d, in fact my best guess is a peak of around 82 Mb/d in 2019, with a brief plateau followed by gradually increasing decline rates.
I don’t have a lot of confidence in the global economy. There is a lot of political instability, not just in developing countries, but also in developed countries.
There is also less political support for global trade. Changes there will affect global economics.
Something will change with petroleum, either higher prices, less demand, or some combination.
There are developments which could drive growth (e.g. comversion to renewables) but it is hard to say if there is the political will to do it.
When we have people like Bannon who have said their goal is essentially to bring down the current world order, there is the potential for chaos and unpredictability.
Hi Boomer,
Perhaps there will be instability and this would likely lead to lower economic growth, that is fine in wealthier nations, in emerging economies where higher income levels are needed hopefully stability can be maintained to allow for rapid economic growth. I for one am rooting for India, China, and other economies to continue their rapid growth, higher income and education levels will help get total fertility levels to 1.75 or less so that population can decline, we really need to focus on better governance and economic development in Africa.
I would like to see China and India make significant moves toward renewables and EVs. China has already indicated it will do so. I don’t know if India will be as successful. But doing so should boost economic growth and reduce petroleum use, which would be useful economically and environmentally for both countries.
Now if there is global economic instability, their export markets will decline. But if they can advance sustainability within their borders, that might reduce their need for imports.
At $200 per barrel they could develop those small oil fields off the Falklands, justify exploring the Rockall Basin in the Atlantic, develop the Canadian Beaufort and Sea of Okhost discoveries, and all sorts of really expensive heavy oil projects. I bet we could add 10 million BOPD of extra marginal oil in 10 years.
Hi Fernando,
What do you think is a realistic oil price in Jan 2017 US$? I doubt we will see $200/b before 2030. Are you suggesting World output could reach 90 Mb/d in 2030 if oil prices reach $200/b in Jan 2017 US$? I doubt we will reach $200/b (about $150/b is as high as it will go for a 12 month average price) and I doubt the World will surpass 85 Mb/d in C+C output over a 12 month period (82 Mb/d is my best guess for a 12 month period).
I expect the peak will be between 2018 and 2023.
Texas Oil Fields Rebound From Price Lull, but Jobs Are Left Behind – The New York Times: “Roughly 163,000 oil jobs were lost nationally from the 2014 peak, or about 30 percent of the total, while oil prices plummeted, at one point by as much as 70 percent. The job losses just in Texas, the most productive oil-producing state, totaled 98,000.
Several thousand workers have come back to work in recent months as the price of oil has begun to rise again, but energy experts say that between a third and a half of the workers who lost their jobs are not returning. Many have migrated to construction or even jobs in renewable energy, like wind power.”
Typical NY Times story. Jobs return as a function of drilling rig and frack crew counts. Right now they are rehiring the better performers they let go. As activity increases we pick up the less experienced and we start seeing roughnecks who barely reach 5 foot 8 inches (being short doesn’t help on a rig crew). Some of the people they let go moved on, got good paying jobs, others are selling Chinese goods at Walmart. Mentioning the wind turbines was simply another plug for renewables. But those jobs don’t pay as well. Nor are they really that steady. Once wind power penetration reaches a certain level Texas will have to slow down wind turbine construction or the grid will be way too unstable.
I think we have or soon will hit peak oil demand. Here’s one reason (good charts in this article):
Global Growth In Energy Consumption (And Economic Growth) Is All About China | Seeking Alpha: “Simply put, China of ’85-’00 grew on population and demographic trends. China of ’00-’15 grew despite decelerating population growth but on accelerating debt growth…this growth in China kept global growth alive. China of ’15-’30 will not grow, will not drive the global economy and absent Chinese growth…the world economy is set to begin an indefinite period of secular contraction (big picture outlined HERE).”
The above article includes a link to this article.
Econimica: Policy Makers, like Generals, Are Busy Fighting The Last War: “It’s long overdue to acknowledge we face a future absent net growth and likely a future with fewer consumers, fewer homebuyers, fewer taxpayers, fewer employees. We face a battle where higher productivity leads to ever more being done by ever fewer people…and it only follows that the declining population with even faster declines in employment will consume less.”
Should Line 5 Pipeline Be Shut Down?
By Jeff Smith, My North, on September 1, 2016
EIA – DrillingInfo monthly LTO production report with preliminary estimates for January is out.
Earlier this month, the EIA has issued its Drilling Productivity Report (DPR) with short-term estimates to March 2017.
Both reports show continued declines in the Bakken (ND+MT) oil production in the beginning of 2017, although less steeper than in December.
Note, that the DPR numbers include some conventional output.
For the Eagle Ford, the EIA Drilling Productivity Report (DPR) projects oil production to bottom in February 2017 and to return to a weak growth in March
According to the EIA-Drillinginfo report, by January 2017 LTO production in the EFS declined by 608 kb/d from the peak in March 2015. For comparison, LTO production in the Bakken declined “only” by 309 kb/d.
It looks like production has been dropping about 25 kbpd per month and it is projected to rise by 10. Based on a quick look Enno Peters’ numbers they’ve been adding about 100 wells per month, which average about 350 bpd in the first month or two. So they’d need another 100 wells on top of the 100: so 200 per month. To maintain a plateau, rather than add another 10 kbpd, it might drop a bit initially but then have to keep on rising each month because of the fast decline in the extra new wells. In most of 2016 there were about 60 oil permits per month, which rose to 109 before Xmas, but dropped again to 95 in January. I don’t think the E&Ps are planning the number of wells the EIA envision, unless there is going to be a big draw down in DUCs. EFS has a big condensate component as well, and there was a similar percentage increase in gas permits, but I don’t see that will give the increase proposed. However the increased permitting, if maintained, does indicate the decline rates should start easing off (and my calcs. here are pretty rough and ready so maybe a flattening off is possible, I don’t think by March though).
Enno Peters’ numbers for Texas shale plays are based on the RRC data, which is incomplete. Still, Enno’s numbers reflect the trends in average well performance.
And they show that the new EFS wells are declining much faster than the old ones (this trend is less visible for the Bakkan and the Permian)
The EIA-Drillinginfo and DPR numbers suggest that monthly production declines in the Eagle Ford have peaked in the second quarter of 2016, and since then have been gradually diminishing. But it is yet to be seen if production may start to rebound from March.
