The EIA recently updated its International Petroleum statistics. World Crude plus Condensate (C+C) output was 80,577 kb/d in Feb 2017 an increase of 72 kb/d from the previous month, this was 1695 kb/d below the monthly peak output of 82,273 kb/d in November 2016. The most recent 12 month average (centered on August/September 2016) was 80,501 kb/d, 3 kb/d less than the previous most recent 12 month’s output. The 12 month centered average peak output was 80,574 kb/d in June/July 2016 as previously predicted by Ron Patterson and currently the 12 month average output is 73 kb/d below the peak.
Conventional crude plus condensate is defined in several different ways. The United States Geological Survey (USGS) uses the categories “conventional” and “continuous” oil resources, where continuous resources includes light tight oil (LTO), Canadian oil sands, and Venezuela’s Orinoco belt. Conventional C+C output has been relatively steady from 2005 to 2014, with an increase of 1.7 Mb/d by 2016 due to increasing OPEC output over that period (a 2 Mb/d increase). Over the earlier 2005-2014 period OPEC output increased by about 1 Mb/d while conventional non-OPEC output decreased.
Using the USGS definition of conventional oil we can use Hubbert Linearization to estimate World Conventional URR.
The vertical axis is annual conventional C+C production divided by cumulative conventional C+C production and the horizontal axis is cumulative conventional C+C output.
The noticeable kink in the data in 1993 (725 Gb cumulative) leads to the choice of 1991-2016 for the data used for the red trend line with a URR of 2400 Gb. The blue line uses all data from 1983 to 2016 and suggests a lower URR of 2200 Gb. Over time the Hubbert Linearization (HL) estimate tends to increase, for example an HL on the data from 1983 to 1995 points to a URR of 1650 Gb and over the years this has gradually increased to 2200 Gb or even 2400 Gb. The tendency of this method to underestimate the URR is a major shortcoming, though it might point to a lower bound for the URR.
In 2000, the USGS estimated a conventional World URR of 3000 Gb, my guess is about 2700 Gb due to a combination of discoveries and reserve growth, but only if progress in developing alternatives to petroleum for transportation is slow. Rapid progress in reducing our dependence on liquid petroleum would result in lower oil prices and potentially a low conventional URR of 2400 Gb or even 2200 Gb in the most optimistic scenarios for rapid technological change.
EIA data just came out – February revised up to 1,749; March was 1,763 kbpd (also might be revised) – a new high, but might be looking at the peak there or maybe April as most start-ups for 2016 and 2017 should be close to plateau now.
Hi George,
Thanks. That is GOM output (probably obvious to everyone). What was it revised up from? I don’t have the old data saved.
The revision was from 1734 to 1749. As far as I can tell, BSEE hasn’t updated their GOM production since January. EIA is updated through March. Not sure why – but BSEE updated the look of their website. BSEE and EIA numbers have usually been slightly different, with the EIA number usually slightly higher (it’s in the 3rd and 4th digits, so less than a %).
BSEE just updated their database with GOM production through March, 2017.
As in the past, their production numbers are slightly lower than EIA numbers.
For the last 4 months, BSEE’s GOM production numbers compared to EIA are (in KBOPD):
—————–BSEE EIA
Dec-2016 – 1723 – 1730
Jan-2017 – 1753 – 1758
Feb-2017 – 1730 – 1749
Mar-2017- 1714 – 1763
The biggest difference is in March – ~50,000 bopd.
The BSEE data suggests a peak in January, and minor decline since then.
The EIA data suggests rising to flat production through March – maybe seeing a plateau?
I believe the BSEE data more. Don’t have a good reason, other than I believe BSEE data is closer to the source
Thanks SoLaGeo,
I imagine you have followed the data closely, does the BSEE (BOEM) data get revised up over time or does the EIA data get revised downward to match?
Dennis,
I don’t follow it that closely because the differences are so small. BSEE does revise previous data, but I’ve never checked to see if they revise it to match EIA data. I suspect they revise it in response to prior period adjustments made by operators.
As George noted above, EIA also revises their data.
Thx both sets of data get revised. I was wondering if BSEE data is incomplete.
The API reported a whopping 8.67 million barrel decline in U.S. crude stocks last week. Trade estimates for the EIA number tomorrow are for just a 3 million barrel drop in stocks.
https://seekingalpha.com/news/3270837-oil-bounces-bullish-storage-report
BP has come out with its 2017 energy outlook
https://www.bp.com/content/dam/bp/pdf/energy-economics/energy-outlook-2017/bp-energy-outlook-2017.pdf
The Australian public broadcaster ABC TV immediately used it to misinform their audience. Here is my analysis:
29/5/2017
Australian ABC TV selectively quotes BP to match its own “no worries” narrative
http://crudeoilpeak.info/australian-abc-tv-selectively-quotes-bp-to-match-its-own-no-worries-narrative
Thanks for the link Matt. From your article below, and my immediate thoughts:
China’s transition from a country with a huge industrial base where energy intensity was high to a services and consumer oriented economy with a much lower energy requirement
http://www.abc.net.au/news/2017-05-26/oil-prices-slide-despite-extension-of-production/8564862?section=business
My guess is that the industrial base will not just disappear into thin air, especially so if China is to transition to a consumer oriented economy, it will go somewhere else/emerge somewhere else (Vietnam, Laos, Myanmar, Philippines, Indonesia, Bangladesh, Sri Lanka, Cambodia, East Africa). Post-China 16 I’ve heard these countries called. The energy consumption profiles of these P-C 16 nations will be interesting to see. My guess is much coal is still yet to be burnt.
https://www.platts.com/latest-news/coal/singapore/vietnam-sees-domestic-coal-demand-surging-nearly-26401582
Link below has data on coal use. I’ve looked up post-China 16 countries on it and find it interesting to consider how they might choose to increase energy production.
http://mazamascience.com/OilExport/
Coal’s dead, except for steelmaking. It’s simply not cost-effective. Any country building new manufacturing will use solar, wind, hydro, and batteries.
Rapid progress in reducing our dependence on liquid petroleum
Might look like this:
https://www.bloomberg.com/graphics/2017-oil-projections/?cmpid=BBD053117_BIZ&utm_medium=email&utm_source=newsletter&utm_term=170531&utm_campaign=bloombergdaily
Thanks Nick,
Possibly a bit optimistic, time will tell.
From the Bloomberg piece linked by Nick above.
Below is a scenario for C+C+NGL in barrels of oil equivalent (NGL barrels adjusted so energy contained is approximately the same as a barrel of crude). The 3600 Gb URR from 1870-2200 includes 2700 Gb of conventional crude plus condensate (C+C), 350 Gb of natural gas liquids (NGL), and 550 Gb of “continuous oil resources” (light tight oil and extra heavy oil with API gravity less than 10 degrees). Chart scaled to match the Bloomberg chart above.
EIA: US Gasoline Demand Falls For Third Consecutive Month
http://www.rigzone.com/news/article.asp?a_id=150388
As Trump considers Paris withdrawal, oil and gas industry divided – Houston Chronicle: “The debate has largely pitted major oil companies that do business around the world against smaller firms already struggling with low oil and gas prices and increased regulations – a split so sharp that the American Petroleum Institute, which represents a wide range of oil and gas companies, has not taken a position on the pact.
‘It means a lot to BP and Exxon and Shell, but the mid-majors, large independents that aren’t involved internationally, don’t care a whole lot about Paris,’ said Charles McConnell, a former top official in the Energy Department during the Obama administration and now executive director of Rice University’s Energy and Environment Initiative. ‘Their concern is, what does it do to the U.S., and do people pay more or less for gasoline?'”
I think the split is more between companies with increasing ratio of gas to oil reserves (e.g. especially BP) and those only in oil.
That’s what I would assume, too.
Dont the monthly data (and also texas direct data) indicate that the increase in us production is much slower than weekpy eia data indicate?
There’s a seasonal decline this time of year as well, and US exports seem to be increasing – that could be some kind of arbitrage impact, but it does take a long time for the oil industry to do anything new so it might just be that they’ve just sorted out all the contracts and logistics needed to use the freedom after the export ban was lifted.
Flotilla of U.S. Crude Heads to Asia as OPEC Weighs Extending Cuts
http://www.rigzone.com/news/oil_gas/a/150211/Flotilla_of_US_Crude_Heads_to_Asia_as_OPEC_Weighs_Extending_Cuts
I don’t know what I was replying to there, but not the comment above I think – sorry about that. I was commenting on the drop in US stocks from API, which will probably be confirmed by TWIP today.
Hi Daniel,
The difference in March (between 4 week average and monthly data) is only about 50 kb/d, but you are correct that the weekly data (or 4 week average) is higher. My chart in the post uses the monthly data and we do not have weekly data fro the GOM or Texas, only monthly data.
Generally the weekly data is not very good and it is not revised, the monthly data is corrected over time as the data becomes more complete over time (this affects Texas data quite a bit, some other states such as North Dakota have pretty complete data when initially reported, maybe better data handling in those places).
I pay more attention to the Texas RRC statistics, than estimates. Any estimates. The initial March 2017 production reported by RRC is 500,000 lower per month than reported initially as of March 2016. Completions per month are not rising much. April completions were about 100 wells less than March. Completions will eventually increase, but not at the rate the EIA and most others are projecting. My guess, and the guess by some other analysts is that the rig count will begin dropping again within the next two months. The current price of oil will not support the level of activity. If WTI goes up to over 60, you will see a larger production increase. At 50, my guess the drop in GOM as reported by George, below, will mostly offset increases in the Permian.
Hi Guym,
All data is an estimate. The RRC statistics have been getting a little better over time, but the EIA data is much closer to what the final numbers will be than the initial report by the RRC. The completions are not a very good gauge by themselves because the type of completion is important, a horizontal well with a 10,000 foot lateral will produce much more oil (if completed in 2017 in the Permian basin) than a vertical well.
Based on data from Enno Peters, the recent wells completed are much more productive than those completed a year ago, so it requires fewer wells completed to match increases from 12 months ago. Chart below was pulled from web page at link below (shaleprofile.com)
https://shaleprofile.com/index.php/2017/05/04/permian-update-through-january-2017/
EIA reports March 2016 about 3 million barrels a mont more than what the reported numbers from RRC have currently. It’s been a year since then, so I doubt it is going to have much more reported. EIA estimates are more than dubious. I have no doubt Texas production will increase some. EIA is simply unrealistic.
Hi Guym,
For March 2016 the EIA reports 102.151 million barrels of Texas C+C output, the RRC reports 100.190 million barrels a difference of 1.96 million barrels (or 63 kb/d).
I have the data from May 2016 for the RRC and at that time (about one year ago) the RRC data for March 2015 was 109.578 million barrels, in May 2017 the RRC reports March 2015 output as 111.725 million barrels, a difference of 2.147 million barrels.
In percentage terms the current EIA estimate is 1.96% higher than the RRC estimate for March 2016, the current RRC estimate for March 2015 is 1.96% higher than the RRC estimate from one year ago.
You should save the RRC estimate from this May on your computer for March 2016 and then check in a year (May 2018) and see if the RRC estimate has increased by about 2%. It takes about 24 months before almost all the RRC output data is correct in the RRC system.
I have said it before and will say it again, the EIA data is not perfect, just much better than what is reported at the RRC for the most recent 24 months.
They change it constantly. March 2016 was 103 just two days ago. Geez! So EIA is always correct because the numbers and estimates are so malleable. The government is right because they said so. The king is naked. If you want to go along with the king, then no one is going to say you are wrong.
Hi Guym,
The RRC numbers also change from one month to the next, but you don’t complain about that. Why the inconsistency?
As I said, the EIA data is not perfect, just better than the RRC data especially for the most recent 18 months, from months 19 to 24 (back from the most recently reported month) RRC will be a little low and EIA is often a little high (about 1.5% low/high) and the average of the two ends up being close to actual output, prior to that months 25 and earlier, the two data sets match closely as the EIA just uses the RRC data.
