USA up 79,000 bpd
North Dakota up 31,000 bpd
New Mexico up 33,000 bpd
Texas up 18,000 bpd
Colorado up 22,000 bpd
Alaska up 16,000 bpd
Gulf of Mexico down 29,000 bpd
Thanks Ron,
A small increase, especially for Texas as GuyM has anticipated.
The last time we had oil prices in high forties for WTI ($48.33/b from July 2016 to August 2017), US C+C output rose at an annual rate of 635 kb/d. I would expect US output to grow relatively slowly (600 to 700 kb/d annual rate of increase) if oil prices remain under $50/b, instead of the rapid increase we have seen for the past 12 months (an annual rate of increase of 1760 kb/d).
The “glut fear” is based on the assumption that the rapid increase in US output seen in the past 12 months will continue, it won’t if oil prices remain low and even at higher oil prices (say $70/b for WTI) pipeline and port constraints will keep wellhead prices low in Texas and output will either be flat or perhaps small increases like the 18 kb/d we saw in October 2018 (about 200 kb/d for 12 months). Most tight oil plays in the US will not make much money with oil prices under $50/b, in fact the average US tight oil well needs at least $60/b at the wellhead to make a decent (10% annual ROI) return. Low oil prices will correspond with low oil output (or at least smaller increases in output).
Let me play along with that. I predict that if prices remain at current levels, which I don’t anticipate, we will see zero growth, amounting to a decline. If prices rise to $70 by June, we could see a 600 bpd increase by year end. The longer they remain at this price, Permian will be flat, or only slight increase to slight decrease. The rest of the plays will tube, making it go negative within three months. I posted earlier that I believed Permian completions may have declined by a third in Dec. Rough guess, and not positive.
As for 2019 being peak, I still think that is a good possibility. I think OPEC will call off their decrease before the end of the first half due to price increases, and US will get what they can, and too much for WTI, when the spread will increase before year end. But, those are wags.
GuyM,
Could be that output is flat as you suggest, for past 3 months (Sept to Nov) US tight oil output has grown at an annual rate of 1.9 Mb/d, I am suggesting this rate falls by a factor of 3 with WTI oil prices around $45-50/b, but maybe I am wrong (as I have been in the past.)
On much we agree, but I doubt 2019 will be the peak, we might see a temporary plateau while pipelines and ports get built in Texas to export the excess tight oil.
When that is accomplished tight oil output will grow in the Permian basin, peak will probably be 2028, but falling output in other tight oil plays starting around 2023 to 2025 will lead to a US tight oil peak around 2025, this is likely to coincide with the peak in World output, though if the Permian ramps up slowly we might see a plateau in World output from roughly 2025 to 2030, a bunch of uncertainty as to what happens in Brazil, Canada, Libya, Iraq, Nigeria, and Venezuela, but I still like 2025 to 2027 as the most likely years for Peak C+C output (12 month centered average World C+C output based on EIA data). In my view the odds of a World C+C peak in output before Jan 2020 are less than 10%.
As of the December DPR 82% of new US shale oil production goes to replace legacy declines, this means only 18% of new shale supply contributes to net growth. Based on this, only a minor slowdown in shale growth, for example 10%, can slow total production growth by 50%. I think many are underestimating the impact of low prices on shale growth, shale oil has changed the oil market supply elasticity, the old oil models where supply is stagnant no matter what prices are (due to the long lead nature of offshore supply, and slow decline of conventional supply) are not valid anymore. The relationship between prices and supply is closely tied today, this requires constant adjustment to the supply models (and demand models as well). I believe US oil prices have sunk too far, having a balanced oil market in 2019 requires WTI to average at least $55 as per my calculations, and this assumes OPEC easing their cuts by April.
I will go along with anything over a 15% decrease causing a decline in production just using some high school math. The DPR is strictly junk, and I wouldn’t rely on it for anything. Dennis has an alternative method, but none of us are far off from each other.
Then, again, my high school math is based upon “normal” decline rates. I assumed our wells were normal, which has been disproved by Shallow Sand. Ours are at 65%, which appears to be is low decline rate. His sample for the EF was a median well, which I looked up and was close to 80% the first year. If that was more “normal”, then 80% of the production of a new well is only covering the decline of that well the next year. Get the drift? What about the years before that? In short, it may be to increase production, you may have to actually be increasing the number of wells. If you staying the same, you get a decline. Time will tell.
GuyM,
Your wells have higher initial production, but perhaps similar decline rates to “average” wells. Essentially the entire well profile for your wells are shifted up compared to an “average well”. keep in mind that with current completion rates (say 375 completed wells per month in the Permian Basin) output was increasing, there is some number of completions (about 285 completions based on the information I have) where output would be flat and higher or lower completion rate would lead to an increase or decrease in output. What completion rate will correspond to current prices? I have no clue really, one would think at anything less than $60/b at the well head the completion rate should be zero, but oil companies think they can drill better than average wells, clearly this cannot be the case for all companies and completion rates will fall, but I don’t know by how much. Note that the “375” guess is for Texas and New Mexico completion rates for horizontal fracced oil wells for Oct 2018 based on EIA “tight oil production estimates by play”.
Interesting read. Especially oil price chart compared to employment. And, if exports slow, WTI discount increases. Permian price decreases. I anticipate the “decrease in increase” at a higher level than you. If prices remain close to where they are now, there will be a decrease in shale production, soon.
Look at the production numbers for Oct. Prices were fine in Oct. Bakken oil price is almost negative now. Decrease in N Dakota would eat up Texas increase. That is, if there is any to eat up. A slow week in completions would eat up 79k pretty fast. And there are plenty of slow completion weeks coming up. And from what I can tell, Dec had its share.
GuyM,
In the past I have thought there would be a large decrease in tight oil output and I was wrong (there was a much smaller decrease than I anticipated).
Always possible that this time will be different, but I believe you have pointed out (correctly in my opinion) that it takes some time for companies to react to changes in prices, some of this might be due to hedging and some may simply be momentum.
So far there has been little change in tight oil output increases in the Permian Basin over the past 3 months (Sept, Oct, Nov) with increases of 84, 86, and 89 kb/d respectively. See “tight oil production estimates by play” at page linked below
Actually, some is momentum. I have looked at the period of time in 2015, when completions and production started dropping. Completions slowed down about two months before it leveled off for a short period of time, and then dropped.
The completion drop was bigger then, but a lot of that was verticals.
GuyM,
I agree. There was a big change in rig counts with vertical rigs dropping by a large measure and horizontal rigs by a smaller amount. As far as I can determine there is not an easy way to tell how many completed wells are vertical vs horizontal (or I just am not familiar enough with the RRC website to figure it out). The data from Baker Hughes on rigs is easy to dig up, but that doesn’t tell us the number of wells completed. It would be interesting to see the vertical vs horizontal well completion data if you have it.
Not really. Our initial production was a little over a thousand barrels a day, the mean well in LaSalle was 1880. It had a quicker decline rate the first year. That’s the trouble with all these damn averages. All have different monthly decline rates. One may start off at 28k the first month, and be 24k the second month. Another may start off at 28k, but be 15k the second month. Looking at it like Shallow Sand is doing is much more meaningful. How much did they produce over a significant amount of time. Nothing else makes much difference. By the time it gets into the fourth year of production, hardly any are contributing much to determine whether the well will be profitable, or not. And from what I can tell, this is not restricted to the EF.
Above us is the Bowman West lease. The first well there started off with less than a 300 bpd initial production, and production indicated that the first month. I went back and looked at it a year later, and it had produced close to 80k. A decent tier three well. Have to be careful with averages until you measure it over a significant time frame.
Guym,
Yes there will be variation from well to well, but if you look at a large number of wells and take averages you will find this to be true. The shape of the well profile does not change that much, the main change tends to be that the well profile tends to be higher over most points in time for more productive wells.
Below is the average well profile for Eagle Ford wells with first production in 2016 based on data downloaded from shaleprofile.com.
The average well had a high output in month 2 (first month on average with close to 30 days of output) of 537 b/d (16338 barrels per month), so roughly half the initial output of your wells. Output after 24 months was about 136 kb for the average well (also about half of your wells at about 275 kb over first 24 months).
Chart is pretty small, but clicking on chart will give you a larger view.
Well, that would be true if they always drilled the same proportion of wells in the same locations as the average is taken from. It won’t be true in the Eagle Ford, nor I doubt the Permian. In short, I dunno.
Guym,
The well profile changes over time. It’s a model that will not reflect reality with perfection. The model assumes the shape of the well profile doesn’t change (for simplicity), the initial rate changes and the well profile gradually gets lower (less productive as the sweet spots get drilled up. Prior to 2016 the average well became more productive over the 2011 to 2016 period, clearly we can only guess what wells will look like from 2018 to the future.
Chart below is such a guess where well profile moves lower over time from an EUR of 258 kb in 2016 to 207 kb at some later date, then 162 kb after that, and finally reaching 132 kb when no more wells are drilled. Only 4 well profiles are selected, in the actual model when EUR decrease begins as sweet spots run out of space, each month has a new (lower) well profile, so if EUR decrease started in Jan 2019 and drilling stopped in Jan 2030, there would be 132 well profiles, one for each month.
As always a bigger chart can be seen by clicking on the chart.
GuyM,
The decline rates are not fixed, they gradually decrease over time for a hyperbolic well profile. decline rates shown in chart below correspond to the average 2016 EFS well shown in another comment.
I know that. Mine do. But, after year three, who cares what they look like. It starts to approximate zero. There will be less money to borrow. Obviously, EOG’s premium drilling program is full of it from what Shallow Sand has contributed. However, the concept is still valid. If you can’t recover most of the cost of drilling the well the first year, then it shouldn’t be drilled. How else would a company afford to keep drilling the same approximate number of wells without that being true. Otherwise, you have to borrow massive amounts of money. Which, I think, is no longer a card to draw for. Unless prices go dramatically higher, a production slowdown is long overdue.
Guym,
According to Mike Shellman, it can work if the well pays out after 3 years, clearly it is better if it happens sooner, but you continue to get some income from wells older than 3 years. The reason this matters is that it will determine the future output from the entire play and that is what interests me. Also my view is that a discounted net cash flow analysis over the life of the well is the best way to approach the economic analysis of whether completing a well makes sense. One needs future well output and future oil prices to do such an analysis.
If the discounted net cash flow over the life of the well (at an annual discount rate of 10%) is greater than or equal to the capital cost of the well, I assume the project makes sense and the well is completed.
When this condition is not met drilling is reduced to a level where the condition is met when the completion rate falls to zero, the play is done and no more wells are completed in the future.
After year 3 about 30% of well output is produced over the next 11 years, it is not a huge amount, but if we add it all up at $50/b and 25% royalty it would be about one million over 11 years for the average 2016 well, so about $90,000 per year on average, hey send the checks to me, as they are approximately zero you won’t miss them. 🙂
On re-reading you must have meant the decline rates are approximately zero, I am not sure, I assume when they get to 10% they continue at an exponential decline rate of 10% per year, which I guess is close to zero.
Find me a well, where 30% is produced after year three?
Guym,
EFS wells started producing in only 2010 and in most cases there are no wells where only one well is producing on a lease for 11 years in any case, so hard to find such a well in Texas. For the average EFS 2016 well profile based on the data from 1373 well which were completed in 2016 and fitting a hyperbolic well profile to the output data. That well profile has an EUR of 245 kb over 16 years of production (it is assumed the well is shut in at 8 b/d of output) at 3 years cumulative output is 157.5 kb, so 157.5/245=64% of total output and 36% of output occurs from Year 4 to year 16.
If we assume the well is shut in at 15 b/d at the end of year 12, then EUR is 232.2 kb and 68.5% of the EUR is produced in the first 3 years and 31.5% of output is produced from year 4 to Year 12.
It is possible these hyperbolic fits overestimate future output, we don’t really know the future output of these wells.
These little oil molecules have a hard time understanding your curves.
Guym,
Your wells will probably produce about 450 kb over the life of the well. What is current cumulative production and monthly output for the most recent month. What month and year did production start?
Actually you could e-mail me the data and I could give you an estimate based on a hyperbolic fit, would be an interesting post perhaps.
Or you could give me just the lease ID # and I can pull the info from RRC.
I emailed the data. Without enhanced production, I estimate EUR to be over 300k, but not near 450k. The newer ones will be longer, and may get to 450k. This is the first one that made over 150k the first year, second lease was over 175 the first year, and the last three were closer to 130k.
GuyM,
Thanks, seems based on your data the EUR will be well over 300 kb and may reach that point by year 5.5. At 7.5 years cumulative output may reach 334 kb, at 10 years 364 kb, and at 12.5 years 389 kb with daily output at that point about 23 b/d. If the well can continue production profitably up to 15 b/d, then EUR will be 418 kb at 16.75 years from first output.
If the well is shut in at 10 b/d, it lasts for 20 years with EUR at 435 kb.
I have assumed a terminal decline rate of 10% per year after year 8.5, a nice well indeed.
Thanks for the work? Be nice to get to twenty, but I won’t borrow on it? But this one is before they extend the laterals?
GuyM,
I have tended to focus on the Permian basin. The 2016 average well there is more like your EFS wells. About 400 kb EUR with about 178 kb after 24 months, decline rate over first 12 months is about 67%. The wells are also more expensive (about $9.5 million).
Dennis, after 16 months with oil in the mid to high $40s from May 2016 to September 2017, the growth rate in US shale oil production stabilized at 80K or so from September to November 2017 (EIA DPR), by December 2017 shale oil growth accelerated to about 100K+ as prices crossed into the $50s and higher in October. What is of interest is that the total legacy decline rate from September to November 2017 averaged around 390K barrels per month, which means for shale to grow at 80K per month, new supply had to come at 470K per month. This is a telling number in light of where we are today. Today the monthly legacy decline rate in shale oil is 530K, this means if shale can only bring in 470K in new supply in the mid to high $40s WTI, US shale supply will start to decline by the end of Q1 latest in response to current prices (In my observation there is about a 2/3 months lag between price and new supply in shale). I think anyone projecting net growth in US shale supply in 2019 at the current strip will be in for a rude awakening in the next couple of months. Unless prices cross above $50 this month, US shale will be in full decline mode in Q2, and without shale growing in 2019 the market will be severely under-supplied. Welcome to the the new oil order: https://oilprice.com/Energy/Crude-Oil/The-New-Oil-Order.html
I think you are right. And, I think it is going to last longer for the Permian than 2019. Talk, already of slowing pipeline completions, and consolidating, already. It has to, until capacity to export is moved up. So, even when prices go up, that part of the shale machine is slowed. Not stopped, just slowed.
Joseph,
The EIA’s DPR is not a very good model, so I ignore it, it is based mostly on rig count and reality does not match the model very well. Also note the model does not distinguish between oil rigs and natural gas rigs, a major shortcoming of the model. Better data on tight oil is from “tight oil production estimates by play” at page below
Keep in mind that legacy decline depends on many factors including the well completion rate so as fewer wells are completed legacy decline gets smaller. You seem to be assuming that legacy decline is always increasing or remains fixed.
As price falls and completion rate falls the legacy decline will also fall (in absolute value or magnitude). Also note in the chart below the rapid change in legacy decline rate in the 3rd and 4th quarters of 2017, if this is not a model defect (and reflects reality), then rapid changes in legacy decline rate are possible, if one simply looks at the smooth part of the model in 2015 to 2016, it is clear that the slower completion rate over that period with a 24% change in legacy decline rate. A similar change from Oct 2018 legacy decline levels would reduce the legacy decline to about 381 kb and we might continue to see slow increases in tight oil output. In any case, I doubt WTI oil prices will remain under $50/b for very long, higher prices (over $50/b for WTI) are likely by May 2019, in my opinion. Also keep in mind hedges by many oil companies may insulate them from lower oil prices and the completion rate may not fall sharply at first.
Yes, I agree sub $50 oil will probably not last by May. And, it doesn’t make a lot of difference whether production declines a little, or increases a little, it will be far short of expectations. Expectations and needs.
GuyM,
Agreed, it will not be the over 1 Mb/d of tight oil claimed by IEA and OPEC, but note that the EIA’s STEO has US L48 onshore output increasing about 600 kb/d over the next 12 months (Oct 2018 to Oct 2019), that estimate seems pretty reasonable. They also have GOM output increasing by 220 kb/d over the same period, that might be too much (I do not follow GOM very closely). The overall US C+C increase is 790 kb/d from Oct 2018 to Oct 2019 vs the 1834 kb/d increase from Oct 2017 to Oct 2018.
My guess is the STEO may be a little high (probably about 200 kb/d), but in the right ballpark.
Dennis, appreciate your feedback, and yes I am aware that the legacy decline rate is not static, the graph you posted is roughly in line with the one I derived from the EIA DPR. I guess we are both in agreement that shale can’t sustain its current production level with WTI under $50, my guess WTI will move firmly above $50 before the end of Q1.
Joseph,
We are not quite in agreement. I think US tight oil will continue to increase even at current oil prices, but the rate of increase will be smaller. For the Sept to Nov period using EIA tight oil estimates (rather than the DPR) the annual rate of increase in US tight oil output was about 1.9 Mb/d, I expect this annual rate of increase to fall to about 600 kb/d, but unless WTI oil prices fall further to perhaps under $40/b for the next 6 months, I think a fall of the rate of growth of tight oil to zero is incorrect. That is because legacy decline will not remain at 500 kb/d, it will fall to 380 kb/d as the rate of well completion falls, but an average rate of increase of 50 kb/d for US tight oil output may be maintained (this is over 3 times lower than recent rates of increase). A change in OPEC strategy to defending market share as was done in 2015 would be the only likely reason that tight oil output will decrease before 2025, if oil prices were cut in half as occurred in the June 2014 to March 2015 period (from $105/b to $48/b) so an equivalent move would be about $34/b in April 2019, then we might see tight oil output decrease. Note that the average oil price over the period of decreasing US tight oil production was about $45/b, about half the level of the period where output was increasing rapidly (from March 2013 to March 2015 with WTI=$90/b). The recent period of rapid tight oil increase occurred with WTI at an average price of $57/b (Oct 2016 to Oct 2018), I doubt we will see half that price level ($28.50/b) until 2040 or beyond (due to lack of demand for oil).
Dennis, we are in agreement that WTI can’t remain under $50, because shale growing at 600K will be substantially below the EIA and IEA shale growth estimates for 2019. I believe we are both shooting in the same direction, shale oil production growth will slowdown materially in the high $40s (your position) or decline (my position) but the outcome on the price (directionally) is the same, WTI needs to move higher for shale to balance the market.
Joseph,
I agree we are pretty close. Note that the EIA’s Short term energy outlook has US L48 (excluding GOM) C+C output increasing at about 560 kb/d from Oct 2018 to Oct 2019, so fairly close to my estimate for tight oil.
I agree that this level of US output combined with OPEC/Russia cuts is likely to result in an increase in oil prices to $65/b for WTI, probably by Sept 2019. Potentially that could lead to slightly higher tight oil output than the 600 kb/d annual rate of increase that I assume, perhaps 800 to 900 kb/d annual rates after oil prices reach the $65/b target for a couple of months.
Lots of moving parts such as price spreads in various tight oil plays which will depend on pipelines, rail capacity, and deep water ports on the Gulf coast. The picture is pretty fuzzy.
Dennis,
Talking about moving parts, I believe service costs is also a big part of the equation, in light of the frantic drilling/completion activity in 2018, service costs seems to have jumped by 35% according to Diamondback Energy. Trough service pricing conditions which helped shale companies increase activity in 2016 and 2017 have reversed, thus cash flows today sub-$50 are not what they were in the sub-$50 window from mid-2016 to mid-2017.
Joseph,
Excellent point, but as completion activity wanes, service costs will drop. Yes lots of pieces to consider. If output goes down due to lower completion activity, we will see costs go down while revenue will increase due to rising oil prices. Also remember that output per well has increased, especially in the Permian Basin.
Though I have read that output for a “normalized well” with fixed lateral length, frac stages and proppant levels has started to decrease in the Permian basin in 2018. I have not seen the data confirming this as it is proprietary.
Thinking about OECD oil stocks and looking at IEA Oil Market reports, I get the chart below for days of forward demand (stocks divided by daily oil consumption).
Not clear from this chart why oil prices have decreased, at least to me.
Look at the Dow on Jan 2, and oil prices. There is no logical connection, yet the connection by now is for real. In the minds of the market turmoil recipients. By now, margin calls are in full swing.
It won’t last for oil, but long enough to reduce capex budgets. I have absolutely no idea how long it will last for the Dow.
US inventory change for the first 10 months of each year (million barrels)(without LPG)
2018
Crude oil +10.8
Products -16.2
Total (crude oil+products) -5.4 (shown on chart)
LPG +34.9 (not included)
Chart https://pbs.twimg.com/media/Dvw-6npXgAAdeDQ.jpg
US inventory change during October (million barrels)
Crude oil +16.3
Products -27
Total (crude oil + products) -10.7 (shown on chart)
LPG +0.3 (not included in the total shown)
SPR -5.2 (also not included)
Chart https://pbs.twimg.com/media/DvxAWwvWoAEPzM4.jpg
US consumption during October (Just the major finished products without LPG or Petcoke)(1000 barrels/day)
Up +442 over September
Up +186 or 1.2% over October 2017
Up an average +226 or +1.48% in 2018 from Jan to Oct compared to the same 10 months in 2017
Chart: https://pbs.twimg.com/media/Dv0ulJGWoAEycS0.jpg
Liquefied Petroleum Gases (not included in the chart)
Up an average +251 or +9.87% in 2018 Jan to Oct compared to the same 10 months in 2017
While the U.S. continues to add oil and natural gas drilling rigs despite the recent swoon in crude prices, Canada’s count in the past two weeks has dropped from 174 to just 70, the lowest since June 2016. Twelve years ago, it had as many as 727 rigs drilling for oil or natural gas, according to data provided by Baker Hughes Inc.
Happy New Year!
The Canadian oil rig count is down to 15. Almost down to the level seen in December 2015 which was 12 oil rigs reported as active. (2015 had 53 reported weeks)
Chart https://pbs.twimg.com/media/Dv1K2iRWsAAIIhj.jpg
Alberta – The month of May is the seasonal low, December is normally just a holiday dip. I guess they could be cutting some rigs ahead of the production cuts that start in January?
Saskatchewan had zero rigs reported as active in the week to December 28th. Which cannot be part of Alberta’s production cuts.
Alberta chart https://pbs.twimg.com/media/Dv1LLvFWkAAySID.jpg
Petrobras new FPSOs – We’ve seen delays in the past, I guess due to low oil prices but I guess it’s too late to delay these now?
Lula Sul FPSO P-69 started Oct
Buzios2 FPSO P-75 started Nov
Lula Norte FPSO P-67 first oil early 2019
Buzios3 FPSO P-76 set sail Dec19th first oil early 2019
Berbigão FPSO P-68 delayed
Buzios FPSO P-77 production scheduled 2019
Atapu FPSO P-70 2019
2020 nothing listed
I guess that I should remind people that Petrobras’ production fell in 2018 partly due to the sale of stakes in several fields. Brazil’s production (ANP) is back up to about the same level as it was in 2017.
Buzios1 FPSO P-74 started in April
Tartaruga Verde e Mestica FPSO Cidade de Campos dos Goytacazes – started June 2018
Hello Dennis Coyne or someelse
What do you think about Delaware Basin has 46.3 billon of barrels?
If the USGS mean estimate is accurate for the Permian Basin (including Delaware Basin), then technically recoverable resources(TRR) for tight oil are about 74 Gb and when we apply the usual economic assumptions the economically recoverable resources (ERR) would be about 60 Gb. Currently Permian output is about 3000 kb/d, the medium model with ERR =60 Gb peaks at about 7300 Gb in 2028 and output doubles to 6000 kb/d by 2023 (about an average annual increase of 750 kb/d in Permian Basin output). The USGS F95 and F5 cases are also covered in the chart below and for all cases the EIA’s AEO 2018 Brent Oil reference case is assumed for future oil prices. For the low (F95) case ERR= 35 Gb and the high (F5) case ERR=98 Gb with peaks of 5500 kb/d and 10,000 kb/d in 2023 and 2031 respectively. Probably 50 to 80 Gb is a reasonable guess with about a 70% probability ERR for the Permian Basin will be in that range.
The article below was published on Sunday (Dec 31) in the older of the two daily newspapers in my neck of the woods. My feeling is that this is an effort by this newspaper to bolster opinion that initiatives to introduce NG as a fuel in Jamaica are the best solution to the islands energy challenges.
For some background, US outfit New Fortress Energy has been having some success with introducing NG as a fuel to the island. There has been a long protracted process to do this that has been mired in corruption with a former energy minister being involved in the setting up of a company that was to supply LNG to the island but it seems New Fortress was finally able to come up with a scheme that satisfied the government and the local private sector. The “Our Work page lists supply of LNG to a 120 MW (Combined Cycle) electricity generating station in Montego Bay that has been converted to run on NG, a floating storage and regasification terminal to supply LNG to a brand new gas-fired combined cycle power plant under construction by the local electricity utility and supply of NG to a new power plant at a bauxite to alumina operation in central Jamaica. It has also been reported in the media that, the island’s largest beverage manufacturer has installed a co-generation pant to provide power, process heat and cooling to their operations, the local campus of the regional university is setting up a co-gen plant on the campus and a second beverage manufacturer/distributor is to set up a co-gen plant as well. I have seen “New Fortress” branded storage tanks at the beverage manufacturer and a single tank at the university’s facility. It is extremely likely that the third announced co-gen pant is also a New Fortress customer. I am a little suspicious of the fact that the entirety of New Fortress’ customer base appears to be in Jamaica.
I am somewhat concerned that my island home is being sucked in by the “energy abundance” hype. Once the infrastructure has been put in place and the co-gen and power plants are built, it will be a difficult/expensive undertaking to to try and switch energy sources again. These Jamaican operations will be married to NG for decades to come.
Last November, diplomats from Brazil to Japan joined oil and gas executives at the headquarters of Washington’s largest lobbying group to christen a new partnership.
Inside the marble walls of the US Chamber of Commerce, a crowd of 200 welcomed the US Gas Infrastructure Exports Initiative ó a coalition of 25 companies, nine trade groups, five law firms, at least five federal agencies and a non-profit think tank. Its mission: to drive sales of American natural gas by pumping dollars into pipelines and gas-processing facilities overseas.
The initiative, coordinated in part by a natural gas lobbyist, is the latest federal effort to market the fuel as a “clean” energy source amid surging US drilling and exports. American gas production is projected to account for almost 40 per cent of the world’s gas growth through 2040, according to the International Energy Agency. Countries like China are buying up tank loads of LNG – natural gas that has been supercooled to liquefy it ó to generate power, heat buildings and fuel trucks.
“When it comes to exporting LNG, the United States is open for business,” Mark Menezes, undersecretary of the US Department of Energy, assured the audience at the launch of the gas initiative. Menezes, a former utility industry lobbyist, added that exporting US liquefied natural gas is “clearly in our economic interest.”
Islandboy
Jamaica is in the forefront of an emerging, global energy paradigm that I have mentioned a few times on this site.
Specifically, the adoption of natgas for a much bigger consumer base than at present.
For your information, New Fortress Energy plans on constructing up to 10 LNG plants with at least 2 in the Appalachian Basin.
Throwing out numbers seems a poor way of transmitting info, but the first AB plant in Bradford county, PA, would produce almost as much as the Elba Island plant (2.1 million tonnes per year … mtpa), cost a – relatively – paltry $850 million, and be built in under 18 months.
These numbers are simply disruptive in the extreme.
Your mention of the co-gen projects (commonly referred as Combined Heat and Power … CHP) is additional evidence of the dizzyingly rapid development of hardware associated with this technology.
(Spending some time reading up on small scale and mid scale LNG will give one a sense of what is coming down the pike).
Your concern about a multi decade long embrace of natgas is shared by a great many competing industries, ideologies and countries.
Hence the scorched earth campaign to impugn US natgas at any and every opportunity.
That your country is proceeding down this path, offering abundant and cheaper energy over a wide swath of your country’s populace might prompt some study in this arena.
On page 2 of the report we find Natural Gas combined cycle has LCOE of $41 to $74 per MWh and utility scale solar a price of $36 to $46 per MWh. These costs are without any subsidies included.
Utility scale solar PV has been falling in cost at a rate of 21.6% per year from 2010 to 2017 based on NREL (National Renewable Energy Laboratory) data.
May the cheapest energy source win!
Note that pollution costs for natural gas are not included in these estimates.
For those who understand that Global Warming puts the world at risk, solar and wind power over natural gas or coal is not a difficult decision.
That same report shows nuclear to be LCOE at $26/MWh.
Before Carlos or others get all frothy on this, read the footnote indicating this is for a fully paid off reactor. The costs at that point are labor, reactor maintenance, re-fueling, security, insurance and such.
The equivalent cost for utility scale Solar electricity that was fully depreciated would be likely about $3/MWh!
For reference sake- The electricity cost from nuclear that isn’t already paid off ranges from $112-189/MWh.
Just like the last four months of 2016, Russia and OPEC is ramping up to maximum possible production so they can “cut”. And their cuts will be from the last few months of 2018 when they were producing every barrel of oil the could possibly produce. However the average for the last four months of OPEC+Russia for 2018 will be about half a million barrels per day less than the average for the last four months of 2016.
Ron,
Good point, but how does it look if we exclude Venezuela? Venezuela’s C+C output has fallen by about 800 kb/d since the 2016 OPEC peak in Nov 2016 through Sept 2018.
If Venezuela is excluded, OPEC+Russia minus Venezuela is slightly higher in Sept 2018 than in November 2016 (45215 kb/d vs 45128 kb/d).
And just why would you exclude Venezuela? I am sure Venezuelan oil production will one day recover, but that is likely to be at least a decade from now. Not only is their infrastructure being destroyed but their economical structure is being destroyed as well.
There will always be countries with political problems that affect oil production. Look at Libya, Nigeria, and Sudan. The political problems in these countries are never ending. If peace broke out all over the world then oil production would definitely go up. Fat chance of that happening.
When peak oil happens, Venezuela will, very likely, be producing less oil than they are today, a lot less oil.
Ron,
The point is to explain that 800 kb/d of the 500 kb/d decrease that you mention is because of Venezuela’s collapse, rather than natural decline in OPEC output. Output in Venezuela may continue to fall, perhaps by another 800 kb/d, though it will not be more than the 1271 kb/d that was produced in Sept 2018. This is just to show that all of the OPEC decrease from Nov 2016 to Sept 2018 is explained by Venezuela’s collapse in oil output. Another potential place where oil output could drop is from Iran in May when the sanction waivers are set to end.