Month-on-month change in oil production in the Eagle Ford (kb/d).
sources: EIA-Drillinginfo monthly U.S. oil production statistics; EIA Drilling Productivity Report.
Oil rig count in the Eagle Ford is up 112% from the low of 26 on July 29, 2016 to 55 on February 17, 2017.
This is still just a quarter of peak 2014 levels
Eagle Ford active oil rigs
source: Baker Hughes
According to the EIA, the number of drilled wells in the Eagle Ford has also doubled from 65-66 per month in May-July 2016 to 132 in January.
But there was no consistent increase in the number of well completions.
The number of the DUCs declined from 1545 in January 2016 to 1228 in November, but thereafter increased to 1255 in January.
Drilled, completed and drilled but uncompleted wells (DUC) in the Eagle Ford
Source: EIA Drilling Productivity Report
Between February and November 2016, completed DUCs on average accounted for 27% of total well completions in the Eagle Ford (reaching 53% in May), but in December 2016 and January 2017 EFS operators were completing newly drilled wells and the number of the DUCs was increasing.
Given the 4-5 months lag between well spud and the start of production, the rebound in drilling activity since August 2016 will likely result in increasing number of well completions in the first half of 2017, even if there is no further decrease in the number of DUCs. That may reverse the declining trend in Eagle Ford oil production.
Wells completed vs. the change in the number of DUCs in the Eagle Ford
Source: EIA Drilling Productivity Report
Given the steep decline rates of the new Eagle Ford wells, a significant growth in oil production would require a sharp rebound in well completions.
This is unlikely, in my view, with oil prices in the $50-60 range for this year and $55-70 for 2018.
Therefore, I expect generally flat or slowly increasing Eagle Ford oil production in the next 2 or 3 years. This is in line with the EIA short-term forecast.
Enno Peters’ data shows that the new Eagle Ford wells (with first flow in 2016) have similar initial production rates, but steeper decline rates than the 2014-2015 wells. That may indicate that relatively few potential drilling locations are left in the EFS sweet spots.
I any case, it is very unlikely that the Eagle Ford production may reach its peak levels of 1.6 mb/d as of March 2015.
In its Annual Energy Outlook 2017, the EIA did not disclose its production projections for individual shale plays. But the chart below shows that the EIA expects gradually declining LTO production in the Eagle Ford for the period to 2040.
Production in the Permian continues to increase, driven by LTO.
Comparison of the EIA-Drillinginfo statistics with the DPR data (which includes total Permian oil production) suggests that conventional output in the Permian is declining.
Texas has no personal state income tax. That oil has to flow to fund state operations. I wonder how they are making it happen. We know how Argentina made it happen.
Jodi data for December is out. I don’t know how useful or accurate this is any more, a lot of countries seem to have stopped reporting in mid year. But they are the only available source for some storage numbers, however their OECD storage numbers are way higher than IEA report. Nevertheless below are their Saudi numbers, it looks like there is accelerating decline.
My oh my, that storage growth in early 2010 resulted in price rise.
With the discussions about oil demand and India, I went looking for articles. Most of them are talking about India’s increasing demand.
But India’s demonetisation had an immediate affect. The assumption is that this decline will be temporary. However, my interpretation is that events can quickly change petroleum demand in India, so we can’t assume it will continue to grow there.
India’s Monthly Oil Demand Plunges Most in 13 Years | Financial Tribune: “India’s monthly oil demand fell the most since May 2003 as the government’s crackdown on high-value currency notes continued to reverberate through the country’s $2 trillion economy.
Fuel consumption fell 4.5% to 15.5 million tons in January from 16.2 million tons a year ago, the Oil Ministry’s Petroleum Planning and Analysis Cell said, Bloomberg reported on Monday.
Diesel use, which accounts for about 40% of total fuel demand in India, dropped 7.8% to 5.8 million tons, the biggest decline since September. Gasoline consumption fell the most since June.”
Oil demand growth in India likely to take a hit post demonetisation shock – The Economic Times: “Sales of scooters and motorcycles, one of the key drivers for gasoline demand, have also taken a hit. India's second largest two-wheeler manufacturer Bajaj Auto Ltd. said its local sales fell 10.3 per cent in November, while sales at India's largest sport utility vehicle-maker Mahindra & Mahindra Ltd. declined 22 per cent in November.”
Here’s another factor which could slow down oil demand in India, particularly if the government wants to encourage more use of renewables and EVs.
Oil Proves Costly For the Indian Economy: “The Economic Survey then goes on to say that India has moved on from a regime of petroleum subsidies to a period of imposing ‘a tax on petroleum products at about US$150 per ton, which is about 6 times greater than the level recommended by the Stern Review on Climate Change.’”
Thanks, and interesting finds.
There are many months left of 2017.
And for what it is worth Indian debt/credit growth (market value) has slowed since 2014 and per Q2-16. This is before the monetary reform and the oil price hit its low during the winter of 2016.
Why not look at other emerging economies as well, like Brazil, which consumed about 3.2 Mb/d of petroleum in 2015 and saw its consumption drop by more than 4% (BP numbers). The exchange rate is part of the explanation, but oil prices dropped from 2014 to 2015.
Most of the projections are just that, projections.
No real news here but several articles in a row on SA.
https://www.bloomberg.com/news/articles/2017-02-20/saudi-arabia-breaks-records-on-oil-exports-and-output-for-year
Norwegian Production figures are out
http://www.npd.no/en/news/Production-figures/2017/January-2017/
Liquid production is down 2% or 43,000 bpd
I expect the temporary shut down of the Goliat field is the main reason for the reduction from Dec to Jan. The shutdown extends into february as well.
Good I see that the 2016 data is out too. Time for new Norway post from Rune?
BofA Merrill Lynch: US shale oil production could grow by 3.5 million b/d to 2022
“In our view, US shale oil producers will come out ahead and deliver outsized market share gains by 2022. Shale oil output in the US may grow sequentially by 600 thousand b/d from fourth quarter of 2016 to Q4’17 on increased activity in oil rigs and fast productivity gains,” said the BofAML report. “Importantly, breakeven costs for key major US plays now stand around the $55/bbl mark. As crude oil prices recover further, cost reflection may partly offset reduced costs linked to less regulation. So assuming a gradual recovery in oil prices into a long-term average of $60 to $70/bbl, average annual US shale oil growth is projected at 700,000 b/d in 2017 to 2022,” the report said”
http://www.vanguardngr.com/2017/02/opec-meet-one-third-rise-global-oil-demand/
The report seems to suggest that the oil is there and all the companies need is enough money per barrel to make it worthwhile. But maybe the oil isn’t there. That’s why these Bakken numbers are so important. What if the oil isn’t there in sufficient quantities no matter how much money is thrown at it?