You seem to imply there is a conspiracy, I disagree. The EIA just estimates as best they can based on the data they collect from surveys of large oil producers (that produce about 90% of the total). This is necessary due to the incomplete nature of the RRC data set. The estimates are likely to be imperfect.
It also occurs to me that the EIA might base their data in the changes in the RRC data, the RRC data comes out first and then a few weeks later the EIA data is updated, perhaps it is not a coincidence that the percentages are exactly the same in the example I gave. I chose those dates based on your comment. Note also that we are talking about 0.9/103=0.87%, you seem to be expecting perfection, the government (both Federal and Texas) is far from perfect.
You said I implied a conspirancy. You can disagree with thin air. Nobody has to take this BS, if they don’t post. The only point I was trying to make is: the amount initially reported out of the ground for March 2017 was about 500k less per month than they reported in March 2016. Even at revised figures that represents about 78k more than the most recent reporting by EIA for Texas in March 2016. It is not realistic. The monthly figures for EIA using this inflated number is almost 9.1 million for March 2017. So, since March, the EIA weekly estimates are at 9.342 million barrels in two months with less completed wells reported by RRC in April. The public was not involved with a “conspiracy” in the story of the Emperor’s new clothes. They were just too frightened of public opinion if they said: “what clothes?”.
Hi Guym,
I have consistently said the weekly data is not very good, often it is off by 200 kb/d or more. The monthly data is better, but not perfect. If the current EIA estimate for March 2017 is incorrect, it is likely to be off by no more than 1.5%.
I don’t think anybody at the EIA has an agenda on this data, they make the best estimates they can, and the monthly estimates are pretty good in my opinion.
US weekly vs monthly oil production data
source: U.S. shale booms and depresses oil prices again: Kemp. By John Kemp. Jun 1, 2017.
http://www.reuters.com/article/us-usa-shale-column-idUSKBN18S5OA
Again, Dennis. “Agendas” and “conspiracies” indicate contrived and nefarious intentions. Nowhere, have I implied that. Incorrect models indicate some level of ignorance. Ignorance is not usually intentional. You think the weekly is about 200k over reality. I think 300k, but let’s use your figure. That means that they are over estimated by about 6,200,000 per month for Texas. Or, about 6%. That’s not slightly over.
“You think the weekly is about 200k over reality. I think 300k, but let’s use your figure. That means that they are over estimated by about 6,200,000 per month for Texas. Or, about 6%. That’s not slightly over.”
There is no weekly estimates for individual states, including Texas. The EIA has monthly estimates only for March, weekly estimates up to end-May
Just noticed the EIA short term outlook states that US production averaged 9.1 million for April 2017. Can’t argue much with that. The weekly states 9.345 million as the end of May. One month increase 245k barrels. Nuff said.
Hi Guym,
I agree the weekly EIA estimate of US C+C output is not very good. It is the monthly estimates that I pay more attention to for the US, these are not perfect, especially the most recent 2 or 3 months, but usually pretty close (within 2% of final numbers).
And it looks like well productivity may continue to improve as Permian Basin shale operators continue to innovate.
Pioneer Natural Resources, having achieved greater well productivity with Fracking Version 3.0, has announced it will begin testing Fracking Version 4.0 later this year.
Occidental Petroleum announced it will begin drilling multiple laterals from a single vertical wellbore. If it works as planned, OXY predicts it will reduce drilling and completion cost per lateral by between $500,000 and $1,000,000, and will reduce lifting cost by more than 50%.
But there is also this.
Has Permian Productivity Peaked? | OilPrice.com: “According to the EIA’s Drilling Productivity Report, productivity (as opposed to absolute production) is set to fall next month in the Permian Basin. In other words, the average rig will only be able to produce an estimated 630 barrels per day of initial production from a new well, down 10 b/d from the 640 b/d that such a rig might have produced in May. That is convoluted way of saying that the ever-increasing returns on throwing more rigs at the problem might be hitting a ceiling.”
Ha! Ha!
Nick Cunningham — “a Vermont-based writer on energy and environmental issues” — doesn’t know the difference between rig productivity and well productivity. He conflates the two when he says, “the average rig will only be able to produce an estimated 630 barrels per day of initial production from a new well.”
Lordy, Lordy, help me!
Rig productivity is a very different animal from well productivity, as should be made clear by the graph I’ve included below.
But inadvertently Cunningham may have hit upon one of the reasons why rig productivity has stalled. He says that in the Permian Basin “the backlog of drilled but uncompleted wells (DUCs) has shot up over the past year, rising by more than 60 percent to 1,995 in April 2017 from a year earlier.”
So looking at the EIA’s methodology of how it calculates rig productivity, it says, “The estimation of new-well production per rig uses several months of recent historical data on total production from new wells for each field divided by the region’s monthly rig count, lagged by two months.”
But if there is an increasing number of DUCs, and they don’t get put on production within the two month lag time allowed by the EIA, this would bring down the total production from new wells for the field that the EIA uses in its calculation, thus bringing down the EIA’s rig productivity figure.
I’m not seeing your interpretation being written about in the oil and gas media.
Permian drilling productivity will see first-ever decline, agency says – Houston Chronicle: “But the Energy Department believes a key metric of drilling productivity is about to turn south in the Permian Basin for the first time since its analysts began tracking it in late 2013.
Next month, the daily oil production of a new Permian well drilled by an average rig will decline by 10 barrels to 630 barrels, the Energy Department said in a recent report.”
The Permian Is Reaching Its Limit | Seeking Alpha: “Over the past four months, productivity improvement rates have been negative (including June’s estimate), with the most recent metric coming in at -1.56% per month. In concrete terms, oil production per rig in the Permian dropped from 680 barrels per day down to 630 barrels per day in a period of only five months. That means that, keeping the rig count flat today, that’s 6.59 million barrels per year less than what would have been expected if these declines did not occur.”
“Based on the data provided, it seems pretty clear to me that the rig data provided by the EIA suggests that investors need to be careful when it comes to concluding whether or not oil output will continue soaring. Without a doubt, the rig increases are more than offsetting changes in the productivity improvement rates and the high monthly decline rates, but what’s important to note is that this may be the first data we’re seeing that implies that the benefits of added rigs in the Permian may be reaching a plateau.”
Hi Boomer,
Rig productivity is different from well productivity, the first is output per active rig and the second is output per well.
There can be many reasons for a reduction in rig productivity only one of which is well productivity. In order for an LTO well to produce the well has to be drilled and then fracked and then pumped full of proppant to keep the fractures open. So a very simple assumption that x rigs will result in an output increase of y, depends on weather, water, proppant, availability of frack crews, and well productivity.
Reality is not as simple as the model used by the EIA in the Drilling Productivity Report.
My experience shows that, as rig count increases and development includes lower quality targets, the BOPD generated per rig day decreases. One would think this is self evident, but over the years I had to fight tooth and nail to dissuade rookie management focused on ratcheting up rig count without understanding the project efficiency drops and sometimes the outcome is negative.
Boomer II,
When I think of “the oil and gas media,” I typically think of publications like the Oil & Gas Journal, Rigzone, the SPE Journal, etc.
OilPrice, the Houston Chronicle and Seeking Alpha are not written for oil and gas professionals, but for a much broader, and very different, audience.
https://www.google.com/finance?q=NYSE%3APXD&ei=u0QwWemGKoi-jAHgnY6YDg
-$2/share earnings for Pioneer and its innovation. dunno if GAAP or non GAAP
Hi Watcher,
That would be GAAP earnings.
OXY did have positive first quarter earnings due to higher realized prices compared to the first quarter of 2016. If oil prices fall they will lose money, this has very little to do with well productivity and more to do with the price of oil, NGLs, and natural gas.
Also as others have pointed out only a little more than half of OXY’s oil and natural gas output is from the US with significant operations in the middle east and a small portion in Latin America.
Hi Glenn,
Maybe the hype will be correct, Continental used to have some interesting presentations about very high density drilling in the Bakken. We don’t hear much about that any more, probably because it did not work out as planned.
I will believe it when I see it in a 10K (where too much hype gets you in trouble with the SEC).
Dennis,
Yes, it didn’t “work out as planned.”
But if the bottom falls out of the price of oil again, so that it plummets to 30% to 50% of its current price, I’m pretty sure that very few things in the oil business will “work out as planned.”
But regardless, you are absolutely right, companies, and especially publicly traded ones, do tend to hype things. And some are just outright liars, frauds. So a healthy dose of skepticism is in order.
But if one is too pessimistic, it leads to surrender, non-action, paralyzation.
What one should seek to be is realistic, which of course is easy to say, but difficult to achieve.
Hi Glenn,
I agree. I try to find a balance between pessimism and optimism, which I would call realism.
The fact that there are many that think I am too optimistic and many others that believe I am too pessimistic, might mean I am on the right track.
I do believe LTO output will rise if oil prices gradually rise to $75/b, but the predictions of the US EIA currently are too optimistic in my view (see AEO 2017). Basically they predict approximately 100 Gb of LTO output, where current USGS estimates are about 40 Gb for TRR, if we assume plays not recently assessed add another 10 Gb (probably optimistic) we would only have a TRR that is half of the EIA AEO 2017 reference case.
Note that the ramp up to 6 Mb/d by 2025 seems realistic, but the plateau that is maintained for 25 years, not so much.
We need to lobby to make Texas join OPEC with a 3.5 mmbopd quota.
Hi Fernando,
Very funny. As I am sure you know, the RRC still has the power to limit output, but chooses not to. Doubtful that it would make that choice (which was last used around 1972.)
Fernando
Is the 3.5 million per day a minimum of maximum quota?
The earlier referenced Permian efficiency decline is due to the massive increase in rig count getting way ahead of the completion crews.
Production is skyrocketing so quickly that takeaway constraints are being discussed.
Seems like the brittleness factor of much of the Delaware sub basin is greatly influencing higher production along with more familiarity of best processes.
EOG’s 4 well Whirling Wind pad produced 420,000 bo first month online, along with 85,000 bbls NGLs and 600 MMcf nat gas.
(EOG just had a Bakken well produce 247,000 bo first five months online. 29 million lbs sand used in frac).
Indian outfit, Reliance Industry, just built massive cracker in India.
They just built and put into service a fleet of 6 huge ships to bring liquefied ethane from Morgan’s Point to their plant in a nonstop, 3 month long journey of a ‘virtual pipeline’ model.
This will boost realized price for operators significantly.
3.5 would be the quota (the maximum). That would increase prices and give Texas much more revenue. Plus the green elves would be happy because higher oil prices would make their EVs a bit more practical.
IEA OMR May is public: https://www.iea.org/media/omrreports/fullissues/2017-05-16.pdf
My take on it:
OECD Products stocks continue their decline.
OECD Crude oil stocks are still high (but the trend is south).
Floating storage is at the lowest level since december 2014 (i.e. onshore drawdown should be next).
Chinese demand and stocks are a big unknown in the short term.
Concerning the discussion on Chinese stock (p.39-40):
“Data from China Oil, Gas and Petrochemicals (China OGP) indicate that commercial crude stocks fell 4.7 mb in March, while gasoline stocks gained 6.2 mb, gasoil fell 7.4 mb and kerosene fell 0.4 mb. Overall, commercial oil stocks in China were 6.3 mb down on the month and 18.7 mb down on the same month in 2016. However, interestingly, record crude imports (9.2 mb/d), as shown in customs data, together with stable refinery runs and crude production, imply a large build in strategic reserves and other stocks not taken into account by ChinaOGP. We estimate the gap, and hence the unreported build, at around 40 mb (1.3 mb/d) for March. Imports of Brent-linked crudes from Angola, the North Sea and Congo, gained the most, followed by crudes from the Middle East .