Dennis, nowhere in my post did I make the claim that it was all due to natural decline. Venezuela is nevertheless still producing every barrel she can possibly produce. Her decline is not due to natural depletion but to political problems.
Other countries are having similar problems as well though not quite as severe as those of Venezuela. There will always be political problems that interfere with oil production. That just goes with the territory.
When peak oil occurs many will countries will still have political problems. The situation is far more likely to get worse than it is to get better. Nevertheless peak oil will be peak oil regardless of the cause.
I’ve noticed that Venezuela imports natural gas. From looking at Canada I notice they use a lot of natural gas to supply energy for bitumen mining. Canada exports natural gas. Perhaps Venezuela doesn’t have the energy to mine their heavy oil sands, as well as political factors. I wonder what mining bitumen using bitumen as an energy source to do so is like in terms of profit/EROI etc. I imagine that once Canada runs thin on natural gas their bitumen mining and processing will decline. I imagine Canada would be doing less well if they had to import natural gas to fuel bitumen mining.
Survivalist – apologies if you know this already. Venezuela heavy oil isn’t bitumen (defined as oil with viscosity above 10000 cP if I remember correctly) and it will flow naturally, if reluctantly, up a conventional well (unlike bitumen). Their upgraders are flexicokers (upgrade by removing carbon) rather than hydrocrackers (upgrade by adding hydrogen from natural gas). Canada uses natural gas to generate steam in SAGD developments and in upgraders, Venezuela doesn’t, although there may be a bit of steam EOR in conventional fields.
George, I think you are mistaken. Venezuela has two types of oil, conventional and bitumen. Their conventional oil is in decline. Their bitumen is not in decline but they are having serious problems with it.
Their bitumen is so heavy it will not flow naturally so they add naptha to it to lower the viscosity before they can ship it through their pipelines. Now they are having very serious problems finding enough naptha to mix with their bitumen.
I have no idea how they extract it from the ground.
“Most of Venezuela’s proved oil reserves are located in the Orinoco Petroleum Belt. Although often referred to as oil sands (or tar sands), Venezuela’s oil sands are technically “extra heavy oil” deposits since they don’t contain bitumen.”
I think they add diluent to get flow in the pipeline from the wellhead to the process ing plants, not as part of the reservoir depletion strategy (same is done in Canada).
George Kaplan,
This post–short, concise, with lots of information included that gives an overview of a particular topic–is an example of what causes me to feel uneasy when you speak of maybe cutting back on posting.
The Orinoco heavy oil belt is very large, the reservoirs are thick, have a range of oil density, solution gas, temperature, and therefore viscosity. I’ve seen a well pump 2600 BOPD of 8 degree API crude, with 120 scf/bsto gas oil ratio, without diluent.
In some fields diluent is added downhole, but this wasn’t that common when I worked there. Most wells have diluent added at the wellhead, to reduce viscosity (given that temperature drops as the oil moves towards the surface).
All upgraders were designed to add hydrogen to the product slate, but they range from a simple addition limited to the coker nafta, to full hydrogenation for some of the syncrude made at the Total upgrader.
I prefer to use the name extra heavy oil for the oil being produced from the Faja, because it’s lower than 10 API. I don’t like the term bitumen, but I suppose one could use it for oil that’s heavier than 10 API and has viscosity higher than say 10K centipoise.
I expect Venezuela’s production to take a hit in January, because on January 10 Maduro will attempt to be sworn in as president, and this isn’t considered legitimate by about 42 nations. FYI I’m advocating all Venezuelan state property and bank accounts be placed under an administrator who will make funds available to the transitional body headed by Guaidó, the new National Assembly President. If my advice is followed the regime should fall sometime over the next three months. I expect a lot of chaos and quite a few deaths.
I don’t like the term bitumen, but I suppose one could use it for oil that’s heavier than 10 API and has viscosity higher than say 10K centipoise.
Almost every article I have ever read on the stuff calls it bitumen. And I have read a lot of articles on the Venezuela bitu…. err… sorry, I have read a lot articles on the Venezuela heavy oil. So imagine my shock when I was told by some on this forum that it it not bitumen at all.
Hi Ron,
There is plenty of stuff written that is not correct.
Ron, there’s nothing I can do if those who don’t get it keep quoting each other and adding to the confusion. I’m just a petroleum engineer who supervised teams doing Faja developments, and to us the reservoir fluid is oil. The high viscosity makes the standard depletion equations a bit inaccurate, but in the end the stuff behaves like oil.
Let’s put it this way: if I see a petroleum engineer referring to the reservoir fluid being produced in the Faja as “bitumen” I would consider him poorly trained and schedule him (or her) to a special catch up training session.
Survivalist, Venezuela has many problems. Their oil field and refinery works are quitting because they do not get paid, or paid very little. They cannot get parts to repair their oil field and refinery infastructure. And they cannot get enough naptha to mix with their bitumen in order to get the viscosity low enough to pump through pipelines.
I am sure they are having problems mining the stuff as well.
Ron,
Orinoco oil is as George said considered extra heavy oil rather than bitumen. It is pumped rather than mined.
On the surface, Alberta and Venezuelan oil sands appear very similar. Both are unconsolidated sandstone deposits, with similar densities and sulphur content. But there are some important differences. And some of those small distinctions give Venezuela several advantages:
1. Better geography:
The Orinoco Petroleum Belt has excellent access to tidewater. And the world’s biggest consumer of heavy oil is relatively close-by in the US Gulf Coast, a mere 5 day boat ride.
Thanks to proximity to the equator, oil sands deposits in Venezuela are closer to 50°C, much warmer than Alberta’s oil sands which tend to average closer to 20°C deep underground and just 5°C close to the surface. That means much less energy is required to bring the oil to a flowing temperature.
2. Simpler geology:
Alberta’s oil deposit is much older, comprised of a more complex geology, more types of sediments and a wider variety of reservoirs. Venezuelan oil sands is younger, deeper, more uniform, more concentrated and more saturated with a coarser grained sand. This allows for better recovery rates under the same operating conditions.
Viscosities in Alberta range from 10,000 cP in the Lloydminster area, 100,000 cP near Cold Lake and 400,000 cP closer to Fort McMurray. Venezuelan heavy oil deposits in contrast have a more uniform viscosity, typically ranging from 4,000 to 5000 cP. Coupled with the warmer climate, that means Venezuelan heavy oil actually flows under ambient conditions, whereas Alberta bitumen is virtually solid at room temperatures.
I think most of their infrastructure is so degraded as to be unfixable and would have to be replaced completely to be acceptably safe under even the most lenient of E&P operating rules. To get back to 2 mmbpd that would probably cost $250 billion upstream, maybe $100 to 200 billion more for midstream and upgrading/refining. Who would invest that given the risk of future nationalisation etc? Who would get the the required skilled work force to go there (many of the best people moved to US when the previous nationalisation happened)? Are the reserves really what is claimed? Even with the best scenario it’s 10 years before any new plant would come on line, and let’s not forget that to save the world oil use is supposed to be reducing at 5% per year – given that why risk investing in the worst possible global environment for energy production.
George,
Excellent analysis (as always), thanks.
Thanks everybody for the info. I appreciate it.
Hi Ron,
Correct, you did not say it was natural decline, nor did I say that you said it.
You said in 2018 OPEC+Russia C+C output was 500 kb/d less than the peak in 2016. I was showing why this is the case, it is entirely due to political problems in Venezuela.
My point is that the decline is 100% (more than that actually, it’s 800 of 500 so 160%) due to the political crisis in Venezuela and yes there have been many other political crises in the past and these will continue in the future. (Soviet Union, Iran, Iraq, Kuwait, Libya, Nigeria, and Venezuela come to mind.)
These are impossible to predict in advance and over time these problems sometimes get resolved (Russia/Soviet Union, Kuwait, Iran, and Iraq being examples as far as recovery in oil production). There have been partial recoveries in Nigeria and Libya, though of these two the situation seems more precarious in Libya. Venezuela seems a long way from resolving political problems and may continue to decline to 400 or 500 kb/d over the next few years. Combined output from US, Russia, and the rest of OPEC (excluding Venezuela) is likely to be enough to keep World C+C output rising if demand for oil continues to rise (which seems likely unless there is another Global Financial Crisis before 2025).
This scenario also assumes we do not have a major War either worldwide or in the Persian Gulf before 2025.
Predicting war or major recessions in advance has never been my strong suit. 🙂
Combined output from US, Russia, and the rest of OPEC (excluding Venezuela) is likely to be enough to keep World C+C output rising if demand for oil continues to rise…
You are of course assuming that output from US, Russia and the rest of OPEC will continue to increase production. And you are also assuming that this rise in production will be great enough to overcome the decrease in production from the rest of the world.
Rather iffy assumptions I would say.
Correct,
Those are assumptions. I would say they are the best assumptions based on the information available. The future is not known, be can only estimate based on the information we have.
The assumption is: All countries that are currently increasing in production will continue to do so for the next several years.
And: All contries currently in decline (the vast majority of oil producing countries), will not significantly increase their decline rate.
That is a bet I would not dare to take.
A few months ago I posted a quote from the OPEC CEO that all mature fields around the world have a decline rate that is increasing. He was calling for more capex from all oil producing countries and companies.
Just in case that is of any interest to you.
“He was calling for more capex from all oil producing countries and companies.“
Ron,
And many know that that amount is increasing, because more and more EOR projects have to be developed to prevent world oil producting from falling.
A remarkable Forbes article from 2016 (I couldn’t copy paste the site because it was marked as spam)
‘Saudi Arabia Burns Through Foreign Reserves As Oil Prices Slide‘
Hi Ron,
Jean Laherrere estimates about 2500 Gb of World conventional resources, in 2000 the USGS estimated a mean TRR for the World of about 3000 Gb, my estimate is about 2800 Gb. Laherrere uses a combination of Hubbert linearization and creaming curves as the basis for his estimates, over time his estimates have tended to be conservative (rising from 1800 Gb to 2500 Gb for conventional C+C from 1998 to 2018), the USGS estimate might be too optimistic so I picked a round number between 2500 and 3000 rounded to the nearest 100 Gb. I think a plateau from 2020 to 2029 between 84 and 85 Mb/d is likely with the most likely date of the peak between 2024 and 2026 (this is centered 12 month average World C+C output).
Our estimates of when the peak will occur are not that far apart. Note also that the low oil prices of the past 4 years suggest that oil supply is adequate, I would expect to see sustained Brent oil prices at over $100/b (in 2017$) as we approach the peak, probably from 2022 to 2026, with oil prices gradually rising from $60/b to $100/b from 2019 to 2022.
Dennis, guesses about how much oil is left in the ground is really a non-issue. All that matters is how much oil can be extracted from the ground on a daily basis. That’s what we watch because that’s all that we can see. And really, that’s all that matters.
Ron,
How much can be extracted depends in part on how much has been discovered and what portion of those discoveries has been produced and what portion remains as recoverable reserves.
Finding what has been produced is pretty straightforward, predicting future production is tricky.
You seem to assume that I assume that all nations that are increasing production will continue to do so, some will and some will not, but on balance output is likely to continue to increase as a slower and slower rate until the peak is reached, we simply disagree about when this will occur by a few years. Eventually your estimate will be correct. Frankly I hope that your estimate is correct, but to me that is just wishful thinking and I am not the optimist that you are. 🙂
“, and let’s not forget that to save the world oil use is supposed to be reducing at 5% per year “
George,
Many think that, notwithstanding increasing renewable energy, world oil use has to increase yoy to keep world economy on a growth path. Of the many big companies who count on that, Boeing is one. If, at last, somewhere in the future, EV sales are taking off seriously, this story becomes different. Then the airline companies can grow while world oil production is declining, assumed that the world economy doesn’t collapse.
Take the many contradictions in the world news, of course that leads to incompatibilities in the decades ahead.
Han,
I think the aim is to reduce carbon emissions by 5% per year. This can come from reducing the use of coal in producing electricity as well as natural gas used in producing electricity as well as reduced oil use, as the peak approaches and fossil fuel prices rise and as costs for solar wind, EVs, and battery storage continue to fall there could be a rapid paradigm shift to less fossil fuel use.
Once peak fossil fuels becomes a reality and is fully accepted by the mainstream, all the time and energy wasted on expensive options like coal, oil, natural gas, and nuclear power will be transferred to cheaper and more environmentally sustainable solutions like solar, wind, EVs, electrified rail, and HVDC transmission widely interconnecting the power grids of most nations which will greatly mitigate the problem of intermittency of alternative energy as it is moved North and South and East and West.
02 Jan 2019 (S&P Platts) Nigeria’s deepwater oil field, Egina has achieved first oil production, helping to push oil production beyond 2.09 million b/d in December.
“At plateau, the Egina field will produce 200,000 barrels of oil per day, which represents about 10% of Nigeria’s production,” Total said in a press release Wednesday that noted production started on December 29th that used the oil major’s largest ever Floating Production Storage and Offloading (FPSO) unit.
World oil production will soar to new records over the next five years, as a dramatic expansion in demand from airlines offsets the arrival of electric cars, according to a report from Opec.
In a forecast that will dismay environmentalists – and which questions the theory that oil company reserves will become “stranded assets” – Opec’s annual report significantly revised production estimates upwards.
Most of the production increase will come from countries outside Opec, led by explosive growth from frackers in the United States, with China and India leading the increase in demand.
Opec expects global oil demand to reach nearly 112m barrels per day by 2040, driven by transportation and petrochemicals. That is up from almost 100m today and higher than last year’s projection.
Coal will continue to be be burned in record amounts, despite concerns about its impact on climate change. Opec estimates that coal usage in the OECD countries will plummet by a third by 2040, but it will increase by 20% in developing countries to reach five times the volumes burned in the west.
It is just assumed that production will rise to meet demand. OPEC knows what they can do so they just assume non-OPEC, primarily the USA, will increase production to meet demand.
So what price and what miracle would sustain and increase the US fracking production through 2040?
The only thing that would do it is God pointing his finger at the US and saying: “Let there be more oil in that US shale.” And he would have to come back every five years and do it again.
Gone Fishing,
If production were increased slowly, US tight oil output might increase through 2040, or at least maintain a plateau for many years, things don’t usually work like that in a free market economy, so not likely. Actually lower prices would make it more likely that production would ramp slowly, something like $50 to $60 per barrel with a gradual increase over time to $100/b
Gone fishing,
Scenario below assumes a slow increase in Permian Basin tight oil output due to pipeline and port constraints tight oil output increases about 750 kb/d from 2019 to 2033 and then falls back to 2019 level by 2037. Clearly this is not the surge in tight oil output that many expect, it is based on the AEO 2018 Brent oil price reference scenario, which has real oil prices in 2017$ only reach $113/b in 2050. I expect by 2027 at the latest there will be severe shortages of oil supply relative to demand at the AEO reference scenario price (Brent oil price about $89/b in 2017 US$).
This scenario has a tight oil URR of about 83 Gb (Permian- 58 Gb, Bakken- 9 Gb, Eagle Ford 10 Gb, Niobrara 3.5 Gb, rest of US tight oil 3 Gb.
Potentially there might be some tight oil output from the rest of the World, but I doubt it will be enough to keep prices low as ramp up is likely to be slower than the US. As demand falls due to the expansion of EVs of all types (2 wheel, 4 wheel, buses and trucks) tight oil may not be viable in other nations competing with cheap oil from the Persian Gulf.
Dennis
For demand to fall there has to be fewer petrol and diesel cars.
Electric cars must also offset the increased consumption from aviation and shipping.
How many electric cars have to be sold each year for total consumption to start to fall?
Hugo,
Oil supply will not be able to increase forever and eventually production is not sufficient to meet consumption at the current price level and the oil price is bid up from too many consumers chasing too few barrels produced. In this environment of continually rising oil prices, air fares increase, shipping costs by water rise and land shipping rates also rise. Fewer goods and people move by air and more of air transport moves to sea. Where possible goods are moved over land (if it is cheaper).
None of this happens overnight, the chart above is for tight oil only (about 9% of total World C+C output at its maximum). For the World output may decline more slowly. Much will depend on the price of oil relative to alternative sources of energy.
“In this environment of continually rising oil prices, air fares increase, shipping costs by water rise and land shipping rates also rise. ”
Dennis,
We’ve seen this before, a decennium ago. When it happens again, we have a lot EV’s on the road. However after a year or so with high oilprices there probably follows a severe economic recession again, resulting in collapse of oilprices. Many people who planned to buy an EV will then buy an ICE car instead, notwithstanding that EV’s will be more available and much cheaper and the ringing alarm bells of climate change. This when world oil production slowly starts to decline around 2023. We know from the models and individual country examples of ‘westexas’ (where is he ? IIRC he was insulted on theoildrum after which he never came back there) that when oil production starts to decline, oil exports start to decline at a much faster rate. If world oil production starts to decline about five years later (2028) then the increase in sales of EV’s will have reached the point of no return.
“Once peak fossil fuels becomes a reality and is fully accepted by the mainstream, ”
Fully accepted….not so easy. Peak coal and peak gas will be later than oil peaks, that is, the geological peak. If it works out as you describe, the decrease in demand for coal and gas could cause the peak. For world oil production also exists the possibility of a many years lasting undulating plateau. That would make the possibility for a smooth transition more likely. Otherwise I predict an energy transition with many ‘problems and pain’. In theoildrum time, it was Ron who repeatedly mentioned the possibility of oil exporting countries starting to hoard oil when oil production starts its irreversible decline. KSA is rapidly burning through its money reserves (most EOR projects are insanely expensive now) and I expect them to leave some not too difficult to recover oil in the ground for future generations and use for aeroplanes.
“…. and as costs for solar wind, EVs, and battery storage continue to fall there could be a rapid paradigm shift to less fossil fuel use.”
We have to differentiate between coal and gas use and oil use. I have to agree with what Hugo states:
“Electric cars must also offset the increased consumption from aviation and shipping.”
For example Boeing has received mega orders already for new airplanes, and not only for replacing old ones. When oil peaks, certainly the number of flights will go down, many (small) airline companies will go bankrupt. A global economic down-turn has its own risks and consequences.
Taken all the issues together, I expect the chance for the smooth transition as you picture not very high.
In theory it is rather easy, but ‘in the real world’ more variables come into play. Human behaviour (look in France now) and the global debt (much more than 10 years ago) and personal debt (many people having more (credit card) debts than 10 years ago) are three of them.
Han,
I have never actually said there will be a “smooth transition”, only that it is possible that one could occur.
There were many obstacles to landing a person on the moon and returning them safely to earth, a rational person in 1961 would have said that President Kennedy’s goal to land a person on the moon by 1969 could never be accomplished, there were too many things that could go wrong.
Note that many of my scenarios show a smooth curve to describe the future, this is simply because future shocks from wars, recessions, or natural disasters cannot be predicted in advance, nor can their magnitude be predicted.
My expectation is that the fact that oil has peaked will make people realize the possibility that coal and natural gas will also peak in the future more accepted by mainstream analysts even before they have occurred.
I also expect that EVs and other factors that may mitigate the peak in oil output will not be enough to avoid economic disruption as the energy transition occurs. The economic disruption is likely to lead to either a severe financial crisis at least as severe as the GFC or possibly to a severe depression like the Great Depression. I expect that to occur from 2030 to 2035.
One possible response is WW3, another possibility is the fear of nuclear holocaust might lead to a Global mobilization to speed up the energy transition, so rather than a World Wide effort to destroy as in 1939-1945, there would be a similar level of effort to dismantle the World fossil fuel industry and replace it with non-fossil fuel energy. Impossible to predict which road will be chosen, but I would choose to avoid WW3.
Hugo,
Using the LTO scenario a few comments up for the US LTO and assuming the rest of the World produces no tight oil and extra heavy oil output ends up being only 230 Gb (supposedly proved reserves of extra heavy oil are 387 Gb with cumulative output of about 16 Gb, implied URR=403 Gb.)
Extraction rate shown is for conventional oil only (excludes extra heavy oil and tight oil), total World C+C URR=3120 Gb, with LTO URR=90 Gb, extra heavy URR=230 Gb and conventional C+C URR=2800 Gb.
Peak for this scenario is about 85 Mb/d in 2024-2026 and output is between 84 and 85 Mb/d from 2020 to 2029. One possibility out of an infinite number of paths future oil output might take.
Dennis
The question is will enough people be buying electric vehicles in 2025 to avoid high oil prices?
If we assume oil production cannot increase after 2025 then demand must also peak. That would require at least 50 million electric vehicles sold each year by then. Once oil production starts to fall, the number of petrol engines must fall at the same rate.
If not oil prices will cripple the economy.
“If not oil prices will cripple the economy.”
Highly likely. Those who have electric vehicles will be lucky, and those countries/regions that have invested in electrified transport of cargo capability will have a big cost/survivability advantage.
The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.
EV30@30 requires all governments to put in place strong incentives to purchase EVs. Such as no sales tax, free parking, zero road tax.
EV30@30 may be enough to meet the Paris agreement be falls short of preventing global warming and comes nowhere near coping with Peak Oil
Even if you put climate goals aside, a strong shift to electrification will be a necessary adaptation to shortfalls in crude oil supply. And that won’t need any economic incentive, beyond what fuel price provides.
It will be obviously much cheaper miles than petrol by mid decade.
The two big variables other than oil supply, is cost of batteries, and the turnover rate of the current fleet of worldwide vehicles. If economies struggle, people will hold onto their current ICE vehicles much longer.
Here is an example of a vehicle available today. I’m getting combined 54 mpg with it. The plugin electricity (from PV roof panels) has provided 69% of miles driven thus far. Great ride , btw https://www.edmunds.com/chrysler/pacifica-hybrid/
“The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.”
That is not optimistic. VW group wants to produce 25% BEVs in 2025, in addition there would be some PHEVs.
IMHO around 2025 the BEV share of new cars will lead to a decreasing demand for fuel, in 2030 more than 40% of the new cars will be BEVs.
However, vans and truck s are more interesting. 🙂
The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.
Ever heard of Tony Seba? his original projection in his 2014 book was for 100% of new US vehicle sales to be electric by 2030. Since the he has upped the ante, projecting 100% of US sales being electric by 2025. An important factor to note, in their May 2017 report, RethinkX, Rethinking Transportation 2020-2030 Seba and his coauthors, in Figure 9. Trends in vehicle sales, on page 39 of the report, project that by 2025 US annual sales will have fallen to less than a third of current levels, that is, roughly 5million units per year.
The most recent Monthly Plug-In EV Sales Scorecard over at insideevs.com has the tally for 2018 US plug-in sales at 361,307. If that figure were to grow exponentially, four doublings would take that figure to over 5.6 million. The growth of plug in sales in the US between 2017 and 2018 was roughly 80% so a quick spreadsheet, extrapolating those numbers, gets us to over 6.8 million unit sales by the end of 2023!
Moving over to the largest market for vehicles in the world, China, the web site 247wallst.com reports:
EV-volumes expects NEV sales to reach 1.1 million units in China this year. Of that total, 74% are forecast to be battery-electric vehicles (BEVs) like the Tesla Model S or the Nissan Leaf and the rest are expected to be plug-in hybrids (PHEVs) like the Chevy Volt. The total 2018 market for new cars in China is forecast at 26.3 million units.
Since June of 2017, the total number of plug-in models available in China has risen from 56 to 101. Of those, 70 are BEVs and 31 are PHEVs, and all are manufactured by 39 automakers. EV-volumes reported that 11 new carmakers joined the NEV fray over the past 12 months and that a shakeout is likely.
The Chinese government’s stated goal is to have 5 million NEVs on the country’s roads by the end of 2020. EV-volumes expects the number to reach about 2.35 million by the end of this year. At current growth rates, 5 million seems like a slam dunk.
Global brands covet the Chinese motor vehicle market and if they are to survive there, they will in all likelihood, have to step up their EV game considerably to comply with government regulations and compete with the local brands.
Still think 30% by 2030 is optimistic?
Hugo,
Prices rise gradually and people start buying more efficient vehicles as oil prices rise, these can be hybrids, plugin hybrids and EVs. As to higher oil prices crippling the economy, the price signal tells people the resource is scarce and causes behavior to change, people stop buying ICEVs and are willing to pay higher prices for EVs and plugin hybrids. Those companies offering compelling EVs and/or plugins do well, those that do not do poorly. The world economy did not do poorly in 2012 and will probably be fine up to an oil price of $160/b, due to the higher economic output in 2025 and the smaller proportion of oil as an energy source relative to fast growing wind, solar, and natural gas. The $160/b is the nominal Brent price, in 2017$ it would be about $127/b.
If plugin vehicle sales grow by 50% per year from 2018 to 2026, then about 46 million are sold by 2026. The 2017 to 2018 growth rate in world plugin sales was 63%. About 2 million were sold in 2018. Telsa sales increased by 282% from 2017 to 2018. Clearly that rate cannot be sustained, but 80% growth may be achievable for Tesla in 2019 and in 2020 the Model Y will ramp up production and take SUV sales in the luxury SUV market, then the Telsa pickup truck will be next in 2022.
Eventually the existing automakers will join the game and try to catch up with Tesla, which will have become synonymous with EV by 2023.
Dennis
Prices have gone from $60 to $147 in 14 months. This was at a time when global oil production increased by 700,000 barrels per day.
By the end of 2025 there will be another 500 million people on the planet. They will all want their food transported by plane, and lorry. They will require extra ships to transport goods around the world and many will join the 4 billion people who took a plane trip last year.
If oil production is flat in 2025, prices will surge. Sales of vehicles will be in the region of 110 million and at least 50 million would need to be electric to keep oil prices within a reasonable range $140 -$160.
India sold over 4 million cars last year and only 1,200 were electric.
I cannot see electric car sales hitting anywhere near 50% in 7 years and every country will have to hit these kind of level.
I’m not as confident as you that there will be an increase in world trade.
Globalism and the trade that goes with it might continue to fall out of favor.
Hugo,
No every nation does not have to reach 50%, just World total sales. If it does not occur then oil prices would be higher. Note that in the 1980s the percentage of World GDP spent on oil went as high as 7% which would be a nominal price in 2025 of about $280/b and about $222/b in 2017$.
So there may be some demand destruction and slowing of economic growth as oil prices rise, partially offset by the expanding EV, wind, solar, and HVDC industries that ramp up to replace fossil fuel.
“For demand to fall there has to be fewer petrol and diesel cars.”
Improved fuel efficiency can do a lot too, even if the number of ICE-vehicles is the same or increase. That is probably why most OECD countries have flat or declining oil consumption.
Jeff,
Most OECD nations no longer have increasing vehicle fleets, total vehicles registered have stabilized in most advanced economies. Fuel economy is also increasing in many nations leading to declining oil consumption, though higher amounts of air travel tends to offset the lower oil use in land transport.
If we have a global recession or depression, we won’t need as many planes flying around, ships going from country to country, or trucks transporting goods from one place to another.
And we don’t need EVs to replace all ICE vehicles if people don’t drive their ICE vehicles.
There are ways to decrease petroleum consumption. Some are less painful than others, but there are multiple ways to do it.
“There are ways to decrease petroleum consumption. Some are less painful than others, but there are multiple ways to do it.”
A very simple way to save 10% on fuel is to slow down something like 10 mph. Country wide- that can be a big deal. Nixon imposed a nation wide 55 mph limit in response to Saudi oil embargo, in 1974.
Hickory,
Great point. Unfortunately there is this urban myth that when the speedometer is at about 12 o clock on an analog gauge, that point is the maximum efficiency point for the vehicle. For many vehicles this is about 70 mph in the. US, about 110 km/hour.
Unfortunately this is not the case, maximum fuel efficiency for most ICEVs is about 50 miles per hour (80 km/h).
Perhaps oil company lobbyists have perpetuated the myth.
For F150 4WD 5 Litre engine , slowing down from 80 mph to 65 mph increases fuel efficiency by 26.7%. Slowing down from 80 mph to 55 mph increases fuel efficiency by about 44%.
When fuel prices increase people may take advantage of these savings, higher tire pressure (35 psi rather than 32 psi ) also helps increase fuel economy. Slightly rougher ride but actually safer at high speed.
And now it is time to think in terms of miles/kwh, which as mentioned at another point in a thread is just as aerodynamically affected.
I have noticed that hills are hell on battery energy levels. I could never directly observe that effect on ICE vehicles, since the fuel guages weren’t digital.
[I live 800 ft up a ridge from town/services].
Perhaps charging stations should be positioned at the base of mountain passes.
Those figures are a bit hokey. NGL production is increasing, but NGL ain’t crude oil or stabilized condensate.
MSM seems to be catching on to the hype in shale, excerpts from an excellent article on shale on WSJ today:
Two-thirds of projections made by the fracking companies between 2014 and 2017 in America’s four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota.
Collectively, the companies that made projections are on track to pump nearly 10% less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are off track by more than 50% in certain regions.
——
In September 2015, Pioneer Natural Resources, based in Irving, Texas, told investors that it expected wells in the Eagle Ford shale of South Texas to produce 1.3 million barrels of oil and gas apiece. Those wells now appear to be on a pace to produce about 482,000 barrels, 63% less than forecast, according to the Journal’s analysis.
An average of Pioneer’s 2015 forecasts for wells it had recently fracked in the Midland portion of the Permian basin suggested they would produce about 960,000 barrels of oil and gas each. Those wells are now on track to produce about 720,000 barrels, according to the Journal’s review, 25% below Pioneer’s projections.
In 2014, Parsley Energy, an Austin, Texas-based producer, told investors its average well in the Midland section of the Permian basin would produce 690,000 barrels, according to a review of Parsley’s quarterly earnings presentations. By 2015, its estimates averaged 1,050,000 barrels.
Parsley is on track to miss its Midland well forecasts for every year from 2014 to 2017 by an average of 25%, according to the Journal’s analysis.
——
One reason thousands of early shale wells aren’t meeting expectations is that many companies extrapolated how much they would produce from small clusters of prolific initial wells, according to reserves specialists. Some also excluded their worst-performing wells from the calculations, which is akin to eliminating strikeouts when projecting a baseball player’s batting average.
It’s not a science,” said Richard Robuck, the company’s treasurer. “It’s more of an art.”
WHAT THE F…k
He’s trying to minimize the incoming lawsuits…
If you knowingly overstate your projected cash flow of your business when applying for loans or soliciting investment, that’s called “fraud.”
There are supposed to be “competent” third party assessments to confirm reserves, but without much end of life history for LTO wells, models that are being continuously tweaked against real production data, and all that hyped “new technology” being applied it’s difficult to see how reliable these can be. If the law suits do start flying it will be interesting to se who else gets dragged in and how quickly the consultants pull out (although they may have enough arse coverage statements in their assessments anyway).