BofA Merrill Lynch is selling Snake oil if you ask me. Think that Snake Oil must be Abiotic in nature because it just keeps bubbling up all over the place. 🙂
If they have clients, there is no requirement that an analyst be correct. There is only a requirement that he attract new clients or new money from current clients.
They have also underwrote a lot of the debt tied to shale oil. Guess they need to unload some these debt products onto their clients before the whole thing falls apart.
Now THAT is a good point.
Every time i see a article like that from a big bank i know the window is closing on them. At some point there won’t even be enough flow to cover dividend and interest payments. It’s a downward spiral. Less flow equals less money which equals less ability to borrow which equals less flow and so on. Money will get cut off it’s just taking a whole lot longer than anybody would have ever believed. Everything was all good as long as the flow was increasing. That is why the Permian is the focus now. It’s all they got left now to increase the flow.
With the Permian becoming the only game left in town so to speak. The Permian could easily start taking investment dollars away from the other 2 major plays. That is something that hasn’t been factored into any model or projection.
I think I saw (and probably posted here) that the Permian is taking investment dollars away from the other areas.
And there are already worries that the Permian is in bubble terrority.
I, too, am skeptical when investment bankers, lease holders, and investors are telling people what a great investment there is to be had. I ask whether their main goal is to unload what they own.
Hi HHH,
Rune has done that model and so have I, just a model with no wells added, last time I put that up everyone thought it was too pessimistic.
Today it would look like this (new wells decrease by 10 per month no wells added from Sept 2017 to the future). The model is very easy to do, but I doubt this scenario is correct.
Well the mad rush to the Permian has been going on for what 6-8 months. We get some actual data, possibly a more informed scenario can be made. Don’t think anybody expects it to drop to zero wells being added by sept. but i think the data will show that money is being diverted from Bakken and EFS to Permian by the end of the year.
This is from November.
Occidental just paid record Permian prices—but remember the Bakken?
This is from two days ago.
Did The Bakken Fall Too Far Too Fast? | OilPrice.com: “The reason for the Bakken bust? Tight competition last year drove investors from the field and pulled more money south to the Permian, where conditions are more favorable and interest more concentrated.”
From two weeks ago.
As oil recovers, U.S. firms descend on the Permian Basin in West Texas – Oilpro: “So at least for now, the Permian accounts for a disproportionate share of the industry’s recovery. The amount spent on Permian land purchases and leases last year represented 39 percent of all deals nationally and tripled the activity seen in any other major U.S. oil region.
Acquisitions in North Dakota’s Bakken shale fields, by comparison, accounted for 3 percent of all deals.”
“Many of recent Permian deals were paid for with cash from secondary stock offerings, an unusual step that investors typically dislike because it dilutes their stakes in companies. But in the Permian, it seems, investors see the payoff.
Companies turned to stock offerings for cash because debt markets were largely closed to oil producers during the two-year price downturn.”
Earth quakes associated with various activities including fracking oil wells, injecting water and gas, filling reservoirs with water, etc, are now known to be quite common.
And while the likelihood of a big one resulting from such activities appears to be rather slim, it might happen.
https://cosmosmagazine.com/geoscience/earthquakes-triggered-by-humans-pose-growing-risk
Fracking oil wells does not cause earthquakes. It can cause minor tremors at the local site. Generally, the protocall is to stop the fracking for several hours, and then continue.
The main cause of the earthquakes comes from the production of oil and gas. Sometimes, many more barrels of brine [extremely salty water that does not lend itself to economical treatment] is produced for each barrel of oil. That brine is disposed of by using injection wells that put the water back into the ground 2+ miles deep.
Because of the salt water disposal problem, Oklahoma led the world in earthquakes. So, there has been intense study of Oklahoma by experts from around the world. Many modifications to the disposal of the salt water have been implemented. The number and severety of earthquakes has dropped significantly, but they still have work to do.
You know, I’ve been wondering about this. That water coming up in the Bakken has lotsa toxins in it and gets pumped back underground at some nearby disposal water well.
What about offshore wells? They got disposal water wells too? In the middle of the ocean? Cool.
Watcher,
It depends on where you are. Sakhalin Is Russia, nothing goes over the side. Everything from cuttings, waste water, excess cement, waste drilling mud gets pumped down a CRI (Cutting re-injection well). Angola, a totally different story, though cuttings from invert mud, are cleaned and must meet certain quality standards.
I know the the North Sea and Alaska, are big users of CRI wells, but not sure if they are as strict as Sakhalin Is.
PS. Sakhalin Island development, got caught up in a political situation, where Gazprom wanted to buy in. Shell was accused of polluting the environment, and had to bend over backwards to avoid losing access to their assets.
Cool. And GOM?
What I have pasted in below is straight from BOEM’s website regarding US offshore operations:
1. What kinds of waste materials can be produced during offshore oil and gas exploration or production activities?
The bulk of waste materials produced by offshore oil and gas activities are formation water (produced water) and drilling muds and cuttings. Additional waste materials include small quantities of treated domestic and sanitary waste, deck drainage, once-through fire water, non-contact cooling water, bilge water, ballast water, produced sands, waste oil, excess cement, chemical products, and trash and debris. All of these waste streams are regulated by the U.S. Environmental Protection Agency (EPA) through discharge permits and are either released after treatment or returned to shore for disposal.
2. Which wastes generated from offshore oil and gas exploration and production activities may be discharged into the ocean?
Routine discharges may include water-based drilling muds and cuttings, synthetic-based mud cuttings, treated produced water, treated sanitary and domestic waste, deck drainage, once-through fire water, and non-contact cooling water. Other wastes, such as excess cement and bilge and ballast waters, may be discharged at some point in the operation. All discharges are regulated by the EPA.
The EPA prohibits the discharge of some wastes. These include oil-based drilling muds and cuttings, produced sands, synthetic-based muds, waste oil, chemical products, and trash and debris, none of which can be discharged into the ocean.