During 1Q17, total Chinese crude stocks – including crude flowing into strategic reserves and
independent terminals – are estimated to have risen by 85-100 mb (700-800 k/d) with a rise in crude
imports and as independent refiners in the northeast used their quotas. China’s strategic crude reserves
stood at 243 mb in the middle of 2016, up a mere 10 mb from the beginning of the year, an update
released by China’s National Bureau of Statistics showed. Given current filled capacity for the SPR of
200 mb, this implies that some 43 mb of strategic stocks were stored at commercial facilities, a practice
that took off in 2015. Additionally, it is highly likely other facilities not mentioned by the NBS are storing
strategic barrels on behalf of the government given the large gap between crude supplies and refinery
runs reported over the last year”
Below is BOEM data for GoM leases started since late 2014 through March. All leases are up to date except Tubular Bells, Caesar and one in Jack. I assumed these had flat production but I think the Jack flow should increase – it has no data since December, but in that time the Jack Phase II wells should have been ramping up. Tubular Bells is BP and they always seem to be six months late. Thunder Horse South is not included – that is also BP so no data yet, but also it can’t be separated from the rest of Thunder Horse. If there’s a rainy day soon I might try and get all the BP fields plus Tahiti data as those are a large chunk of GoM (and probably the biggest reserves).
I think there is now enough data to say that almost all the new wells on the smaller fields added over this period just don’t have plateaus. They ramped up to a maximum and are now in decline, even Julia. So either newer development wells get drilled (e.g. especially Lucius, Cardamom, Julia, Dalmatian) or things keep declining. Maybe none of these would have been developed had oil not got above $100.
(p.s. looking at the chart it looks like I left Jack/St. Malo off so I’ll add it when the data is up to date.)
It looks like it’s hard times for Gulf of Mexico operators.
http://www.msn.com/en-ca/money/companies/brought-down-by-long-bust-texas-oil-men-pray-for-another-boom/ar-AAnP4lA?li=AA54rW
There was no increase in drilling activity in the Gulf of Mexico when oil prices rebounded into the $50 to $55 range, the way there was in the Permian Basin. Well economics in the Gulf of Mexico don’t justify it, and these rapid decline rates may be part of that.
.
George Kaplan,
Is there any way to break that down between shallow-water and deep-water?
From what I read in oil and gas publications, it is the shallow-water Gulf of Mexico that is struggling the most, with deep-water less so.
That is all deep except maybe Coalecanth. Shallow water has been in long term decline, deep has grown from new projects, but has probably now run out of oomph. According to Schlumberger they have average 20% depletion rates, so without a lot of drilling they will have very high decline rates, which can be seen in individual fields like Lucius and Cardamom but not yet overall.
Shallow-water Gulf of Mexico drilling at lowest level in 70 years: Hercules CEO
https://www.platts.com/latest-news/oil/houston/shallow-water-gulf-of-mexico-drilling-at-lowest-21188902
Glenn,
BSEE has published an annual break out between shallow water and deep water production. That database is updated through 2014. In 2014, deepwater production was 81% of total GOM production. Total daily production for 2014 was ~1.4 mmbopd, so deepwater was about 1.13.
Currently, I would assume deepwater production is around 85% of the total, but that is just an assumption. I suppose it could be as high as 90%, but, at 85%, with recent production levels averaging about 1.74 total for the last four months, that would suggest deepwater production is about 1.48 mmbopd.
This is about as good an estimate as I can make – unless BSEE updates their database, or, if you can convince George to do a field by field roll up of all deepwater fields!
SLG – I’ll do BP fields and Ceasar/Tonga – since BSEE changed their site so you can download Excel files it’s pretty easy. Maybe next month though – at the moment the weather is beautiful, which is not that common, and England are managing to win at cricket, which is still rarer.
SouthLaGeo,
Thanks for the heads up. That’s very interesting information.
Thanks George.
I assume the vertical axis is barrels per day and that this is mostly (or maybe all) deep water fields.
Is that correct?
Chart below shows EIA data for Gulf of Mexico from Jan 2015 to March 2017, roughly 300 kb/d increase over that period and 250 kb/d of that is from the fields shown in George Kaplan’s chart above (please correct me if I have misinterpreted your chart.)
Looking a little more closely at George Kaplan’s chart, the increase from the fields he presents from Jan 2015 to March 2017 looks like about 280 kb/d, so roughly 93% of the Gulf of Mexico increase reported by the EIA (which might be revised as George has pointed out in an earlier comment).
SoLaGeo expects a plateau of about 1650 kb/d as I recall, the low rig count and steep declines in some fields (Lucius/Hadrian South and others) may indicate decline rather than plateau which George’s comments seem to imply.
I just published a post on tight gas production in the Haynesville basin (Louisiana side), available here.
George Kaplan:
In looking at your charts ( thanks to your data and participation in this blog) one can see an obvious ramp up in production from May15-July 15 and May16-July 16. The obvious conclusion is that jump up is seasonal, (same quarter each year) but that doesn’t seem to make much sense as it doesn’t get to cold in the GOM as it does in Canada. Do you have any thoughts on why production in both of those quarters jumps?
I don’t have much experience in GoM, actually more in colder climates where, as you say, there is definite seasonality. They do have a seasonal effect from hurricanes which can shut off production in August and September – and did last year. There is also a thing called a loop current, which I think can really mess things up if you are trying to keep a geostationary position, but I don’t know if this is seasonal (i.e. it might influence when installation is preferred). Also it could just be coincidence – it would only take a couple of the big platforms to go into major turnaround or unplanned shutdown at the same time in the year for the impact to be noted – Atlantis was offline in September which had an impact on overall production (not captured above). The kink shown in July last year above is all from Delta House fields so presumably it was off line then (it is built with low on-line sparing and therefore low availability). The 2015 kink looks like it came from Mars – so maybe a few fields off-line for a month or the whole facility for a couple of weeks. June might be a good time for maintenance if there is lower gas demand then (or is there – just a guess, no heating, but before maximum A/C demand?). Those comments would imply the seasonality is with a drop in the trend in June / July. If there is an impact on installation it may explain a run up in spring – I don’t know enough to say on that.
Hi all,
http://ir.eia.gov/wpsr/overview.pdf
The EIA reports that commercial crude stocks fell by 6.4 Mb from a week ago for the week ending May 26, 2017). Total stocks (crude plus petroleum products) excluding the SPR dropped by 5.2 million barrels.
Crude commercial stocks remain 5.7 million barrels above year ago levels (1.1%) and total stocks excluding the SPR are 2.6 million barrels below year ago levels (-0.2%).
Also from
http://ir.eia.gov/wpsr/wpsrsummary.pdf
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 6.4 million barrels from the previous week. At 509.9 million barrels, U.S. crude oil inventories are in the upper half of the average range for this time of year. Total motor gasoline inventories decreased by 2.9 million barrels last week, but are near the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories increased by 0.4 million barrels last week and are near the upper limit of the average range for this time of year. Propane/propylene inventories increased by 3.4 million barrels last week but are in the lower half of the average range. Total commercial petroleum inventories decreased by 5.2 million barrels last week.
Dennis. Look at US crude exports in the EIA weekly released today. Big number.
Hi Shallow sands,
Yes a high going back to week ending Feb 8, 1991. This past week 1303 kb/d, previous high was week ending Feb 17, 2017 at 1211 kb/d.
Apart from the storage numbers EIA TWIP has quite an important article out today:
OIL COMPANIES’ PROVED RESERVES DECLINE FOR SECOND CONSECUTIVE YEAR AS FINDING COSTS REMAIN NEAR HISTORICAL AVERAGE
Information in the 2016 annual reports of 68 publicly-traded oil companies indicates that their aggregate proved reserves declined in 2016 for the second consecutive year. In addition, reported finding costs—which are exploration and development expenditures per barrel of proved reserves added—remain near their historical average. The decline in proved reserves was heavily concentrated in a few companies that wrote down Canadian oil sands projects. However, low extensions and discoveries also contributed to fewer proved reserves additions. Together, the downward revisions, the amount of oil produced (withdrawn), and the lower extensions and discoveries led to a net decline in reserves.
See chart below. The drop in ‘extensions, discoveries and improved recovery’ is very noticeable – and it has been going on since 2012, i.e. through the high price years. They promise:
Later this year, EIA will issue an annual report that focuses exclusively on proved reserves located in the United States, including all U.S. producers, whether or not they are publicly traded.
I predict that will be bad news and hence will not get very much coverage. E&Y used to do an annual reserve report as well but I haven’t seen it yet this year (I think they alternate USA and global, with global due).
https://www.eia.gov/petroleum/weekly/
Also from EIA’s TWIP
https://www.eia.gov/petroleum/weekly/crude.php
For Crude oil stocks, the days of supply are well below last year’s levels.
Hi George,
As pointed out in your quote much of this was in the Canadian oil sands.
Also from EIA’s TWIP:
Three companies contributed the most to of the group’s combined downward revisions of 6.7 billion barrels. Each made downward reserves revisions associated with Canadian oil sands and bitumen projects totaling 1.1 billion barrels, 3.7 billion barrels, and 2.7 billion barrels, respectively. Collectively, Canadian oil sands revisions represented the largest reduction in proved reserves among companies whose 2016 reports were reviewed for any region globally (Figure 1).
Figure 1 is below
“The past two years had “exceptionally strong” demand growth, said Paul Cheng, an equity research analyst at Barclays in New York. “We think we should be growing at 0.4%-0.8% this year,” he said by email. Gasoline demand last week climbed to a record 9.822 MMbpd, EIA data show.”
http://www.worldoil.com/news/2017/6/1/americans-are-doing-everything-they-can-to-drain-oil-inventories
geez record gasoline demand here in the US, who would have thought that? with so many not wanting cars or saving their pennies for a new electric one, one would think we would not sustain A NEW RECORD DEMAND IN GASOLINE if those poster on this forum were remotely correct in their view points. I suppose they could be right one day, perhaps in the year 2030+
Hi Texas tea,
The demand includes exports of gasoline, and World demand will increase for a while, in about 5 to 10 years high oil prices will lead to a decrease in oil demand as better efficiency, fuel switching, and electricity and other innovations reduce demand, my guess is 2023 (6 years from now) for the peak in C+C output.
I’m actually wondering if we reached the world peak for *conventional* oil production last year.
http://fuelfix.com/blog/2017/06/01/after-storms-fights-and-months-of-delay-the-dakota-access-pipeline-finally-opens/
In the long term, it is a ‘gassy’ future.
How much condensate will come from gas varies – wet wells are more valuable (all equal) than dry wells, but my recollection is that somewhat here some years ago noted that the global trend is to increasing dry over wet gas wells..
Then there is the issue of ‘orphaned gas’, too remote and expensive to pipe.
Apparently there has been a significant gas find in Russia, mentioned today by Pres. Putin at the St. Petersburg Economic Forum Press dialogue:
http://en.kremlin.ru/events/president/news/54650
“That is not to mention the energy sector. Germany has decided to phase out nuclear energy, but nuclear energy accounts for a big share of Germany’s energy, bigger than in Russia today. Where will Germany get its energy from? We see that Norway’s resources are coming to an end, and Britain will soon be a net consumer country. Their resources are also dwindling. So, where will the energy come from?
At the last forum, we spoke about the prospects on the Yamal Peninsula, where we had reserves of 2.7 trillion cubic metres of gas. Gazprom just briefed me on the new reserves they have discovered there. Can you imagine what this increase represents? It’s a two-fold increase. We have another 4.2 trillion cubic metres there, and that is just in one small region. But these reserves are global in scale, and given Russia’s proximity to Europe and cheap logistics and well-organised procedures and technology, this is an absolutely natural partnership. We offer a cheap and clean energy source, if its hydrocarbons we’re looking at. This is absolutely natural. In the long term, if we look at long-term contracts, this guarantees stable supplies and – also very important – guarantees that the entire German economy is competitive. This is tremendously important. It’s a relatively cheap resource and comes from a reliable source.”
– Pres. Putin in dialogue with world press at St. Petersburg.