Don’t have the paywall, but you’ve given the gist. Investors were not happy with returns. Now, they are being fact checked, and that can look real messy. Borrowing is set to become restricted for many reasons. I really see some headwinds for future production increases. Based on first year production numbers supplied by Shallow Sand, production can’t increase without borrowing, except in some isolated areas. To get even close to covering declines from last years wells, they have to, at least, recover most of that capex cost in the first year of production. That is far from reality, right now. To increase, or later to even keep up, with production, they will have to borrow money. They can possibly make a profit in three years, but that is meaningless to providing for growth. Think it going to start looking nastier.
And to add to Ron’s answer, God would have to add, and make each well profitable the first year.
The miracle of US shale is about to have Toto pull back the curtain and reveal the real wizard.
Shale was, is, and will be just a supplemental source of oil supply. An investor could, if it was managed right, put x amount into the business, and in several years get a marginal return. In two to three years, a second well could be drilled to increase that income. That would be shale production growth. Not the imaginary growth numbers that are being thrown out.
The putrid 10Qs and 10ks for 2019 will add to the fire.
GuyM,
As long as debt can be serviced, borrowing is fine. Lots of businesses borrow when they start. Wells do not need to pay out in one year in the oil business. Mike Shellman aims for a 36 month payout and shallow sand uses a 60 month payout rule. Probably anything in that range would work. Some wells may payout in a years time, but that is a small percentage of the total, perhaps 10% or less.
Dennis.
As I have posted before, the wells we apply a 60 month payout to have a much lower decline rate than the shale wells, and are being drilled out of cash flow, not borrowed money.
For example, a well we drilled in 2006 just passed 10,000 BO and produced 370 BO in 2018. It cost about 1/100 the cost of a shale well ($70K +/-).
Maybe not a valid comparison, but. 100:1 ratio would be cumulative of 1 million BO and annual of 37,000 BO, which I think a rate you will not find often for any US shale well after 12.5 years on production.
Our LOE is higher per BO, so not entirely valid, but still maybe somewhat useful for comparison.
I note in the WSJ article PXD argued that the comparisons weren’t valid because they use a 50 year well life in calculating EUR v 30 year well life in the study.
I would think the PV of years 30-50 would be tiny on a 20,000’ hz well producing under 20 BOEPD! That PXD uses that argument seems to make them look a little foolish? Or am I being too tough on them?
Shallow, you know they can’t run a stripper well like you. Damn thing will be plugged at seven years. Dennis can calculate his damn curves to twenty to thirty years if he wants to. I can’t disprove it, because we are only in about year eight, and some have probably been plugged already, although I have no statistics on it. Although, I found one of EOGs that didn’t make it 7 years without trying too hard.
Mike was talking about borrowing on conventional production that has a much smaller decline rate. You drill one this year, and borrow the next year to drill another, you are increasing production. Not running on a treadmill.
Guym,
The wells are assumed to be shut in around 8 b/d, in the Eagle Ford that happens around year 16 for the average well with the hyperbolic I have fit. Absolutely true that we don’t have data for many years. Most of this started around 2008 in the North Dakota Bakken. So we only have about 11 years of data on the wells that started producing in Jan 2008.
For Permian Basin wells completed in 2016, the hyperbolic fit to the first 18 months of data is at 10 b/d at 19.7 years. I assume oil prices will be higher in the future so the well will probably continue to produce up to that point (EUR 377 kb at that point).
If we assume well shut in occurs at 15 b/d, then the well is shut in at 15.5 years and EUR is reduced to 359 kb.
In my scenarios I assume net revenue each month must be at least $15,000 in 2017$ for the well to continue producing, so when the well gets shut in depends on the price of oil and output.
Permian Basin 2016 well profile.
q(t)=q/(1+Dt) where t is time in months from first output and I use t=0.5,1.5, 2.5,… this is a special case where b=1 which fits this data pretty well.
Guym,
Note that Enno puts zeroes in for wells that have been plugged, so when I pull data from his site the averages include any wells that have been shut in. In my models and scenarios the wells are shut in based on economics, if the well is no longer profitable to produce it is shut in and output is zero.
Also note that the model is tested against past data, and the fit is very good, in many cases it underestimates actual output, rather than overestimating in fact a major criticism of many of my past scenarios is that they have usually been too conservative. That is output has usually been higher than I have predicted, with the exception of the oil price crash of 2015-2016, which I did not anticipate in 2012- 2014.
Hey Shallow sand,
Could you share output data from your well if you have it handy (monthly output or even yearly output would do), a hyperbolic could be fit to the data to make a comparison with tight oil wells?
None of these wells will continue to be profitable beyond 30 years (even the best wells).
What is the annual decline rate today for the well drilled in 2006?
What was the decline rate for the first year?
Note that when I do a discounted cash flow (DCF) analysis on tight oil wells (for say the average 2016 well completed in the Permian basin), the 60 month payout rule equates to an annual ROI of roughly 11%/year, and is pretty similar to what I would get for a DCF with an annual discount rate of 11%.
Whether the money is borrowed or not doesn’t really matter, the person who borrows has to pay some of their returns to the lender, if the price drops they may be in trouble and have to cut back on drilling or sell shares of stock to raise cash.
The “typical wells” presented in most of the investor presentations I have read are a joke, typically using BOE to hide the fact that they are so lousy, it’s surprising the energy analysts don’t call them on this, as the “barrel” natural gas is worth maybe one fifth or less of a barrel of crude. Often the typical well overstates the output of the average well by a factor of 2 or more.
One potential mistake I have made is to ignore the NGL that might be produced from the natural gas.
It seems that a lot of the natural gas in the Permian basin is being flared and there is not NGPL produced from gas that is flared.
Shallow sand,
If you are interested in sharing any data, I think you have my e-mail or use peakoilbarrel@gmail.com.
Hi Shallow Sand,
Don’t forget to adjust for inflation. That 70k well in 2006, if we assume 3% average annual inflation would be about 100k today. So about 90 times less expensive than your 100k well. Still true that not many (or maybe any) tight oil wells produce 900 kb in 12.5 years.
Is this an “average” well or one of the better wells you have drilled?
Wow,
1 b/d in the most recent year and 2.2 b/d over the life of the well.
At what point does it make sense to stop producing these wells? I would assume a down hole failure would mean shut in.
Very interesting, thanks. Did the well payout in 60 months? Maybe 3500 barrels over first 5 years?
Yeah, that seems like a lot of work. Probably close to daily monitoring and upkeep. Trucks once a month? Won’t catch EOG working that hard.
Yes, Dennis. You can borrow, if cash flow profit materializes. It hasn’t, and it probably won’t at anywhere near these prices, and Mike Shellman is the first to point that out. The E&Ps have been their own worst enemies in this fiasco. It’s flat going to be tougher to borrow the money. Investors and the media have every right to scream, where’s the beef.
Guym,
At $62/b at the wellhead (when any income from NGL is ignored) the 2016 Permian wells generate an ROI of 10% per year. Assuming the oil price remains at that level for the entire life of the well.
I agree that at present oil prices, the average well loses money. Whether money is borrowed or not is not really the question, in my view. The important thing is the profit or loss.
This is a significant paragraph to me. Given all the investments available, why throw money at oil-and-gas?
“Shale companies have attracted huge amounts of capital from Wall Street over the past decade. So far, investors have largely lost money. Since 2008, an index of U.S. oil-and-gas companies has fallen 43%, while the S&P 500 index has more than doubled in that time, including dividends. The 29 companies in the Journal’s analysis have spent $112 billion more in cash than they generated from operations in the last 10 years, according to data from FactSet, a financial- information firm.”
You guys insist on continuing to think money isn’t created from thin air by the Fed and actually means something in the context of a substance that feeds you food. If you have to have it, and you do have to have it, things will be done for you to get it. Borrowed money that was created from thin air . . . who cares if you can’t pay it back? You have to eat.
Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because there is no meaning to anything created from thin air when applied to something that depends on physics.
You won’t know anything until you find yourself sitting in a line waiting for gasoline. You won’t see it coming. You won’t predict it. It will just happen someday.
Soon.
Some truth to that Watcher. Simplistic thinking in investors. If we aren’t making much money, the US won’t be making much money, so the price of oil must go lower. Not just simplistic, flat out stupid.
And the number of people who think oil supply is limited is fairly scarce in relation to the population as a whole. Probably less than the number of people who think chocolate milk comes from brown cows.
And if you think I am being unreasonably hard on the average IQ, google who is now running the country, and consider almost 50% voted for him. Ok, I’ll give them somewhat of a break, as I didn’t like the alternative, either. They should allow write ins, so we can all vote.
And any moron can borrow 20 billion and service the debt for awhile. Maybe all of it, if they are lucky. Who cares, it’s only paper. Not a bad idea. I have an oil company, I can borrow 20 billion, stick half into BNO, and have a ball with the rest. If I lose, I can declare bankruptcy, and they can get my prepaid funeral expenses, but none of my gold bars in the Caymans. And, I am 99.9% certain that is less of a risk than any E&P I can think of.
White eggs come from white chickens. Brown eggs come from brown chickens.
I had chickens that laid green eggs.
And they were multicolored.
You eat those with ham. 🙂
It’s All About The Chicken
You might assume that white eggs are laid by white-feathered chickens and brown eggs by brown-feathered ones, and you would be somewhat correct with that assumption. The color of the chicken does play a role, but it is the color of the earlobe that determines the shell color. White or light-colored lobes indicate white eggs and chickens with red lobes produce brown eggs.
North Dakota natural gas flaring hits records, improvement expected in 2019
Amy Dalrymple
Natural gas flaring reached record volumes in North Dakota in 2018, enough in October to heat 4.25 million average U.S. homes.
The volume flared — 527 million cubic feet per day — could have met the natural gas needs for all of North Dakota and South Dakota, including industrial and commercial demand.
The state is expected to catch up on gas processing capacity by the end of 2019. But gas volumes are projected to nearly double from current levels, requiring even more long-term investments for 2020 and beyond.
Ron Ness, president of the North Dakota Petroleum Council, estimates the industry has invested a total of $18 billion for gas capture in the Bakken.
“We’re probably going to need at least another $10 billion or more in order to build the necessary infrastructure. It’s not going to all come right away,” Ness said. “Our productivity has just outpaced the expectations on gas so much.”
North Dakota produced 2.56 billion cubic feet per day of natural gas in October, the most recent figures available. Oil production reached 1.39 million barrels per day that month…By the end of 2019, North Dakota [is projected to] produce 2.9 billion cubic feet per day of natural gas and 1.49 million barrels of oil per day.
Hi Dennis,
this simulation by the IEA about US tight oil production is quite close to yours, am I right?
Yes that is very similar to an earlier simulation I had done.
I had to shrink the picture. My model is the red line, the blue crosses are EIA tight oil output data. My model ERR is 84 Gb through 2052. Peak is 9.7 Mb/d in 2025.
Interesting graph. Can I post the IEA plot overlaid with yours on my Twitter timeline?
Thanks.
Dean,
Feel free, with maybe a link to the comment (clicking on date stamp gets you that.) or some attribution in any case.
Any chart I post you are free to use.
Thanks for asking.
I will email you a chart with better resolution.
Should be in your e-mail.
As you are aware, but others may not be, the IEA scenario for the US assumes 115 Gb of ERR for US tight oil, based on USGS estimates to date for the Bakken, Eagle Ford and Permian Basin the mean TRR estimate is 100 Gb for all 3 major plays combined, and perhaps a 15 Gb estimate for the rest of US tight oil plays is reasonable, which gets us to a TRR estimate of 115 Gb, the ERR will be close to the TRR only under a high oil price scenario. I used the AEO 2018 Brent oil price reference case for my scenario that arrives at an ERR of 84 Gb (about 73% of the IEA scenario ERR). The IEA may also have assumed the USGS estimates were too conservative, in general mainstream economists tend to believe every resource estimate is too low.
Nice graph. After world peak oil, or start of an undulating plateau, by most of you expected somewhere in the 2020’s, world oil production will be very difficult to predict, not to write more difficult than ever, for the decennia ahead. At that time ELM becomes one of the high risk factors.
Han,
I have never bought the Export Land Model, it always made some questionable assumptions about past trends continuing. Oil exporters will continue to export because they need the income and they may gradually reduce subsidies because as oil prices rise the subsidies become more costly (if you are exporting at $150/b, but only charging $25/b for oil used domestically you forgo $125/b for the subsidized oil). In addition natural gas and solar will substitute for oil for electricity production in oil exporting nations. Bottom line, World output is all that really matters, if exporting oil nations choose to hoard their oil, it simply drives up oil prices and speeds the World’s transition to other forms of energy, exporting nations would be best served by keeping prices low enough to slow the transition to battery electric vehicles and plugin hybrids.
Once that transition occurs, the oil left in the ground in oil exporting nations will be worth much less than it is today.
“I have never bought the Export Land Model, it always made some questionable assumptions about past trends continuing.”
Dennis,
Ok, but the many examples ‘ westexas’ published on theoildrum was about net oil exporting (small) countries that turned into net oil importing countries, very quick after Peakoil was reached. Of course this won’t happen with the big oil exporting countries in the world.
And what you wrote:
“In addition natural gas and solar will substitute for oil for electricity production in oil exporting nations. ”
will be the case. But the big solar plans KSA has since many years, until now didn’t materialize. For now they continue spending very much money on EOR projects and desalination units.
After the transition is almost done (at least two decades away), the oil left in the ground will be worth much less, yes indeed, but very valuable for aviation for example. In 2040 the big planes won’t fly on battery power yet, and maybe never, I think
Han,
It will depend on price and demand, air travel will become more efficient, there may be less of it and substitutes such as synthetic fuel or biofuels will compete with petroleum, I agree solar/battery powered planes that are practical are likely many decades away. Jet fuel use by commercial airlines was about 6 Mb/d in 2018, about 7.5% of total C+C output, this will be one of the last uses to go, but supply may be much larger than demand so that mostly conventional oil from low cost producers will be used. I didn’t mean to imply that petroleum reserves will be worthless, only that they will be worth less (price will be lower.) 🙂
Han,
The assumption that didn’t make sense was that as oil becomes scarce and expensive, the ELM assumes that the consumption patterns of oil exporting nations will not be affected.
In my opinion this very poor assumption makes the model’s predictions highly suspect. The nations that have gone from exporters to importers to date have done so in an environment where World oil output has been increasing and when oil prices have been high rather than hoarding oil exporters have maximized production to take advantage of high oil prices. This is likely to continue and it is better in my opinion to simply focus on World output of C+C, hoarding by exporters will simply drive prices up, speed up the transition and ultimately hurt the oil exporting nations as they will drive demand down in the long run more quickly (as it will speed up the transition to EVs, electric rail, and light rail, urban buses on overhead electric lines, etc) which will drive oil prices down and reduce the value of their product.
From an economic perspective the model fails.
>In 2040 the big planes won’t fly on battery power yet, and maybe never, I think
On the other hand, its questionable that anyone needs big planes built on the current design pattern. The A380 only seems to have one customer, Emirates, and the 747 is in decline. Neither is used on flights within North America, for example. Their only justification is the rules that two engine planes can’t fly transcontinental routes. The other justification is the hub and spoke model, but it is on its way out as well.
Airplane engines are unreliable, fiddly and expensive to maintain. That is why two engine planes are considered too dangerous for transcontinental flights. Electric engines are much cheaper to build and maintain, and will probably eliminate the last justification for jumbo jets with four engines.
If it came down to it, a modern civilization could do just fine with no air travel.
Sure some things would suffer, like organ transplantation and aerial bombing runs. Pesticide spraying, and Disney trips. Global warming conventions, and rodeo flings. Roses from Chile and Trumps overnighter to Mar Lago (at your expense).
But a civilization could find ways to carry on.
>Oil exporters will continue to export because they need the income
Or simply maintain subsidies and fail, as several exporters already have.
There is a lot of irrationality in the market, both on the supply and demand side. Considering that there is a realistic way to replace most oil consumption with EVs, I think that net import countries and regions are nuts not to switch away from oil. Only Norway and China seem to have figured this out so far.
That OECD graph clearly shows that the glut has disappeared in Europe. Now the glut in US is mostly due to crude build. US production has increased from 8 MBD in January 2014 to most likely 12 MBD in December 2018 (due to very large adjustment factor in EIA report). The pipeline fills and new storage tank additions in US most likely contributed to the crude build. I counted over 110 MM barrels storage capacity added since 2011.
Yes I guess that storage levels in the USA are not likely to go down any more than they already have, as you say, due to pipeline fills and new storage to cover the increase in US exports etc
OECD Americas: Canada, Chile, Mexico & United States
OECD Asia Oceania: Australia, Israel, Japan, Korea & New Zealand
When one looks at days of forward supply for the OECD, we are basically back at the 2011- 2014 level for OECD stocks, the “glut” only exists in the minds of those that believe tight oil breaks even at $40/b and it only does that for about 1% of the tight oil wells that have been drilled to date. This is pretty basic stuff, I wonder if any of these energy analysts have studied economics? Very strange.
This report is a long read, a one sentence summary = NEB Canada says that Western Canada’s oil supply is 365,000 barrels above the amount of oil flowing daily in existing pipelines.
December 2018 – Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity
Figure C.5 illustrates NEB-estimated available capacity from the WCSB for crude oil pipelines between January 2010 and September 2018. Figure C.5 also illustrates the amount of crude oil available for export. Footnote 14 In September 2018, the amount of crude oil available for export exceeded available pipeline capacity by an estimated 202 000 b/d. The NEB also estimates this number would be 365 000 b/d if pipeline throughput, rather than available capacity, was used to represent the amount of crude oil that can move out of the basin by pipeline.
This excess oil supply is either held in storage, where available, or exported from the WCSB by other modes of transportation, such as rail. http://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/rprt/2018wstrncndncrd/index-eng.html
Think oil prices are finally uncoupled from the Dow.
I saw that also. At least for today. I still remember 2008 when everything went down, including oil stocks that I hold to this day thinking the dividends will get me back to even.
They are likely to go down some more, before going up. The good news is they will probably be up to stay. Depending on what they are.
Never been any reason to presume oil price was stock price determinant.
Likely to go down. But what’s the alternative in the short run? Oh, I forgot, Trump can just tweet it out of the ground. It’s amazing, that not once, does anybody acknowledge the shale problem, is an oil price problem.
From the piece you linked above which seems to indicate capex spending will be flat to slightly down there was also this:
Asked to provide a specific price for WTI used for capital planning this year, executives said they expect prices to average $54/bbl, with responses ranging from $50 to $64.99. Only 9% thought prices would be below $50.
If their oil price expectation (the average) proves correct, there will not be a lot of money made in 2019 in the tight oil plays of Texas.
Oh, I think they will make some money, as oil prices will probably rise substantially. However, the production (rise?) the first half will be meager. And service companies will be behind the eight ball, again, for employees the second half.
GuyM,
I agree oil prices are likely to rise, but the oil executives surveyed (who likely know more than me) have an average expectation on $55/b. I guess you think they are incorrect, I agree with you. I think you expect about $75/b (or $80/b?) for WTI by the end of 2019, and something like that seems reasonable.
My analysis suggests that in the Permian basin at least $62/b is needed for breakeven at the wellhead (about $67/b for WTI assuming $5/b transport cost), so until oil prices rise to that point, money is not being made by completing a well.
Well, they probably will utilize their DUC inventory to maintain production as best they can. For 2019, DUC costs are basically dead costs for 2019 financials. I think that many, many DUCs are dead DUCs at anywhere near this price, but some can be revived, because they are only spending 60% of the capex. They are DUCs, because they basically know what they have after drilling.
There are many new DUCs in the Delaware. Many will probably remain DUCs. Outside of some core areas, I don’t think they found a bunch. Companies maintain they have not hit too many dry holes in shale, but a Dead DUC is about as dry as you can get.
Wily Coyote was going over the cliff before prices started going down. In effect, the Road Runner has just handed him an anvil to help his descent.
Besides the money to complete, there’s an incentive to keep what looks like a bad well as DUC. If it isn’t producing, one doesn’t need to include it in production average. If it’s a good well that’s profitable at $50, it’s not going to sit uncompleted for longer than physically necessary, no way. Even with logistical constraints the decline from producing wells is so high that good replacements just maintain numbers and cash flow. Hell in bad prices, the incentive to open up a moneymaker is going to be even higher because that debt is still going to need to be serviced.
I’m guessing there is going to ultimately prove to be a distinct pattern between long-term DUC and where the tiers boundaries in the Delaware actually are (as opposed to what EIA projects from average production).
Do you know how good a well will be just after drilling, but before fracking?
It should be goal for geologists to find out that even before drilling.
It is all a big illusion that oil is cheap like water in my opinion. To manipulate the market down will only make for more volatility in the future, and it is a good a bet as when the oil price fell to 30 dollars/b in 2016 that prices will eventually rise again from this level. It has do with that the tanking of oil prices is out of the usual cycle in the industry (low investments makes for less oil after 3+ years). I have started to bet on oil prices going up again even more for the fun of it (a few bets made too early I have to admit) and now I put some meaningful amount of money in it; to make it even more fun hopefully. The EIA weekly reports are a joke with zero movements for crude inventory for last 2 weeks. And an adjustment factor that nobody understands. Maybe the government shutdown has some influence after all. To build a wall against the tide water is an illustration of how successful it will be to keep the oil prices down with illusional data alone. And I stand by that a recession based on “fear” news alone is fake, but can ofcourse in the end become a self fulfilling prophecy. And the real fear is inflation based on too high oil prices. Extensive tariffs to hinder trade will also never help prosperity, but it remains to be seen if threats are made real or if the policy at some point will be revoked. The story is to be continued…
Does this seem right to people.
“During the period 2008-2017, OPEC Member Countries added 262.5 billion barrels to their total proven crude oil reserves, a significant addition compared to other crude oil producers.”
especially the spreadsheet is useful, look at historical oil reserves and you will find that most of those reserves were from Venezuela adding Orinoco reserves (224 Gb) over the period from 2006 to 2017.
If those are excluded OPEC reserves increased by only 60 Gb over that period. Reserves can increase from both new discoveries and reserve growth (where new knowledge gained from exploration and production can lead to improved estimates of reserves over time). In theory estimates should decrease as often as they increase so the net should be zero. In practice, proved reserve estimates tend to be conservative and on balance tend to be revised up more than down so that typically we see reserve growth. The US saw about 60% reserve growth over the period from 1980 to 2005 (about 2% per year). For OPEC reserves (excluding Orinoco belt reserves) the rate of reserve growth from 1990 to 2017 was about 1% per year (about half the US rate from 1980 to 2005).
There is little transparency for OPEC reserves, one paper I read suggested World proved reserves as reported by BP (excluding oil sands) are pretty close to World 2P reserves (proved plus probable) in the IHS database as of 2012. I do not have access to IHS data.
Thanks Dennis for the clear up.
There has occasionally been mentioned on this site about potential ‘shale’ regions being developed in other parts of the world.
Yesterday (1/3/19), an article from E&P magazine titled ‘The Other Shales’ mentioned new developments in Abu Dhabi, the UK (Cuadrilla), and the Tuscaloosa Marine Shale.
The TMS description was particularly intriguing as it mentioned a well – the Lawson 25-13H in Amite county, Mississippi, originally drilled by Encana – as having produced over 300,000 bo first 24 months.
A small Australian company is planning on at least 6 new TMS wells with first flow from 2 of them this coming spring.
As there were about 60 TMS horizontal drilled during the ‘boom’ a few years ago – mostly unsuccessful – there is a body of knowledge for these new guys to work with.
This area is near the Louisiana Austin Chalk that had attracted the keen interest from Marathon, EOG, and COP.
With a 92% oil cut, estimated 8 billion barrels earl, and a recent history of attempted development, the TMS may well be lining up to be another formation that will economically produce hydrocarbons.
From what I understand, the Eagle Ford and the TMS are basically close to the same formation (just deeper), lying under the Austin Chalk. The Austin Chalk is not a source rock, and relies on natural fractures to trap oil from the TMS and the EF. There is a fault in eastern Louisiana that may wind up being similar to the Karnes fault, if they are lucky. Which could be good for both AC and TMS.
EOG was wild on the Austin Chalk for awhile, after they had such good wells out of the Karnes Fault area. They were tooting their horn that they unlocked the secret of drilling the Austin Chalk, and they could get the same results throughout the EF. But, they couldn’t. The “widow maker” struck again. They finally admitted that it was only effective where there were natural fractures. That did not surprise many who had been around awhile.
“As there were about 60 TMS horizontal drilled during the ‘boom’ a few years ago – mostly unsuccessful – there is a body of knowledge for these new guys to work with.”
Yes, apparently they learned how to drill unsuccessfully. Quite the body.
Watcher
As … peculiar … a slant your comment implies, any serious student of this unconventional industry might use the brief TMS development (or lack of) history to better understand what is unfolding in the Uinta, the Powder River, the Rogersville, possibly the Bowland, several Aussie hydrocarbon basins, the Dead Cow … pretty much anywhere with perhaps the Bakken being a highly instructive model as it was one of the earliest, data- rich operations.
In fact, Liberty Resources ambitious current EOR trial could well shed light on what may be possible, recovery wise, in ‘shale plays’ throughout the world.
The TMS operators struggled with optimal target depth, daunting geology, mud specs, expensive capital outlays, on and on.
So, yes, anyone with a scintilla of familiarity can recognize that what not to do can be every bit as crucial as knowing what to do … most especially in a high risk, capital intensive project.
Mexico will be lucky only to drop 40, though there are a couple of new developments due, same maybe for Oman, Algeria and Ecuador (and Malaysia?). Libya, Angola and Nigeria will ignore any numbers and you get what you get depending on how the new projects ramp up, decline kicks in and geopolitical issues manifest themselves.
There have been assertions that the number of DUCs has increased to around 4000 in Texas. Enough to maintain production growth even if drilling drops. Russell Hall says there are many less due to Texas reporting and the pending file at the RRC. I know some of you follow RRC more than I. Any thoughts about this?
In September Enno Peters has the Permian Basin DUC count at 1250 wells. In Feb 2018 the count was 2354 wells (which was the peak), the last time the DUC count in the Permian was lower than Sept 2018 (most recent date reported at shaleprofile) was Oct 2016.
I believe the most recent data points often get revised up later as the RRC data often is revised later, mostly higher.
For the Eagle Ford in Sept 2018 DUCs were 590 wells with a near term peak in Feb 2018 at 1030 wells and an all time peak at 1833 wells in Feb 2015.
New Data Suggests Shocking Shale Slowdown
By Nick Cunningham – Jan 06, 2019, 6:00 PM CST
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U.S. shale executives often boast of low breakeven prices, reassuring investors of their ability to operate at a high level even when oil prices fall. But new data suggests that the industry slowed dramatically in the fourth quarter of 2018 in response to the plunge in oil prices.
A survey from the Federal Reserve Bank of Dallas finds that shale activity slammed on the brakes in the fourth quarter. “The business activity index—the survey’s broadest measure of conditions facing Eleventh District energy firms—remained positive, but barely so, plunging from 43.3 in the third quarter to 2.3 in the fourth,” the Dallas Fed reported on January 3.
The 2.3 reading is only slightly positive – zero would mean that business activity from Texas energy firms was flat compared to the prior quarter. A negative reading would mean a contraction in activity.
The deceleration was true for multiple segments within oil and gas. For instance, the oil production index fell from 34.8 in the third quarter to 29.1 in the fourth. The natural gas production index to 24.8 in the fourth quarter, down from 35.5 in the prior quarter.
But even as production held up, drilling activity indicated a sharper slowdown was underway. The index for utilization of equipment by oilfield services firms dropped sharply in the fourth quarter, down from 43 points in the third quarter to just 1.6 in the fourth – falling to the point where there was almost no growth at all quarter-on-quarter.
There is a lot more in this article. Read it and comment if you wish. I would love to get other opinions on this.
Price hasn’t yet found a bottom yet in this current downturn. We will see lower before higher price. Slowdown should be expected in a low price environment. Price should consolidate for while before going lower and finding a bottom. Then and only then should we look for higher prices to come. It could be 3-4 months before price hits it’s final bottom in this current downturn. Price could easily stay below $50 all year long. People like to give their fundamental view on why oil market will tighten and we will get higher price in 2019. But the price charts tell us a different story and something they are missing in their forecast leads them to believe price will turn around quick. I think shale will hit a peak earlier on in 2019 and be well into decline by years end. Maybe when price recovers we get a new high in production. Maybe not.
I posted the same info from a different source, above, on Jan 4. You posted Texas production as only up 18k for Oct. in the first post. That is the first month in the quarter. Things deteriorated from then. Bakken price is in the toilet. Permian is not much better. I think that there is a high possibility that US production may decrease at these prices, rather than what is being reported by the EIA weeklies, we may have actual production 300k to 400k below what they are currently reporting by January. And the Permian will probably not increase much in 2019, because of pipeline constraints followed by shipping restraints, not counting all the other constraints. That’s going to happen no matter what prices are. So all this production increase EIA and IEA are counting is not going to happen. OPEC production decrease will happen. Demand better turn seriously negative to offset all this. But, I don’t think that would happen, so my bet is some serious inventory drops, and Trump will tweet.
I’m thinking it will take months of the EIA monthlies dropping, or even not increasing, before anyone pulls their head out. There are so many myths that are taken as fact, it’s going to take chiropatric assistance to pull it out. “Price bands, shale oil profitable at $50 per barrel, and the list goes on.
USA November, December and January numbers are going to miss the estimate curve by a large margin. LTO legacy decline doesn’t care about market price.
Dunno if that will cause a swift rebound in price when it materializes. It’s backward looking and the general economic slowdown is real.
The DPR numbers are not very accurate, through Nov 2018 the US tight oil output is as shown in chart below with an increase in Nov of 135 kb/d to 7035 kb/d. The rate of increase from Jan 2017 to Nov 2018 has been about 1400 kb/d per year. If prices remain at about $50/b, I expect the rate of increase to slow to 300 kb/d+/-300 kb/d.
If oil prices rise as I expect from May 2019 to Oct 2019 to about $70/b for WTI (monthly average price by Sept 2019), then the average increase in output (annual rate) from Nov 2018 to Nov 2019 is more likely to be 600 kb/d+/-300 Kb/d.
If oil prices fall to $40/b and remain there for a few months (Feb to July 2019), we may see flat to decreasing US tight oil output as the well completion rate may fall steeply in that case.
forgot chart
US tight oil output data from “tight oil production estimate by play” at page below, this is the only EIA tight oil data worth looking at in my opinion.
Note I miscalculated trend From Jan 2017-Nov 2018 (it was Dec 2017- Nov 2018 for the estimate in previous comment), the correct slope of the trend line since Jan 2017 is a 1416 kb/d annual increase in tight oil output and the past 3 months output has been above the trend line.