3. What are the alternatives to discharging offshore oil and gas exploration and production wastes into the ocean?
The wastes may be reinjected into geologic formations (i.e., layers of rocks sharing common properties) or disposed of onshore. Wastes that do not meet regulatory requirements for offshore discharge into the ocean must be properly disposed of or recycled onshore according to state and federal regulations.
Good data. Thanx
low oil-prices impacting safety?
http://www.ptil.no/investigations/order-after-the-investigation-of-the-well-control-incident-in-well-g-4-on-troll-article12616-893.html
The Saudis are apparently finally actually doing something about their long announced intentions to go renewable on the grand scale.
http://www.tradearabia.com/news/IND_321080.html
And while a few hundred megawatts don’t amount to much, in terms of the additional amount of oil they have available for sale, the potential for solar power all thru that part of the world is enormous.
The cost of solar has fallen so fast, and is still falling, that it looks like they can’t afford NOT to go solar, and sell the oil, rather than burning it to generate electricity, and while they’re short of money, compared to times past, they apparently still have some, and easy access to credit on easy terms.
So- How much MORE oil might the Saudis and their exporting neighbors be able to sell four or five years from now, if they keep the pedal to the metal on solar, and maybe wind too?
My seat of the pants guess is that there might be more than a million barrels a day freed up for export within five or six years, between all the exporters, if the rest of them follow the Saudi lead.
Perhaps my calculus is way of, the numbers I get seems to be low.
SA aim to have 3.45 GW in 2020 and 10GW in 2023
1 BOE is approx 1.7 MWh
I’m not sure how much 1 GW solar PV produce in a year in SA. But found som numbers on google from a small roof-top installation. If these are correct then:
3.45 GW produce energy eq. of 3350000 BOE per year or 9200 BOE per day. Assuming the oil is burned to produce electricity this would reduce SA oil consumption by approx 30 kbd.
Same for 10 GW would thus be approx. 80 kbd.
1 BOE is approx 1.7 MWh
That doesn’t include efficiency, which is perhaps 38% (the european average for oil-fired generation, as reported by BP). So, one barrel of oil would have about .6MWh.
On the other hand, a new installation in KSA should have at least one axis tracking, and very reliable insolation, and probably could reach 30% capacity factor.
So 10GW = 10GW x 30% CF x 8760 hours = 26 terawatt hours; 26 TWH / 365 / .6MWh = 120kbd.
That’s about 9% of KSA’s 275 TWHs of electrical generation (2014).
“Kingdom’s fuel mix (for electricity) strikes a resemblance to its image of being the largest oil exporter, with around 50% of the Kingdom’s electricity needs being met by fuel oil and diesel, while gas providing the rest. It is estimated that more than 500,000 barrels/day of oil (since 2011) are burned for power generation, with summer peak demand topping at 900,000 barrels/day.
In regard to electricity, the Kingdom has one of the highest per capita consumption rates in the world [around 8,161 Kilo Watt Hour (kWh)/capita], which is almost three times more than the world’s average. The demand in correspondence has grown at a much higher pace of around 5–8% Compound Annual Growth Rate (CAGR) annually. The peak load has been growing annually at a rate of 7.86 (2013–2014). ”
http://www.jeg.org.sa/data/modules/contents/uploads/infopdf/2832.pdf
I wrote: “9200 BOE per day. Assuming the oil is burned to produce electricity this would reduce SA oil consumption by approx 30 kbd.” i.e. I assumed slightly more than 30% conversion eff.
Oh for God’s sake.
KSA, with a population of 31.5 million, will be the 4th largest oil consumer in the world this year. One more time. KSA WILL BE THE 4TH LARGEST OIL CONSUMER IN THE WORLD THIS YEAR.
USA, China, India, and KSA will replace Japan in 4th place this year. Japan population 126 million.
KSA consumption 3.895 million bpd 2015, growth of 5% over 2014. Japan consumption 4.15 million bpd 2015 shrinkage -3.9% from 2014.
Look, you green wackos need to go to the BP website and download the spreadsheet for the World Statistical Review. They spend a LOT of money tracking production and consumption country by country, and provide some history on the spreadsheets too. They are really amazing for a private entity, and they are tracking this info for places that are not their customers.
(or you can bookmark mazamascience.com/oilexport which graphs that BP data)
(BTW this KSA number is not the largest per capita consumption in the world. Not even in their own region. Kuwait and Qatar both burn more oil per person than KSA. And Singapore burns almost 2X more per person. Similarly the US is not even the largest burner per person in its own region. Canada burns more per person than the US, and only 1/2 KSA’s number. “only” meaning not 1/10th or 1/100th. 1/2 says KSA’s number is not bizarre.)
What part of “[p]erhaps my calculus is way of, the numbers I get seems to be low” did you interpret as “Solar PV will save the day and replace all oil KSA use”?
wasn’t pointed at you, replies go anywhere sometimes
Yes, it’s true: Saudi Arabia wastes vast amounts of oil. It’s very, very weird just how stupid KSA is being about it’s domestic oil consumption.
They’ve known for a very long time they need to dramatically change their wasteful ways, but there has been no will to make any changes until now. Now, they’re starting to reduce the mindboggling waste of oil for power generation, and starting to charge consumers for fuel.
It’s about time.
Yeah, that wasn’t quite clear.
I guess the take-away here is that if you want other people to check your calculations, it helps to break out all of the assumptions and calculations in detail.
“The cost of solar has fallen so fast, and is still falling, that it looks like they can’t afford NOT to go solar, and sell the oil, rather than burning it to generate electricity, and while they’re short of money, compared to times past, they apparently still have some, and easy access to credit on easy terms. ”
But it was already true in 2014, new PV with german prices generated chepear electrcity than oil at 50 USD/b.
Nonrenewable Resources, Strategic Behavior and the Hotelling Rule: An Experiment
(March 2014)
A potential problem with Hotelling and maybe ‘et al.’ is that interest rates are near zero (so how’s the price supposed to rise according to interest rates?) and that an oil or fossil fuel commodity is not like a commodity like tin or copper.