The problem of course, is that gas is ‘too abundant’ at the moment. China is ‘bucking’ at the agreed gas-take from Russia as prices at the time of negotiation were higher than today. Russia needs to sell hydrocarbons. Maybe they should use ‘take or pay’ contracts.
Even converting gas to urea ( a use for ‘excess’ gas) is no longer viable, given capital cost of plants. The price I pay for urea has fallen considerably lately, I assume due to cheap gas and more conversion plants.
“That is not to mention the energy sector. Germany has decided to phase out nuclear energy, but nuclear energy accounts for a big share of Germany’s energy, bigger than in Russia today. Where will Germany get its energy from?”
Nice propaganda. Only 8% of the NG in Germany is used to generate electricity and can of course be substituted with REs. The phase out of nuclear power is a non-argument. Sorry.
The more interesting question for Russia is how the demand for NG in the fields of industry and space heating will develope in Germany in future, i.e. when will we see a peak. And of course the 400 pound gorilla are EVs, when 30% of new sales are EVs, this will very likely happen before 2030, we will see a 2% reduction of demand per year for oil.
About 23 years from 2016 to get to 30% world sales. So 2029. Good guess.
https://www.bloomberg.com/news/videos/2017-06-01/russia-s-oreshkin-on-opec-oil-prices-sanctions-video
Synopsis:
Maxim Oreshkin speaks very good English. He is the Russian Economy Minister.
“What do you have to say about oil prices, Mr. Minister?”
“I do not understand the hedge funds funding US shale producers. They are not making money. They are also at risk for the future.”
“What risk?”
“That oil prices might be much, much lower.”
“Is that your expectation? That when the production cut agreement’s extension ends, prices will be much lower.”
“Blah blah blah long term short term this and that, but without question those shale funding sources are taking a big risk.”
“Doesn’t this put Russia at risk, too?”
“Well, not really. The Russian economy is far less dependent on oil prices than it was 5-10 yrs ago. So . . . no.”
“But it’s still important to you, yes?”
“No. Not that much. This is your story. We are prepared to live with oil prices below $40 forever. We are self funding. Not a problem for us.”
[All those who believe Russia can endure sub $40 prices FAR more credibly than shale can, raise your hands. 0/ That’s one hand up. Others?]
Bloomberg reporter quiet a moment. “Let me ask you about capital outflows. You saw $15 billion outflow of capital last year, down 70% from 2015. Do you expect ouflow this year?”
“No, we have already seen $3 billion of inflow this year. This question often comes up talking to investment managers and they want to lump us with Turkey and South Africa. We have no inflation problem. Our inflation is at our Central Bank’s target (unlike the US). But we don’t care much, we are self funding.”
“Gary Cohn is a Trump economic advisor and he has said sanctions may be stiffened.”
“We don’t care. We are much more concerned about what goes on inside Russia than outside. This is all your story. It is important to you. It is not to us. We are self financing.”
Sharp cookie.
The difference between shale oil and russia is:
Russia make less money at 40$ – less, but they make money. They can expand, drill new field and make money.
You can adopt if you make money, just not that big heaps of money.
Shale simply wastes money at 40$ – all companies reported here in the blog wrote red ink in their shale business in Q1. And there the oilprice was > 50$.
Of cause for wallstreet ist wasting money a good business, you can earn double. First in giving the loan to the shale company, then selling the toxic papers nicely packed to privat investors and stupid pension fonds, and when restructuring a bottom up company you can even earn again while restructuring and giving new loans.
Just dispose the toxic papers fast enough.
Eulen,
You must look deeper. Money is just claim on energy. US must have those 5mbd from shale to support fairy tale 21k Dow paper economy.
So, if not 5mbd from shale then from where are you going to get it? There is no low cost 5mbd of oil sitting ready in some Saudi pantry. When everyone is forced to circle in their cars daily, 9-5, aimlessly to support some delusional economic statistics (e.g. GDP, annual growth) and to support their debt payments just for good measure of being in line, then you need those extra expensive 5mbd shale to do just that.
Having high GDP is like showing with Gucci bag or Mont Blank pen among peers at the G7 cocktail party. Imagine mingling at G7 party: “How do you do? This my GDP numbers? What are your GDP numbers?”
That is Maya, delusion of this modern world.
Yeah, you have always had a feel for what has evolved to be a desperate facade.
What is most clear from the interview is Russia knows what’s going on. They know what’s going on more profoundly than most oil analysts in the US. They know shale is a scam and it’s perpetuated by borrowed money. I thought it was clever how he got “Central Bank” mentioned later in the interview juxtaposed with the entire issue of who is funding shale.
US media talks non stop about OPEC and Russia having to cut production to raise price. I have yet to see reporters at US oil company headquarters asking CEOs if they will cut production to get price up. It’s not even mentioned.
This Russian guy has a total grasp of the whole situation, and there is an edge of contempt in his tone. Rightfully so. That is not a desperate country. Others are.
Amazing how you guys are on the same page with Russia and Mike, who are both sore that the shale producers flooded the world with oil and demolished high oil prices.
At least they have a vested economic interest in seeing the rapid demise of shale. Their longing for shale’s demise is entirely rational.
So what’s your reason?
“So what’s your reason?”
Glenn,
In this world, there is always consequence or price to pay for all actions. So, You and I, will pay the price in few years when pendulum of oil price moves in other direction (and we get $150/barrel) due to current shale producers flooding the market and all long-term oil explorations have been ceased. At this point Shale destroyed any balance not just of oil market but the whole energy market including the renewables.
So you believe the low energy prices that the shale revolution has produced are a bad thing?
It’s a good thing in that it has discouraged Arctic drilling and expansion of tar sands.
In the past it would have a bad thing for EVs, but those seem to be moving forward no matter what the price of oil.
Low oil prices are bad for the oil industry.
One can find predictions of future EV usage to fit just about any narrative one wants to spin.
But EV market penetration to date, outside of Norway and the Neatherlands, is almost nil.
I won’t speculate on how fast EVs will be adopted, but there is so much incentive on many fronts for transportation/energy production/energy efficiency changes that it will continue to happen and snowball.
The auto industry was pretty set for a long time. It was US makers and European makers. Then the Asian countries saw an opportunity and in time grew to international auto giants.
Now the opportunities are in EVs, batteries, renewable energy, distributed generation, digitally controlled energy networks, internet-driven ride sharing, etc.
There is very little room for new gas and oil players or technology innovations. It’s a depletion industry and doesn’t have the room to expand that the digital industries do. So neither entrepreneurs nor developing countries have much reason to try to become dominant forces in established industries. But for clean energy tech, the potential to become the next Amazon or Google is there.
Look at what Amazon has done to retail. People like Musk are looking for those homeruns and it isn’t going to come from gas and oil.
Established auto makers will either choose not to get into EVs or they will. Right now they are having trouble unloading their ICE inventory and therefore are discounting heavily. If this continues, they will look for alternative vehicles to sell or ways to get more involved in new transportation trends.
Glenn,
Nothing is “bad” or “good” in this world. “Bad” or “Good” are just labels that we attach on things. Even for some oil producers today is great time. Casual commentator Tee-Tee always likes to stop by here and tell us how he is doing great. And probably he is living a dream even with this low oil price. But Tee-Tee is not aware that all this shale hype is possible only with Feds printing out of thin air.
So, the benchmark of understanding should be “awareness” and not the labels “good” or “bad” that we attach to a things.
Ves,
So you believe the shale industry to be a repeat of John Law’s Compagnie d’Occident?
Could be.
But there is more and more evidence accumulating with every passing day that indicates that will not be the case.
In Law’s case, the “very large gold deposits which Lousiana was thought to have as subsoil” didn’t exist.
But the “very large oil and gas deposits which shale is thought to have” certainly do exist. That much is history. That much is known.
What is not known is how much more oil and gas production they have.
And the EIA has certainly hedged its bets, leaving open the possibility of a wide range of future possiblities.
“So you believe the shale industry to be a repeat of John Law’s Compagnie d’Occident?”
Glenn,
I don’t believe in anything . If you believe in the head and its dictation — “First know, then you can trust”. Then you will never trust, because knowing cannot happen without trust. And do you really trust lying politicians and bankers and revolutionaries that become anti-revolutionaries as soon they get in power?
EIA is in tarot card or palm reading business 🙂 The only difference is they don’t work one-on-one, so they must give you few options so you get identified with provided options.
Optimist will go with your last model graph (increasing tight oil production) and pessimist will go with your middle graph (decreasing tight oil production).
Everyone gets identified with “story”. If you carefully read Watcher transcript or video from the link above of that interview where Russian guy tells the Bloomberg interviewer: “That is only YOUR story!! We don’t care”.
That is the highlight of the interview for me.
So, it is only “stories” that we argue about. There is no bigger sin in the world than identification. Everybody gets identified with story. You, maybe because of financial reasons, are identified with this story about Permian profitability and sustainability, on other thread people get identified with “Green” thing and so on…These are just “stories” in people’s minds…People should just drop the “mind” and move to the heart. Heart is the feeling center…and my gut feeling is we will have a very bumpy ride ahead.
Intuition or gut feeling is maybe the mind being honest with itself.
Watcher,
Thanks for that your “modified” Bloomberg transcript 🙂 And the link. I usually don’t go there since Bloomberg is dangerous for the mind 🙂
Yes, everyone that needs to know already knows what is going on.
Eulenspiegel,
Nonsense.
Pioneer Resources had a positive operating cash flow of $364 million for 1Q2017, and a positive free cash flow of $66 million.
It produced 249,000 BOEPD in 1Q2017, up from 242,000 in 4Q2016, and up from 222,000 in 1Q2016.
That’s not bad work if you can get it: $66 million of free cash flow while increasing production 3% from the previous quarter and 9% YOY.
Another company that operates predominately in the Permian Basin, Concho Resources, had a positive operating cash flow of $407 million in 1Q2017 and a positive free cash flow of $77 million.
It produced 181,400 BOEPD in 1Q2017, up from 164,300 in 4Q2017, and up from 139,500 in 1Q2016.
Again, that’s not bad work if you can get it: $77 million of free cash flow while increasing production 10% from the previous quarter and 30% YOY.
.
Pioneer Ressources?
First quartal 42 million $ loss,
Planned dividend 2017 8 cent, at a stock value of 164$.
That’s not an oil stock, that’s a tech stock in the wild 1999/2000 years. An oil stock pays a dividend – that’s what oil is for, earning money not burning money.
And even when the oil price climbs a bit – the moment the big bonanza in Permian begins, utility prices will crash up again, when oil companies will bid themselves up for rigs, fracking crews, sand, trucks, pipeline slots.
I am with you – Permian will boost output, but I doubt there will be much money earned – especially when the boom is as hard as you think. Oil price down and utility price up, land price up, everything price up – since you have to continue drilling like mad in shale, this is the main problem earning money there.
With a slow groth, prices could keep down and money can be earned – but not in this boom/bust way.
Eulenspiegel,
So positive earnings and whether a stock pays dividends are the lone criteria that determine its value?
Well if that’s what you believe, there are certainly plenty of stocks out there for you.
But by the look of the impressive rise in Pioneer’s and Concho’s stock, there are plenty of people out there — and people who are willing to put their money where their mouth is — who disagree with you.
Why aren’t you mentioning EOG? They are commonly referred to as the “Apple” of shale?
Eulenspiegel, shale companies are more like tech companies. I think they are now up to 4.0 on fracking technology.
Seriously, equity for shale in certain instances, such as PXD, EOG and CXO, is valued considerably higher than that of majors like XOM, on a per barrel basis. Whiting and Sandridge used to be too. I haven’t looked but I assume most shale stocks have a high beta.
For some reason I am still holding onto a small position in EGN. It was a gas utility with a small position in the San Juan Basin and Permian Basin. I have owned it for well over 20 years. It is now a pure play on Permian shale.