For the past 18 months the linear trend for tight oil output has increased at an annual rate of 1559 kb/d, for that line recent output data (through Nov 2018) is right on trend.
I expect this slope will be 3 times lower(520 kb/d) from Dec 2018 to Dec 2019, if WTI oil prices remain at about $50+/-5/b over that period.
This is old, but very broad. Assay of different Venezuelan fields.
Lots heavy. Lots not.
It’s very old, some of those crudes are blends, and all of it has been depleted and produces a lot less than in the past. Today the largest stream is the 8 degrees API coming from the Faja, blended with nafta to approximately 16 degrees, some of it is fed to the upgraders, some is diluted with imported light crude and a bit of Venezuelan light.
I expect OPEC to report Venezuela production to be 1.1 mmbopd, at least half is at or below 10 degrees API. But January production should drop below 1 mmbopd.
Meanwhile, the estimates given to investors were sometimes extrapolated from only the best performing wells. Other companies excluded their worst performing wells from the calculations. Texas A&M University professor John Lee, an expert on calculating oil and gas reserves stated: “There are a number of practices that are almost inevitably going to lead to overestimates.”
When Lee gave a presentation in Houston this past July, highlighting methods that could produce more accurate forecasts, one engineer jokingly stated that their companies weren’t using his methods “because [they] own [their company’s] stock”.
I’m getting notice of spam comment
retried, failed
Watcher,
Sorry.
If your comment doesn’t go through in future, try it without the link and just say go to zero hedge and give the title, some websites the spam filter doesn’t like. I don’t have enough expertise to customize the spam filter.
ya it was a surprise, I’m sure there have been other ZH links, but can work around.
Watcher,
For some reason this link works, not sure what the deal is
January 7, 2019 (Rystad Energy) US fracking activity peaked in May/June
nationwide fracking activity was mostly stable from April 2018 to August 2018 at an average daily level of between 48 and 50 fracked wells. However, the fracking rate has slipped to a range of between 44 and 46 for the period of September to November 2018. https://www.rystadenergy.com/newsevents/news/press-releases/frack-jobs-peaked-in-may/
Yeah, EF should be the last to decline. Their pipelines go mostly to MEH. That’s not a WTI discount, it’s a premium.
Question for Fernando: Do you have any idea if production ceased at the Priobskoye field due to the fire? thanks!
I don’t see how production could cease at Priobskoye from a plant fire, because the field straddles the Ob River, and there are separate plants serving as hubs for different areas. The last time I was there they had been drilling pipelines under the river to connect the newer north bank developments to the south bank, but the river is a formidable barrier, and the field is so large that a simple fire can’t take it out unless it takes place at Transneft pipeline stations.
Baker Hughes GE International Rig Count December
Total +34 to 1025
Split: Oil +23 to 806 & NatGas +10 to 189 & Misc +1
Split: Land +6 & Offshore +28
Offshore chart https://pbs.twimg.com/media/DwYwivGXQAET9dO.jpg
Venezuela’s new National Assembly President, 35 year old Juan Guaidó, was interviewed in Venevision yesterday, in what appeared to be a well rehearsed 12 minute question and answer session. The interviewer was a young woman, evidently very brave, who asked incendiary questions and was answered by Guaidó forming a duet with her. All the content emphasized that Maduro had to be taken out, plus messages of gratitude to the international community for supporting the Assembly against the dictatorship, as well as reminders to Russia and China that their investment was protected only if law and order prevailed.
What’s the significance? It’s been a long time since a guy like Guaidó could get on a TV station which reached poor areas (Venevision has rights to broadcast over the air, doesn’t require cable). This implies Guaidó has some sort of protection from heavy weights within the regime. Otherwise they would have cut power to the station and put everybody in jail.
We have two possible interpretations: 1. Guaidó is faking and is a regime mole. 2. Maduro has lost the support of a powerful faction within the ruling mafia. It’s even possible the Cubans decided to get rid of Maduro.
Today the National Assembly will meet to discuss the options they have to take Maduro out. If the transmission is seen via livestream (check VPI TV on YouTube) then something may be happening. If Venevision shows it then I think Maduro will be gone in a few days, and we may see very few deaths.
In any case, we are lobbying to have Trump take control of all Venezuela assets the US can reach, including all oil sold after January 9, 2019. There’s a subsidiary effort to have EU nations take all Venezuelan diplomats out unless they state they acknowledge being under National Assembly leadership.
Interesting stuff Fernando, though keep in mind the conspiracy theory speculation, makes it less credible. I know you don’t believe this, but Cuba does not rule the world. 🙂
They are not behind every nefarious political event in Latin America.
Dennis, you are quite disconnected from reality regarding the Castro dictatorship role in Venezuela. This is understandable because US leftists mostly feed off a leftist media with its own agenda. To those of us who lived there, had access to very high officials, and know what’s going on, the Cuban role is a fact nobody questions. If you speak Spanish I could try giving you videos and documents showing how it works.
Fernando,
I really don’t know but have a friend who is from Venezuela and still has family there, he doesn’t really mention the Cuba connection, or does not seem to be focused on it. No entiendo bien el espanol. So I do in fact get my news from the leftist media in the US (NY Times, Washington Post, NPR, etc.) Curious, do you also consider Fox News as a leftist outlet? 🙂
This comes from a US publication in English, Foreign Policy, an article called
“Cuba Is Making the Crisis in Venezuela Worse” from early 2018.
Quoting:
“Today, the penetration of Venezuela by thousands of Cuban operatives is complete. While it remains difficult to quantify the exact numbers, according to a Brookings Institution report, Cuban intelligence operatives and military advisors in Venezuela range from hundreds to thousands. Organization of American States Secretary General Luis Almagro puts the number at 15,000, likening them to “an occupation army from Cuba in Venezuela.””
I happen to know a bit more than what Almagro lets on he knows, although I assume he has been briefed, and can’t go public with everything. One comment Guaidó made yesterday during his interview directly addressed this point, when he discussed the meaning of puppet. If you want to see the interview look up
Entrevista Juan Guaidó por Venevision.
Google is rabidly left wing, but I’m sure the search will show you a link to the video uploaded yesterday.
Fernando,
You were doing ok up to “Google is rabidly left wing”. You just sound nutty when you make such comments.
“You just sound nutty when you make such comments.”
Atleast there is a high level of consistency to it.
Agreed. Now I need to block Fernando L as well as Fernando Leanme. Sigh 🙂
Not only narrowed, but above the average level from 2015-2017 of about $13/b, currently the spread is only -$10.50/b, near the highs from 2015 to 2017.
There’s no shortage of fuel in Asia at the moment. There are 4 new refineries. And economic growth seems to have slowed due to higher rates and trade tariffs etc. Also fuel prices were too high last summer into October2018.
New Refineries – JANUARY 7, 2019 (Reuters) Malaysian state oil company Petronas started trial runs at the crude distillation unit (CDU) for a joint-venture refinery with Saudi Aramco in Malaysia last week, two sources with knowledge of the matter said on Monday.
The move marks a major milestone for the $2.7 billion project known as RAPID – or Refinery and Petrochemical Integrated Development – located in Pengerang in Johor, at the southern tip of peninsular Malaysia. The test runs put the project on track for commercial operation in 2019.
The refinery is one of four new complexes in Asia that represent a combined processing capacity of nearly 1.3 million bpd scheduled to start up from late 2018 to 2019.
Another of the four complexes, a 400,000-bpd refinery, owned by Hengli Petrochemical in Dalian in northeast China, started trial runs in December. https://www.reuters.com/article/us-malaysia-refinery-petronas-saudi-aram/petronas-saudi-rapid-refinery-begins-trials-on-crude-oil-unit-sources-idUSKCN1P10NO
A monthly chart for fuel inventories with the latest weekly number
December’s completions and permits look pretty bleak for Texas.
GuyM,
For the Permian basin completions were 359 in Sept 2018 and 343 in Dec 2018.
The decreases may continue.
I assume a small part of that is seasonality since it’s December?
How quickly does this translate into measurable production numbers?
Some may be from budget expiration, but not due to weather, or giving a couple of days for Christmas. But, as Dennis says, and Kol says below, the trend is there.
Guym,
The trend in Permian completions has been down since Jan 2018, but through Nov 2018 output has continued to increase, there is some point that the output increases stop, my model suggests this point is output 280 completions per month (that is for Texas and New Mexico Permian Basin output). We may be getting close to that point, though one problem is trying to estimate the number of vertical oil well completions. I believe you also have suggested in the past the RRC drilling and completion reports may not be very accurate, though I might have not understood correctly.
I was surprised to read that the trend in completions had been down since January? Prices were rising through much of that period? Also, how then have they managed to bring down the inventory of DUCs down so much based on the information you posted earlier in this thread? What have been the monthly completion numbers in the Permian? Is there a source you could point me to that has those numbers. Thank you.
This is for all wells drilled in Permian Basin, see page below.
Chart with Texas Permian Oil Completions in 2018, total oil completions (avg=464) and new drill completions(avg=379).
New drill completions may reflect the level of horizontal completions better, there are a lot of vertical wells that may be reworked from time to time, the horizontal wells are newer and probably not many are re-completed. Note that the new drill trend line has not decreased very much (decrease at a rate of 2 per year).
Big jump in October and steep decline after may just be statistical noise.
Also some of the new drill completions are probably vertical oil wells, but it is unclear how many. Note that shale profile has about 304 Permian horizontal oil completions in Texas for the first 6 months of 2018, for new drill completions the average for the first 6 months was 373, implying about 69 of the new drill completions were vertical oil wells for the first 6 months of 2018. If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2019.
Thank you so much for that information Dennis. Truly appreciated. A few “uninformed” comments and guesses follow:
1) It “appears” that the amount of DUCs might be reaching some type of equilibrium based on the convergence in the fourth quarter of total completions and new drill completions?
2) the third quarter saw completions down fairly dramatically, especially on the new drill side. Guessing holidays and oppressive heat has something to do with that?
3) if DUCs are indeed down to a normalized level, then total completions should be down in 2019, all things being equal unless there is a significant increase in new drills and new drill completions?
Again, thank you so much. You put out some great information here. Much appreciated.
Mario,
I think we have a different understanding of “new drill” completions. My understanding is the “new drill” means a well that has never been completed before (a virgin hole in the ground of sorts). The “not new drill” oil well completions is a recompletion of an already existing well so maybe a new frac job or something of that sort.
GuyM or anybody with actual oil field experience (I have none) can correct me.
Bottom line I don’t think this tells us anything about DUCs.
Go to shaleprofile.com and look at the “well status tab” and then choose DUCs only under “show well status”, also you can choose TX Permian under basin for Texas only. The DUCs were at 2052 in Jan 2018 and had fallen to 1668 by June 2018, the data beyond that at shale profile (July, August, and Sept) are likely to be revised. The reported DUC number for August is 1265. Since Jan 2018 the DUC trend has been down at annual rate of about 735 per year, from Jan 2015 to July 2016 the DUCs were pretty steady at about 950, so I would expect it to stabilize around there until oil prices rise.
If I am correct that the new drill completions are the more important metric and they continue at about 379 per month on average (with perhaps 310 of these being horizontal oil wells) then we might not see much of a change. I expect the level of completions will drop and output will rise much more slowly than it did in 2018 (maybe a 200 kb/d increase in Permian basin output over the next 12 months.) Much will depend on the price of oil.
I did warn you my comments and questions were uninformed. 😉
Again, a big thank you. I found that on shaleprofile.com and it is very helpful, especially seeing it in graphic form going back several years.
But if that data is correct and DUCs have declined significantly, I think it stands to reason that all things being equal, there should be fewer new completions next year unless the pace of drilling accelerates? That of course assumes that DUCs stay at the same level as at year end.
Thanks again.
The real answer as to RRC completion and permit report is, I’m not sure. Many times, companies will post a shut in as a completion. So, logically the actual completion posted, should be a re-completion. But, sometimes they just wait for the real completion, and don’t post the shut in as a completion. They did it to one of ours, which was over a year delay between drilling and completion.
I only view the reports as indicating trends. I don’t think it’s accuracy is close to argue with.
Guym,
Thanks, though I think that means your not sure what “new drill” on the RRC report means either. Do I have that right?
Do you interpret it the way I do, but in practice find that’s not quite right, or is it just a mystery (like much in the RRC world, at least from a Yankee perspective). 😉
Mario,
Yes I think that’s right, they may need to drill wells at a slightly higher rate, in order to maintain last years completion rate due to fewer DUCs.
One thing to keep in mind at shale profile is that the most recent 2 to 3 months usually get revised higher as more data comes in, so best to ignore the DUC data after June 2018 for the most recent (Sept 2018) Permian update.
Enno Peters’ data is the best around, but the underlying data from the Texas RRC is not perfect, so his data will also be a bit less than perfect.
Note that the Texas RRC is dealing with 350,000 to 400,000 oil wells so it is not surprising the data is not perfect, no data is.
By comparison in North Dakota they have about 15,000 oil wells about 1/25th the number in Texas.
If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2019.
Sorry, 2019 should have been 2018 in the sentence quoted above.
Sentence below is correct version:
If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2018.
EIA estimate of Permian Basin Output for Nov 2017 to Nov 2018 period, see “tight oil production estimates by play” at page below,
Permian is sum of Spraberry, Wolfcamp, and Bonespring plays.
Annual rate of increase for past 13 months about 994 kb/d for Permian tight oil, for next 12 months at $50/b for WTI, I would expect a lower rate of annual increase perhaps 300 kb/d+/-100 kb/d.
Rystad’s data said something similar. Small E&P’s already adjusting to pipeline constaints in Aug-Oct by reducing completions in Permian it seems, even before the steep fall in prices. This policy of holding oil prices down can not last very long. I will give it to Feb at most, when you got all the forces on the supply side in the world trying revert the direction.
Hi GuyM,
Hi-Crush, L.P. (HCLP), a fracking sand supplier, has stated today that its 4th quarter revenues will come in a third lower than originally estimated, and that it will have to suspended its distribution for the quarter in light of the dire economic situation. Sounds like the slow down might be bigger than anyone expected.
Doesn’t that seem at odds with what Dennis posted regarding completions just above? It seems there were tons of completions in the fourth quarter, especially in October which was extremely high. I’m a little perplexed.
Mario,
My data is specifically for the Texas Permian basin, that company may operate in a different tight oil play. Or my data my not be giving an accurate picture, there are many facets to this and the picture is always pretty fuzzy.
In short, we won’t know about December until late January when the estimates come out (and those are often revised later).
Financier, you have to remember that expectations of growth in the Permian defied any reality. Companies geared up for massive production growth, and one of the groups were for sand. Many new local sand producers popped up, taking away sales from other producers, and to the dismay of the poor protected lizard. I looked at some averages for completions in 2017, and could agree with Dennis, as long as 2018 completions were significantly over 2017, it could rise overall, even if current completions trended down. At some point in 2019, keeping it level, will eventually cause a production drop. I do not expect that, and I expect the Permian production to be flat, or at an amusing growth level to past projections by everyone, including EIA. Completions will probably have to pick up later, just to keep it level. The current rate of WTI price increase should mean shale overall production rate will probably be flat, and pick up as prices climb over $70 (if they do, I’m just betting, literally, they will). But, most of the increases will likely not come from the Permian until port expansion capabilities are vastly improved.
Hi GuyM,
Hi-Crush is a player in all the major oil and gas basins. Its largest frac-sand operation is in the Permian. Its sand sales dropped by a third as compared to the last quarter. It didn’t break out any numbers regarding sales in the various basins and maybe the Permian was an exception, but it is blaming its woes on the lack of completions.
Well, I know the Permian started using local sand as an alternative. A lot. It was cheaper, and not subject to rail delays, which was a huge problem the first of the year. Lack of completions would be a fact, and it sounds so much better than we got beat out by cheaper competitors.
Guym,
Can the Permian oil go to Cushing and then be distributed to East coast refineries, I think they can handle the lighter crude, it just seems crazy that nobody anticipated this problem.
EIA predicts only a 550 kb/d increase in USL48 onshore output from Oct 2018 to Oct 2019, which is about 3 times less than the US tight oil annual rate of increase over the Nov 2017 to Nov 2018 period (1545 kb/d).
The EIA’s Short Term Energy Outlook for US L48(excluding GOM) seems pretty reasonable at $50 to 55/b for WTI. I would say 450+/-100 kb/d over the Nov 2018 to Nov 2019 period for US tight oil output is a reasonable guess.
Early last year they opened up a pipeline from Cushing to Tennessee refineries, which took about 300k a day. That’s when Cushing started decreasing. Now, they opened up a new pipeline in Nov from Midland to Cushing with about the equivalent amount, so it’s back to increasing. I know some East Coast refineries are set up to handle higher API, but around 50 or above is probably too high for even those refineries.
What would work (when port capability is up) is more pipelines from Cushing to the Coast. Last I heard, the lighter oil was playing second fiddle to the heavier oil for the refineries through the current pipelines. I read one article that stated an interest in doing this, but have read none on concrete plans. If they do that, then MEH becomes more of the official standard than WTI Cushing.
As to production increases, anything is possible. I don’t think the sharpest tools in the shed are running these companies. Logically, though, why should it? Permian and Bakken are ripped by transportation problems. And, from your analysis, none are making money at $55 a barrel, so why should it increase at a $50 to $55 a barrel range?
GuyM,
It probably should not increase, but for some reason they complete wells anyway based on past experience. It may be that the companies will focus on their better prospects as EOG has done in the Eagle Ford, by “high grading” the average well EUR may increase and allow breakeven at $55/b. Also I have assumed a 10% ROI as “breakeven”, if a 0% ROI is defined as “breakeven”, or maybe 3% (return on 10 year Treasury), then breakeven price is lower. For the Permian, if we ignore natural gas and NGL sales and assume breakeven ROI is 3% and well cost is $9 million, then breakeven oil price is about $51.35, for the average 2017 Permian well (refinery gate price), the wellhead breakeven price is $47.35/b. Note that the bigger players have access to pipelines and probably get a higher price at the wellhead than smaller conventional producers. In any case I expect output will continue to increase at a slower rate (3 times more slowly than in 2018) in 2019 at 50-55 per barrel for WTI.
I have been wrong in the past and I am consistent. 🙂
Okay, this worked. A repaste of the failure above failed again. Extracting the square brackets in the text also failed.
Something about those two paragraphs trigger the spam thing. That’s a heads up to others, if you get rejected look at the text below the link. The problem is somewhere there.
It’s an art, like finger painting or coloring books.
Canada, Alberta AER, Total Crude Oil and Equivalent Production at 3,725 thousand barrels per day in November, up +62 kb/day month/month
Up +541 kb/day from the average during 2017 which was 3,184 kb/day https://pbs.twimg.com/media/DwaY1vkXgAAkoU6.jpg
Canada, Alberta AER, crude oil closing stocks at 74,081 thousand barrels in November.
Down -1,547 thousand barrels month/month
November 2017 was at 64,191 thousand barrels https://pbs.twimg.com/media/DwaZ0y-XcAA1hlQ.jpg
CNBC headline that BP “discovered” 1 billion barrels in Thunderhorse field. Attribute it to advanced seismic.
2019-01-09 (Argus) Venezuela’s state-owned PdV has checked a decline in crude production mainly thanks to repairs to two heavy-crude upgraders run by its joint ventures with foreign partners, according to PdV officials, Argus estimates and internal company data.
Output is holding at around 1.1mn b/d for now, but it is unlikely to be sustained without substantial new investment, PdV mid-level managers say.
The upgraders associated with the PetroMonagas and PetroPiar joint ventures, both led by PdV with majority stakes, have undergone key repairs in recent months, stabilizing operations and freeing up more production from the Orinoco heavy oil belt. https://www.argusmedia.com/en/news/1823842-venezuela-checks-oil-production-decline-for-now
Even with US government help, port expansion won’t happen until 2020.
I would think in the mean time they could use smaller ships to export the oil.
They are doing that now. At about max.
Today’s RBN Energy has a description of exactly that.
LOOP just finished upgrading and loaded 3 2 million barrel VLCCs in 7 days in December.
The port in Corpus is loading VLCCs up to 1.2 million barrels and reverse lightening the balance offshore.
A third port in Texas City is starting to do the partial loading/reverse lightening also.
According to RBN, all the ships are going to Rotterdam.
I guess that the EIA might be understating US oil exports due to the Gov shutdown?
The EIA reported weekly crude oil exports at 2065 kb/day
Whereas S&P-Platts tanker trackers reported 2533 kb/day
Looks like a normal for exports is around 2.5 million a day from histories. The week loop loaded 3 VLCCs, we went up to over 3 million per day. So, there is nothing in the history that indicates we would be able to ship 2.5 million more a day, if the pipelines come online before shipping capacity increased. Loop can’t do that every week, yet. It looks like to handle the capacity of the pipelines, we would need to be able to comfortably ship 5 million barrels a day.
Then, we get back to the original question, to whether the Permian will increase another 2.5 mbpd at a $50 to $55 price?
Nothing in these projections are realistic. Yeah, if prices spiked, you bet it would eventually happen. My guess it will, but, at any price, not before 2020.
GuyM,
As I have said before, the EIA’s short term energy outlook has US L48 excluding Gulf of Mexico increasing only by 550 kb/d from Oct 2018 to Oct 2019, if we assume Permian Basin output is about 2/3 of this (as in 2018), then we would see about a 370 kb/d increase in Permian basin output in 2019. Somewhere in that range seems reasonable say 250 to 450 kb/d, probably toward the low end at current WTI (about $51/b).
There are higher estimates for US tight oil (OPEC and IEA and others) that seem to not take account of pipeline and port constraints in the Permian basin.
‘REALISTIC’ NEW MODEL POINTS THE WAY TO MORE EFFICIENT AND PROFITABLE FRACKING
“This work offers improved predictive capability that enables better control of production while reducing the environmental footprint by using less fracturing fluid,” said Hari Viswanathan, computational geoscientist at Los Alamos National Laboratory. “It should make it possible to optimize various parameters such as pumping rates and cycles and changes of fracturing fluid properties such as viscosity. This could lead to a greater percentage of gas extraction from the deep shale strata, which currently stands at about 5 percent and rarely exceeds 15 percent.”
Only 5-15% of gas is extracted? 15% of what? Of the gas in the volume of rock within some X distance of the bore?
TransCanada is taking “Canada” out of its name, and will call itself TC Energy.
New Leaf with over 220 mile range is coming this spring. Sounds like a perfect partner to my Versa. About four times the price of the Versa, though.
The Tesla Model 3 is pretty sweet, test drive one before buying the Leaf, by summer the 35k version of the Model 3 will be out, (about the same range as the Leaf, but probably a nicer car). Or you can get the mid-range model 3 at 44k with a range of 260 miles, with a 3750 rebate until June 30 so net before sales tax (do you have that in Texas) is about 40k. The leaf supposedly will be about 42k and would be about 34.5k after Federal tax rebate, so about 5.5k less than the M3 but 35 miles less range (which may not be important, but the low end M3 with about 210 miles of range will be 31k after rebate, if it is available before July 1 (not clear when Tesla plans to release that version). In any case, the test drive is free, maybe you will like the Leaf better or prefer Japanese to US made vehicles.
The Tesla is the first US made car I have owned since 1982 (I had a 68 Pontiac when I was young).
By far the nicest car I have driven, I have mostly owned Toyotas and Hondas since 1984.
Main problem with the Leaf is long distance driving. It has only passive battery cooling – so after a longer drive on the highway it can’t supercharge at full rates due to a hot battery. Especially not when doing this a second time.
Here are Teslas much better.
If you’re only driving locally, this shouldn’t be a problem.
A quick look at US holiday inventory builds for products (2010 to 2018). The sum of the last week of December plus the first week of January for 7 products.
We had the $100 oil years and then the glut years. I guess this year could revised in the monthly figures due to the Gov shutdown? It looks like holiday inventory builds are in an uptrend but it might be partly coincidence. If US production & exports increase, we could see builds increase in the off-peak season but draws would increase during peak demand? https://pbs.twimg.com/media/DwipzDjWoAA8t62.jpg
2019-01-10 (S&P Platts) The Norwegian Petroleum Directorate – In its annual industry report, the NPD forecast a further 4.7% drop in oil production this year, including condensate and natural gas liquids, after a greater-than-expected 6.3% fall last year. Last year’s decline had been greater than expected due to the complexity of some more recently launched fields and a shortfall in drilling activity, it added.
The NPD reiterated expectations that overall liquids output will return above 2 million b/d in 2020 thanks particularly to the start of production at the Johan Sverdrup field, expected toward the end of this year. https://www.spglobal.com/platts/en/market-insights/latest-news/oil/011019-norway-resource-shortfall-to-curtail-oil-gas-production-improvement-regulator
EIA Petroleum Supply Monthly with data for October 2018.
Largest changes
USA up 79,000 bpd
North Dakota up 31,000 bpd
New Mexico up 33,000 bpd
Texas up 18,000 bpd
Colorado up 22,000 bpd
Alaska up 16,000 bpd
Gulf of Mexico down 29,000 bpd
Thanks Ron,
A small increase, especially for Texas as GuyM has anticipated.
The last time we had oil prices in high forties for WTI ($48.33/b from July 2016 to August 2017), US C+C output rose at an annual rate of 635 kb/d. I would expect US output to grow relatively slowly (600 to 700 kb/d annual rate of increase) if oil prices remain under $50/b, instead of the rapid increase we have seen for the past 12 months (an annual rate of increase of 1760 kb/d).
The “glut fear” is based on the assumption that the rapid increase in US output seen in the past 12 months will continue, it won’t if oil prices remain low and even at higher oil prices (say $70/b for WTI) pipeline and port constraints will keep wellhead prices low in Texas and output will either be flat or perhaps small increases like the 18 kb/d we saw in October 2018 (about 200 kb/d for 12 months). Most tight oil plays in the US will not make much money with oil prices under $50/b, in fact the average US tight oil well needs at least $60/b at the wellhead to make a decent (10% annual ROI) return. Low oil prices will correspond with low oil output (or at least smaller increases in output).
Let me play along with that. I predict that if prices remain at current levels, which I don’t anticipate, we will see zero growth, amounting to a decline. If prices rise to $70 by June, we could see a 600 bpd increase by year end. The longer they remain at this price, Permian will be flat, or only slight increase to slight decrease. The rest of the plays will tube, making it go negative within three months. I posted earlier that I believed Permian completions may have declined by a third in Dec. Rough guess, and not positive.
As for 2019 being peak, I still think that is a good possibility. I think OPEC will call off their decrease before the end of the first half due to price increases, and US will get what they can, and too much for WTI, when the spread will increase before year end. But, those are wags.
GuyM,
Could be that output is flat as you suggest, for past 3 months (Sept to Nov) US tight oil output has grown at an annual rate of 1.9 Mb/d, I am suggesting this rate falls by a factor of 3 with WTI oil prices around $45-50/b, but maybe I am wrong (as I have been in the past.)
On much we agree, but I doubt 2019 will be the peak, we might see a temporary plateau while pipelines and ports get built in Texas to export the excess tight oil.
When that is accomplished tight oil output will grow in the Permian basin, peak will probably be 2028, but falling output in other tight oil plays starting around 2023 to 2025 will lead to a US tight oil peak around 2025, this is likely to coincide with the peak in World output, though if the Permian ramps up slowly we might see a plateau in World output from roughly 2025 to 2030, a bunch of uncertainty as to what happens in Brazil, Canada, Libya, Iraq, Nigeria, and Venezuela, but I still like 2025 to 2027 as the most likely years for Peak C+C output (12 month centered average World C+C output based on EIA data). In my view the odds of a World C+C peak in output before Jan 2020 are less than 10%.
As of the December DPR 82% of new US shale oil production goes to replace legacy declines, this means only 18% of new shale supply contributes to net growth. Based on this, only a minor slowdown in shale growth, for example 10%, can slow total production growth by 50%. I think many are underestimating the impact of low prices on shale growth, shale oil has changed the oil market supply elasticity, the old oil models where supply is stagnant no matter what prices are (due to the long lead nature of offshore supply, and slow decline of conventional supply) are not valid anymore. The relationship between prices and supply is closely tied today, this requires constant adjustment to the supply models (and demand models as well). I believe US oil prices have sunk too far, having a balanced oil market in 2019 requires WTI to average at least $55 as per my calculations, and this assumes OPEC easing their cuts by April.
I will go along with anything over a 15% decrease causing a decline in production just using some high school math. The DPR is strictly junk, and I wouldn’t rely on it for anything. Dennis has an alternative method, but none of us are far off from each other.
Then, again, my high school math is based upon “normal” decline rates. I assumed our wells were normal, which has been disproved by Shallow Sand. Ours are at 65%, which appears to be is low decline rate. His sample for the EF was a median well, which I looked up and was close to 80% the first year. If that was more “normal”, then 80% of the production of a new well is only covering the decline of that well the next year. Get the drift? What about the years before that? In short, it may be to increase production, you may have to actually be increasing the number of wells. If you staying the same, you get a decline. Time will tell.
GuyM,
Your wells have higher initial production, but perhaps similar decline rates to “average” wells. Essentially the entire well profile for your wells are shifted up compared to an “average well”. keep in mind that with current completion rates (say 375 completed wells per month in the Permian Basin) output was increasing, there is some number of completions (about 285 completions based on the information I have) where output would be flat and higher or lower completion rate would lead to an increase or decrease in output. What completion rate will correspond to current prices? I have no clue really, one would think at anything less than $60/b at the well head the completion rate should be zero, but oil companies think they can drill better than average wells, clearly this cannot be the case for all companies and completion rates will fall, but I don’t know by how much. Note that the “375” guess is for Texas and New Mexico completion rates for horizontal fracced oil wells for Oct 2018 based on EIA “tight oil production estimates by play”.
https://www.dallasfed.org/research/update/reg/2018/1808.aspx
Interesting read. Especially oil price chart compared to employment. And, if exports slow, WTI discount increases. Permian price decreases. I anticipate the “decrease in increase” at a higher level than you. If prices remain close to where they are now, there will be a decrease in shale production, soon.
Look at the production numbers for Oct. Prices were fine in Oct. Bakken oil price is almost negative now. Decrease in N Dakota would eat up Texas increase. That is, if there is any to eat up. A slow week in completions would eat up 79k pretty fast. And there are plenty of slow completion weeks coming up. And from what I can tell, Dec had its share.
GuyM,
In the past I have thought there would be a large decrease in tight oil output and I was wrong (there was a much smaller decrease than I anticipated).
Always possible that this time will be different, but I believe you have pointed out (correctly in my opinion) that it takes some time for companies to react to changes in prices, some of this might be due to hedging and some may simply be momentum.