In any case, some of the literature seems to suggest, past peak, increasing leaning toward the Hotelling rule and international cooperation and/or localization/nationalization and/or protectionism (i.e., more taxes on imports) and/or isolationism (i.e., more walls, less immigrants) and/or ‘cheaper’ proxy wars (ISIL/ISIS and drone warfare as proxies for USA as well as assorted false-flag, sabre-rattling and chest-puffing/chest-beating/fur-fluffing/back-arching distractions), which may shift the price structure (debt defaults/jubilees, petrodollar abandonments) and/or resource-utilization/optimization, etc. approaches.
Well good for Harold. In a world of QE, Kaldor Hicks and that crap has no chance.
Victory isn’t measured in dollars, and the Russians have excellent reason to be angry about what was done to them.
Look, people, there’s a lot to be learned in maybe the best precedent. GHW Bush’s This Will Not Stand. That was in reply to some academic type on staff who mused “We have to start thinking about a world where Hussein controls not just his oil, but Kuwait’s, too.” And the price tag that would face the US in trying to undo it.
This Will Not Stand, regardless of price, because maybe, just maybe oil man GHW Bush knew money mattered a lot less than oil.
So three cheers for the study, which can educate us if we think someone seeking victory will let pieces of inked paper obstruct him, or her.
I posted a comment somewhat with you in mind under the new article.
Then again:
https://i1.wp.com/progressivespring.com/wp-content/uploads/2015/10/trickle-down-economics.jpg
DUCs Are Done, But PUCs on Horizon? – BTU Analytics: “But production associated with current rig activity in the Permian will begin testing takeaway infrastructure later this year. As producers in the basin push ahead with their development plans without fully considering the impact of herd mentality, BTU Analytics expects excess backlog in the basin to grow once again (Permian Uncompleted Wells? PUCS!).”
Biggest Gasoline Glut In 27 Years Could Crash Oil Markets | OilPrice.com: “In fact, the glut of gasoline is now the worst in 27 years. At 259 million barrels, U.S. gasoline storage levels are now at their highest level since the EIA began tracking the data back in 1990.”
“U.S. gasoline demand plunged to just 8.2 million barrels per day in January, and sales were down 4 percent from a year earlier. It was also the lowest level in four years. …
Demand is seasonal, with softer demand in winter months, but this winter’s ‘valley’ is lower than any other since 2012.
The problem becomes particularly acute when you take into account the fact that refiners have actually cut back on gasoline production in recent weeks. Even with lower refining runs, gasoline storage levels continued to rise.”
“The glut of gasoline has led to tankers being turned away at New York Harbor in recent weeks, diverted to ports in the Caribbean. However, even that did not resolve the glut on the U.S. east coast. ‘Record-high inventories in the region are now pushing prices low enough to turn the typical trade flow on its head,’ Bloomberg reports. The east coast typically imports a lot of crude oil and refined products. But refined products are instead heading in the other direction because of the buildup in supply.”
If you need diesel, you can’t avoid getting gasoline even if you don’t want it.
Watcher,
It has been interesting watching the weekly oil production reports. Last year, as the drilling rig count was dropping, diesel consumption was down each week. Of course coal production was also down, so rail may also may have had an effect on diesel consumption. This year, with a rising rig count, and a stable coal production, diesel consumption is up every week. So if you want diesel to run drilling rigs, you also need more crude, to state the obvious. Of course, if the price is right, Nat Gas can displace diesel for those drilling rigs and frac pumps.
http://ir.eia.gov/wpsr/wpsrsummary.pdf
Yeah, that final paragraph lays it out. Middle distillate consumption is strong.
Some time ago I came across a blurb somewhere saying the majority of Chinese oil consumption growth was diesel. That’s what led to the blurb about Libyan oil having twice the diesel in it as KSA oil. In retrospect this didn’t really have to mean anything because one could cherry pick blends and declare that.
But overall it’s a good reason to care nothing about above ground storage. If you need diesel, and don’t need gasoline, your gasoline stocks will grow, and if you continue to need diesel, hell, you may just start flaring off gasoline.
That would be cool.
But why would the ratio of diesel to gasoline be any different now than it has been historically unless something has shifted in the economy? Is diesel demand unusually high and gasoline demand unusually low? And if so, can we use this to make predictions about future petroleum consumption?
Shrug. Car sales in the US emphasize fuel guzzling pickup trucks. The proportion of diesel to gasoline consumption might be changing. See Dodge RAM.
Non-commercial trucks have been popular for years and lots of them use gas rather than diesel. I doubt the suburban truck driver population would be accounting for a switch from gas to diesel. I can check but those fuel guzzlers have been around for quite awhile.
Pickup trucks are gas guzzlers only by comparison to cars, and at that , to ordinary cars.
As big as the newer models are, they still use less fuel than the older models sold some years ago.
My impression is that Dodge sells about twenty percent of Ram pickups with diesel engines, and that Ford and GM sell a lot less than twenty percent.
Diesel cars and trucks are not yet cutting very deeply into gasoline consumption in the USA.
“EXXON CAVES TO OIL CRASH WITH HISTORIC GLOBAL RESERVES CUT”
https://www.bloomberg.com/news/articles/2017-02-22/exxon-takes-historic-cut-to-oil-reserves-amid-crude-market-rout
“The equivalent of about 3.3 billion barrels of untapped crude was removed from the so-called proved reserves category in Exxon’s books, the Irving, Texas-based explorer said in a statement. The revisions were triggered when low energy prices made it mathematically impossible to profitably harvest those fields within five years. The sprawling, 3.5-billion barrel Kearl oil-sands development in western Canada accounted for most of the hit. … The reserves are now at their lowest since 1997”
“ConocoPhillips on Tuesday removed the equivalent of 1.15 billion barrels of oil-sands crude from its books as part of a 21 percent cut that pushed the Houston-based company’s reserves to a 15-year low.”
ExxonMobil cut was expected and their shares rose after hours, so maybe not so bad, or maybe investors have completely given up looking beyond three months ahead. I think CoP, like MArathon before them, are starting to fade away as an international player.
I haven’t checked the numbers in detail but I think even without the write off ExxonMobil would still have had less than 100% replacement, with about 1.5 Gb produced but only 1.0 Gb added.
” I think CoP, like Marathon before them, are starting to fade away as an international player.”
COP and many other U.S. E&Ps were selling conventional international assets for the past 5-6 years.
Interestingly, those assets were low-growth, but net cash generative.