It used to have an A rating on its debt and paid a nice dividend. It’s stock used to split 2 for 1 every few years. Low volatility.
Dividend has been eliminated. High volatility. Debt rating has streadily declined over time.
Only 8% of EOG’s production comes the Permian Basin.
Furthermore, 50% of EOG’s production is natural gas.
So EOG is neither a predominately Permian Basin producer nor a predominately oil producer, as are Pioneer and Concho.
.
Which company or companies is operating the minerals you own in the Permian?
I’m curious about that, too.
Endeavor Energy Resources.
It’s a private limited partnership that controls more than 330,000 acres in the Permian Basin.
At one time it controlled more than 370,000 acres, but in 2014 farmed out 34,000 acres to an ExxonMobil subsidiary, XTO Energy, Inc. plus in 2016 sold off another small portion of its acreage to pay down debt. The company now is practically debt free, and owes less than $500 million.
My lease is still controlled by Endeavor.
The company currently has five rigs running, and the goal for 2017 is to bring 75 horizontal wells online.
The company’s remaining 334,000 acres, given that Midland Basin acreage has recently sold in a range between $50,000 and $80,000 per acre, is probably worth between $17 and $27 billion.
Autry Stevens, who owns 34% of the company, started the company in 1979.
I remember him and Endeavor from watching Black Gold on truTV. Not an easy show to watch, reality TV doesn’t work to well on drilling oil wells. Hard to jazz it up.
I recall Stephens predicting a bust in late 2014. He was right. The Bakken folks at that time weren’t too concerned, as I recall.
I assume he has some strong backing. Shale takes major capital, more than even the Yates, Bass and Fasken families are willing to spend.
I think they are still looking for money. An article said they were considering an IPO and were courting the bond market.
This appears to be the way they have raised some money.
Ares Management announces Development Capital Resources, partners with Endeavor – Midland Reporter-Telegram: “One of the company’s first projects is a $300 million drilling partnership with Endeavor Energy Resources. Development Capital will provide the majority of the capital and participate as a non-operator to finance and develop identified drilling locations. Once a designated return on investment has been achieved, the company’s working interest will decline during the operations phase of the drilling joint venture.”
I recognize this financing model, but it’s safer to do it with solar farms.
As a general rule, resent shale companies as the business model historically has been burn cash, but deliver on oil production (& hence depress oil prices).
However, in this case, Glenn is correct on Concho- US$50/barrel in 1Q17 worked for Concho (aided by their adept use of derivatives) as US$50m neg. FCF (excl. disposals) is an acceptable price to grow production rapidly.
Pioneer was similar – small negative FCF (US$60m) on an underlying basis (i.e. excluding net disposals / working capital movements).
Now, this was achieved in during a period when service costs were still depressed & the entities above were among the top performers in an ugly segment of the Oil & Gas industry.
Going forward, if production growth remains strong – costs should not stay at current levels (unless service company’s act irrational & tap the same herd that values growth over returns).
Personally, I cannot wait for these service company’s to re-establish & for the wall street flood of cash in shale to slow to a trickle (though I have been very wrong on this front, never expected people to throw good money after bad for so long). So far, I have misjudged the US investor base thirst and craze for pure growth stories (tech, shale, etc.).
You are another here that DOES NOT UNDERSTAND CASH FLOW.
Cash flow is cash. It is not profit. You can borrow money, have cash appear as a result, have that cash influx exceed cash outflux and declare positive cash flow.
Cash flow is a parameter used nowadays only by hypesters trying to reassure victims that the company burn rate won’t deplete money to zero.
YOU CAN ACHIEVE CASH FLOW NEUTRAL WITHOUT SELLING A SINGLE BARREL OF OIL. If someone will lend cash to you (or has been told to lend it to you), you can have positive cash flow and it means nothing whatsoever about present or future situation.
Watcher,
Cash flow from financing activities is included in neither the universally accepted definition of cash flow from operating activities nor the universally accepted definition of free cash flow.
Do you believe you can just create your own definitions of cash flow from operating activities and free cash flow out of thin air?
In 1Q2017 Pioneer Resources had negative cash flow from financing activities of $521 million. This consisted of a $485 million outlay which Pioneer used to pay down its long-term debt, and a $36 million outlay Pioneer used to purchase treasury securities.
In 1Q2017 Concho Resources had a negative cash flow from financing activitiees of $19 million. This consisted of proceeds from issuance of debt of $105 million, payments of debt of $105 million, and a payment of $19 million to buy treasury securities.
I really don’t have time for this but
cash flow
Incomings and outgoings of cash, representing the operating activities of an organization.
In accounting, cash flow is the difference in amount of cash available at the beginning of a period (opening balance) and the amount at the end of that period (closing balance). It is called positive if the closing balance is higher than the opening balance, otherwise called negative. Cash flow is increased by (1) selling more goods or services, (2) selling an asset, (3) reducing costs, (4) increasing the selling price, (5) collecting faster, (6) paying slower, (7) bringing in more equity, or (8) taking a loan.
Read more: http://www.businessdictionary.com/definition/cash-flow.html
Look, you don’t need me to tell you these things. Just look them up.
So, we have three different forms of cash flow:
1) “Cash flow”: difference between cash in bank at beginning and end of period;
2) “Operating cash flow” and
3) “Free cash flow”.
Glenn appears to be using #2, and Watcher is using #1.
Can we agree on which to use??
Overcomplexity = It doesn’t quite matter.
Naked-ape time and energy are being overextended/wasted with relative and frenzied abandon, and in cyberspace as well, thanks to cheap, abundant energy.
How else is there cyberspace to begin with?
(cue Charlie Brown teacher sound…)
person1: “No, it’s like this.”
person2: “No, it’s like that.”
person3: “Well, it’s kind of like that but more like this, if you consider this and that…”
person4: “So bla bla bla…”
person5: “Maybe bla bla blaa… bla bla… blaa…”
(Yes, it’s purposely all one long hyperlink.)
If we take 1/2 a day to ‘tie our shoelaces’ we will hardly get anything else done or at least that makes more sense.
Who wrote something about ‘driving around in circles’? Ves?
Increasingly-decreasing societal energy available will probably make ‘quick work’ of decreasing much nonsense and uselessness.
Watcher,
If one looks at Pioneer’s and Concho’s actual SEC filings, instead of what one conjures up in one’s mind, they took out no loans.
And in fact Pioneer paid off $485 million of long-term debt, and Concho bought $19 in treasury securities during 1Q2017. So both Pioneer’s and Concho’s cash flow from financing activities was negative.
The facts in no way support your argument.
Why are you so resistant when someone tries to point out the facts to you?
PEAK OIL 2005
http://www.theoildrum.com/story/2005/11/27/172849/36
OK not 2005 but 2008 definitely
http://www.resilience.org/stories/2008-12-05/peak-oil-crisis-july-2008-%E2%80%93-month-remember/
OK, OK not 2005 or 2008. This time I am right it will be 2015
http://oilprice.com/Energy/Crude-Oil/2015-Could-Be-The-Year-Of-Peak-Oil.html
Peak 2016, peak 2017, peak 2018 One day you will be right.
Hi Jan,
I have been saying 2020-2025 for quite a while. Since at least July 2015 (actually going back to 2012) see 3400 Gb URR scenario at link below.
http://peakoilbarrel.com/oil-shock-models-with-different-ultimately-recoverable-resources-of-crude-plus-condensate-3100-gb-to-3700-gb/
Other posts from 2012 have the peak around 2020, see
http://oilpeakclimate.blogspot.com/2012/
http://oilpeakclimate.blogspot.com/2012/07/further-modeling-for-world-crude-plus.html
Models at post below suggest a peak as late as 2030 (from August 2012)
http://oilpeakclimate.blogspot.com/2012/08/i-noticed-that-compared-to-model-by.html
Post below has a plateau scenario out to 2035
http://oilpeakclimate.blogspot.com/2012/08/extraction-rates-and-developed-reserves.html
Note that we have exceeded the plateau of that scenario (about 74 Mb/d from 2012 to 2040) with recent C+C output at about 80.5 Mb/d, so that maintaining current levels of output for such a long time would be difficult, though it might be possible to maintain a plateau at 2015 output levels until 2030, but decline would be steeper as a result as resources are not unlimited at reasonable oil prices (under $100/b in 2016 $).
Many participants here think my scenarios are far too optimistic, a lot will depend on oil prices.
Low oil prices will mean that the lower output scenarios are more likely as expensive resources will be unprofitable to produce (3000 Gb C+C URR and possibly less) whereas high oil prices might lead to higher URR scenarios.
My hope is that the scenarios of Tony Seba will prove correct and World C+C URR will be 2500 Gb or less, the realist in me believes it is more likely to be 3300 Gb with the scenarios of Seba delayed by 10 to 20 years.
Hi Jan,
The second link above was incorrect, it should have been
http://oilpeakclimate.blogspot.com/2012/07/an-early-scenario-for-world-crude-oil.html
This was my first post on the oil shock model on July 20, 2012.
Hi Dennis
Thank you for your reply. 2020 to 2025 is a reasonable assessment.
It all depends on Global Oil demand.
http://www.opec.org/opec_web/en/publications/338.htm
If world oil demand increases by around 1.3 million barrels per day, then the global oil overcapacity will be used up by 2020-2022.
This however depends on how long OPEC limits production, which in turn will effect how US shale and Canadian tar sands recover in the next 2-3 years.
Can Iraq produce 9 million barrels per day?
http://www.businessinsider.com/iraq-published-data-on-crude-oil-output-at-fields-2016-11
https://currencyliquidator.com/blog/iraq-oil-industry-and-current-economic-outlook/
The amount of drilling in Iraq has been tiny in comparison to the United States.
At the moment no one knows how well Russia will develop it’s Arctic and shale resources.
http://oilprice.com/Energy/Crude-Oil/When-Will-Russia-Run-Out-Of-Oil.html
https://www.washingtonpost.com/news/wonk/wp/2017/06/02/venezuelas-descent-into-anarchy-is-only-beginning/?utm_term=.1f6454ac2222
Who knows what will happen in Venezuela, an extended decent into anarchy or a quick revolution enabling independent oil companies to develop the large quantities of heavy oil.
All in all, decline rates coupled with above ground idiocy will combine to make increases beyond 2025 difficult.
Dennis & the Group,
The most recent graph of global NGL production I found was on Euan Mearns website, but that was for 2013.
Does anyone have a link or info on global NGL production and or a breakdown of the different total liquids production.
Thanks… Steve
Hi Steve,
Just use the EIA data at
https://www.eia.gov/totalenergy/data/browser/index.php?tbl=T11.01B#/?f=M&start=200001
and BP data at
http://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy/downloads.html
BP gives C+C+NGL in World oil production data, I would take the data in tonnes and convert to boe at 7.33 barrels per tonne, then subtract EIA C+C data to get NGL in barrels of oil equivalent per day.
For now this would only give you data through the end of 2015, but if you wait a week or so the new BP statistical review will be out and you will have data through the end of 2016.
BP Stats for 2017 will be out on June 13, 2017
Dennis,
Thanks a million. That works.
Steve
Hats off to whoever fixed this website. I have had no problems for the past several days.
I don’t think anybody fixed it. Things just worked out on its own. We unnecessarily do too much of “fixing” and later on we regret.
Hi Clueless,
I haven’t done anything, but I am glad it’s working for you. Maybe Ron fixed it.
ZH picked it up:
http://www.zerohedge.com/news/2017-06-02/russias-economy-minister-we-can-live-forever-40-oil
The oilprice.com shill who quoted it did a lot more “interpreting” than quoting. Sometimes he concludes unrelated things to what the guy said. Or, as bad, decided that when the guy said he can last forever at $40, that meant something different.
Has anyone ever known a Russian to publicly admit weakness?
How about shale CEOs? What do they admit?
For them it’s what they emit – BS.
so what about all the recent protests in Russia? can Russian citizens live with social spend 40% down in USD terms and not revolt?