So far there has been little change in tight oil output increases in the Permian Basin over the past 3 months (Sept, Oct, Nov) with increases of 84, 86, and 89 kb/d respectively. See “tight oil production estimates by play” at page linked below
https://www.eia.gov/petroleum/data.php#crude
Actually, some is momentum. I have looked at the period of time in 2015, when completions and production started dropping. Completions slowed down about two months before it leveled off for a short period of time, and then dropped.
The completion drop was bigger then, but a lot of that was verticals.
GuyM,
I agree. There was a big change in rig counts with vertical rigs dropping by a large measure and horizontal rigs by a smaller amount. As far as I can determine there is not an easy way to tell how many completed wells are vertical vs horizontal (or I just am not familiar enough with the RRC website to figure it out). The data from Baker Hughes on rigs is easy to dig up, but that doesn’t tell us the number of wells completed. It would be interesting to see the vertical vs horizontal well completion data if you have it.
Not really. Our initial production was a little over a thousand barrels a day, the mean well in LaSalle was 1880. It had a quicker decline rate the first year. That’s the trouble with all these damn averages. All have different monthly decline rates. One may start off at 28k the first month, and be 24k the second month. Another may start off at 28k, but be 15k the second month. Looking at it like Shallow Sand is doing is much more meaningful. How much did they produce over a significant amount of time. Nothing else makes much difference. By the time it gets into the fourth year of production, hardly any are contributing much to determine whether the well will be profitable, or not. And from what I can tell, this is not restricted to the EF.
Above us is the Bowman West lease. The first well there started off with less than a 300 bpd initial production, and production indicated that the first month. I went back and looked at it a year later, and it had produced close to 80k. A decent tier three well. Have to be careful with averages until you measure it over a significant time frame.
Guym,
Yes there will be variation from well to well, but if you look at a large number of wells and take averages you will find this to be true. The shape of the well profile does not change that much, the main change tends to be that the well profile tends to be higher over most points in time for more productive wells.
Below is the average well profile for Eagle Ford wells with first production in 2016 based on data downloaded from shaleprofile.com.
The average well had a high output in month 2 (first month on average with close to 30 days of output) of 537 b/d (16338 barrels per month), so roughly half the initial output of your wells. Output after 24 months was about 136 kb for the average well (also about half of your wells at about 275 kb over first 24 months).
Chart is pretty small, but clicking on chart will give you a larger view.
Well, that would be true if they always drilled the same proportion of wells in the same locations as the average is taken from. It won’t be true in the Eagle Ford, nor I doubt the Permian. In short, I dunno.
Guym,
The well profile changes over time. It’s a model that will not reflect reality with perfection. The model assumes the shape of the well profile doesn’t change (for simplicity), the initial rate changes and the well profile gradually gets lower (less productive as the sweet spots get drilled up. Prior to 2016 the average well became more productive over the 2011 to 2016 period, clearly we can only guess what wells will look like from 2018 to the future.
Chart below is such a guess where well profile moves lower over time from an EUR of 258 kb in 2016 to 207 kb at some later date, then 162 kb after that, and finally reaching 132 kb when no more wells are drilled. Only 4 well profiles are selected, in the actual model when EUR decrease begins as sweet spots run out of space, each month has a new (lower) well profile, so if EUR decrease started in Jan 2019 and drilling stopped in Jan 2030, there would be 132 well profiles, one for each month.
As always a bigger chart can be seen by clicking on the chart.
GuyM,
The decline rates are not fixed, they gradually decrease over time for a hyperbolic well profile. decline rates shown in chart below correspond to the average 2016 EFS well shown in another comment.
I know that. Mine do. But, after year three, who cares what they look like. It starts to approximate zero. There will be less money to borrow. Obviously, EOG’s premium drilling program is full of it from what Shallow Sand has contributed. However, the concept is still valid. If you can’t recover most of the cost of drilling the well the first year, then it shouldn’t be drilled. How else would a company afford to keep drilling the same approximate number of wells without that being true. Otherwise, you have to borrow massive amounts of money. Which, I think, is no longer a card to draw for. Unless prices go dramatically higher, a production slowdown is long overdue.
Guym,
According to Mike Shellman, it can work if the well pays out after 3 years, clearly it is better if it happens sooner, but you continue to get some income from wells older than 3 years. The reason this matters is that it will determine the future output from the entire play and that is what interests me. Also my view is that a discounted net cash flow analysis over the life of the well is the best way to approach the economic analysis of whether completing a well makes sense. One needs future well output and future oil prices to do such an analysis.
If the discounted net cash flow over the life of the well (at an annual discount rate of 10%) is greater than or equal to the capital cost of the well, I assume the project makes sense and the well is completed.
When this condition is not met drilling is reduced to a level where the condition is met when the completion rate falls to zero, the play is done and no more wells are completed in the future.
After year 3 about 30% of well output is produced over the next 11 years, it is not a huge amount, but if we add it all up at $50/b and 25% royalty it would be about one million over 11 years for the average 2016 well, so about $90,000 per year on average, hey send the checks to me, as they are approximately zero you won’t miss them. 🙂
On re-reading you must have meant the decline rates are approximately zero, I am not sure, I assume when they get to 10% they continue at an exponential decline rate of 10% per year, which I guess is close to zero.
Find me a well, where 30% is produced after year three?
Guym,
EFS wells started producing in only 2010 and in most cases there are no wells where only one well is producing on a lease for 11 years in any case, so hard to find such a well in Texas. For the average EFS 2016 well profile based on the data from 1373 well which were completed in 2016 and fitting a hyperbolic well profile to the output data. That well profile has an EUR of 245 kb over 16 years of production (it is assumed the well is shut in at 8 b/d of output) at 3 years cumulative output is 157.5 kb, so 157.5/245=64% of total output and 36% of output occurs from Year 4 to year 16.
If we assume the well is shut in at 15 b/d at the end of year 12, then EUR is 232.2 kb and 68.5% of the EUR is produced in the first 3 years and 31.5% of output is produced from year 4 to Year 12.
It is possible these hyperbolic fits overestimate future output, we don’t really know the future output of these wells.
These little oil molecules have a hard time understanding your curves.
Guym,
Your wells will probably produce about 450 kb over the life of the well. What is current cumulative production and monthly output for the most recent month. What month and year did production start?
Actually you could e-mail me the data and I could give you an estimate based on a hyperbolic fit, would be an interesting post perhaps.
Or you could give me just the lease ID # and I can pull the info from RRC.
I emailed the data. Without enhanced production, I estimate EUR to be over 300k, but not near 450k. The newer ones will be longer, and may get to 450k. This is the first one that made over 150k the first year, second lease was over 175 the first year, and the last three were closer to 130k.
GuyM,
Thanks, seems based on your data the EUR will be well over 300 kb and may reach that point by year 5.5. At 7.5 years cumulative output may reach 334 kb, at 10 years 364 kb, and at 12.5 years 389 kb with daily output at that point about 23 b/d. If the well can continue production profitably up to 15 b/d, then EUR will be 418 kb at 16.75 years from first output.
If the well is shut in at 10 b/d, it lasts for 20 years with EUR at 435 kb.
I have assumed a terminal decline rate of 10% per year after year 8.5, a nice well indeed.
Thanks for the work? Be nice to get to twenty, but I won’t borrow on it? But this one is before they extend the laterals?
GuyM,
I have tended to focus on the Permian basin. The 2016 average well there is more like your EFS wells. About 400 kb EUR with about 178 kb after 24 months, decline rate over first 12 months is about 67%. The wells are also more expensive (about $9.5 million).
Dennis, after 16 months with oil in the mid to high $40s from May 2016 to September 2017, the growth rate in US shale oil production stabilized at 80K or so from September to November 2017 (EIA DPR), by December 2017 shale oil growth accelerated to about 100K+ as prices crossed into the $50s and higher in October. What is of interest is that the total legacy decline rate from September to November 2017 averaged around 390K barrels per month, which means for shale to grow at 80K per month, new supply had to come at 470K per month. This is a telling number in light of where we are today. Today the monthly legacy decline rate in shale oil is 530K, this means if shale can only bring in 470K in new supply in the mid to high $40s WTI, US shale supply will start to decline by the end of Q1 latest in response to current prices (In my observation there is about a 2/3 months lag between price and new supply in shale). I think anyone projecting net growth in US shale supply in 2019 at the current strip will be in for a rude awakening in the next couple of months. Unless prices cross above $50 this month, US shale will be in full decline mode in Q2, and without shale growing in 2019 the market will be severely under-supplied. Welcome to the the new oil order: https://oilprice.com/Energy/Crude-Oil/The-New-Oil-Order.html
I think you are right. And, I think it is going to last longer for the Permian than 2019. Talk, already of slowing pipeline completions, and consolidating, already. It has to, until capacity to export is moved up. So, even when prices go up, that part of the shale machine is slowed. Not stopped, just slowed.
Joseph,
The EIA’s DPR is not a very good model, so I ignore it, it is based mostly on rig count and reality does not match the model very well. Also note the model does not distinguish between oil rigs and natural gas rigs, a major shortcoming of the model. Better data on tight oil is from “tight oil production estimates by play” at page below
https://www.eia.gov/petroleum/data.php#crude
Keep in mind that legacy decline depends on many factors including the well completion rate so as fewer wells are completed legacy decline gets smaller. You seem to be assuming that legacy decline is always increasing or remains fixed.
As price falls and completion rate falls the legacy decline will also fall (in absolute value or magnitude). Also note in the chart below the rapid change in legacy decline rate in the 3rd and 4th quarters of 2017, if this is not a model defect (and reflects reality), then rapid changes in legacy decline rate are possible, if one simply looks at the smooth part of the model in 2015 to 2016, it is clear that the slower completion rate over that period with a 24% change in legacy decline rate. A similar change from Oct 2018 legacy decline levels would reduce the legacy decline to about 381 kb and we might continue to see slow increases in tight oil output. In any case, I doubt WTI oil prices will remain under $50/b for very long, higher prices (over $50/b for WTI) are likely by May 2019, in my opinion. Also keep in mind hedges by many oil companies may insulate them from lower oil prices and the completion rate may not fall sharply at first.
Yes, I agree sub $50 oil will probably not last by May. And, it doesn’t make a lot of difference whether production declines a little, or increases a little, it will be far short of expectations. Expectations and needs.
GuyM,
Agreed, it will not be the over 1 Mb/d of tight oil claimed by IEA and OPEC, but note that the EIA’s STEO has US L48 onshore output increasing about 600 kb/d over the next 12 months (Oct 2018 to Oct 2019), that estimate seems pretty reasonable. They also have GOM output increasing by 220 kb/d over the same period, that might be too much (I do not follow GOM very closely). The overall US C+C increase is 790 kb/d from Oct 2018 to Oct 2019 vs the 1834 kb/d increase from Oct 2017 to Oct 2018.
My guess is the STEO may be a little high (probably about 200 kb/d), but in the right ballpark.
Dennis, appreciate your feedback, and yes I am aware that the legacy decline rate is not static, the graph you posted is roughly in line with the one I derived from the EIA DPR. I guess we are both in agreement that shale can’t sustain its current production level with WTI under $50, my guess WTI will move firmly above $50 before the end of Q1.
Joseph,
We are not quite in agreement. I think US tight oil will continue to increase even at current oil prices, but the rate of increase will be smaller. For the Sept to Nov period using EIA tight oil estimates (rather than the DPR) the annual rate of increase in US tight oil output was about 1.9 Mb/d, I expect this annual rate of increase to fall to about 600 kb/d, but unless WTI oil prices fall further to perhaps under $40/b for the next 6 months, I think a fall of the rate of growth of tight oil to zero is incorrect. That is because legacy decline will not remain at 500 kb/d, it will fall to 380 kb/d as the rate of well completion falls, but an average rate of increase of 50 kb/d for US tight oil output may be maintained (this is over 3 times lower than recent rates of increase). A change in OPEC strategy to defending market share as was done in 2015 would be the only likely reason that tight oil output will decrease before 2025, if oil prices were cut in half as occurred in the June 2014 to March 2015 period (from $105/b to $48/b) so an equivalent move would be about $34/b in April 2019, then we might see tight oil output decrease. Note that the average oil price over the period of decreasing US tight oil production was about $45/b, about half the level of the period where output was increasing rapidly (from March 2013 to March 2015 with WTI=$90/b). The recent period of rapid tight oil increase occurred with WTI at an average price of $57/b (Oct 2016 to Oct 2018), I doubt we will see half that price level ($28.50/b) until 2040 or beyond (due to lack of demand for oil).
Dennis, we are in agreement that WTI can’t remain under $50, because shale growing at 600K will be substantially below the EIA and IEA shale growth estimates for 2019. I believe we are both shooting in the same direction, shale oil production growth will slowdown materially in the high $40s (your position) or decline (my position) but the outcome on the price (directionally) is the same, WTI needs to move higher for shale to balance the market.
Joseph,
I agree we are pretty close. Note that the EIA’s Short term energy outlook has US L48 (excluding GOM) C+C output increasing at about 560 kb/d from Oct 2018 to Oct 2019, so fairly close to my estimate for tight oil.
I agree that this level of US output combined with OPEC/Russia cuts is likely to result in an increase in oil prices to $65/b for WTI, probably by Sept 2019. Potentially that could lead to slightly higher tight oil output than the 600 kb/d annual rate of increase that I assume, perhaps 800 to 900 kb/d annual rates after oil prices reach the $65/b target for a couple of months.
Lots of moving parts such as price spreads in various tight oil plays which will depend on pipelines, rail capacity, and deep water ports on the Gulf coast. The picture is pretty fuzzy.
Dennis,
Talking about moving parts, I believe service costs is also a big part of the equation, in light of the frantic drilling/completion activity in 2018, service costs seems to have jumped by 35% according to Diamondback Energy. Trough service pricing conditions which helped shale companies increase activity in 2016 and 2017 have reversed, thus cash flows today sub-$50 are not what they were in the sub-$50 window from mid-2016 to mid-2017.
Joseph,
Excellent point, but as completion activity wanes, service costs will drop. Yes lots of pieces to consider. If output goes down due to lower completion activity, we will see costs go down while revenue will increase due to rising oil prices. Also remember that output per well has increased, especially in the Permian Basin.
Though I have read that output for a “normalized well” with fixed lateral length, frac stages and proppant levels has started to decrease in the Permian basin in 2018. I have not seen the data confirming this as it is proprietary.
Thinking about OECD oil stocks and looking at IEA Oil Market reports, I get the chart below for days of forward demand (stocks divided by daily oil consumption).
Not clear from this chart why oil prices have decreased, at least to me.
Look at the Dow on Jan 2, and oil prices. There is no logical connection, yet the connection by now is for real. In the minds of the market turmoil recipients. By now, margin calls are in full swing.
GuyM,
Fear seems to be in charge in both markets.
For an alternative view
https://oilprice.com/Energy/Oil-Prices/Why-2019-Could-Start-With-An-Oil-Rally.html
It won’t last for oil, but long enough to reduce capex budgets. I have absolutely no idea how long it will last for the Dow.
US inventory change for the first 10 months of each year (million barrels)(without LPG)
2018
Crude oil +10.8
Products -16.2
Total (crude oil+products) -5.4 (shown on chart)
LPG +34.9 (not included)
Chart https://pbs.twimg.com/media/Dvw-6npXgAAdeDQ.jpg
US inventory change during October (million barrels)
Crude oil +16.3
Products -27
Total (crude oil + products) -10.7 (shown on chart)
LPG +0.3 (not included in the total shown)
SPR -5.2 (also not included)
Chart https://pbs.twimg.com/media/DvxAWwvWoAEPzM4.jpg
US consumption during October (Just the major finished products without LPG or Petcoke)(1000 barrels/day)
Up +442 over September
Up +186 or 1.2% over October 2017
Up an average +226 or +1.48% in 2018 from Jan to Oct compared to the same 10 months in 2017
Chart: https://pbs.twimg.com/media/Dv0ulJGWoAEycS0.jpg
Liquefied Petroleum Gases (not included in the chart)
Up an average +251 or +9.87% in 2018 Jan to Oct compared to the same 10 months in 2017
https://www.forbes.com/sites/rrapier/2018/12/30/opecs-shale-problem/#6e4dbbb46b02
Who blinks first (US, KSA, Russia)
https://thumbor.forbes.com/thumbor/960×0/https%3A%2F%2Fblogs-images.forbes.com%2Frrapier%2Ffiles%2F2018%2F07%2FOil-Supply-Growth.jpg
Seems that the most growth came out of US, so it has the biggest strain
Happy New Year all!
Thank you, likewise.
Canada’s Rig Count Plunges by More Than Half in Two Weeks
While the U.S. continues to add oil and natural gas drilling rigs despite the recent swoon in crude prices, Canada’s count in the past two weeks has dropped from 174 to just 70, the lowest since June 2016. Twelve years ago, it had as many as 727 rigs drilling for oil or natural gas, according to data provided by Baker Hughes Inc.
Happy New Year!
The Canadian oil rig count is down to 15. Almost down to the level seen in December 2015 which was 12 oil rigs reported as active. (2015 had 53 reported weeks)
Chart https://pbs.twimg.com/media/Dv1K2iRWsAAIIhj.jpg
Alberta – The month of May is the seasonal low, December is normally just a holiday dip. I guess they could be cutting some rigs ahead of the production cuts that start in January?
Saskatchewan had zero rigs reported as active in the week to December 28th. Which cannot be part of Alberta’s production cuts.
Alberta chart https://pbs.twimg.com/media/Dv1LLvFWkAAySID.jpg
https://www.houstonpublicmedia.org/articles/news/energy-environment/2018/12/31/316118/new-pipelines-to-relieve-bottleneck-in-2019-but-what-about-after/amp/
Probably to slow and consolidate new pipelines from the Permian. Knew that was coming,
Dec27 Petróleo Brasileiro, November crude oil (oil+condensate+LPG) production in Brazil 2.01 million b/day Of note in November is the start-up of the P-75 platform, the second unit installed in the Buzios field, in the pre-salt of the Santos Basin.
http://www.investidorpetrobras.com.br/en/press-releases/oil-and-natural-gas-production-november-2
Chart https://pbs.twimg.com/media/Dv12DadXQAAkXOz.jpg
Petrobras new FPSOs – We’ve seen delays in the past, I guess due to low oil prices but I guess it’s too late to delay these now?
Lula Sul FPSO P-69 started Oct
Buzios2 FPSO P-75 started Nov
Lula Norte FPSO P-67 first oil early 2019
Buzios3 FPSO P-76 set sail Dec19th first oil early 2019
Berbigão FPSO P-68 delayed
Buzios FPSO P-77 production scheduled 2019
Atapu FPSO P-70 2019
2020 nothing listed
I guess that I should remind people that Petrobras’ production fell in 2018 partly due to the sale of stakes in several fields. Brazil’s production (ANP) is back up to about the same level as it was in 2017.
Buzios1 FPSO P-74 started in April
Tartaruga Verde e Mestica FPSO Cidade de Campos dos Goytacazes – started June 2018
Hello Dennis Coyne or someelse
What do you think about Delaware Basin has 46.3 billon of barrels?
https://www.sciencedaily.com/releases/2018/12/181206135643.htm
Cecilia,
If the USGS mean estimate is accurate for the Permian Basin (including Delaware Basin), then technically recoverable resources(TRR) for tight oil are about 74 Gb and when we apply the usual economic assumptions the economically recoverable resources (ERR) would be about 60 Gb. Currently Permian output is about 3000 kb/d, the medium model with ERR =60 Gb peaks at about 7300 Gb in 2028 and output doubles to 6000 kb/d by 2023 (about an average annual increase of 750 kb/d in Permian Basin output). The USGS F95 and F5 cases are also covered in the chart below and for all cases the EIA’s AEO 2018 Brent Oil reference case is assumed for future oil prices. For the low (F95) case ERR= 35 Gb and the high (F5) case ERR=98 Gb with peaks of 5500 kb/d and 10,000 kb/d in 2023 and 2031 respectively. Probably 50 to 80 Gb is a reasonable guess with about a 70% probability ERR for the Permian Basin will be in that range.
The article below was published on Sunday (Dec 31) in the older of the two daily newspapers in my neck of the woods. My feeling is that this is an effort by this newspaper to bolster opinion that initiatives to introduce NG as a fuel in Jamaica are the best solution to the islands energy challenges.
For some background, US outfit New Fortress Energy has been having some success with introducing NG as a fuel to the island. There has been a long protracted process to do this that has been mired in corruption with a former energy minister being involved in the setting up of a company that was to supply LNG to the island but it seems New Fortress was finally able to come up with a scheme that satisfied the government and the local private sector. The “Our Work page lists supply of LNG to a 120 MW (Combined Cycle) electricity generating station in Montego Bay that has been converted to run on NG, a floating storage and regasification terminal to supply LNG to a brand new gas-fired combined cycle power plant under construction by the local electricity utility and supply of NG to a new power plant at a bauxite to alumina operation in central Jamaica. It has also been reported in the media that, the island’s largest beverage manufacturer has installed a co-generation pant to provide power, process heat and cooling to their operations, the local campus of the regional university is setting up a co-gen plant on the campus and a second beverage manufacturer/distributor is to set up a co-gen plant as well. I have seen “New Fortress” branded storage tanks at the beverage manufacturer and a single tank at the university’s facility. It is extremely likely that the third announced co-gen pant is also a New Fortress customer. I am a little suspicious of the fact that the entirety of New Fortress’ customer base appears to be in Jamaica.
I am somewhat concerned that my island home is being sucked in by the “energy abundance” hype. Once the infrastructure has been put in place and the co-gen and power plants are built, it will be a difficult/expensive undertaking to to try and switch energy sources again. These Jamaican operations will be married to NG for decades to come.
When it comes to natural gas, US is ‘open’ for business
Last November, diplomats from Brazil to Japan joined oil and gas executives at the headquarters of Washington’s largest lobbying group to christen a new partnership.
Inside the marble walls of the US Chamber of Commerce, a crowd of 200 welcomed the US Gas Infrastructure Exports Initiative ó a coalition of 25 companies, nine trade groups, five law firms, at least five federal agencies and a non-profit think tank. Its mission: to drive sales of American natural gas by pumping dollars into pipelines and gas-processing facilities overseas.
The initiative, coordinated in part by a natural gas lobbyist, is the latest federal effort to market the fuel as a “clean” energy source amid surging US drilling and exports. American gas production is projected to account for almost 40 per cent of the world’s gas growth through 2040, according to the International Energy Agency. Countries like China are buying up tank loads of LNG – natural gas that has been supercooled to liquefy it ó to generate power, heat buildings and fuel trucks.
“When it comes to exporting LNG, the United States is open for business,” Mark Menezes, undersecretary of the US Department of Energy, assured the audience at the launch of the gas initiative. Menezes, a former utility industry lobbyist, added that exporting US liquefied natural gas is “clearly in our economic interest.”
Islandboy
Jamaica is in the forefront of an emerging, global energy paradigm that I have mentioned a few times on this site.
Specifically, the adoption of natgas for a much bigger consumer base than at present.
For your information, New Fortress Energy plans on constructing up to 10 LNG plants with at least 2 in the Appalachian Basin.
Throwing out numbers seems a poor way of transmitting info, but the first AB plant in Bradford county, PA, would produce almost as much as the Elba Island plant (2.1 million tonnes per year … mtpa), cost a – relatively – paltry $850 million, and be built in under 18 months.
These numbers are simply disruptive in the extreme.
Your mention of the co-gen projects (commonly referred as Combined Heat and Power … CHP) is additional evidence of the dizzyingly rapid development of hardware associated with this technology.
(Spending some time reading up on small scale and mid scale LNG will give one a sense of what is coming down the pike).
Your concern about a multi decade long embrace of natgas is shared by a great many competing industries, ideologies and countries.
Hence the scorched earth campaign to impugn US natgas at any and every opportunity.
That your country is proceeding down this path, offering abundant and cheaper energy over a wide swath of your country’s populace might prompt some study in this arena.
A report on LCOE of various energy sources below
https://www.lazard.com/media/450784/lazards-levelized-cost-of-energy-version-120-vfinal.pdf
On page 2 of the report we find Natural Gas combined cycle has LCOE of $41 to $74 per MWh and utility scale solar a price of $36 to $46 per MWh. These costs are without any subsidies included.
Utility scale solar PV has been falling in cost at a rate of 21.6% per year from 2010 to 2017 based on NREL (National Renewable Energy Laboratory) data.
May the cheapest energy source win!
Note that pollution costs for natural gas are not included in these estimates.
For those who understand that Global Warming puts the world at risk, solar and wind power over natural gas or coal is not a difficult decision.
That same report shows nuclear to be LCOE at $26/MWh.
Before Carlos or others get all frothy on this, read the footnote indicating this is for a fully paid off reactor. The costs at that point are labor, reactor maintenance, re-fueling, security, insurance and such.
The equivalent cost for utility scale Solar electricity that was fully depreciated would be likely about $3/MWh!
For reference sake- The electricity cost from nuclear that isn’t already paid off ranges from $112-189/MWh.
2019-01-02 (Bloomberg) Russia December crude oil production 11.45 million b/d, source CDU TEK.
Bloomberg chart https://pbs.twimg.com/media/Dv4tZm7WwAAfM58.jpg
Just like the last four months of 2016, Russia and OPEC is ramping up to maximum possible production so they can “cut”. And their cuts will be from the last few months of 2018 when they were producing every barrel of oil the could possibly produce. However the average for the last four months of OPEC+Russia for 2018 will be about half a million barrels per day less than the average for the last four months of 2016.
Ron,
Good point, but how does it look if we exclude Venezuela? Venezuela’s C+C output has fallen by about 800 kb/d since the 2016 OPEC peak in Nov 2016 through Sept 2018.
If Venezuela is excluded, OPEC+Russia minus Venezuela is slightly higher in Sept 2018 than in November 2016 (45215 kb/d vs 45128 kb/d).
And just why would you exclude Venezuela? I am sure Venezuelan oil production will one day recover, but that is likely to be at least a decade from now. Not only is their infrastructure being destroyed but their economical structure is being destroyed as well.
There will always be countries with political problems that affect oil production. Look at Libya, Nigeria, and Sudan. The political problems in these countries are never ending. If peace broke out all over the world then oil production would definitely go up. Fat chance of that happening.
When peak oil happens, Venezuela will, very likely, be producing less oil than they are today, a lot less oil.
Ron,
The point is to explain that 800 kb/d of the 500 kb/d decrease that you mention is because of Venezuela’s collapse, rather than natural decline in OPEC output. Output in Venezuela may continue to fall, perhaps by another 800 kb/d, though it will not be more than the 1271 kb/d that was produced in Sept 2018. This is just to show that all of the OPEC decrease from Nov 2016 to Sept 2018 is explained by Venezuela’s collapse in oil output. Another potential place where oil output could drop is from Iran in May when the sanction waivers are set to end.
Dennis, nowhere in my post did I make the claim that it was all due to natural decline. Venezuela is nevertheless still producing every barrel she can possibly produce. Her decline is not due to natural depletion but to political problems.
Other countries are having similar problems as well though not quite as severe as those of Venezuela. There will always be political problems that interfere with oil production. That just goes with the territory.
When peak oil occurs many will countries will still have political problems. The situation is far more likely to get worse than it is to get better. Nevertheless peak oil will be peak oil regardless of the cause.
I’ve noticed that Venezuela imports natural gas. From looking at Canada I notice they use a lot of natural gas to supply energy for bitumen mining. Canada exports natural gas. Perhaps Venezuela doesn’t have the energy to mine their heavy oil sands, as well as political factors. I wonder what mining bitumen using bitumen as an energy source to do so is like in terms of profit/EROI etc. I imagine that once Canada runs thin on natural gas their bitumen mining and processing will decline. I imagine Canada would be doing less well if they had to import natural gas to fuel bitumen mining.
Survivalist – apologies if you know this already. Venezuela heavy oil isn’t bitumen (defined as oil with viscosity above 10000 cP if I remember correctly) and it will flow naturally, if reluctantly, up a conventional well (unlike bitumen). Their upgraders are flexicokers (upgrade by removing carbon) rather than hydrocrackers (upgrade by adding hydrogen from natural gas). Canada uses natural gas to generate steam in SAGD developments and in upgraders, Venezuela doesn’t, although there may be a bit of steam EOR in conventional fields.
George, I think you are mistaken. Venezuela has two types of oil, conventional and bitumen. Their conventional oil is in decline. Their bitumen is not in decline but they are having serious problems with it.
Their bitumen is so heavy it will not flow naturally so they add naptha to it to lower the viscosity before they can ship it through their pipelines. Now they are having very serious problems finding enough naptha to mix with their bitumen.
I have no idea how they extract it from the ground.
“Most of Venezuela’s proved oil reserves are located in the Orinoco Petroleum Belt. Although often referred to as oil sands (or tar sands), Venezuela’s oil sands are technically “extra heavy oil” deposits since they don’t contain bitumen.”
https://www.oilsandsmagazine.com/news/2016/2/15/why-venezuela-is-albertas-biggest-competitor
I think they add diluent to get flow in the pipeline from the wellhead to the process ing plants, not as part of the reservoir depletion strategy (same is done in Canada).
George Kaplan,
This post–short, concise, with lots of information included that gives an overview of a particular topic–is an example of what causes me to feel uneasy when you speak of maybe cutting back on posting.
The Orinoco heavy oil belt is very large, the reservoirs are thick, have a range of oil density, solution gas, temperature, and therefore viscosity. I’ve seen a well pump 2600 BOPD of 8 degree API crude, with 120 scf/bsto gas oil ratio, without diluent.
In some fields diluent is added downhole, but this wasn’t that common when I worked there. Most wells have diluent added at the wellhead, to reduce viscosity (given that temperature drops as the oil moves towards the surface).
All upgraders were designed to add hydrogen to the product slate, but they range from a simple addition limited to the coker nafta, to full hydrogenation for some of the syncrude made at the Total upgrader.
I prefer to use the name extra heavy oil for the oil being produced from the Faja, because it’s lower than 10 API. I don’t like the term bitumen, but I suppose one could use it for oil that’s heavier than 10 API and has viscosity higher than say 10K centipoise.
I expect Venezuela’s production to take a hit in January, because on January 10 Maduro will attempt to be sworn in as president, and this isn’t considered legitimate by about 42 nations. FYI I’m advocating all Venezuelan state property and bank accounts be placed under an administrator who will make funds available to the transitional body headed by Guaidó, the new National Assembly President. If my advice is followed the regime should fall sometime over the next three months. I expect a lot of chaos and quite a few deaths.
I don’t like the term bitumen, but I suppose one could use it for oil that’s heavier than 10 API and has viscosity higher than say 10K centipoise.