Proceeds from international asset sales were used for acquisitions in the U.S. shale oil and gas sector (high-growth, but cash-burning).
Prior to Exxon and Conoco, Canadian assets were written down by Statoil and Shell.
“Since 2012, the write-downs from those companies and Canadian producers have exceed $20 billion.”
“In the decade leading up to the 2014 price collapse, companies spent as much as $200 billion building megaprojects to extract heavy oil in Alberta’s boreal forest.
Today, only about 20% of those reserves, or about 36.5 billion barrels, are capable of being profitable, according to energy consultancy Wood Mackenzie.”
http://www.foxbusiness.com/features/2017/02/17/energy-companies-face-crude-reality-better-to-leave-it-in-ground.html
CHEVRON … NEUTRAL ZONE FIELDS SET TO RE-OPEN
http://www.worldoil.com/news/2017/2/22/chevron-names-saudi-veteran-to-head-kuwait-operations-neutral-zone-fields-set-to-re-open
“Chevron holds 50% of the Wafra onshore oil and natural gas fields that lie in both Kuwait and Saudi Arabia. Wafra, which Chevron operates on behalf of Saudi Arabia, closed in May 2015 because of difficulties in securing work permits and access to equipment. The other shared fields are offshore and run by Khafji Joint Operations. They closed in October 2014 because of unspecified environmental concerns. Wafra and Khafji have combined output capacity of more than 500,000 bpd.”
Not exactly the news would be expected when they are trying to assure everyone the cuts are working, but they might be planning to rest some of the other fields that have been operating flat out.
Brazil – The Libra FPSO is expected to achieve first oil by Q3 2017 and will operate on the Libra field offshore Brazil under a 12-year charter.
Teekay Corp. on twitter: https://twitter.com/TeekayCorp/status/834813710233264128
Russia crude oil output likely to fall almost 200,000 yoy in Q4 2017 but preparing to pump more from 2018, says Bank of America & Merril Lynch
chart on twitter: https://pbs.twimg.com/media/C5WYBqkXUAEgFZI.jpg
Oops, maybe the “source” that said their stated reserves were all being confirmed was a bit premature. I’d like to know what’s happened to MbS, who started all this (and a couple of wars). He made a spot purchase of a monster yacht in France and hasn’t been heard of since.
SAUDI ARABIA’S OIL WEALTH IS ABOUT TO GET A REALITY CHECK:
https://www.bloomberg.com/news/articles/2017-02-23/saudi-arabia-2-trillion-aramco-vision-runs-into-market-reality
“Saudi Arabia has said oil giant Saudi Aramco is worth more than $2 trillion, enough to consume Apple Inc. twice, and still have room for Google parent Alphabet Inc.
“The kingdom may have to settle for less. A lot less.
“Industry executives, analysts and investors told Bloomberg their analysis — based on oil reserves and cash flow projections under different tax scenarios — suggests Aramco is worth no more than half, and maybe as little as a fifth, of that amount. This means Saudi Arabia would earn a fraction of the $100 billion implied by its valuation if it sells 5% to the public in 2018, as planned.
“For example, Wood Mackenzie Ltd. came up with a rough valuation of Aramco’s core business of $400 billion, according to clients who attended a private meeting at the oil consultant’s City of London office this month and asked not to be named. The Edinburgh-based company, popular for its analysis and valuation of energy companies and assets, declined to comment.”
Rystad Energy’s estimate of Saudi Arabia’s reserves is also much smaller than the official estimate.
But Aramco had hired two U.S. oil reserve auditors, Gaffney, Cline and Associates (part of Baker Hughes) and DeGolyer and MacNaughton, not Woodmac and Rystad.
Rystad Energy estimate of Saudi Arabia oil reserves
Y’all do realize the Saudi sovereign wealth fund can pay whatever price for Aramco’s offering desired? Stop thinking money has any purity. That went away over the past 10yrs of QE.
Remember . . . Central banks buy stocks. It is explicitly done by the SNB, the BOJ and ECB. They can define prices. Why shouldn’t the Saudis?
Colombia is holding a plateau for oil, up slightly on the month though still down over 10% y-o-y.
From the ministry of mines press release (Google Translated).
“The growth is due to increased production in the Casabe, Castilla Norte, Chichimene, Infantas, La Cira, Rubiales, Provincia and Quifa fields.
“On the other hand, the preliminary figure for gas production was 847 million cubic feet per day, lower volume by 3.2% compared to December 2016.”
Mexico decline is holding at 10% y-o-y. For crude only it is slightly worse than all liquids. They haven’t issued field data yet but I’m pretty sure that Maloob, which is the biggest producer in KMZ, is seeing increasing gas breakthrough, and consequently accelerating decline. They have cut their oil rigs as well so things are unlikely to improve near term.
This shows C&C data for individual fields. The numbers in brackets are y-o-y declines. KMX has gone 1.05%, 2.82% , 3.30% in the last three months – that is indicative of a field coming off plateau.
This shows KMX production and GOR. It looks like they have been hitting gas handling limits for the last 18 months and have been changing the production mix to maximise oil. Ku field was the first to ramp up and then declined at about 12% per year. The decline might have been managed to allow Maloob and Zaap to ramp up, or because of gas handling issues. Zaap and, especially Maloob are now seeing gas breakthrough and it looks like they are having to cut back on Maloob accordingly. If these two fields follow Ku at 12% decline then I’d suggest Pemex is pretty much fucked.
That was the wrong file – but it shows the KMX decline more clearly. Here is the right one:
George Kaplan and Alex S
The data I have from the A.A.P.G Giant Oil field data base for Saudi 58 largest fields indicate less than 44 Billion barrels recoverable remaining. I can’t get the data to down load but if you provide your email address I will send it to you and for Iraq, Iran, Kuwait and UAE. Not a pretty picture.
RK – thanks. Put them in a spreadsheet, take a screen shot (or copy to Powerpoint and save as pictures), save as GIF or JPEG file and ensure it is below 45 KB, then attach with “Choose File” button. I think everybody will be interested.
Recession Concerns Grow After Gasoline Demand Slides Most In 16 Years | Zero Hedge: “Two weeks ago, we reported that when Goldman observed the latest gasoline demand data, it said that either something must be wrong with the data, or the US is in a recession: as the firm’s commodity analyst Damien Courvalin put it, such a steep drop in in US gasoline demand ‘would require a US recession.'”