Surprised I missed this –http://economictimes.indiatimes.com/news/economy/foreign-trade/indias-2016-iran-oil-imports-hit-record-high/articleshow/56914858.cms
Some advance India stuff . . . In advance of the upcoming BP Bible release.
The number 3 oil consumer in the world increased oil imports 7.3% in 2016. India’s 2015 oil consumption growth was 7%. Unless they had a production collapse, this points at another year of booming consumption growth. Don’t have the exact 2015 number on this machine, but my recall is 7%, so this may be not just booming growth, but also acceleration. And the article notes the growth is from Iran — who would seem to have no reason to cut, given that voracious customer.
If the growth in world oil consumption does not accelerate, it looks like Russia’s and OPEC’s attempt to balance world oil markets could be quite an uphill struggle.
“Igor Sechin, chief of Russia’s largest oil producer, Rosneft, said U.S. producers could add up to 1.5 million bpd to world oil output next year,” reports Rigzone.
Oil Down 1% On Rising US Drilling Fears, Supply Glut
http://www.rigzone.com/news/oil_gas/a/150438/Oil_Down_1_On_Rising_US_Drilling_Fears_Supply_Glut
Article quotes 4.3 million bpd Indian oil imports. Indian consumption 2015 was 4.1 million bpd. Clear growth. Reduced Latin American and African oil and ramped Iranian and Iraqi oil, though mostly Iranian.
API 31-35 out of Iran. Proper oil.
Reasonably good article on Iraq here, though WoodMac never see anything but the high side of any development:
http://www.epmag.com/iraq-faces-obstacles-path-oil-production-target-1606846#p=4
IRAQ FACES OBSTACLES ON PATH TO OIL PRODUCTION TARGET
Meanwhile, “progress has stalled” on Iraqi’s proposed Common Seawater Supply Project. Wood Mackenzie explained that Iraq’s oil fields need water injection to improve recovery rates, something the report noted was critical for fields such as Mishrif which have heavy oil, poor aquifer support and fast decline rates.
The project would make up to 12.5 MMbbl/d of desalinated water available to southern oil fields, but money could be an issue for the Iraqi government. The report, however, pointed out a scaled-down plan to supply seawater in 2.5 MMbbl/d stages is in the works.
Despite the challenges, Iraq “undoubtedly has the large-scale low-cost oil resources in its southern fields to underpin production of over 10 MMbbl/d. And with companies actively repositioning lower down the cost curve there is a fundamental (e.g. pre-tax and excluding country risk) advantage for Iraqi assets to attract capital,” the report said.
…
Though Iraq, OPEC’s second-largest oil producer, has more than 70 oil fields, only 30% of these are developed or partially developed, he said, after mentioning how international oil companies have been invited to submit new contract models to develop fields. In Iraq, fields considered small are capable of producing 100 Mbbl/d, with giants at more than 1 MMbbl/d.
“capable of” is a bit meaningless I think, if it only lasts a couple of years. If the 70% undeveloped are small fields then the upper limit to their production is going to be 5 mmbpd based on 100 kbpd limit, so the 10mmbpd is maybe less easy, and they will need much more than 2.5 mmbpd water to support that, probably more than the original 12.5 mmbpd.
As we’re getting to halfway through the year I had a search for what oil projects (non US LTO) have been approved. Although there are a few more than last year I think in terms of capital and capacity it’s quite a way down so far. I get Kaikias, Horn Mountain Deep and Constellation in GoM (all tie backs, two quite big though), Skarfjel and Trestakk in Norway (small / medium tie backs), Kirby oil sands (which is completion of a half finished project, West White Rose in Canada (a wellhead / drilling platform tied to an existing and pretty old FPSO), Ca Rong Do in Vietnam (a small relocated FPSO), and nothing else I can find. I think those will not give more than 200 kbpd nameplate and, except the completion of Kirby, no strictly new processing capacity added at all (i.e. they depend on decline in other facilities to provide processing space). Note I’ve assumed Mad Dog II was approved last year, but strictly speaking I’m not sure if all partners have yet agreed.
There are some big gas projects, although I think only Leviathan has been formally approved. There are some bigger oil projects that look likely to go ahead this year or early next: Liza, Sepia (maybe – depends on Brazil politics), and Zabazaba-Etan for Eni in Nigeria, maybe Njord redevelopment and Snorre extension in Norway. They’d add another 300 to 350 kbpd, though not starting in the same year, , but you’d have to say that, so far, the investment drought is continuing, or even has worsened, which means it could likely be from late 2018/early 2019 up to 2023 with few major new projects getting up to plateau. Iran and Iraq, which I’d expected to declare a couple of big developments haven’t so far, though Azadegan might be close (but things seem to take a long time there and can easily get stopped). See above for Iraq. Anybody think of any other projects?
http://www.globalforestwatch.ca/sites/gfwc/files/data/20100730A_TarSandsProjectsMap.pdf
You can find the Kirby project on here. Note that Suncor is the big kahuna in that oil sands world and they bought leases up north of Ft MacMurray, not south. Sweet spot.
Kirby. Suspicious potential.
Ooops forgot to answer:
The Fort Hills oil sands mining project is located in Alberta’s Athabasca region, 90 kilometres north of Fort McMurray, Alberta and is recognized as one of the best undeveloped oil sands mining assets in the region. The project’s co-owners are:
Suncor Energy Inc.
Total E&P Canada Ltd.
Teck Resources Limited
The project is operated by Suncor, and is scheduled to produce first oil by the end of fourth quarter of 2017 and achieve 90% of its planned production capacity of 194,000 barrels per day within 12 months. The mine life is expected to be approximately 50 years at the current planned production rate.
MORE DELAYED PROJECTS SANCTIONED H1 2017 THAN THE ENTIRETY OF 2016
https://www.rystadenergy.com/NewsEvents/PressReleases/more-projects-sanctioned-h12017
Apparently Mad Dog counts against this year, though I think BP approved it in December, which means volumes and capital might be a bit up this year on last. Rystad mention an Iraq project, which I think must be the refinery, not upstream, and a Chinese project, which is gas (I’ve forgotten the name so can’t check).
They state that West White Rose wellhead is deepwater, which it definitely is not (I think 100m) – FPSOs are used out there because of iceberg risk, not because it is deep.
The number of delayed FID projects is given below. I’m not sure how they determine expected FID dates.
GOM RECOVERY LIKELY AT $60 PER BARREL
https://www.rystadenergy.com/NewsEvents/PressReleases/gom-recovery-likley-at-usd60-per-bbl
Rystad expect Vito and Shenandoah FID next year and Anchor, North Platte and Phobos thereafter. I don’t know if they have allowed for the big downgrade in Shenandoah reserves. No mention of Buckskin or Tigris.
In the short term, outlooks are still dire due to operators wanting to secure positive cash flows before increasing investments. From 2019, however, as development and exploration activity picks up, a gradual recovery in investments seems inevitable. When analyzing sensitivities, we indicate a modest increase in investments over the next five years at 60 USD/bbl oil prices. When assuming oil prices at 80 USD/bbl or more, a new boom is likely.
I don’t see how there can be a construction boom without new discoveries, and they are pretty rare at the moment. However they are now lumping Mexico and USA GoM all together, so maybe they are expecting more activity over the border. But to get the investment shown below I think there have to be some big finds made in the next 18 months.
http://www.zerohedge.com/news/2017-06-04/aaa-raises-premiums-teslas-saying-owners-file-claims-abnormally-high-rates
Comment in the thread:
“Tesla will have to start making self-towing cars.”
haha
Top Russia Oil Boss Scorns Tesla, Electric Cars as Overrated
http://www.rigzone.com/news/oil_gas/a/150432/Top_Russia_Oil_Boss_Scorns_Tesla_Electric_Cars_as_Overrated
Hi Glenn.
Consider the source of the commentary- the biggest threat to the ability of Rosneft to sell their product for a high dollar is the potential success of the electric car industry. I don’t think American producers will have too much trouble selling their oil for good money over the next 10-15 yrs, given the supply/demand scenario here. But Russias longterm earning potential could be at some risk.
It does sound like Sechin is talking his book.
But what about this? This certainly doesn’t sound like he’s trying to talk up the price of oil:
The success of the USA shale drilling/LTO production has certainly been the biggest factor cutting into Russian energy earnings over the past 7 yrs, and can be seen as bridge til the time when the global electric vehicle industry will join as a big factor in reducing the pricing power of the Russian oil industry.
US might add 500 kb/d at most. Annual 2016 C+C vs annual 2017 c+c output. Not enough to offset cut of 1.8 Mb/d
Dennis,
Actual annual-average cut will be less than 1.8 mbd (probably, much less – in case of cheating).
Still, OPEC/NOPEC cuts + global demand growth should exceed US C+C growth + global NGL and other.
We already see a decline in global inventories.
But increased spare capacity is a threat to the market rebalancing in the short term.
Hi AlexS,
Spare capacity was close to zero in Nov 2016, any “claimed” spare capacity in that month probably exists only on paper. You are correct that the cut is likely to be less than 1.8 Mb/d, perhaps 1.4 Mb/d for 2017, let’s assume US increases output by 500 kb/d (for the 2017 annual average vs 2016 annual average), we will also assume NGL output increases by 500 kb/d and demand increases by 1.2 Mb/d, this leaves a deficit of 1.6 Mb/d on average during 2017 which should reduce World crude plus product stocks by 584 million barrels in 2017.
I doubt spare capacity will be much of an issue and by the end of 2017 any spare capacity will be brought online to keep stocks from falling further, oil prices will likely have risen to $70/b or more due to falling stocks by late 2017, prices may stay at this level until May 2018 and then World output will struggle to stay on plateau as decline may out strip increases from LTO, oil sands, and OPEC.
Dennis,
If several major producers quickly reduce output, it means that they now have spare capacity and may restart production within a month.
Along with commercial inventories, spare capacity is a market buffer.
Hi AlexS,
Yes If OPEC and non-OPEC cuts are 1.5 Mb/d and spare capacity was low before the cuts (say 1 Mb/d or less) then we would have 2.5 Mb/d of spare capacity. This is not very much by historic standards, so I think it will have little effect relative to falling oil stocks.
Bringing the 1.5 Mb/d back on line may be enough to meet the demand increase in 2018, unless lack of investment from 2014-2017 causes an increase in the World decline rate of post peak fields, in which case output might remain flat at 2017 levels.
I think World C+C output might increase back to 2016 annual average levels in 2018 and remain on plateau until 2022, then a decline in World C+C output is likely to begin, even with high oil prices.
How important is this going to look in a few months/years? And where’s oil price likely to go now?
Saudi Arabia, UAE, Egypt, Bahrain cut ties to Qatar
Qatar calls decision by Gulf nations and Egypt ‘unjustified’, saying allegations against Doha have ‘no basis in fact’.
The Saudi kingdom made the announcement via its state-run Saudi Press Agency early on Monday, saying it was taking action for what it called the protection of national security.
The three Gulf states gave Qatari visitors and residents two weeks to leave their countries, Reuters news agency reported.
Saudi also closed the border and halted air and sea traffic with Qatar, urging “all brotherly countries and companies to do the same”.
http://www.aljazeera.com/news/2017/06/saudi-arabia-uae-egypt-bahrain-cut-ties-qatar-170605031700062.html
It’s got MbS’s fingerprints all over it. Used to be the world would have looked to USA to smooth things over a bit, but I’d expect now they all hope Trump goes for another tub of Ben and Jerry’s and play’s golf for a couple of weeks.