Almost every article I have ever read on the stuff calls it bitumen. And I have read a lot of articles on the Venezuela bitu…. err… sorry, I have read a lot articles on the Venezuela heavy oil. So imagine my shock when I was told by some on this forum that it it not bitumen at all.
Hi Ron,
There is plenty of stuff written that is not correct.
See
https://en.wikipedia.org/wiki/Asphalt
where Venezuela is not mentioned.
It may be that you have assumed oil sands and bitumen are the same thing, I had thought so myself, but now realize that I was incorrect.
There is a distinction which George Kaplan very politely pointed out to me, and I appreciate knowing the difference.
I do know that Laherrere always refers to Venezuelan Orinoco belt oil as extra heavy oil. Bitumen is essentially natural asphalt.
Also in Venezuela they do not mine the oil sands they use a process called CHOPS.
https://en.wikipedia.org/w/index.php?title=Cold_heavy_oil_production_with_sand&redirect=no
Ron, there’s nothing I can do if those who don’t get it keep quoting each other and adding to the confusion. I’m just a petroleum engineer who supervised teams doing Faja developments, and to us the reservoir fluid is oil. The high viscosity makes the standard depletion equations a bit inaccurate, but in the end the stuff behaves like oil.
Let’s put it this way: if I see a petroleum engineer referring to the reservoir fluid being produced in the Faja as “bitumen” I would consider him poorly trained and schedule him (or her) to a special catch up training session.
Survivalist, Venezuela has many problems. Their oil field and refinery works are quitting because they do not get paid, or paid very little. They cannot get parts to repair their oil field and refinery infastructure. And they cannot get enough naptha to mix with their bitumen in order to get the viscosity low enough to pump through pipelines.
I am sure they are having problems mining the stuff as well.
Ron,
Orinoco oil is as George said considered extra heavy oil rather than bitumen. It is pumped rather than mined.
See
https://www.oilsandsmagazine.com/news/2016/2/15/why-venezuela-is-albertas-biggest-competitor
On the surface, Alberta and Venezuelan oil sands appear very similar. Both are unconsolidated sandstone deposits, with similar densities and sulphur content. But there are some important differences. And some of those small distinctions give Venezuela several advantages:
1. Better geography:
The Orinoco Petroleum Belt has excellent access to tidewater. And the world’s biggest consumer of heavy oil is relatively close-by in the US Gulf Coast, a mere 5 day boat ride.
Thanks to proximity to the equator, oil sands deposits in Venezuela are closer to 50°C, much warmer than Alberta’s oil sands which tend to average closer to 20°C deep underground and just 5°C close to the surface. That means much less energy is required to bring the oil to a flowing temperature.
2. Simpler geology:
Alberta’s oil deposit is much older, comprised of a more complex geology, more types of sediments and a wider variety of reservoirs. Venezuelan oil sands is younger, deeper, more uniform, more concentrated and more saturated with a coarser grained sand. This allows for better recovery rates under the same operating conditions.
Viscosities in Alberta range from 10,000 cP in the Lloydminster area, 100,000 cP near Cold Lake and 400,000 cP closer to Fort McMurray. Venezuelan heavy oil deposits in contrast have a more uniform viscosity, typically ranging from 4,000 to 5000 cP. Coupled with the warmer climate, that means Venezuelan heavy oil actually flows under ambient conditions, whereas Alberta bitumen is virtually solid at room temperatures.
I think most of their infrastructure is so degraded as to be unfixable and would have to be replaced completely to be acceptably safe under even the most lenient of E&P operating rules. To get back to 2 mmbpd that would probably cost $250 billion upstream, maybe $100 to 200 billion more for midstream and upgrading/refining. Who would invest that given the risk of future nationalisation etc? Who would get the the required skilled work force to go there (many of the best people moved to US when the previous nationalisation happened)? Are the reserves really what is claimed? Even with the best scenario it’s 10 years before any new plant would come on line, and let’s not forget that to save the world oil use is supposed to be reducing at 5% per year – given that why risk investing in the worst possible global environment for energy production.
George,
Excellent analysis (as always), thanks.
Thanks everybody for the info. I appreciate it.
Hi Ron,
Correct, you did not say it was natural decline, nor did I say that you said it.
You said in 2018 OPEC+Russia C+C output was 500 kb/d less than the peak in 2016. I was showing why this is the case, it is entirely due to political problems in Venezuela.
My point is that the decline is 100% (more than that actually, it’s 800 of 500 so 160%) due to the political crisis in Venezuela and yes there have been many other political crises in the past and these will continue in the future. (Soviet Union, Iran, Iraq, Kuwait, Libya, Nigeria, and Venezuela come to mind.)
These are impossible to predict in advance and over time these problems sometimes get resolved (Russia/Soviet Union, Kuwait, Iran, and Iraq being examples as far as recovery in oil production). There have been partial recoveries in Nigeria and Libya, though of these two the situation seems more precarious in Libya. Venezuela seems a long way from resolving political problems and may continue to decline to 400 or 500 kb/d over the next few years. Combined output from US, Russia, and the rest of OPEC (excluding Venezuela) is likely to be enough to keep World C+C output rising if demand for oil continues to rise (which seems likely unless there is another Global Financial Crisis before 2025).
This scenario also assumes we do not have a major War either worldwide or in the Persian Gulf before 2025.
Predicting war or major recessions in advance has never been my strong suit. 🙂
Combined output from US, Russia, and the rest of OPEC (excluding Venezuela) is likely to be enough to keep World C+C output rising if demand for oil continues to rise…
You are of course assuming that output from US, Russia and the rest of OPEC will continue to increase production. And you are also assuming that this rise in production will be great enough to overcome the decrease in production from the rest of the world.
Rather iffy assumptions I would say.
Correct,
Those are assumptions. I would say they are the best assumptions based on the information available. The future is not known, be can only estimate based on the information we have.
The assumption is: All countries that are currently increasing in production will continue to do so for the next several years.
And: All contries currently in decline (the vast majority of oil producing countries), will not significantly increase their decline rate.
That is a bet I would not dare to take.
A few months ago I posted a quote from the OPEC CEO that all mature fields around the world have a decline rate that is increasing. He was calling for more capex from all oil producing countries and companies.
Just in case that is of any interest to you.
“He was calling for more capex from all oil producing countries and companies.“
Ron,
And many know that that amount is increasing, because more and more EOR projects have to be developed to prevent world oil producting from falling.
A remarkable Forbes article from 2016 (I couldn’t copy paste the site because it was marked as spam)
‘Saudi Arabia Burns Through Foreign Reserves As Oil Prices Slide‘
Hi Ron,
Jean Laherrere estimates about 2500 Gb of World conventional resources, in 2000 the USGS estimated a mean TRR for the World of about 3000 Gb, my estimate is about 2800 Gb. Laherrere uses a combination of Hubbert linearization and creaming curves as the basis for his estimates, over time his estimates have tended to be conservative (rising from 1800 Gb to 2500 Gb for conventional C+C from 1998 to 2018), the USGS estimate might be too optimistic so I picked a round number between 2500 and 3000 rounded to the nearest 100 Gb. I think a plateau from 2020 to 2029 between 84 and 85 Mb/d is likely with the most likely date of the peak between 2024 and 2026 (this is centered 12 month average World C+C output).
Our estimates of when the peak will occur are not that far apart. Note also that the low oil prices of the past 4 years suggest that oil supply is adequate, I would expect to see sustained Brent oil prices at over $100/b (in 2017$) as we approach the peak, probably from 2022 to 2026, with oil prices gradually rising from $60/b to $100/b from 2019 to 2022.
Dennis, guesses about how much oil is left in the ground is really a non-issue. All that matters is how much oil can be extracted from the ground on a daily basis. That’s what we watch because that’s all that we can see. And really, that’s all that matters.
Ron,
How much can be extracted depends in part on how much has been discovered and what portion of those discoveries has been produced and what portion remains as recoverable reserves.
Finding what has been produced is pretty straightforward, predicting future production is tricky.
You seem to assume that I assume that all nations that are increasing production will continue to do so, some will and some will not, but on balance output is likely to continue to increase as a slower and slower rate until the peak is reached, we simply disagree about when this will occur by a few years. Eventually your estimate will be correct. Frankly I hope that your estimate is correct, but to me that is just wishful thinking and I am not the optimist that you are. 🙂
“, and let’s not forget that to save the world oil use is supposed to be reducing at 5% per year “
George,
Many think that, notwithstanding increasing renewable energy, world oil use has to increase yoy to keep world economy on a growth path. Of the many big companies who count on that, Boeing is one. If, at last, somewhere in the future, EV sales are taking off seriously, this story becomes different. Then the airline companies can grow while world oil production is declining, assumed that the world economy doesn’t collapse.
Take the many contradictions in the world news, of course that leads to incompatibilities in the decades ahead.
Han,
I think the aim is to reduce carbon emissions by 5% per year. This can come from reducing the use of coal in producing electricity as well as natural gas used in producing electricity as well as reduced oil use, as the peak approaches and fossil fuel prices rise and as costs for solar wind, EVs, and battery storage continue to fall there could be a rapid paradigm shift to less fossil fuel use.
Once peak fossil fuels becomes a reality and is fully accepted by the mainstream, all the time and energy wasted on expensive options like coal, oil, natural gas, and nuclear power will be transferred to cheaper and more environmentally sustainable solutions like solar, wind, EVs, electrified rail, and HVDC transmission widely interconnecting the power grids of most nations which will greatly mitigate the problem of intermittency of alternative energy as it is moved North and South and East and West.
02 Jan 2019 (S&P Platts) Nigeria’s deepwater oil field, Egina has achieved first oil production, helping to push oil production beyond 2.09 million b/d in December.
“At plateau, the Egina field will produce 200,000 barrels of oil per day, which represents about 10% of Nigeria’s production,” Total said in a press release Wednesday that noted production started on December 29th that used the oil major’s largest ever Floating Production Storage and Offloading (FPSO) unit.
Nigeria must reconcile an improving production profile with its commitment under the Organization of Petroleum Exporting Countries latest 1.2 million b/d output cut that kicked in on January 1. Nigeria’s daily oil production should now be cut to 1.738 million b/d, according to documents seen by S&P Global Platts.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/010219-nigeria-output-gets-boost-as-egina-achieves-first-oil
https://oilprice.com/Energy/Energy-General/Oil-Tanker-Firms-Scrap-Most-Ships-In-Three-Decades.html
The build up to the perfect storm continues.
2019-01-02 (Bloomberg survey) OPEC oil production fell -530 kb/d in December to 32.6 million b/d.
Just ran across this, published last September, bold mine.
Opec predicts massive rise in oil production over next five years
World oil production will soar to new records over the next five years, as a dramatic expansion in demand from airlines offsets the arrival of electric cars, according to a report from Opec.
In a forecast that will dismay environmentalists – and which questions the theory that oil company reserves will become “stranded assets” – Opec’s annual report significantly revised production estimates upwards.
Most of the production increase will come from countries outside Opec, led by explosive growth from frackers in the United States, with China and India leading the increase in demand.
Opec expects global oil demand to reach nearly 112m barrels per day by 2040, driven by transportation and petrochemicals. That is up from almost 100m today and higher than last year’s projection.
Coal will continue to be be burned in record amounts, despite concerns about its impact on climate change. Opec estimates that coal usage in the OECD countries will plummet by a third by 2040, but it will increase by 20% in developing countries to reach five times the volumes burned in the west.
It is just assumed that production will rise to meet demand. OPEC knows what they can do so they just assume non-OPEC, primarily the USA, will increase production to meet demand.
So what price and what miracle would sustain and increase the US fracking production through 2040?
The only thing that would do it is God pointing his finger at the US and saying: “Let there be more oil in that US shale.” And he would have to come back every five years and do it again.
Gone Fishing,
If production were increased slowly, US tight oil output might increase through 2040, or at least maintain a plateau for many years, things don’t usually work like that in a free market economy, so not likely. Actually lower prices would make it more likely that production would ramp slowly, something like $50 to $60 per barrel with a gradual increase over time to $100/b
Gone fishing,
Scenario below assumes a slow increase in Permian Basin tight oil output due to pipeline and port constraints tight oil output increases about 750 kb/d from 2019 to 2033 and then falls back to 2019 level by 2037. Clearly this is not the surge in tight oil output that many expect, it is based on the AEO 2018 Brent oil price reference scenario, which has real oil prices in 2017$ only reach $113/b in 2050. I expect by 2027 at the latest there will be severe shortages of oil supply relative to demand at the AEO reference scenario price (Brent oil price about $89/b in 2017 US$).
This scenario has a tight oil URR of about 83 Gb (Permian- 58 Gb, Bakken- 9 Gb, Eagle Ford 10 Gb, Niobrara 3.5 Gb, rest of US tight oil 3 Gb.
Potentially there might be some tight oil output from the rest of the World, but I doubt it will be enough to keep prices low as ramp up is likely to be slower than the US. As demand falls due to the expansion of EVs of all types (2 wheel, 4 wheel, buses and trucks) tight oil may not be viable in other nations competing with cheap oil from the Persian Gulf.
Dennis
For demand to fall there has to be fewer petrol and diesel cars.
http://subscribers.wardsintelligence.com/analysis/world-vehicle-population-rose-46-2016
Electric cars must also offset the increased consumption from aviation and shipping.
How many electric cars have to be sold each year for total consumption to start to fall?
Hugo,
Oil supply will not be able to increase forever and eventually production is not sufficient to meet consumption at the current price level and the oil price is bid up from too many consumers chasing too few barrels produced. In this environment of continually rising oil prices, air fares increase, shipping costs by water rise and land shipping rates also rise. Fewer goods and people move by air and more of air transport moves to sea. Where possible goods are moved over land (if it is cheaper).
None of this happens overnight, the chart above is for tight oil only (about 9% of total World C+C output at its maximum). For the World output may decline more slowly. Much will depend on the price of oil relative to alternative sources of energy.
“In this environment of continually rising oil prices, air fares increase, shipping costs by water rise and land shipping rates also rise. ”
Dennis,
We’ve seen this before, a decennium ago. When it happens again, we have a lot EV’s on the road. However after a year or so with high oilprices there probably follows a severe economic recession again, resulting in collapse of oilprices. Many people who planned to buy an EV will then buy an ICE car instead, notwithstanding that EV’s will be more available and much cheaper and the ringing alarm bells of climate change. This when world oil production slowly starts to decline around 2023. We know from the models and individual country examples of ‘westexas’ (where is he ? IIRC he was insulted on theoildrum after which he never came back there) that when oil production starts to decline, oil exports start to decline at a much faster rate. If world oil production starts to decline about five years later (2028) then the increase in sales of EV’s will have reached the point of no return.
“Once peak fossil fuels becomes a reality and is fully accepted by the mainstream, ”
Fully accepted….not so easy. Peak coal and peak gas will be later than oil peaks, that is, the geological peak. If it works out as you describe, the decrease in demand for coal and gas could cause the peak. For world oil production also exists the possibility of a many years lasting undulating plateau. That would make the possibility for a smooth transition more likely. Otherwise I predict an energy transition with many ‘problems and pain’. In theoildrum time, it was Ron who repeatedly mentioned the possibility of oil exporting countries starting to hoard oil when oil production starts its irreversible decline. KSA is rapidly burning through its money reserves (most EOR projects are insanely expensive now) and I expect them to leave some not too difficult to recover oil in the ground for future generations and use for aeroplanes.
“…. and as costs for solar wind, EVs, and battery storage continue to fall there could be a rapid paradigm shift to less fossil fuel use.”
We have to differentiate between coal and gas use and oil use. I have to agree with what Hugo states:
“Electric cars must also offset the increased consumption from aviation and shipping.”
For example Boeing has received mega orders already for new airplanes, and not only for replacing old ones. When oil peaks, certainly the number of flights will go down, many (small) airline companies will go bankrupt. A global economic down-turn has its own risks and consequences.
Taken all the issues together, I expect the chance for the smooth transition as you picture not very high.
In theory it is rather easy, but ‘in the real world’ more variables come into play. Human behaviour (look in France now) and the global debt (much more than 10 years ago) and personal debt (many people having more (credit card) debts than 10 years ago) are three of them.
Han,
I have never actually said there will be a “smooth transition”, only that it is possible that one could occur.
There were many obstacles to landing a person on the moon and returning them safely to earth, a rational person in 1961 would have said that President Kennedy’s goal to land a person on the moon by 1969 could never be accomplished, there were too many things that could go wrong.
Note that many of my scenarios show a smooth curve to describe the future, this is simply because future shocks from wars, recessions, or natural disasters cannot be predicted in advance, nor can their magnitude be predicted.
My expectation is that the fact that oil has peaked will make people realize the possibility that coal and natural gas will also peak in the future more accepted by mainstream analysts even before they have occurred.
I also expect that EVs and other factors that may mitigate the peak in oil output will not be enough to avoid economic disruption as the energy transition occurs. The economic disruption is likely to lead to either a severe financial crisis at least as severe as the GFC or possibly to a severe depression like the Great Depression. I expect that to occur from 2030 to 2035.
One possible response is WW3, another possibility is the fear of nuclear holocaust might lead to a Global mobilization to speed up the energy transition, so rather than a World Wide effort to destroy as in 1939-1945, there would be a similar level of effort to dismantle the World fossil fuel industry and replace it with non-fossil fuel energy. Impossible to predict which road will be chosen, but I would choose to avoid WW3.
Hugo,
Using the LTO scenario a few comments up for the US LTO and assuming the rest of the World produces no tight oil and extra heavy oil output ends up being only 230 Gb (supposedly proved reserves of extra heavy oil are 387 Gb with cumulative output of about 16 Gb, implied URR=403 Gb.)
Extraction rate shown is for conventional oil only (excludes extra heavy oil and tight oil), total World C+C URR=3120 Gb, with LTO URR=90 Gb, extra heavy URR=230 Gb and conventional C+C URR=2800 Gb.
Peak for this scenario is about 85 Mb/d in 2024-2026 and output is between 84 and 85 Mb/d from 2020 to 2029. One possibility out of an infinite number of paths future oil output might take.
Dennis
The question is will enough people be buying electric vehicles in 2025 to avoid high oil prices?
If we assume oil production cannot increase after 2025 then demand must also peak. That would require at least 50 million electric vehicles sold each year by then. Once oil production starts to fall, the number of petrol engines must fall at the same rate.
If not oil prices will cripple the economy.
“If not oil prices will cripple the economy.”
Highly likely. Those who have electric vehicles will be lucky, and those countries/regions that have invested in electrified transport of cargo capability will have a big cost/survivability advantage.
The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.
https://www.resilience.org/stories/2018-07-19/electric-car-numbers-and-projections-to-2030/
EV30@30 requires all governments to put in place strong incentives to purchase EVs. Such as no sales tax, free parking, zero road tax.
EV30@30 may be enough to meet the Paris agreement be falls short of preventing global warming and comes nowhere near coping with Peak Oil
Even if you put climate goals aside, a strong shift to electrification will be a necessary adaptation to shortfalls in crude oil supply. And that won’t need any economic incentive, beyond what fuel price provides.
It will be obviously much cheaper miles than petrol by mid decade.
The two big variables other than oil supply, is cost of batteries, and the turnover rate of the current fleet of worldwide vehicles. If economies struggle, people will hold onto their current ICE vehicles much longer.
Here is an example of a vehicle available today. I’m getting combined 54 mpg with it. The plugin electricity (from PV roof panels) has provided 69% of miles driven thus far. Great ride , btw
https://www.edmunds.com/chrysler/pacifica-hybrid/
“The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.”
That is not optimistic. VW group wants to produce 25% BEVs in 2025, in addition there would be some PHEVs.
IMHO around 2025 the BEV share of new cars will lead to a decreasing demand for fuel, in 2030 more than 40% of the new cars will be BEVs.
However, vans and truck s are more interesting. 🙂
The most optimistic projection for EV sales is for EV to make up 30% of sales by 2030.
Ever heard of Tony Seba? his original projection in his 2014 book was for 100% of new US vehicle sales to be electric by 2030. Since the he has upped the ante, projecting 100% of US sales being electric by 2025. An important factor to note, in their May 2017 report, RethinkX, Rethinking Transportation 2020-2030 Seba and his coauthors, in Figure 9. Trends in vehicle sales, on page 39 of the report, project that by 2025 US annual sales will have fallen to less than a third of current levels, that is, roughly 5million units per year.
The most recent Monthly Plug-In EV Sales Scorecard over at insideevs.com has the tally for 2018 US plug-in sales at 361,307. If that figure were to grow exponentially, four doublings would take that figure to over 5.6 million. The growth of plug in sales in the US between 2017 and 2018 was roughly 80% so a quick spreadsheet, extrapolating those numbers, gets us to over 6.8 million unit sales by the end of 2023!
Moving over to the largest market for vehicles in the world, China, the web site 247wallst.com reports:
China Electric Vehicle Sales More Than Double in First Half of 2018
EV-volumes expects NEV sales to reach 1.1 million units in China this year. Of that total, 74% are forecast to be battery-electric vehicles (BEVs) like the Tesla Model S or the Nissan Leaf and the rest are expected to be plug-in hybrids (PHEVs) like the Chevy Volt. The total 2018 market for new cars in China is forecast at 26.3 million units.
Since June of 2017, the total number of plug-in models available in China has risen from 56 to 101. Of those, 70 are BEVs and 31 are PHEVs, and all are manufactured by 39 automakers. EV-volumes reported that 11 new carmakers joined the NEV fray over the past 12 months and that a shakeout is likely.
The Chinese government’s stated goal is to have 5 million NEVs on the country’s roads by the end of 2020. EV-volumes expects the number to reach about 2.35 million by the end of this year. At current growth rates, 5 million seems like a slam dunk.
Global brands covet the Chinese motor vehicle market and if they are to survive there, they will in all likelihood, have to step up their EV game considerably to comply with government regulations and compete with the local brands.
Still think 30% by 2030 is optimistic?
Hugo,
Prices rise gradually and people start buying more efficient vehicles as oil prices rise, these can be hybrids, plugin hybrids and EVs. As to higher oil prices crippling the economy, the price signal tells people the resource is scarce and causes behavior to change, people stop buying ICEVs and are willing to pay higher prices for EVs and plugin hybrids. Those companies offering compelling EVs and/or plugins do well, those that do not do poorly. The world economy did not do poorly in 2012 and will probably be fine up to an oil price of $160/b, due to the higher economic output in 2025 and the smaller proportion of oil as an energy source relative to fast growing wind, solar, and natural gas. The $160/b is the nominal Brent price, in 2017$ it would be about $127/b.
If plugin vehicle sales grow by 50% per year from 2018 to 2026, then about 46 million are sold by 2026. The 2017 to 2018 growth rate in world plugin sales was 63%. About 2 million were sold in 2018. Telsa sales increased by 282% from 2017 to 2018. Clearly that rate cannot be sustained, but 80% growth may be achievable for Tesla in 2019 and in 2020 the Model Y will ramp up production and take SUV sales in the luxury SUV market, then the Telsa pickup truck will be next in 2022.
Eventually the existing automakers will join the game and try to catch up with Tesla, which will have become synonymous with EV by 2023.
Dennis
Prices have gone from $60 to $147 in 14 months. This was at a time when global oil production increased by 700,000 barrels per day.
https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdfs/energy-economics/statistical-review/bp-stats-review-2018-oil.pdf
By the end of 2025 there will be another 500 million people on the planet. They will all want their food transported by plane, and lorry. They will require extra ships to transport goods around the world and many will join the 4 billion people who took a plane trip last year.
If oil production is flat in 2025, prices will surge. Sales of vehicles will be in the region of 110 million and at least 50 million would need to be electric to keep oil prices within a reasonable range $140 -$160.
India sold over 4 million cars last year and only 1,200 were electric.
https://auto.ndtv.com/news/electric-car-sales-in-india-fall-in-fy18-electric-two-wheelers-record-healthy-growth-1934323
I cannot see electric car sales hitting anywhere near 50% in 7 years and every country will have to hit these kind of level.
I’m not as confident as you that there will be an increase in world trade.
Globalism and the trade that goes with it might continue to fall out of favor.
Hugo,
No every nation does not have to reach 50%, just World total sales. If it does not occur then oil prices would be higher. Note that in the 1980s the percentage of World GDP spent on oil went as high as 7% which would be a nominal price in 2025 of about $280/b and about $222/b in 2017$.
So there may be some demand destruction and slowing of economic growth as oil prices rise, partially offset by the expanding EV, wind, solar, and HVDC industries that ramp up to replace fossil fuel.
“For demand to fall there has to be fewer petrol and diesel cars.”
Improved fuel efficiency can do a lot too, even if the number of ICE-vehicles is the same or increase. That is probably why most OECD countries have flat or declining oil consumption.
Jeff,
Most OECD nations no longer have increasing vehicle fleets, total vehicles registered have stabilized in most advanced economies. Fuel economy is also increasing in many nations leading to declining oil consumption, though higher amounts of air travel tends to offset the lower oil use in land transport.
If we have a global recession or depression, we won’t need as many planes flying around, ships going from country to country, or trucks transporting goods from one place to another.
And we don’t need EVs to replace all ICE vehicles if people don’t drive their ICE vehicles.
There are ways to decrease petroleum consumption. Some are less painful than others, but there are multiple ways to do it.
“There are ways to decrease petroleum consumption. Some are less painful than others, but there are multiple ways to do it.”
A very simple way to save 10% on fuel is to slow down something like 10 mph. Country wide- that can be a big deal. Nixon imposed a nation wide 55 mph limit in response to Saudi oil embargo, in 1974.
Hickory,
Great point. Unfortunately there is this urban myth that when the speedometer is at about 12 o clock on an analog gauge, that point is the maximum efficiency point for the vehicle. For many vehicles this is about 70 mph in the. US, about 110 km/hour.
Unfortunately this is not the case, maximum fuel efficiency for most ICEVs is about 50 miles per hour (80 km/h).
Perhaps oil company lobbyists have perpetuated the myth.
See
https://fueleconomy.gov/feg/driveHabits.jsp
For F150 4WD 5 Litre engine , slowing down from 80 mph to 65 mph increases fuel efficiency by 26.7%. Slowing down from 80 mph to 55 mph increases fuel efficiency by about 44%.
When fuel prices increase people may take advantage of these savings, higher tire pressure (35 psi rather than 32 psi ) also helps increase fuel economy. Slightly rougher ride but actually safer at high speed.
And now it is time to think in terms of miles/kwh, which as mentioned at another point in a thread is just as aerodynamically affected.
I have noticed that hills are hell on battery energy levels. I could never directly observe that effect on ICE vehicles, since the fuel guages weren’t digital.
[I live 800 ft up a ridge from town/services].
Perhaps charging stations should be positioned at the base of mountain passes.
Those figures are a bit hokey. NGL production is increasing, but NGL ain’t crude oil or stabilized condensate.
MSM seems to be catching on to the hype in shale, excerpts from an excellent article on shale on WSJ today:
Two-thirds of projections made by the fracking companies between 2014 and 2017 in America’s four hottest drilling regions appear to have been overly optimistic, according to the analysis of some 16,000 wells operated by 29 of the biggest producers in oil basins in Texas and North Dakota.
Collectively, the companies that made projections are on track to pump nearly 10% less oil and gas than they forecast for those areas, according to the analysis of data from Rystad Energy AS, an energy consulting firm. That is the equivalent of almost one billion barrels of oil and gas over 30 years, worth more than $30 billion at current prices. Some companies are off track by more than 50% in certain regions.
——
In September 2015, Pioneer Natural Resources, based in Irving, Texas, told investors that it expected wells in the Eagle Ford shale of South Texas to produce 1.3 million barrels of oil and gas apiece. Those wells now appear to be on a pace to produce about 482,000 barrels, 63% less than forecast, according to the Journal’s analysis.
An average of Pioneer’s 2015 forecasts for wells it had recently fracked in the Midland portion of the Permian basin suggested they would produce about 960,000 barrels of oil and gas each. Those wells are now on track to produce about 720,000 barrels, according to the Journal’s review, 25% below Pioneer’s projections.
In 2014, Parsley Energy, an Austin, Texas-based producer, told investors its average well in the Midland section of the Permian basin would produce 690,000 barrels, according to a review of Parsley’s quarterly earnings presentations. By 2015, its estimates averaged 1,050,000 barrels.
Parsley is on track to miss its Midland well forecasts for every year from 2014 to 2017 by an average of 25%, according to the Journal’s analysis.
——
One reason thousands of early shale wells aren’t meeting expectations is that many companies extrapolated how much they would produce from small clusters of prolific initial wells, according to reserves specialists. Some also excluded their worst-performing wells from the calculations, which is akin to eliminating strikeouts when projecting a baseball player’s batting average.
Full article here (behind a paywall):
https://www.wsj.com/articles/frackings-secret-problemoil-wells-arent-producing-as-much-as-forecast-11546450162
It’s not a science,” said Richard Robuck, the company’s treasurer. “It’s more of an art.”
WHAT THE F…k
He’s trying to minimize the incoming lawsuits…
If you knowingly overstate your projected cash flow of your business when applying for loans or soliciting investment, that’s called “fraud.”
There are supposed to be “competent” third party assessments to confirm reserves, but without much end of life history for LTO wells, models that are being continuously tweaked against real production data, and all that hyped “new technology” being applied it’s difficult to see how reliable these can be. If the law suits do start flying it will be interesting to se who else gets dragged in and how quickly the consultants pull out (although they may have enough arse coverage statements in their assessments anyway).
WSJ – E&P enterprise values have increased from 1.7 times proved reserves in 2007, to 2.8 times now
Graphic https://pbs.twimg.com/media/Dv7VBccWoAAZaOE.jpg
Don’t have the paywall, but you’ve given the gist. Investors were not happy with returns. Now, they are being fact checked, and that can look real messy. Borrowing is set to become restricted for many reasons. I really see some headwinds for future production increases. Based on first year production numbers supplied by Shallow Sand, production can’t increase without borrowing, except in some isolated areas. To get even close to covering declines from last years wells, they have to, at least, recover most of that capex cost in the first year of production. That is far from reality, right now. To increase, or later to even keep up, with production, they will have to borrow money. They can possibly make a profit in three years, but that is meaningless to providing for growth. Think it going to start looking nastier.
And to add to Ron’s answer, God would have to add, and make each well profitable the first year.
The miracle of US shale is about to have Toto pull back the curtain and reveal the real wizard.
Shale was, is, and will be just a supplemental source of oil supply. An investor could, if it was managed right, put x amount into the business, and in several years get a marginal return. In two to three years, a second well could be drilled to increase that income. That would be shale production growth. Not the imaginary growth numbers that are being thrown out.
The putrid 10Qs and 10ks for 2019 will add to the fire.