“Bloomberg’s Liam Denning confirms that ‘big dips in U.S. gasoline demand, especially of 5 percent or more, are almost unheard of outside of a recession or oil crisis.'”
“Which means that all those hedge funds who currently have record long WTI positions and who have been ignoring the troubling fundamental data from America’s roads, will sooner or later be forced to close out, resulting in one of the biggest oil price drops in history, in the process perhaps unleashing the next deflationary shock.”
Gasoline Glut Remains The Biggest Red Flag For Oil Markets | OilPrice.com: “The gasoline glut is the worst in nearly three decades, with stocks rising to their highest level since data collection began in 1990. And as with any market suffering from too much supply, prices have crashed. Refining margins for gasoline are at their lowest level in years due to the overhang, and major refiners are being forced to throttle back on production.
Reuters reports that at least three refineries have reduced output recently.”
GAS EXPORTS: Peak LNG glut is just 2 years away — Moody's — Thursday, February 23, 2017 — http://www.eenews.net: “An ongoing build-out of world capacity to liquefy natural gas will cost more than $1 trillion and will bring a growing surplus of LNG that will peak in 2019 before fading out in the early 2020s, according to a new analysis by Moody’s Investors Service.”
The IEA OMR for February is out as public access. It’s a lot shorter than usual with no written analysis as their full year review is due this month. Do the stock charts below suggest a market that has been significantly oversupplied recently? Also does anyone know why the IEA stocks are so different from JODI for OECD – is it to do with whether they count government and industry stocks and/or crude versus products?
https://www.iea.org/oilmarketreport/omrpublic/currentreport/
I still don’t fully understand: “OECD total oil stocks fell nearly 800 kb/d in 4Q16, the largest fall in three years. End-December inventories were below 3 000 mb for the first time since December 2015. Stocks continued to build in China and other emerging economies and volumes of oil at sea also increased.”
Stocks in OECD Asia Oceania and Europe are declining rapidly. Stocks in Americas are stable. There must be huge build of inventory in China to compensate for this.
Someone with money in their pocket and access to storage has placed a bet on higher prices. The market looks way too much on US inventory levels and rig counts, IMHO.
IEA will release their annual 5y oil outlook on 6 March. Can be interesting, considering last WEO.
If they know stocks are building in developing countries and at sea does that mean the data is available, and if so why not publish the actual numbers? Or do they just infer some from import / export balance, in which case they are depending a lot on accurate flow numbers over time.
According to the IEA,in 4Q16, global supply exceeded demand by 0.51 mb/d.
OECD inventories (commercial and government) decreased by 0.71 mb/d
That was partly offset by a 0.25 mb/d increase in floating storage.
Balancing items of 0.97 mb/d (89.6 million barrels for the quarter) include “changes in non-reported stocks in OECD and non-OECD areas”, as says the IEA.
I don’t think that non-OECD stocks may have increased by almost 1 mb/d.
My guess is that the IEA may have overestimated global supply or underestimated global demand.
Global supply-demand balance and change in inventories (mb/d)
source: IEA Oil Market Report February 2017
So volumes at sea increased for the quarter but look to be below recent averages.
The table shows changes in stocks during the quarter, not absolute volumes.
Oil at see has been increasing in 6 of the 8 quarters in 2015-16
Cumulative increase in floating storage over the past 2 years was 160 million barrels.
Art Berman has a great new post up today:
Don’t Hold Your Breath For $70 Oil and The Demise of the Bakken
The second half is all about the demise of the Bakken. Notice he says and the demise of the Bakken. The article has about 40 bullet points, far too many to quote here, but one of them:
• The premature demise of the Bakken is a signal that the other plays may meet a similar end.
Thanks Ron
Art’s last 2 bullets:
“• Under-investment in E&P will result in tight supply over the next several years and prices will
increase to abnormal levels.
• Even with considerable improvement in the global economy, this may be a disaster.”
I guess that he is saying that he eventually sees a train wreck from underinvestment?
“Under-investment in E&P will result in tight supply over the next several years and prices will increase to abnormal levels.”
But what many of us here are asking is what oil will that E&P discover or produce? To what extent will pouring more money into E&P result in more production?
At some point, from an investment standpoint, it will make more sense to put more money into other sources of energy and to adjust to limited petroleum supplies and high prices.
Can you fellows answer “what are these financial writers smokin?” (I want some of that)
This story would seem to contradict everything that the knowledgeable people who post here on POB have been saying
“Coming Shale Growth a Major Threat to Oil Prices”
[Morningstar]
Stephen Simko, CFA (stephen.simko@morningstar.com)
MorningstarFebruary 24, 2017
https://finance.yahoo.com/m/b9f38ee9-7356-3cfb-a105-62370e41167e/coming-shale-growth-a-major.html
Cheers,
B.G. in Wisconsin
He says, “We continue to view the U.S. refining and midstream sectors as the most attractive areas of oil and gas.”
But from a different article:
Gasoline Glut Remains The Biggest Red Flag For Oil Markets | OilPrice.com: “Refining margins for gasoline are at their lowest level in years due to the overhang, and major refiners are being forced to throttle back on production.”
ExxonMobil’s view of the world to 2040:
From http://www.epmag.com/nape-oil-gas-demand-energized-through-2040-exxonmobil-says-1466936#p=full
Quote:
Tight oil, too, will make North America into a net exporter within a few years, ExxonMobil forecasts.
“We expect growth in tight oil alone worldwide to be about 10 million barrels a day (MMbbl/d),” Onderdonk said, adding that NGL will increase to about 5 MMbbl/d.
By 2040, tight oil and NGL will exceed 25% of global liquids supply.
To keep pace, development of upstream supplies—conventional and continuous—will require an annual investment of about $450 billion. Another $250 billion will be needed to support upstream natural gas development.
“So about $700 billion a year to meet this rising demand for oil and natural gas,” Onderdonk said, adding midstream and downstream would also require investments.
Without funding, liquids supply will likely decline sharply, as more than 80% of new liquids will offset natural declines.
End quote.
This shows oil requirements (from the ExxonMobil yearly outlook report for 2016. Better get those exploration rigs fired up.
The two parameters present themselves. Consumption GROWTH and flow decline.