Some background information on Qatar
Bloomberg https://www.bloomberg.com/quicktake/qatar-s-bets
Qatar is the world’s largest LNG exporter, in 2016 it exported 78 Mt, nearly 30% of Global LNG supply
Wood Mackenzie: https://pbs.twimg.com/media/DBh4kLsUQAE4Nkm.jpg
Qatar’s oil production ranks 10/13 in OPEC (0.6 million b/day)
Reuters: https://pbs.twimg.com/media/DBivZsFUQAElVQo.jpg
A bit more. First historical mention of the Qatar peninsula was by Pliny the Elder. He was a Roman Admiral who was an intellectual, recognized as such by the Roman command structure, and sent out sailing his fleet around exploring and recording. He was later killed by Vesuvius leading a rescue flotilla to try to evacuate Pompeii. (His nephew was Pliny the Younger, who carefully recorded the appearance of the Vesuvius eruption and so good was his description that such eruptions to this day are called Plinian.)
Mostly Sunni. 20% Shiite. 14% Christian, 14% Hindu. But this is skewed because of a population of 2.6 million, only 300K are Qatari. Gazillion expats.
12,000 man military, but a huge air base on Qatar territory run by the US.
Richest per capita country in the world. Likely most of the reason the Saudis hate them.
The rapid increase in Libya’s oil production is heading toward a hard ceiling.
Crude output in the politically fragmented country has more than doubled in the past year to exceed 800,000 barrels a day, according to the state-run National Oil Corp., as fighting and labor unrest at ports and fields have subsided. But with foreign staff of international companies staying away, analysts from Energy Aspects Ltd. to Wood Mackenzie Ltd. say Libya’s ability to pump more oil will soon reach a limit — and won’t be enough to upset an oversupplied market.
Libya’s output capacity has atrophied after six years of intermittent fighting that led most foreign oil workers to stay clear of the place. While local employees have continued to pump crude when security allows, they’ve been unable to keep up with maintenance or repair facilities damaged by looting or attacks, due to a shortage of equipment and training, Mallinson of Energy Aspects said.
https://www.bloomberg.com/news/articles/2017-06-04/oil-bears-can-t-count-on-libya-as-expat-exodus-hinders-recovery
Be interesting to see whether some of their reservoirs have been permanently damaged by all this stopping and starting – e.g. have they managed to maintain water injection and voidage replacement or have they been pulling too hard just to get production when they are able?
May be of interest:
http://oilpro.com/gallery/2357/33123/
Art Berman: Crude Oil Special
Erik Townsend welcomes Art Berman to MacroVoices. Erik and Art discuss:
Perspective on OPEC and the 9-month extension on production cuts
OPEC’s goal to keep a floor under oil prices
Positioning of oil traders since February
Reasons for lower oil prices
Putting U.S. production into perspective
Where does comparative inventory price Brent and WTI
Inventory data and forecasts
Impact of capital markets and central bank policy
Early recovery from oil price collapse
Correlation of U.S. debt to tight oil
Term structure of the crude oil markets
Art Berman starts with the unshakable assumption that shale is crap, and that assumption taints his analysis.
Take, for instance, this from slide 2:
What is of course omitted from this rather blatant example of historical revisionism is what I have boxed in red in the attached graph.
OPEC did not “do nothing” after oil prices collapsed in 2014. What OPEC did was to get in a price war with US shale producers. This was a calculated move. OPEC calculated that with a few months of low prices it could finish off the US shale industry. So it opened the taps, increased production by about 3 million BOPD, and further drove down the price of oil.
But OPEC miscalculated. US shale production wasn’t wiped out as quickly as it had hoped. US shale producers proved to be more resilient than OPEC had calculated. OPEC members began to suffer their own fiscal problems and the cartel was forced to relent.
But for Berman it would be unacceptable to admit that shale proved to be more resilient than he had predicted. His whole spiel, after all, is built on shale being crap. And so we get his blinkered version of events.
None of that has the slightest connection with what he actually said as far as I can see. It seems to be ‘something you prepared earlier’.
George Kaplan,
So then you believe what Berman said is true?
You believe, as Berman said, that, “At first, OPEC did nothing after oil prices collapsed in 2014”?
If so, then what is that increase in OPEC production from 36.72 million BOPD in Feb 2015 to 38.49 million BOPD in July 2015?
And furthermore, you believe, as Berman said, “When prices fell to $26 per barrel in early 2016, OPEC floated the idea of a production freeze and that established a floor from which prices increased to more than $50 per barrel during the first half of the year.”
If so, then what is that increase in OPEC production from 38.22 BOPD in February 2016 to 39.82 BOPD in November, 2016?
How do you explain the discrepencies between what Berman says and what the EIA is reporting?
Do you believe the EIA is lying, as some of the anti-goverment folks over at the sister peak oil sight, Our Finite World, claim, and that it is Berman, and not the EIA, who is telling the truth?
OPEC has underestimated the ability of shale companies to squeeze margins of the oil services sector, and the willingness of the banks, private equity funds and other classes of investors to finance the loss-making shale producers.
Nice ad hoc rescue there — an attempt to change the subject.
Nevertheless, Berman’s claims are false, unless you believe the EIA to be lying, as some of the folks over at Our Finite World believe.
Shale is crap just like sub prime was crap. It’s just not gone pop yet.
Pretty much that. Shale companies have not proven resilient. The Federal Reserve has. It’s borrowed money.
“What OPEC did was to get in a price war with US shale producers.”
Glenn,
From the pure market perspective this just does not make any sense. Why just against US shale? Why not against Angola? Or China? Or Denmark (I think they produce tiny bit of oil),or Venezuela, or Iran or Russia, or Azerbaijan.
You got identified with this “story” that you heard many times in the news. So, it is not your knowledge. It is borrowed knowledge. Someone on TeeVee told you this “story” and you are telling us the same story. You have to explain it why the oil price war is just against US shale?
Do you believe the graph I have attached might be the reason why OPEC perceived U.S. shale to be the culprit that caused world oil markets to crater?
Do you believe that OPEC’s calculus might have been influenced by the analysis of folks like Art Berman, who predicted that shale was a flash in the pan?
You know, Berman was far from being alone, There were many others (including me) who made the same prediction that Berman did. He’s not the only one whose predictions were proved wrong.
Glenn,
If two parties are in oil price war they don’t do traditional local sword dance together or buy billions $ of weapons or import oil from them.
Ves,
So then you believe what Berman said is true?
You believe, as Berman said, that, “At first, OPEC did nothing after oil prices collapsed in 2014”?
If so, then what is that increase in OPEC production from 36.72 million BOPD in Feb 2015 to 38.49 million BOPD in July 2015?
And furthermore, you believe, as Berman said, “When prices fell to $26 per barrel in early 2016, OPEC floated the idea of a production freeze and that established a floor from which prices increased to more than $50 per barrel during the first half of the year.”
If so, then what is that increase in OPEC production from 38.22 BOPD in February 2016 to 39.82 BOPD in November, 2016?
How do you explain the discrepencies between what Berman says and what the EIA is reporting?
Do you believe the EIA is lying, as some of the anti-goverment folks over at the sister peak oil sight, Our Finite World, claim, and that it is Berman, and not the EIA, who is telling the truth?
Glenn,
Why I would discuss with you about what Berman wrote? I did not read his articles for the last 2 years. For me everything is clear. You on other hand want to know icing of the cake or juicy details and dynamics how decisions are made in 2014 among world power elites including major oil producers.
First of all, it is irrelevant now because that is in the past. Second of all you cannot know details unless you stumble on Niami (ex Aramco chief) or Obama, or Ruhani (Iran prez) on a street and go for coffee with them and if they are willing to talk to you. How else are you going to know?
I am discussing with you what you wrote above about imaginary war between US shale and Saudi. If there is oil price war it is war among ALL oil producers. If every oil producer is suffering with low oil price how can you say it is only war between shale and Saudis?
Listen solution is very simple, if US, Canada, UK, Norway do not like the current price they can join participating OPEC and non-OPEC in oil production cuts or sell to the Martians for the higher price. But it is not so simple because this so-called oil price war is just extension of bigger war. So, oil producers are collateral damage.
Hi Glenn,
That chart looks like it is from the EIA’s DPR.
That data includes output from various “regions” and often includes output that is not LTO.
Chart below has data from
https://www.eia.gov/energyexplained/data/U.S.%20tight%20oil%20production.xlsx
Peak was 4.56 Mb/d in March 2015.
Hi Glenn,
You are correct that OPEC did not do nothing, they did the opposite of what many expected at the time. Most expected that OPEC would cut production to support prices, so when Berman says they “did nothing”, the clear implication (to me) is that they did nothing to support the price of oil. The did the opposite and increased output starting in April 2015 (at first they did do nothing as prices started falling in Sept 2014, so they waited 7 months before doing anything).
I also expected LTO output would fall much faster than it did and was surprised costs could be lowered as much as has happened (driving many service companies to bankruptcy).
You love to claim how low oil prices are a good thing, I believe the price volatility that is likely to result from a period where investment is very low will prove very disruptive.
Eventually the market will become balanced and oil prices will need to rise in order to have adequate World oil supply.
Another place where Berman plays fast and loose with the facts is on slide 6 where he proclaims:
I would offer two pieces of empirical evidence that contradict Berman’s claim. (There are others I could mention, but these two serve to illustrate my point.)
One is this graph which clearly shows the great improvement in well productivity which has been achieved in the Permian Basin.
The other is a graph that shows how rapidly drilling technology has advanced. The number of rig days required to drill a horizontal well has fallen markedly, in some cases by almost 50%.
Less rig days = lower cost
He clearly says that switching to pad drilling had a big impact, but the next increments are much less. ‘Most’ does not equal ‘all’, so nothing you say contradicts him at all, in fact it has little to do with anything he said. At least 80% of what he talks about has nothing at all to do with LTO, which is probably about as it should be given long term impacts on the world.
The above reductions in rig days have absolutely nothing to do with the efficiencies realized by pad drilling.
Note that the chart reads “spud to release” days.
In the old days, after a rig was released, it would have to be moved to a new drilling pad before a new well could be spudded. Depending on how long the move was, this could take several days. It involved trucking and fork lift cost, and the loss of several days of rig time while the rig was being moved.
In addition, the old way required the construction of a new drilling pad and mud pits for each new well, the laying of a water line to the rig, etc. These costs are now split between several wells.
With pad drilling, the rig is just skidded over and a new well is spudded.
What the above graph shows is the number of days between the time when a well is spudded and the time the rig is released. It has absolutely nothing to do with the efficiencies and cost reductions that are gained by pad drilling.
So what – the fact that he didn’t specifically mention something specifically in a long talk just means there were other things more important – he said pad drilling was the biggest impact – he didn’t say there was nothing else. He might not give a shit one way or the other, most people don’t.
George Kaplan said:
Well, exactly.
But for those who are actually in the shale oil business, and actually know something about the business, they care very much.
Every single rig day that can be shaved off of the time to drill a well is a signficant savings.
Decreasing drilling and completion times is key to bringing costs down, which is an important part of making the drilling economics of these wells work.
And of course we already know that Berman doesn’t “give a shit one war or another.” He’s already made up his mind before he even begins his analysis that shale is crap, and that the economics of drilling shale well can never be made to work.
And that’s the reason Berman’s analyses are shit.
You really don’t get nuance do you?
Berman is right. The cost of drilling oil and gas wells dropped ~55% and only now started to recover (+3.5% from recent lows)
Producer Price Index by Industry: Drilling Oil and Gas Wells Index (Dec 1985=100)
source: U.S. Bureau of Labor Statistics
Frac sand cost was down 30% (but has recovered by 10.5% by April 2017 vs. Nov. 2016)
Producer Price Index by Industry: Hydraulic Fracturing Sand, Index (Dec 2012=100)
source: U.S. Bureau of Labor Statistics
I’ve seen several estimates saying that about 75 to 80% of the decline in LTO production costs in 2015-16 was due to cost deflation (mainly drilling and services), the rest is due to technological improvements
Alex, Glen, Mr. Kaplan
There should be no doubt that at least 3 components are in play here with respect to shale economics …
Lowered prices paid to service companies (unsustainable)
Receptive atmosphere – on the whole – from financial markets to the industry
Technical improvements
There should be NO doubt whatsoever for anyone following the day by day developments that this industry has, and CONTINUES to implement products and processes that are bringing WAY more hydrocarbons to the surface than even two years ago … and doing it over an enlarging area.