GuyM,
As long as debt can be serviced, borrowing is fine. Lots of businesses borrow when they start. Wells do not need to pay out in one year in the oil business. Mike Shellman aims for a 36 month payout and shallow sand uses a 60 month payout rule. Probably anything in that range would work. Some wells may payout in a years time, but that is a small percentage of the total, perhaps 10% or less.
Dennis.
As I have posted before, the wells we apply a 60 month payout to have a much lower decline rate than the shale wells, and are being drilled out of cash flow, not borrowed money.
For example, a well we drilled in 2006 just passed 10,000 BO and produced 370 BO in 2018. It cost about 1/100 the cost of a shale well ($70K +/-).
Maybe not a valid comparison, but. 100:1 ratio would be cumulative of 1 million BO and annual of 37,000 BO, which I think a rate you will not find often for any US shale well after 12.5 years on production.
Our LOE is higher per BO, so not entirely valid, but still maybe somewhat useful for comparison.
I note in the WSJ article PXD argued that the comparisons weren’t valid because they use a 50 year well life in calculating EUR v 30 year well life in the study.
I would think the PV of years 30-50 would be tiny on a 20,000’ hz well producing under 20 BOEPD! That PXD uses that argument seems to make them look a little foolish? Or am I being too tough on them?
Shallow, you know they can’t run a stripper well like you. Damn thing will be plugged at seven years. Dennis can calculate his damn curves to twenty to thirty years if he wants to. I can’t disprove it, because we are only in about year eight, and some have probably been plugged already, although I have no statistics on it. Although, I found one of EOGs that didn’t make it 7 years without trying too hard.
Mike was talking about borrowing on conventional production that has a much smaller decline rate. You drill one this year, and borrow the next year to drill another, you are increasing production. Not running on a treadmill.
Guym,
The wells are assumed to be shut in around 8 b/d, in the Eagle Ford that happens around year 16 for the average well with the hyperbolic I have fit. Absolutely true that we don’t have data for many years. Most of this started around 2008 in the North Dakota Bakken. So we only have about 11 years of data on the wells that started producing in Jan 2008.
For Permian Basin wells completed in 2016, the hyperbolic fit to the first 18 months of data is at 10 b/d at 19.7 years. I assume oil prices will be higher in the future so the well will probably continue to produce up to that point (EUR 377 kb at that point).
If we assume well shut in occurs at 15 b/d, then the well is shut in at 15.5 years and EUR is reduced to 359 kb.
In my scenarios I assume net revenue each month must be at least $15,000 in 2017$ for the well to continue producing, so when the well gets shut in depends on the price of oil and output.
Permian Basin 2016 well profile.
q(t)=q/(1+Dt) where t is time in months from first output and I use t=0.5,1.5, 2.5,… this is a special case where b=1 which fits this data pretty well.
Guym,
Note that Enno puts zeroes in for wells that have been plugged, so when I pull data from his site the averages include any wells that have been shut in. In my models and scenarios the wells are shut in based on economics, if the well is no longer profitable to produce it is shut in and output is zero.
Also note that the model is tested against past data, and the fit is very good, in many cases it underestimates actual output, rather than overestimating in fact a major criticism of many of my past scenarios is that they have usually been too conservative. That is output has usually been higher than I have predicted, with the exception of the oil price crash of 2015-2016, which I did not anticipate in 2012- 2014.
Hey Shallow sand,
Could you share output data from your well if you have it handy (monthly output or even yearly output would do), a hyperbolic could be fit to the data to make a comparison with tight oil wells?
None of these wells will continue to be profitable beyond 30 years (even the best wells).
What is the annual decline rate today for the well drilled in 2006?
What was the decline rate for the first year?
Note that when I do a discounted cash flow (DCF) analysis on tight oil wells (for say the average 2016 well completed in the Permian basin), the 60 month payout rule equates to an annual ROI of roughly 11%/year, and is pretty similar to what I would get for a DCF with an annual discount rate of 11%.
Whether the money is borrowed or not doesn’t really matter, the person who borrows has to pay some of their returns to the lender, if the price drops they may be in trouble and have to cut back on drilling or sell shares of stock to raise cash.
The “typical wells” presented in most of the investor presentations I have read are a joke, typically using BOE to hide the fact that they are so lousy, it’s surprising the energy analysts don’t call them on this, as the “barrel” natural gas is worth maybe one fifth or less of a barrel of crude. Often the typical well overstates the output of the average well by a factor of 2 or more.
One potential mistake I have made is to ignore the NGL that might be produced from the natural gas.
It seems that a lot of the natural gas in the Permian basin is being flared and there is not NGPL produced from gas that is flared.
Shallow sand,
If you are interested in sharing any data, I think you have my e-mail or use peakoilbarrel@gmail.com.
Hi Shallow Sand,
Don’t forget to adjust for inflation. That 70k well in 2006, if we assume 3% average annual inflation would be about 100k today. So about 90 times less expensive than your 100k well. Still true that not many (or maybe any) tight oil wells produce 900 kb in 12.5 years.
Is this an “average” well or one of the better wells you have drilled?
Wow,
1 b/d in the most recent year and 2.2 b/d over the life of the well.
At what point does it make sense to stop producing these wells? I would assume a down hole failure would mean shut in.
Very interesting, thanks. Did the well payout in 60 months? Maybe 3500 barrels over first 5 years?
Yeah, that seems like a lot of work. Probably close to daily monitoring and upkeep. Trucks once a month? Won’t catch EOG working that hard.
Yes, Dennis. You can borrow, if cash flow profit materializes. It hasn’t, and it probably won’t at anywhere near these prices, and Mike Shellman is the first to point that out. The E&Ps have been their own worst enemies in this fiasco. It’s flat going to be tougher to borrow the money. Investors and the media have every right to scream, where’s the beef.
Guym,
At $62/b at the wellhead (when any income from NGL is ignored) the 2016 Permian wells generate an ROI of 10% per year. Assuming the oil price remains at that level for the entire life of the well.
I agree that at present oil prices, the average well loses money. Whether money is borrowed or not is not really the question, in my view. The important thing is the profit or loss.
This is a significant paragraph to me. Given all the investments available, why throw money at oil-and-gas?
“Shale companies have attracted huge amounts of capital from Wall Street over the past decade. So far, investors have largely lost money. Since 2008, an index of U.S. oil-and-gas companies has fallen 43%, while the S&P 500 index has more than doubled in that time, including dividends. The 29 companies in the Journal’s analysis have spent $112 billion more in cash than they generated from operations in the last 10 years, according to data from FactSet, a financial- information firm.”
You guys insist on continuing to think money isn’t created from thin air by the Fed and actually means something in the context of a substance that feeds you food. If you have to have it, and you do have to have it, things will be done for you to get it. Borrowed money that was created from thin air . . . who cares if you can’t pay it back? You have to eat.
Consumption of oil is up. OPEC and Russia have reduced output. The price falls, because there is no meaning to anything created from thin air when applied to something that depends on physics.
You won’t know anything until you find yourself sitting in a line waiting for gasoline. You won’t see it coming. You won’t predict it. It will just happen someday.
Soon.
Some truth to that Watcher. Simplistic thinking in investors. If we aren’t making much money, the US won’t be making much money, so the price of oil must go lower. Not just simplistic, flat out stupid.
And the number of people who think oil supply is limited is fairly scarce in relation to the population as a whole. Probably less than the number of people who think chocolate milk comes from brown cows.
That would be less than 7%.
https://www.washingtonpost.com/news/wonk/wp/2017/06/15/seven-percent-of-americans-think-chocolate-milk-comes-from-brown-cows-and-thats-not-even-the-scary-part/?utm_term=.a74d6a28880a
And if you think I am being unreasonably hard on the average IQ, google who is now running the country, and consider almost 50% voted for him. Ok, I’ll give them somewhat of a break, as I didn’t like the alternative, either. They should allow write ins, so we can all vote.
And any moron can borrow 20 billion and service the debt for awhile. Maybe all of it, if they are lucky. Who cares, it’s only paper. Not a bad idea. I have an oil company, I can borrow 20 billion, stick half into BNO, and have a ball with the rest. If I lose, I can declare bankruptcy, and they can get my prepaid funeral expenses, but none of my gold bars in the Caymans. And, I am 99.9% certain that is less of a risk than any E&P I can think of.
White eggs come from white chickens. Brown eggs come from brown chickens.
That would be the justification for the opinion.
re: brown eggs from brown chickens…
Not true:
https://www.strombergschickens.com/category/brown-egg-layers
all kinds of colours there, including white chickens.
Not true other way as well, brown leghorns lay white eggs.
https://www.strombergschickens.com/product/Brown-Lehorn-Chicks/white-egg-layers
Robins aren’t blue, but their eggshells are.
I had chickens that laid green eggs.
And they were multicolored.
You eat those with ham. 🙂
It’s All About The Chicken
You might assume that white eggs are laid by white-feathered chickens and brown eggs by brown-feathered ones, and you would be somewhat correct with that assumption. The color of the chicken does play a role, but it is the color of the earlobe that determines the shell color. White or light-colored lobes indicate white eggs and chickens with red lobes produce brown eggs.
North Dakota natural gas flaring hits records, improvement expected in 2019
Amy Dalrymple
https://trib.com/business/energy/north-dakota-natural-gas-flaring-hits-records-improvement-expected-in/article_dba5f305-029c-5e90-b973-416db05d12e7.html
Natural gas flaring reached record volumes in North Dakota in 2018, enough in October to heat 4.25 million average U.S. homes.
The volume flared — 527 million cubic feet per day — could have met the natural gas needs for all of North Dakota and South Dakota, including industrial and commercial demand.
The state is expected to catch up on gas processing capacity by the end of 2019. But gas volumes are projected to nearly double from current levels, requiring even more long-term investments for 2020 and beyond.
Ron Ness, president of the North Dakota Petroleum Council, estimates the industry has invested a total of $18 billion for gas capture in the Bakken.
“We’re probably going to need at least another $10 billion or more in order to build the necessary infrastructure. It’s not going to all come right away,” Ness said. “Our productivity has just outpaced the expectations on gas so much.”
North Dakota produced 2.56 billion cubic feet per day of natural gas in October, the most recent figures available. Oil production reached 1.39 million barrels per day that month…By the end of 2019, North Dakota [is projected to] produce 2.9 billion cubic feet per day of natural gas and 1.49 million barrels of oil per day.
Hi Dennis,
this simulation by the IEA about US tight oil production is quite close to yours, am I right?
https://www.iea.org/newsroom/news/2019/january/could-tight-oil-go-global.html
Dean,
Yes that is very similar to an earlier simulation I had done.
I had to shrink the picture. My model is the red line, the blue crosses are EIA tight oil output data. My model ERR is 84 Gb through 2052. Peak is 9.7 Mb/d in 2025.
Interesting graph. Can I post the IEA plot overlaid with yours on my Twitter timeline?
Thanks.
Dean,
Feel free, with maybe a link to the comment (clicking on date stamp gets you that.) or some attribution in any case.
Any chart I post you are free to use.
Thanks for asking.
I will email you a chart with better resolution.
Should be in your e-mail.
Link to chart below, for anyone interested.
https://drive.google.com/file/d/1xpOnXaTmwC5FVdTPKPM86qraxSchb0VO/view?usp=sharing
Thanks!
Regards, Dean
Dean,
As you are aware, but others may not be, the IEA scenario for the US assumes 115 Gb of ERR for US tight oil, based on USGS estimates to date for the Bakken, Eagle Ford and Permian Basin the mean TRR estimate is 100 Gb for all 3 major plays combined, and perhaps a 15 Gb estimate for the rest of US tight oil plays is reasonable, which gets us to a TRR estimate of 115 Gb, the ERR will be close to the TRR only under a high oil price scenario. I used the AEO 2018 Brent oil price reference case for my scenario that arrives at an ERR of 84 Gb (about 73% of the IEA scenario ERR). The IEA may also have assumed the USGS estimates were too conservative, in general mainstream economists tend to believe every resource estimate is too low.
Nice graph. After world peak oil, or start of an undulating plateau, by most of you expected somewhere in the 2020’s, world oil production will be very difficult to predict, not to write more difficult than ever, for the decennia ahead. At that time ELM becomes one of the high risk factors.
Han,
I have never bought the Export Land Model, it always made some questionable assumptions about past trends continuing. Oil exporters will continue to export because they need the income and they may gradually reduce subsidies because as oil prices rise the subsidies become more costly (if you are exporting at $150/b, but only charging $25/b for oil used domestically you forgo $125/b for the subsidized oil). In addition natural gas and solar will substitute for oil for electricity production in oil exporting nations. Bottom line, World output is all that really matters, if exporting oil nations choose to hoard their oil, it simply drives up oil prices and speeds the World’s transition to other forms of energy, exporting nations would be best served by keeping prices low enough to slow the transition to battery electric vehicles and plugin hybrids.
Once that transition occurs, the oil left in the ground in oil exporting nations will be worth much less than it is today.
“I have never bought the Export Land Model, it always made some questionable assumptions about past trends continuing.”
Dennis,
Ok, but the many examples ‘ westexas’ published on theoildrum was about net oil exporting (small) countries that turned into net oil importing countries, very quick after Peakoil was reached. Of course this won’t happen with the big oil exporting countries in the world.
And what you wrote:
“In addition natural gas and solar will substitute for oil for electricity production in oil exporting nations. ”
will be the case. But the big solar plans KSA has since many years, until now didn’t materialize. For now they continue spending very much money on EOR projects and desalination units.
After the transition is almost done (at least two decades away), the oil left in the ground will be worth much less, yes indeed, but very valuable for aviation for example. In 2040 the big planes won’t fly on battery power yet, and maybe never, I think
Han,
It will depend on price and demand, air travel will become more efficient, there may be less of it and substitutes such as synthetic fuel or biofuels will compete with petroleum, I agree solar/battery powered planes that are practical are likely many decades away. Jet fuel use by commercial airlines was about 6 Mb/d in 2018, about 7.5% of total C+C output, this will be one of the last uses to go, but supply may be much larger than demand so that mostly conventional oil from low cost producers will be used. I didn’t mean to imply that petroleum reserves will be worthless, only that they will be worth less (price will be lower.) 🙂
Han,
The assumption that didn’t make sense was that as oil becomes scarce and expensive, the ELM assumes that the consumption patterns of oil exporting nations will not be affected.
In my opinion this very poor assumption makes the model’s predictions highly suspect. The nations that have gone from exporters to importers to date have done so in an environment where World oil output has been increasing and when oil prices have been high rather than hoarding oil exporters have maximized production to take advantage of high oil prices. This is likely to continue and it is better in my opinion to simply focus on World output of C+C, hoarding by exporters will simply drive prices up, speed up the transition and ultimately hurt the oil exporting nations as they will drive demand down in the long run more quickly (as it will speed up the transition to EVs, electric rail, and light rail, urban buses on overhead electric lines, etc) which will drive oil prices down and reduce the value of their product.
From an economic perspective the model fails.
>In 2040 the big planes won’t fly on battery power yet, and maybe never, I think
On the other hand, its questionable that anyone needs big planes built on the current design pattern. The A380 only seems to have one customer, Emirates, and the 747 is in decline. Neither is used on flights within North America, for example. Their only justification is the rules that two engine planes can’t fly transcontinental routes. The other justification is the hub and spoke model, but it is on its way out as well.
Airplane engines are unreliable, fiddly and expensive to maintain. That is why two engine planes are considered too dangerous for transcontinental flights. Electric engines are much cheaper to build and maintain, and will probably eliminate the last justification for jumbo jets with four engines.
If it came down to it, a modern civilization could do just fine with no air travel.
Sure some things would suffer, like organ transplantation and aerial bombing runs. Pesticide spraying, and Disney trips. Global warming conventions, and rodeo flings. Roses from Chile and Trumps overnighter to Mar Lago (at your expense).
But a civilization could find ways to carry on.
>Oil exporters will continue to export because they need the income
Or simply maintain subsidies and fail, as several exporters already have.
There is a lot of irrationality in the market, both on the supply and demand side. Considering that there is a realistic way to replace most oil consumption with EVs, I think that net import countries and regions are nuts not to switch away from oil. Only Norway and China seem to have figured this out so far.
International Energy Agency – Oil Market Report: 13 December 2018
Now available to non-subscribers – download from here
https://www.iea.org/oilmarketreport/omrpublic/currentreport/
Chart showing crude oil inventories of OECD countries without the USA compared to the USA https://pbs.twimg.com/media/Dv_8K59WsAEYd0z.jpg
OECD middle distillates and gasoline
https://pbs.twimg.com/media/Dv_8lNRWwAA_H5A.jpg
Total OECD inventories (crude oil + distillates)
https://pbs.twimg.com/media/Dv_8wbrW0AYRyp_.jpg
Total OECD Europe inventories (crude oil + distillates)
https://pbs.twimg.com/media/DwAQj9zUwAE3sv8.jpg
That OECD graph clearly shows that the glut has disappeared in Europe. Now the glut in US is mostly due to crude build. US production has increased from 8 MBD in January 2014 to most likely 12 MBD in December 2018 (due to very large adjustment factor in EIA report). The pipeline fills and new storage tank additions in US most likely contributed to the crude build. I counted over 110 MM barrels storage capacity added since 2011.
Yes I guess that storage levels in the USA are not likely to go down any more than they already have, as you say, due to pipeline fills and new storage to cover the increase in US exports etc
May 29, 2018 (Bloomberg) Gulf Coast – The region’s key shipping hubs — Corpus Christi, Houston and Beaumont in Texas, and St. James in Louisiana — plan to add at least 54 million barrels of storage capacity starting next year, a 25 percent increase, Fielden said in his report.
https://www.bloomberg.com/news/articles/2018-05-29/shale-s-surge-crashes-into-bottlenecks-from-pipelines-to-ports
OECD Americas: Canada, Chile, Mexico & United States
OECD Asia Oceania: Australia, Israel, Japan, Korea & New Zealand
When one looks at days of forward supply for the OECD, we are basically back at the 2011- 2014 level for OECD stocks, the “glut” only exists in the minds of those that believe tight oil breaks even at $40/b and it only does that for about 1% of the tight oil wells that have been drilled to date. This is pretty basic stuff, I wonder if any of these energy analysts have studied economics? Very strange.
This report is a long read, a one sentence summary = NEB Canada says that Western Canada’s oil supply is 365,000 barrels above the amount of oil flowing daily in existing pipelines.
December 2018 – Western Canadian Crude Oil Supply, Markets, and Pipeline Capacity
Figure C.5 illustrates NEB-estimated available capacity from the WCSB for crude oil pipelines between January 2010 and September 2018. Figure C.5 also illustrates the amount of crude oil available for export. Footnote 14 In September 2018, the amount of crude oil available for export exceeded available pipeline capacity by an estimated 202 000 b/d. The NEB also estimates this number would be 365 000 b/d if pipeline throughput, rather than available capacity, was used to represent the amount of crude oil that can move out of the basin by pipeline.
This excess oil supply is either held in storage, where available, or exported from the WCSB by other modes of transportation, such as rail.
http://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/rprt/2018wstrncndncrd/index-eng.html
Think oil prices are finally uncoupled from the Dow.
I saw that also. At least for today. I still remember 2008 when everything went down, including oil stocks that I hold to this day thinking the dividends will get me back to even.
They are likely to go down some more, before going up. The good news is they will probably be up to stay. Depending on what they are.
Never been any reason to presume oil price was stock price determinant.
Before SWFs.
https://oilprice.com/Energy/Energy-General/Bloodbath-In-Oil-Gas-Stocks-Could-Continue.html
Likely to go down. But what’s the alternative in the short run? Oh, I forgot, Trump can just tweet it out of the ground. It’s amazing, that not once, does anybody acknowledge the shale problem, is an oil price problem.
https://www.naturalgasintel.com/articles/116950-eps-ofs-firms-cite-uncertainty-as-activity-slows-dramatically-in-4q2018-says-dallas-fed
More info from Dallas Fed.
Thanks GuyM,
From the piece you linked above which seems to indicate capex spending will be flat to slightly down there was also this:
Asked to provide a specific price for WTI used for capital planning this year, executives said they expect prices to average $54/bbl, with responses ranging from $50 to $64.99. Only 9% thought prices would be below $50.
If their oil price expectation (the average) proves correct, there will not be a lot of money made in 2019 in the tight oil plays of Texas.
Oh, I think they will make some money, as oil prices will probably rise substantially. However, the production (rise?) the first half will be meager. And service companies will be behind the eight ball, again, for employees the second half.
GuyM,
I agree oil prices are likely to rise, but the oil executives surveyed (who likely know more than me) have an average expectation on $55/b. I guess you think they are incorrect, I agree with you. I think you expect about $75/b (or $80/b?) for WTI by the end of 2019, and something like that seems reasonable.
My analysis suggests that in the Permian basin at least $62/b is needed for breakeven at the wellhead (about $67/b for WTI assuming $5/b transport cost), so until oil prices rise to that point, money is not being made by completing a well.
Well, they probably will utilize their DUC inventory to maintain production as best they can. For 2019, DUC costs are basically dead costs for 2019 financials. I think that many, many DUCs are dead DUCs at anywhere near this price, but some can be revived, because they are only spending 60% of the capex. They are DUCs, because they basically know what they have after drilling.
There are many new DUCs in the Delaware. Many will probably remain DUCs. Outside of some core areas, I don’t think they found a bunch. Companies maintain they have not hit too many dry holes in shale, but a Dead DUC is about as dry as you can get.
Wily Coyote was going over the cliff before prices started going down. In effect, the Road Runner has just handed him an anvil to help his descent.
Besides the money to complete, there’s an incentive to keep what looks like a bad well as DUC. If it isn’t producing, one doesn’t need to include it in production average. If it’s a good well that’s profitable at $50, it’s not going to sit uncompleted for longer than physically necessary, no way. Even with logistical constraints the decline from producing wells is so high that good replacements just maintain numbers and cash flow. Hell in bad prices, the incentive to open up a moneymaker is going to be even higher because that debt is still going to need to be serviced.
I’m guessing there is going to ultimately prove to be a distinct pattern between long-term DUC and where the tiers boundaries in the Delaware actually are (as opposed to what EIA projects from average production).
Do you know how good a well will be just after drilling, but before fracking?
It should be goal for geologists to find out that even before drilling.
It is all a big illusion that oil is cheap like water in my opinion. To manipulate the market down will only make for more volatility in the future, and it is a good a bet as when the oil price fell to 30 dollars/b in 2016 that prices will eventually rise again from this level. It has do with that the tanking of oil prices is out of the usual cycle in the industry (low investments makes for less oil after 3+ years). I have started to bet on oil prices going up again even more for the fun of it (a few bets made too early I have to admit) and now I put some meaningful amount of money in it; to make it even more fun hopefully. The EIA weekly reports are a joke with zero movements for crude inventory for last 2 weeks. And an adjustment factor that nobody understands. Maybe the government shutdown has some influence after all. To build a wall against the tide water is an illustration of how successful it will be to keep the oil prices down with illusional data alone. And I stand by that a recession based on “fear” news alone is fake, but can ofcourse in the end become a self fulfilling prophecy. And the real fear is inflation based on too high oil prices. Extensive tariffs to hinder trade will also never help prosperity, but it remains to be seen if threats are made real or if the policy at some point will be revoked. The story is to be continued…
Does this seem right to people.
“During the period 2008-2017, OPEC Member Countries added 262.5 billion barrels to their total proven crude oil reserves, a significant addition compared to other crude oil producers.”
https://www.opec.org/opec_web/en/data_graphs/331.htm
Iron Mike,
Look at BP Statistical Review
https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html
especially the spreadsheet is useful, look at historical oil reserves and you will find that most of those reserves were from Venezuela adding Orinoco reserves (224 Gb) over the period from 2006 to 2017.
If those are excluded OPEC reserves increased by only 60 Gb over that period. Reserves can increase from both new discoveries and reserve growth (where new knowledge gained from exploration and production can lead to improved estimates of reserves over time). In theory estimates should decrease as often as they increase so the net should be zero. In practice, proved reserve estimates tend to be conservative and on balance tend to be revised up more than down so that typically we see reserve growth. The US saw about 60% reserve growth over the period from 1980 to 2005 (about 2% per year). For OPEC reserves (excluding Orinoco belt reserves) the rate of reserve growth from 1990 to 2017 was about 1% per year (about half the US rate from 1980 to 2005).
There is little transparency for OPEC reserves, one paper I read suggested World proved reserves as reported by BP (excluding oil sands) are pretty close to World 2P reserves (proved plus probable) in the IHS database as of 2012. I do not have access to IHS data.
Thanks Dennis for the clear up.
There has occasionally been mentioned on this site about potential ‘shale’ regions being developed in other parts of the world.
Yesterday (1/3/19), an article from E&P magazine titled ‘The Other Shales’ mentioned new developments in Abu Dhabi, the UK (Cuadrilla), and the Tuscaloosa Marine Shale.
The TMS description was particularly intriguing as it mentioned a well – the Lawson 25-13H in Amite county, Mississippi, originally drilled by Encana – as having produced over 300,000 bo first 24 months.
A small Australian company is planning on at least 6 new TMS wells with first flow from 2 of them this coming spring.
As there were about 60 TMS horizontal drilled during the ‘boom’ a few years ago – mostly unsuccessful – there is a body of knowledge for these new guys to work with.
This area is near the Louisiana Austin Chalk that had attracted the keen interest from Marathon, EOG, and COP.
With a 92% oil cut, estimated 8 billion barrels earl, and a recent history of attempted development, the TMS may well be lining up to be another formation that will economically produce hydrocarbons.
From what I understand, the Eagle Ford and the TMS are basically close to the same formation (just deeper), lying under the Austin Chalk. The Austin Chalk is not a source rock, and relies on natural fractures to trap oil from the TMS and the EF. There is a fault in eastern Louisiana that may wind up being similar to the Karnes fault, if they are lucky. Which could be good for both AC and TMS.
EOG was wild on the Austin Chalk for awhile, after they had such good wells out of the Karnes Fault area. They were tooting their horn that they unlocked the secret of drilling the Austin Chalk, and they could get the same results throughout the EF. But, they couldn’t. The “widow maker” struck again. They finally admitted that it was only effective where there were natural fractures. That did not surprise many who had been around awhile.
“As there were about 60 TMS horizontal drilled during the ‘boom’ a few years ago – mostly unsuccessful – there is a body of knowledge for these new guys to work with.”
Yes, apparently they learned how to drill unsuccessfully. Quite the body.
Watcher
As … peculiar … a slant your comment implies, any serious student of this unconventional industry might use the brief TMS development (or lack of) history to better understand what is unfolding in the Uinta, the Powder River, the Rogersville, possibly the Bowland, several Aussie hydrocarbon basins, the Dead Cow … pretty much anywhere with perhaps the Bakken being a highly instructive model as it was one of the earliest, data- rich operations.
In fact, Liberty Resources ambitious current EOR trial could well shed light on what may be possible, recovery wise, in ‘shale plays’ throughout the world.
The TMS operators struggled with optimal target depth, daunting geology, mud specs, expensive capital outlays, on and on.
So, yes, anyone with a scintilla of familiarity can recognize that what not to do can be every bit as crucial as knowing what to do … most especially in a high risk, capital intensive project.
OPEC 2019 quotas, (S&P Platts) Table
https://pbs.twimg.com/media/DvTGBe1UUAUqy7d.jpg
Nice graphic on Twitter
https://pbs.twimg.com/media/Dv8SUNbUUAAFoe6.jpg
Mexico will be lucky only to drop 40, though there are a couple of new developments due, same maybe for Oman, Algeria and Ecuador (and Malaysia?). Libya, Angola and Nigeria will ignore any numbers and you get what you get depending on how the new projects ramp up, decline kicks in and geopolitical issues manifest themselves.
There have been assertions that the number of DUCs has increased to around 4000 in Texas. Enough to maintain production growth even if drilling drops. Russell Hall says there are many less due to Texas reporting and the pending file at the RRC. I know some of you follow RRC more than I. Any thoughts about this?
https://www.mrt.com/business/oil/article/CO2-Conference-speaker-has-new-way-to-count-DUCs-13448075.php
Shaleprofile has DUC counts.
https://shaleprofile.com/2019/01/07/permian-update-through-september-2018/
In September Enno Peters has the Permian Basin DUC count at 1250 wells. In Feb 2018 the count was 2354 wells (which was the peak), the last time the DUC count in the Permian was lower than Sept 2018 (most recent date reported at shaleprofile) was Oct 2016.
I believe the most recent data points often get revised up later as the RRC data often is revised later, mostly higher.
For the Eagle Ford in Sept 2018 DUCs were 590 wells with a near term peak in Feb 2018 at 1030 wells and an all time peak at 1833 wells in Feb 2015.
https://shaleprofile.com/2019/01/03/eagle-ford-update-through-september-2018/
For North Dakota in Oct 2018, DUCs are 726 with near term peak of 880 in June 2018 and all time peak of 1070 in Nov 2014.
https://shaleprofile.com/2018/12/17/north-dakota-update-through-october-2018/
Thank You Dennis.
dclonghon,
You’re welcome!
New Data Suggests Shocking Shale Slowdown
New Data Suggests Shocking Shale Slowdown
By Nick Cunningham – Jan 06, 2019, 6:00 PM CST
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U.S. shale executives often boast of low breakeven prices, reassuring investors of their ability to operate at a high level even when oil prices fall. But new data suggests that the industry slowed dramatically in the fourth quarter of 2018 in response to the plunge in oil prices.
A survey from the Federal Reserve Bank of Dallas finds that shale activity slammed on the brakes in the fourth quarter. “The business activity index—the survey’s broadest measure of conditions facing Eleventh District energy firms—remained positive, but barely so, plunging from 43.3 in the third quarter to 2.3 in the fourth,” the Dallas Fed reported on January 3.
The 2.3 reading is only slightly positive – zero would mean that business activity from Texas energy firms was flat compared to the prior quarter. A negative reading would mean a contraction in activity.
The deceleration was true for multiple segments within oil and gas. For instance, the oil production index fell from 34.8 in the third quarter to 29.1 in the fourth. The natural gas production index to 24.8 in the fourth quarter, down from 35.5 in the prior quarter.
But even as production held up, drilling activity indicated a sharper slowdown was underway. The index for utilization of equipment by oilfield services firms dropped sharply in the fourth quarter, down from 43 points in the third quarter to just 1.6 in the fourth – falling to the point where there was almost no growth at all quarter-on-quarter.
There is a lot more in this article. Read it and comment if you wish. I would love to get other opinions on this.