XOM says no to the second, as they must.
Odds just don’t look good. The population rises and people want the lifestyle high per capita burn provides. Flow to meet it? It almost all has to be new sources. George is on this like white on rice. Better get those exploration rigs drilling.
With what, Watcher; where are you going to get the money? Lay it out for us. Start with nationalizing all minerals in America, taking private enterprise out of the process, and turning it over to the American taxpayer. I am legitimately interested why the cost of this “flow” thing doesn’t matter anymore and what Plan B is going to look like. Be specific, thanks.
It wouldn’t be without precedent.
Specifics?
Libya’s NOC flowed oil. Rosneft flows oil and it’s what, 50% public 50% govt? Saudi Aramco? Petrochina? Sinopec? PetroBras? Pemex? The concept is by no means startling and “out of the mainstream”. It’s the norm. NOCs control 90% of the world’s reserves (says the wiki). YPF in Argentina got the price of oil decreed to be $70+ so they can flow oil.
If you have to have oil, and you DO have to have oil, you will do anything to get it.
Many of the uses for oil can be eliminated or downsized if necessary. If a country thinks in has to take any measures to fund oil, chances are the local economy will be shot anyway and demand for oil will have gone way down.
By the time a country is rigging the economy to keep oil flowing, it is way past the point where oil will save it.
They have been robbing retirement accounts in order to fund it. The promise was decades of oil. They know damn well the money won’t be paid back by selling the oil that was recovered. Question is in regards to the debt is it systemic risk or not. If not Shale oil will be allowed to fail. Plan B would be making oil flow one way or another from somewhere else.
I knew my statement would lead to a response that the US system is rigged already. Yes, it is. And if it is rigged primarily to keep us in oil at a financial loss, then yes, the US system is failing and we will be the worse for it.
And if we continue to conduct foreign policy and wars based on oil, we’ll fall behind other countries that use their money more wisely.
If the entire purpose of the US economy is based on oil (and we could argue that it has been since the early 1900s) and we can’t adapt to a post-fossil fuel economy, then we will see the rise and fall of the US as a global power and economic engine.
Already happened.
I’m a bit more conservative. I anticipate it happening, but I wouldn’t say it has happened yet. But between the US government spending its budget on border patrols and the military and backing away from renewables, I see the door being left wide open for China.
The current administration wants to channel money into activities that won’t lead the country forward, and that presents opportunities to other countries. Plus who knows how trade will go in the future.
This article has a chart showing the wide variety in demand projections from various sources. It’s worth looking at.
Why Oil Demand Forecasts Have Become A Guessing Game | OilPrice.com: “The range of consumption estimates 25-years out is wider than the tailgate of a Ford F350; on one end is 35 MMB/d, on the other 120 MMB/d. Even the top cluster varies by 20 percent.”
Baker Hughes data for this week:
US oil rigs: +5
gas rigs: -2
oil rigs:
Eagle Ford: +4
Permian: +3
Bakken: -1
This article from Resilience is about something that deserves a LOT of thought.
http://www.resilience.org/stories/2017-02-12/does-the-australian-lng-export-experience-foreshadow-soaring-u-s-natural-gas-prices/
The price of natural gas, and of oil to some lesser extent, is going to be determined in to a substantial degree by politicians, who either will or will not allow American domestically produced gas and oil to be exported.
I can’t even make a good guess as to what decisions will be made, because it will be a while before they are made, and Sky Daddy alone knows who will be making the decision. Trump and his homies might still be in the driver’s seat, or not.
And if they are, it would still be hard to decide whether they line up with domestic customers for gas, or with the folks who own it and want to export it.
Did you see the link I posted that predicted a global glut in LNG in a few years. S0 economically there may not be a compelling reason for US producers to push for exports anyway.
With articles saying the refineries are slowing down because of an excess of gasoline and with tankers being turned away in New York, I am wondering what will happen when the pipelines are finished. I haven’t seen any mention of that anywhere.
When pipelines are finished, oil currently transported by rail will be transported by pipeline.
Producers will get higher netback prices.
By the time pipelines are finished, the gasoline glut may disappear.
Yes, the producers will get higher netback prices. But will any related production increases then drop the overall price of oil? And then if we have more production than demand, will drilling slow again, giving us excess pipeline capacity?
Potential additional 100-150 kb/d (my wild guess) from the Bakken will not significantly change the global supply-demand balance
Aren’t the first questions to ask: when did the ships leave port and where is Chinese production and demand? I guess it’s zero hedge though.
http://www.zerohedge.com/news/2017-02-24/chinese-import-data-strongly-suggests-opec-lying-about-production-cut
Saw that article. One always has to look twice at ZH, but they absolutely do not parrot narratives so to some extent they deserve two looks, for multiple reasons.
“As JPMorgan writes, while IEA estimated the OPEC crude oil production fell by 1mbd to 32.06mbd in January, suggesting an initial compliance of 90% with the output agreement reached end 2016, the latest oil supply details released by China customs today suggest a reduction of supplies was not yet seen by China, the world’s largest oil importer.”
Useful to remember it was JPM placing high yield paper to fund shale. They have a LOT of incentive to talk up price.
“To those cynics who accuse the self-monitoring OPEC, and its various adjunct agencies, of lying that it has implemented last year’s agreed upon production cuts, China just released January crude import data, which validates this skepticism.” That’s from Durden, and it’s worth two looks.
“In fact, quite the contrary: crude oil shipments from the 11 OPEC nations committed to a 1.2mbd output cut increased by 28% yoy, and more importantly, rose 4% from December 2016 – in a time when production was supposed to be declining – to 4.6mbd in January, accounting for 57% of China’s total oil imports.”
Okay, you can reduce production (per agreement) and increase exports ($$$) at the same time if you have a domestic consumption decline, and son of a gun if December and January aren’t winter time requiring less air con.
It’s all a scam.
Thanks for all the back-and-forth banter on that article link I posted. These days you see the wildly optimistic stories about oil getting debunked in a few days’ time by more responsible reporting…
Art Berman has a pessimistic article on the outlook for the Bakken:
http://www.artberman.com/the-beginning-of-the-end-for-the-bakken-shale-play/
http://www.zerohedge.com/news/2017-03-02/beware-bakken
ditto
Looks like a pretty classic production curve well over the top now. Wonder when Sen Seneca will bite?