Price hasn’t yet found a bottom yet in this current downturn. We will see lower before higher price. Slowdown should be expected in a low price environment. Price should consolidate for while before going lower and finding a bottom. Then and only then should we look for higher prices to come. It could be 3-4 months before price hits it’s final bottom in this current downturn. Price could easily stay below $50 all year long. People like to give their fundamental view on why oil market will tighten and we will get higher price in 2019. But the price charts tell us a different story and something they are missing in their forecast leads them to believe price will turn around quick. I think shale will hit a peak earlier on in 2019 and be well into decline by years end. Maybe when price recovers we get a new high in production. Maybe not.
I posted the same info from a different source, above, on Jan 4. You posted Texas production as only up 18k for Oct. in the first post. That is the first month in the quarter. Things deteriorated from then. Bakken price is in the toilet. Permian is not much better. I think that there is a high possibility that US production may decrease at these prices, rather than what is being reported by the EIA weeklies, we may have actual production 300k to 400k below what they are currently reporting by January. And the Permian will probably not increase much in 2019, because of pipeline constraints followed by shipping restraints, not counting all the other constraints. That’s going to happen no matter what prices are. So all this production increase EIA and IEA are counting is not going to happen. OPEC production decrease will happen. Demand better turn seriously negative to offset all this. But, I don’t think that would happen, so my bet is some serious inventory drops, and Trump will tweet.
I’m thinking it will take months of the EIA monthlies dropping, or even not increasing, before anyone pulls their head out. There are so many myths that are taken as fact, it’s going to take chiropatric assistance to pull it out. “Price bands, shale oil profitable at $50 per barrel, and the list goes on.
USA November, December and January numbers are going to miss the estimate curve by a large margin. LTO legacy decline doesn’t care about market price.
Dunno if that will cause a swift rebound in price when it materializes. It’s backward looking and the general economic slowdown is real.
The DPR numbers are not very accurate, through Nov 2018 the US tight oil output is as shown in chart below with an increase in Nov of 135 kb/d to 7035 kb/d. The rate of increase from Jan 2017 to Nov 2018 has been about 1400 kb/d per year. If prices remain at about $50/b, I expect the rate of increase to slow to 300 kb/d+/-300 kb/d.
If oil prices rise as I expect from May 2019 to Oct 2019 to about $70/b for WTI (monthly average price by Sept 2019), then the average increase in output (annual rate) from Nov 2018 to Nov 2019 is more likely to be 600 kb/d+/-300 Kb/d.
If oil prices fall to $40/b and remain there for a few months (Feb to July 2019), we may see flat to decreasing US tight oil output as the well completion rate may fall steeply in that case.
forgot chart
US tight oil output data from “tight oil production estimate by play” at page below, this is the only EIA tight oil data worth looking at in my opinion.
https://www.eia.gov/petroleum/data.php
Note I miscalculated trend From Jan 2017-Nov 2018 (it was Dec 2017- Nov 2018 for the estimate in previous comment), the correct slope of the trend line since Jan 2017 is a 1416 kb/d annual increase in tight oil output and the past 3 months output has been above the trend line.
For the past 18 months the linear trend for tight oil output has increased at an annual rate of 1559 kb/d, for that line recent output data (through Nov 2018) is right on trend.
I expect this slope will be 3 times lower(520 kb/d) from Dec 2018 to Dec 2019, if WTI oil prices remain at about $50+/-5/b over that period.
http://www.genesisny.net/Commodity/Oil/OSpecs.html
This is old, but very broad. Assay of different Venezuelan fields.
Lots heavy. Lots not.
It’s very old, some of those crudes are blends, and all of it has been depleted and produces a lot less than in the past. Today the largest stream is the 8 degrees API coming from the Faja, blended with nafta to approximately 16 degrees, some of it is fed to the upgraders, some is diluted with imported light crude and a bit of Venezuelan light.
I expect OPEC to report Venezuela production to be 1.1 mmbopd, at least half is at or below 10 degrees API. But January production should drop below 1 mmbopd.
https://www.zerohedge.com/news/2019-01-06/us-fracking-wells-are-producing-far-less-forecast
Meanwhile, the estimates given to investors were sometimes extrapolated from only the best performing wells. Other companies excluded their worst performing wells from the calculations. Texas A&M University professor John Lee, an expert on calculating oil and gas reserves stated: “There are a number of practices that are almost inevitably going to lead to overestimates.”
When Lee gave a presentation in Houston this past July, highlighting methods that could produce more accurate forecasts, one engineer jokingly stated that their companies weren’t using his methods “because [they] own [their company’s] stock”.
I’m getting notice of spam comment
retried, failed
Watcher,
Sorry.
If your comment doesn’t go through in future, try it without the link and just say go to zero hedge and give the title, some websites the spam filter doesn’t like. I don’t have enough expertise to customize the spam filter.
ya it was a surprise, I’m sure there have been other ZH links, but can work around.
Watcher,
For some reason this link works, not sure what the deal is
https://www.zerohedge.com/news/2019-01-07/new-data-suggests-shocking-shale-slowdown
maybe you should try one, I am curious.
January 7, 2019 (Rystad Energy) US fracking activity peaked in May/June
nationwide fracking activity was mostly stable from April 2018 to August 2018 at an average daily level of between 48 and 50 fracked wells. However, the fracking rate has slipped to a range of between 44 and 46 for the period of September to November 2018.
https://www.rystadenergy.com/newsevents/news/press-releases/frack-jobs-peaked-in-may/
Yeah, EF should be the last to decline. Their pipelines go mostly to MEH. That’s not a WTI discount, it’s a premium.
Question for Fernando: Do you have any idea if production ceased at the Priobskoye field due to the fire? thanks!
I don’t see how production could cease at Priobskoye from a plant fire, because the field straddles the Ob River, and there are separate plants serving as hubs for different areas. The last time I was there they had been drilling pipelines under the river to connect the newer north bank developments to the south bank, but the river is a formidable barrier, and the field is so large that a simple fire can’t take it out unless it takes place at Transneft pipeline stations.
Baker Hughes GE International Rig Count December
Total +34 to 1025
Split: Oil +23 to 806 & NatGas +10 to 189 & Misc +1
Split: Land +6 & Offshore +28
Offshore chart https://pbs.twimg.com/media/DwYwivGXQAET9dO.jpg
Just oil rigs
Brazil +2
Indonesia -5 https://pbs.twimg.com/media/DwYylgkXcAIDnwh.jpg
offshore China +5
Colombia +4
Norway +3
UK +4
Algeria +4
Nigeria +2
Saudi Arabia +2
Venezuela +2
Baker Hughes –> http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsintl
Venezuela’s new National Assembly President, 35 year old Juan Guaidó, was interviewed in Venevision yesterday, in what appeared to be a well rehearsed 12 minute question and answer session. The interviewer was a young woman, evidently very brave, who asked incendiary questions and was answered by Guaidó forming a duet with her. All the content emphasized that Maduro had to be taken out, plus messages of gratitude to the international community for supporting the Assembly against the dictatorship, as well as reminders to Russia and China that their investment was protected only if law and order prevailed.
What’s the significance? It’s been a long time since a guy like Guaidó could get on a TV station which reached poor areas (Venevision has rights to broadcast over the air, doesn’t require cable). This implies Guaidó has some sort of protection from heavy weights within the regime. Otherwise they would have cut power to the station and put everybody in jail.
We have two possible interpretations: 1. Guaidó is faking and is a regime mole. 2. Maduro has lost the support of a powerful faction within the ruling mafia. It’s even possible the Cubans decided to get rid of Maduro.
Today the National Assembly will meet to discuss the options they have to take Maduro out. If the transmission is seen via livestream (check VPI TV on YouTube) then something may be happening. If Venevision shows it then I think Maduro will be gone in a few days, and we may see very few deaths.
In any case, we are lobbying to have Trump take control of all Venezuela assets the US can reach, including all oil sold after January 9, 2019. There’s a subsidiary effort to have EU nations take all Venezuelan diplomats out unless they state they acknowledge being under National Assembly leadership.
Interesting stuff Fernando, though keep in mind the conspiracy theory speculation, makes it less credible. I know you don’t believe this, but Cuba does not rule the world. 🙂
They are not behind every nefarious political event in Latin America.
Dennis, you are quite disconnected from reality regarding the Castro dictatorship role in Venezuela. This is understandable because US leftists mostly feed off a leftist media with its own agenda. To those of us who lived there, had access to very high officials, and know what’s going on, the Cuban role is a fact nobody questions. If you speak Spanish I could try giving you videos and documents showing how it works.
Fernando,
I really don’t know but have a friend who is from Venezuela and still has family there, he doesn’t really mention the Cuba connection, or does not seem to be focused on it. No entiendo bien el espanol. So I do in fact get my news from the leftist media in the US (NY Times, Washington Post, NPR, etc.) Curious, do you also consider Fox News as a leftist outlet? 🙂
This comes from a US publication in English, Foreign Policy, an article called
“Cuba Is Making the Crisis in Venezuela Worse” from early 2018.
Quoting:
“Today, the penetration of Venezuela by thousands of Cuban operatives is complete. While it remains difficult to quantify the exact numbers, according to a Brookings Institution report, Cuban intelligence operatives and military advisors in Venezuela range from hundreds to thousands. Organization of American States Secretary General Luis Almagro puts the number at 15,000, likening them to “an occupation army from Cuba in Venezuela.””
I happen to know a bit more than what Almagro lets on he knows, although I assume he has been briefed, and can’t go public with everything. One comment Guaidó made yesterday during his interview directly addressed this point, when he discussed the meaning of puppet. If you want to see the interview look up
Entrevista Juan Guaidó por Venevision.
Google is rabidly left wing, but I’m sure the search will show you a link to the video uploaded yesterday.
Fernando,
You were doing ok up to “Google is rabidly left wing”. You just sound nutty when you make such comments.
“You just sound nutty when you make such comments.”
Atleast there is a high level of consistency to it.
Agreed. Now I need to block Fernando L as well as Fernando Leanme. Sigh 🙂
+1
The Canada WCS discount has narrowed
Bloomberg chart: https://pbs.twimg.com/media/DwYaTO1X4AA3KLC.jpg
Energy News,
Not only narrowed, but above the average level from 2015-2017 of about $13/b, currently the spread is only -$10.50/b, near the highs from 2015 to 2017.
There’s no shortage of fuel in Asia at the moment. There are 4 new refineries. And economic growth seems to have slowed due to higher rates and trade tariffs etc. Also fuel prices were too high last summer into October2018.
2019-01-08 (Reuters) Asia jetfuel cash differentials hit a record seasonal low on supply surge / weak demand
Reuters chart https://pbs.twimg.com/media/DwX7A9bUYAAVudG.jpg
New Refineries – JANUARY 7, 2019 (Reuters) Malaysian state oil company Petronas started trial runs at the crude distillation unit (CDU) for a joint-venture refinery with Saudi Aramco in Malaysia last week, two sources with knowledge of the matter said on Monday.
The move marks a major milestone for the $2.7 billion project known as RAPID – or Refinery and Petrochemical Integrated Development – located in Pengerang in Johor, at the southern tip of peninsular Malaysia. The test runs put the project on track for commercial operation in 2019.
The refinery is one of four new complexes in Asia that represent a combined processing capacity of nearly 1.3 million bpd scheduled to start up from late 2018 to 2019.
Another of the four complexes, a 400,000-bpd refinery, owned by Hengli Petrochemical in Dalian in northeast China, started trial runs in December.
https://www.reuters.com/article/us-malaysia-refinery-petronas-saudi-aram/petronas-saudi-rapid-refinery-begins-trials-on-crude-oil-unit-sources-idUSKCN1P10NO
A monthly chart for fuel inventories with the latest weekly number
https://www.rrc.state.tx.us/media/49753/ogdc1218.pdf
December’s completions and permits look pretty bleak for Texas.
GuyM,
For the Permian basin completions were 359 in Sept 2018 and 343 in Dec 2018.
The decreases may continue.
I assume a small part of that is seasonality since it’s December?
How quickly does this translate into measurable production numbers?
Some may be from budget expiration, but not due to weather, or giving a couple of days for Christmas. But, as Dennis says, and Kol says below, the trend is there.
Guym,
The trend in Permian completions has been down since Jan 2018, but through Nov 2018 output has continued to increase, there is some point that the output increases stop, my model suggests this point is output 280 completions per month (that is for Texas and New Mexico Permian Basin output). We may be getting close to that point, though one problem is trying to estimate the number of vertical oil well completions. I believe you also have suggested in the past the RRC drilling and completion reports may not be very accurate, though I might have not understood correctly.
I was surprised to read that the trend in completions had been down since January? Prices were rising through much of that period? Also, how then have they managed to bring down the inventory of DUCs down so much based on the information you posted earlier in this thread? What have been the monthly completion numbers in the Permian? Is there a source you could point me to that has those numbers. Thank you.
This is for all wells drilled in Permian Basin, see page below.
https://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/
Chart with Texas Permian Oil Completions in 2018, total oil completions (avg=464) and new drill completions(avg=379).
New drill completions may reflect the level of horizontal completions better, there are a lot of vertical wells that may be reworked from time to time, the horizontal wells are newer and probably not many are re-completed. Note that the new drill trend line has not decreased very much (decrease at a rate of 2 per year).
Big jump in October and steep decline after may just be statistical noise.
Also some of the new drill completions are probably vertical oil wells, but it is unclear how many. Note that shale profile has about 304 Permian horizontal oil completions in Texas for the first 6 months of 2018, for new drill completions the average for the first 6 months was 373, implying about 69 of the new drill completions were vertical oil wells for the first 6 months of 2018. If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2019.
Thank you so much for that information Dennis. Truly appreciated. A few “uninformed” comments and guesses follow:
1) It “appears” that the amount of DUCs might be reaching some type of equilibrium based on the convergence in the fourth quarter of total completions and new drill completions?
2) the third quarter saw completions down fairly dramatically, especially on the new drill side. Guessing holidays and oppressive heat has something to do with that?
3) if DUCs are indeed down to a normalized level, then total completions should be down in 2019, all things being equal unless there is a significant increase in new drills and new drill completions?
Again, thank you so much. You put out some great information here. Much appreciated.
Mario,
I think we have a different understanding of “new drill” completions. My understanding is the “new drill” means a well that has never been completed before (a virgin hole in the ground of sorts). The “not new drill” oil well completions is a recompletion of an already existing well so maybe a new frac job or something of that sort.
GuyM or anybody with actual oil field experience (I have none) can correct me.
Bottom line I don’t think this tells us anything about DUCs.
Go to shaleprofile.com and look at the “well status tab” and then choose DUCs only under “show well status”, also you can choose TX Permian under basin for Texas only. The DUCs were at 2052 in Jan 2018 and had fallen to 1668 by June 2018, the data beyond that at shale profile (July, August, and Sept) are likely to be revised. The reported DUC number for August is 1265. Since Jan 2018 the DUC trend has been down at annual rate of about 735 per year, from Jan 2015 to July 2016 the DUCs were pretty steady at about 950, so I would expect it to stabilize around there until oil prices rise.
If I am correct that the new drill completions are the more important metric and they continue at about 379 per month on average (with perhaps 310 of these being horizontal oil wells) then we might not see much of a change. I expect the level of completions will drop and output will rise much more slowly than it did in 2018 (maybe a 200 kb/d increase in Permian basin output over the next 12 months.) Much will depend on the price of oil.
I did warn you my comments and questions were uninformed. 😉
Again, a big thank you. I found that on shaleprofile.com and it is very helpful, especially seeing it in graphic form going back several years.
But if that data is correct and DUCs have declined significantly, I think it stands to reason that all things being equal, there should be fewer new completions next year unless the pace of drilling accelerates? That of course assumes that DUCs stay at the same level as at year end.
Thanks again.
The real answer as to RRC completion and permit report is, I’m not sure. Many times, companies will post a shut in as a completion. So, logically the actual completion posted, should be a re-completion. But, sometimes they just wait for the real completion, and don’t post the shut in as a completion. They did it to one of ours, which was over a year delay between drilling and completion.
I only view the reports as indicating trends. I don’t think it’s accuracy is close to argue with.
Guym,
Thanks, though I think that means your not sure what “new drill” on the RRC report means either. Do I have that right?
Do you interpret it the way I do, but in practice find that’s not quite right, or is it just a mystery (like much in the RRC world, at least from a Yankee perspective). 😉
Mario,
Yes I think that’s right, they may need to drill wells at a slightly higher rate, in order to maintain last years completion rate due to fewer DUCs.
One thing to keep in mind at shale profile is that the most recent 2 to 3 months usually get revised higher as more data comes in, so best to ignore the DUC data after June 2018 for the most recent (Sept 2018) Permian update.
Enno Peters’ data is the best around, but the underlying data from the Texas RRC is not perfect, so his data will also be a bit less than perfect.
Note that the Texas RRC is dealing with 350,000 to 400,000 oil wells so it is not surprising the data is not perfect, no data is.
By comparison in North Dakota they have about 15,000 oil wells about 1/25th the number in Texas.
If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2019.
Sorry, 2019 should have been 2018 in the sentence quoted above.
Sentence below is correct version:
If we assume this rate did not change for the second 6 months of 2018, that would imply an average of about 310 horizontal oil well completions per month in the Texas Permian basin in 2018.
EIA estimate of Permian Basin Output for Nov 2017 to Nov 2018 period, see “tight oil production estimates by play” at page below,
Permian is sum of Spraberry, Wolfcamp, and Bonespring plays.
https://www.eia.gov/petroleum/data.php#crude
Annual rate of increase for past 13 months about 994 kb/d for Permian tight oil, for next 12 months at $50/b for WTI, I would expect a lower rate of annual increase perhaps 300 kb/d+/-100 kb/d.
Rystad’s data said something similar. Small E&P’s already adjusting to pipeline constaints in Aug-Oct by reducing completions in Permian it seems, even before the steep fall in prices. This policy of holding oil prices down can not last very long. I will give it to Feb at most, when you got all the forces on the supply side in the world trying revert the direction.
Hi GuyM,
Hi-Crush, L.P. (HCLP), a fracking sand supplier, has stated today that its 4th quarter revenues will come in a third lower than originally estimated, and that it will have to suspended its distribution for the quarter in light of the dire economic situation. Sounds like the slow down might be bigger than anyone expected.
Doesn’t that seem at odds with what Dennis posted regarding completions just above? It seems there were tons of completions in the fourth quarter, especially in October which was extremely high. I’m a little perplexed.
Mario,
My data is specifically for the Texas Permian basin, that company may operate in a different tight oil play. Or my data my not be giving an accurate picture, there are many facets to this and the picture is always pretty fuzzy.
In short, we won’t know about December until late January when the estimates come out (and those are often revised later).
Financier, you have to remember that expectations of growth in the Permian defied any reality. Companies geared up for massive production growth, and one of the groups were for sand. Many new local sand producers popped up, taking away sales from other producers, and to the dismay of the poor protected lizard. I looked at some averages for completions in 2017, and could agree with Dennis, as long as 2018 completions were significantly over 2017, it could rise overall, even if current completions trended down. At some point in 2019, keeping it level, will eventually cause a production drop. I do not expect that, and I expect the Permian production to be flat, or at an amusing growth level to past projections by everyone, including EIA. Completions will probably have to pick up later, just to keep it level. The current rate of WTI price increase should mean shale overall production rate will probably be flat, and pick up as prices climb over $70 (if they do, I’m just betting, literally, they will). But, most of the increases will likely not come from the Permian until port expansion capabilities are vastly improved.
Hi GuyM,
Hi-Crush is a player in all the major oil and gas basins. Its largest frac-sand operation is in the Permian. Its sand sales dropped by a third as compared to the last quarter. It didn’t break out any numbers regarding sales in the various basins and maybe the Permian was an exception, but it is blaming its woes on the lack of completions.
Well, I know the Permian started using local sand as an alternative. A lot. It was cheaper, and not subject to rail delays, which was a huge problem the first of the year. Lack of completions would be a fact, and it sounds so much better than we got beat out by cheaper competitors.
Guym,
Can the Permian oil go to Cushing and then be distributed to East coast refineries, I think they can handle the lighter crude, it just seems crazy that nobody anticipated this problem.
EIA predicts only a 550 kb/d increase in USL48 onshore output from Oct 2018 to Oct 2019, which is about 3 times less than the US tight oil annual rate of increase over the Nov 2017 to Nov 2018 period (1545 kb/d).
The EIA’s Short Term Energy Outlook for US L48(excluding GOM) seems pretty reasonable at $50 to 55/b for WTI. I would say 450+/-100 kb/d over the Nov 2018 to Nov 2019 period for US tight oil output is a reasonable guess.
Early last year they opened up a pipeline from Cushing to Tennessee refineries, which took about 300k a day. That’s when Cushing started decreasing. Now, they opened up a new pipeline in Nov from Midland to Cushing with about the equivalent amount, so it’s back to increasing. I know some East Coast refineries are set up to handle higher API, but around 50 or above is probably too high for even those refineries.
What would work (when port capability is up) is more pipelines from Cushing to the Coast. Last I heard, the lighter oil was playing second fiddle to the heavier oil for the refineries through the current pipelines. I read one article that stated an interest in doing this, but have read none on concrete plans. If they do that, then MEH becomes more of the official standard than WTI Cushing.
As to production increases, anything is possible. I don’t think the sharpest tools in the shed are running these companies. Logically, though, why should it? Permian and Bakken are ripped by transportation problems. And, from your analysis, none are making money at $55 a barrel, so why should it increase at a $50 to $55 a barrel range?
GuyM,
It probably should not increase, but for some reason they complete wells anyway based on past experience. It may be that the companies will focus on their better prospects as EOG has done in the Eagle Ford, by “high grading” the average well EUR may increase and allow breakeven at $55/b. Also I have assumed a 10% ROI as “breakeven”, if a 0% ROI is defined as “breakeven”, or maybe 3% (return on 10 year Treasury), then breakeven price is lower. For the Permian, if we ignore natural gas and NGL sales and assume breakeven ROI is 3% and well cost is $9 million, then breakeven oil price is about $51.35, for the average 2017 Permian well (refinery gate price), the wellhead breakeven price is $47.35/b. Note that the bigger players have access to pipelines and probably get a higher price at the wellhead than smaller conventional producers. In any case I expect output will continue to increase at a slower rate (3 times more slowly than in 2018) in 2019 at 50-55 per barrel for WTI.
I have been wrong in the past and I am consistent. 🙂
test
https://www.zerohedge.com/news/2019-01-06/us-fracking-wells-are-producing-far-less-forecast
Okay, this worked. A repaste of the failure above failed again. Extracting the square brackets in the text also failed.
Something about those two paragraphs trigger the spam thing. That’s a heads up to others, if you get rejected look at the text below the link. The problem is somewhere there.
It’s an art, like finger painting or coloring books.
1959 — Cuban revolutionaries under Fidel Castro victorious. US goes into denial, as usual, in an attempt to protect “
MobUS interests.”http://dwardmac.pitzer.edu/Anarchist_Archives/bright/dolgoff/cubanrevolution/toc.html
Canada, Alberta AER, Total Crude Oil and Equivalent Production at 3,725 thousand barrels per day in November, up +62 kb/day month/month
Up +541 kb/day from the average during 2017 which was 3,184 kb/day
https://pbs.twimg.com/media/DwaY1vkXgAAkoU6.jpg
Upgraded up +134 kb/day month/month
Non-upgraded down -63 kb/day month/month
Crude Oil + Condensate -9 kb/day month/month
https://pbs.twimg.com/media/DwaZMNnWoAAUY_9.jpg
Canada, Alberta AER, crude oil closing stocks at 74,081 thousand barrels in November.
Down -1,547 thousand barrels month/month
November 2017 was at 64,191 thousand barrels
https://pbs.twimg.com/media/DwaZ0y-XcAA1hlQ.jpg
CNBC headline that BP “discovered” 1 billion barrels in Thunderhorse field. Attribute it to advanced seismic.
2019-01-09 (Argus) Venezuela’s state-owned PdV has checked a decline in crude production mainly thanks to repairs to two heavy-crude upgraders run by its joint ventures with foreign partners, according to PdV officials, Argus estimates and internal company data.
Output is holding at around 1.1mn b/d for now, but it is unlikely to be sustained without substantial new investment, PdV mid-level managers say.
The upgraders associated with the PetroMonagas and PetroPiar joint ventures, both led by PdV with majority stakes, have undergone key repairs in recent months, stabilizing operations and freeing up more production from the Orinoco heavy oil belt.
https://www.argusmedia.com/en/news/1823842-venezuela-checks-oil-production-decline-for-now
2019-01-09 (Reuters) – Curacao’s 335,000-barrel-per-day (bpd) Isla refinery has resumed work, management of the government-owned facility said on Tuesday, after eight months of paralysis caused by a dispute between its operator, Venezuela’s PDVSA, and U.S. producer ConocoPhillips.
https://www.reuters.com/article/us-refinery-operations-pdvsa-curacao/curacao-oil-refinery-resumes-work-after-eight-month-stoppage-idUSKCN1P22CI
True, but it is no longer to be PVDSA’s refinery. Motiva is the most likely bet.
https://oilprice.com/Energy/Crude-Oil/US-Army-Joins-Race-To-Expand-US-Oil-Exports.html
Even with US government help, port expansion won’t happen until 2020.
I would think in the mean time they could use smaller ships to export the oil.
They are doing that now. At about max.
Today’s RBN Energy has a description of exactly that.
LOOP just finished upgrading and loaded 3 2 million barrel VLCCs in 7 days in December.
The port in Corpus is loading VLCCs up to 1.2 million barrels and reverse lightening the balance offshore.
A third port in Texas City is starting to do the partial loading/reverse lightening also.
According to RBN, all the ships are going to Rotterdam.
I guess that the EIA might be understating US oil exports due to the Gov shutdown?
The EIA reported weekly crude oil exports at 2065 kb/day
Whereas S&P-Platts tanker trackers reported 2533 kb/day
(RBN Energy) Standing On The Shore – Suddenly, A Slew Of Gulf Coast Crude Loadings Onto VLCCs
Tuesday, January 8th – Published by: Laura Blewitt
https://rbnenergy.com/standing-on-the-shore-suddenly-a-slew-of-gulf-coast-crude-loadings-onto-vlccs
Looks like a normal for exports is around 2.5 million a day from histories. The week loop loaded 3 VLCCs, we went up to over 3 million per day. So, there is nothing in the history that indicates we would be able to ship 2.5 million more a day, if the pipelines come online before shipping capacity increased. Loop can’t do that every week, yet. It looks like to handle the capacity of the pipelines, we would need to be able to comfortably ship 5 million barrels a day.
Then, we get back to the original question, to whether the Permian will increase another 2.5 mbpd at a $50 to $55 price?
Nothing in these projections are realistic. Yeah, if prices spiked, you bet it would eventually happen. My guess it will, but, at any price, not before 2020.
GuyM,
As I have said before, the EIA’s short term energy outlook has US L48 excluding Gulf of Mexico increasing only by 550 kb/d from Oct 2018 to Oct 2019, if we assume Permian Basin output is about 2/3 of this (as in 2018), then we would see about a 370 kb/d increase in Permian basin output in 2019. Somewhere in that range seems reasonable say 250 to 450 kb/d, probably toward the low end at current WTI (about $51/b).
There are higher estimates for US tight oil (OPEC and IEA and others) that seem to not take account of pipeline and port constraints in the Permian basin.
‘REALISTIC’ NEW MODEL POINTS THE WAY TO MORE EFFICIENT AND PROFITABLE FRACKING
“This work offers improved predictive capability that enables better control of production while reducing the environmental footprint by using less fracturing fluid,” said Hari Viswanathan, computational geoscientist at Los Alamos National Laboratory. “It should make it possible to optimize various parameters such as pumping rates and cycles and changes of fracturing fluid properties such as viscosity. This could lead to a greater percentage of gas extraction from the deep shale strata, which currently stands at about 5 percent and rarely exceeds 15 percent.”
Read more at: https://phys.org/news/2019-01-realistic-efficient-profitable-fracking.html#jCp
Only 5-15% of gas is extracted? 15% of what? Of the gas in the volume of rock within some X distance of the bore?
TransCanada is taking “Canada” out of its name, and will call itself TC Energy.
New Leaf with over 220 mile range is coming this spring. Sounds like a perfect partner to my Versa. About four times the price of the Versa, though.
The Tesla Model 3 is pretty sweet, test drive one before buying the Leaf, by summer the 35k version of the Model 3 will be out, (about the same range as the Leaf, but probably a nicer car). Or you can get the mid-range model 3 at 44k with a range of 260 miles, with a 3750 rebate until June 30 so net before sales tax (do you have that in Texas) is about 40k. The leaf supposedly will be about 42k and would be about 34.5k after Federal tax rebate, so about 5.5k less than the M3 but 35 miles less range (which may not be important, but the low end M3 with about 210 miles of range will be 31k after rebate, if it is available before July 1 (not clear when Tesla plans to release that version). In any case, the test drive is free, maybe you will like the Leaf better or prefer Japanese to US made vehicles.
The Tesla is the first US made car I have owned since 1982 (I had a 68 Pontiac when I was young).
By far the nicest car I have driven, I have mostly owned Toyotas and Hondas since 1984.
Main problem with the Leaf is long distance driving. It has only passive battery cooling – so after a longer drive on the highway it can’t supercharge at full rates due to a hot battery. Especially not when doing this a second time.
Here are Teslas much better.
If you’re only driving locally, this shouldn’t be a problem.
A quick look at US holiday inventory builds for products (2010 to 2018). The sum of the last week of December plus the first week of January for 7 products.
We had the $100 oil years and then the glut years. I guess this year could revised in the monthly figures due to the Gov shutdown? It looks like holiday inventory builds are in an uptrend but it might be partly coincidence. If US production & exports increase, we could see builds increase in the off-peak season but draws would increase during peak demand?
https://pbs.twimg.com/media/DwipzDjWoAA8t62.jpg
Saxo Bank chart summary
https://pbs.twimg.com/media/DwilCbcWkAAvPel.jpg
2019-01-10 (S&P Platts) The Norwegian Petroleum Directorate – In its annual industry report, the NPD forecast a further 4.7% drop in oil production this year, including condensate and natural gas liquids, after a greater-than-expected 6.3% fall last year. Last year’s decline had been greater than expected due to the complexity of some more recently launched fields and a shortfall in drilling activity, it added.
The NPD reiterated expectations that overall liquids output will return above 2 million b/d in 2020 thanks particularly to the start of production at the Johan Sverdrup field, expected toward the end of this year.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/011019-norway-resource-shortfall-to-curtail-oil-gas-production-improvement-regulator
New Open threads are up.
http://peakoilbarrel.com/open-thread-petroleum-january-10-2019/
http://peakoilbarrel.com/open-thread-non-petroleum-january-10-2019/