The longest onshore lateral ever drilled – 19,300 feet, in 17 days, no less – was done a few weeks ago in Ohio … the Great Scott from Eclipse.
The tightening of perf clusters and stages, the near and far field diversion techniques, the newly introduced micro proppants, the fluid to fluid pressure transfer (Vorteq) being introduced by Schlumberger and Liberty Oilfield Services to protect frac pumps, and on and on.
These innovations are not immediately, universally embraced.
Heck, some don’t work and others are quickly superseded by even newer innovations.
Folks, there is a core reason why the “big” companies have floundered in this unconventional realm.
Nimbleness and astute embrace of “what works” is a prerequisite for success in this still- emerging field.
According to Berman there is absolutely no discernible difference between the performance of the larger firms and the supposedly nimble smaller ones from there financial reports (I think near the middle of the first broadcast). They both benefited pretty well equally from technology, cost deflation and whatever else has improved the costs over the past couple of years.
Mr. Kaplan
If the discernable difference refers to financial performance, I’ll not be able to comment as that is an area outside my interest.
However, the much stronger economic model of the majors would cushion them, to an extent, from the wildly fluctuating situation of the smaller independents who have – historically – been exposed to immediate monetary consequences deriving from day to day decision making.
However, if there is any statement that the ‘big boys’ have operational results commensurate with the nimble independents, that should be readily disproven.
Using Enno’s excellent site, check out BHP, XTO, Shell, ConocoPhilips, Statoil, Chevron in the Eagle Ford, Bakken, Marcellus.
You should readily see the vast differences in well performance from a host of smaller independents.
A good part of this is the quality of acreage the smaller companies have, but that, too, is a quintessential quality of being able to ‘hire an army of landmen and flooding the county courthouses the NEXT DAY’, as a CEO said years ago in the advantages of split second decision making and implementation.
This is an ongoing work in progress that benefits from minimal institutional encumbrances.
But there is nothing new about that, nor is it special to the oil industry or LTO, it’s just how small vs large enterpises function, there are pros and cons for each.
Exactly so, with – perhaps – a relevant qualifier.
Absent an ‘in place’ process to allow a bottom up operation to proceed and, maybe, encouraged, the big boys will never succeed in what is coming to be recognized as an emerging paradigm in the O&G world.
ExxonMobil paid almost $40 billion for Petrohawk years ago.
Kept it as a near autonomous entity, XTO, with mixed results.
Shell’s history is particularly telling as they seem to be granting their small Appalachian Basin operation free from to function as if they were an independent.
The CEO up there (SWEPI) said that the entire Shell organization is watching the AB folks in an attempt to apply this localized structure throughout the company.
Mr. Kaplan, to underscore the significance, take a pithy comment from a frac engineer years ago …
When a reporter asked the difference between Bakken wells and EF wells, his response was “The difference between EF wells themselves are huge, and – in fact – between individual stages within a single EF well”.
The vast heterogeneous nature of geology, techniques, hardware, emerging processes (micro proppants closely following the still-evolving diversion operations) portend success or failure on a compny’s successful embrace of all this.
Just wrote a detailed reply … lost it.
Extraordinary components including extreme heterogeneous nature of basins, processes, emerging technologies mandate successful adaption and implementation of best practices in a timely manner.
Failure is virtually guaranteed otherwise.
Per graph – drilling cost went from a high of about 455 to a low of about 290. A drop of 165, or about 36.2%. I do not “see” about 55%.
yeah it’s an easy mistake to make when you are in a rush.
(The index went up 50% from 2010 but down only 33% from 2014).
Apologies, the decline from high to low for drilling cost index was 36.7%
Have had a problem from day one with these “service company cost cuts”.
What’s the theory? The oil producers were allowing themselves to be gouged by the service companies in 2014? Who now decide to gut themselves so producers can still have a loss? How does this work? Who took the pay cut to fund the cost decrease? Why did they allow gouging in 2014?
Look, it’s all crap. If “breakeven” is declared by leaving out costs in the calculations, there’s no real reason why some of those excluded costs can’t be service company costs. Leave out some of those and you can pretend to have decrease in cost to justify the breakeven price that was incorrect to begin with.
EOG runs a loss. CLR runs a loss. Whiting runs a loss. Oasis runs a loss.
It’s all lying.
It would be nice to see a graph, by year, of the average length of the lateral. Likewise, a graph, by year, of the average tons of sand used per well. I beleive that there still is a significant productivity increase, but in some cases, the laterals have doubled and the sand has more than doubled.
As an analogy, I could claim that the productivity in my transportaion business tripled. How did I do that you ask. Well, I replaced my $50,000 vans that could haul 10 people, with $$150,000 buses that can haul 40 people.
There’s actually been a productivity decrease.
A decision was made to switch from ceramic proppant to sand. The ceramics for years came from China. Switched over about 2012 or 2013. Flow decreased, and was camouflaged by longer laterals (increased stage counts), but make no mistake, ultimate recovery is down stage per stage vs ceramics.
Oh and btw, re the Statoil Assay, the Bakken doesn’t flow API 39 oil anymore (if it ever did). It’s now 42-43 and that means scarce middle distillates. It’s not very valuable vs, say, Ghawar or Louisiana Light Sweet, which have proper diesel/kerosene content. This should undo all historical comparisons, but it won’t.
(Buses run on diesel)
Clueless
There seems to be a growing desire to learn those metrics, particularly length of lateral, but there is no simple source for that information.
Although many on this site deride the companies’ ongoing presentations, they regularly provide a wealth of current data, including proppant amounts and lateral lengths. (Precise proppant amount, type, size as well as fluid amounts can be found at Fracfocus.org on a well by well basis).
Lateral length is a particularly significant aspect as Appalachian Basin operators claim significant (33% +/-) savings for drilling costs when they go 10,000′ or more.
From Pioneer’s June investor presentation.
Here are the sources Pioneer uses for the graph:
1) Source: IHS Energy Blog “The Permian Basin: A magnet for risk capital” January 31, 2017
2) Drilling and completion costs per perforated lateral foot; represents all PXD horizontal wells in Spraberry/Wolfcamp since Q4 2014
Those cost reductions come in spite of Pioneer using Version 3.0 completions on its more recent wells, which come at a cost of about $1 to $1.5 million over Version 1.0 completions.
Hi Glenn,
Note that the cost is in well per foot. The reduction in costs is due to lower service cost from 2014 to 2017, the service costs will rise as activity increases and well costs will start to rise. This will reduce profits for any given level of well productivity, and any further increases in well productivity will require version 4, 5, and 6 all of which will be more expensive than the previous version.
Economists have a theory about this called the law of diminishing returns, well productivity in output per dollar of capital spent on the well, or better the NPV of well output will reach some maximum (probably by 2019) and eventually the sweet spots will become saturated with wells and well productivity will then decrease. That is likely in the Permian by 2021 (or perhaps sooner, it will depend on the rate that wells are completed annually).
The faster the ramp up, the sooner the peak is reached, just like the Bakken and Eagle Ford. These older plays might attain a secondary peak, but it will only be marginally higher than the initial peak (200 kb/d more for the Bakken and maybe 100 kb/b at most for the Eagle Ford, though for the Eagle Ford a new peak probably will not be reached ).
The Permian has some room to run, maybe 2 Mb/d above the 2016 average level, by 2023.
Scenario below is my best guess for US LTO for the given guess at future oil prices (right hand axis). The wells required would be about 125,000 wells competed in the LTO plays (at about $10 million per well) so $1.25 trillion (2016 $) in capex over 10 years or about $125 billion per year.
Don’t forget the 5 Mb/d of non-LTO US output will likely be declining at 4%/year so by 2023, this is about 1.25 Mb/d, so the net increase in US C+C output is about 0.75 Mb/b above the April 2015 level (Jan 1972-March 2017 US C+C peak) of 9.627 Mb/d. This would be a new US monthly peak of 10.4 Mb/d (if actually reached), surpassing the Nov 1970 peak of 10.04 Mb/d. It will be short lived, if attained, with LTO output falling by 4.5 Mb/d from 2023 to 2032 and overall US C+C falling by 5.7 Mb/d to 4.7 Mb/d in 2032.
Dennis Coyne says:
“The Permian has some room to run, maybe 2 Mb/d above the 2016 average level, by 2023.
You seem to not be aware of the vastness of the Permian Basin shales.
In a recent study, BTU Analytics pegged the size of the Delaware Basin at 8465 square miles, and that of the Midland Basin at 7,385 square miles.
https://btuanalytics.com/how-big-is-the-permian-basin/
But that’s hardly the end of the story. Since there are as many as 16 stacked plays in the Delaware Basin, and 10 in the Midland Basin. the effective horizontal area of the Permian Basin is about 210,000 square miles.
On 140 acre spacing, that’s enough to drill about 950,000 wells.
If we trim that down to what BTU Analytics says are the core areas of the plays — 38% of the gross area — where produers are currently aggressively drilling, that brings us down to about 80,000 square miles.
And if we trim that down further to allow only for the three resource benches that Pioneer is now concentrating on in the Midland Basin, and the four zones that most operators are concentrating on in the Delaware Basin, that brings us down to 21,286 square miles of effective horizontal acreage.
On 140 acre spacing, that’s enough to drill about 100,000 wells. That, unless the price of oil craters again to sub-$40 levels, is probably the worst-case scenario for the Permian Basin.
One must recall that there are only about 11,000 wells in the state of North Dakota, and the Eagle Ford only has about 18,000 producing wells.
So the pre-2015 runup in production from those two plays was achieved with about 30,000 wells.
On top of this, the production levels achieved in North Dakota and the Eagle Ford in the pre-2015 period were achieved with wells that had an average well productivity which was only a fraction of those currently being achieved from shale wells in the Permian Basin.
Hi Glenn,
The Permian wells are not likely to be much better than the Bakken wells, your 100,000 well estimate sounds possible and I am well aware of the statistics on the Permian Basin, the USGS has the TRR at about 28 Gb, the economically recoverable resources (ERR) will be less.
For the Permian Basin 2016 wells the average 12 month cumulative is 119 kb. For the average Bakken 2016 well cumulative output at 12 months is 120 kb. For the Eagle Ford average 2016 well cumulative 12 month output is 97 kb.
Another problem for the Permian Basin is that 29 billion barrels of oil have already been extracted over the past 90 years, there might be another 29 billion barrels of oil, but how quickly it can be extracted is an open question.
Under reasonable economic and oil price assumptions about 19 Gb of LTO oil is extracted from the Permian LTO from 2005 to 2040, 8 Gb is extracted from the Bakken (North Dakota), 7.6 Gb from Eagle Ford, and 6 Gb from other US LTO plays.
My model has 80,000 total horizontal wells drilled in the Permian basin (with 12,000 completed through the end of January 2017). Eventually well productivity increases will slow down, as has already been seen in the Eagle Ford from 2015 to 2016 (increases in average well productivity were quite small only a 3% increase over the first 12 months). This after only 5 years of rapid development, so we might see something similar in the Permian basin, perhaps by 2020 or 2021.
See
http://peakoilbarrel.com/future-us-light-tight-oil-lto-update/
Dennis Coyne said:
“For the Permian Basin 2016 wells the average 12 month cumulative is 119 kb. For the average Bakken 2016 well cumulative output at 12 months is 120 kb. For the Eagle Ford average 2016 well cumulative 12 month output is 97 kb.”
Well yes, Version 2.0 and 3.0 completions have also been used in the Eagle Ford and Bakken, and with spectacular results. And this is in spite of the fact that these are much more mature basins with far fewer opportunities for high-grading.
But what did those first year well cumulatives in the Bakken and Eagle Ford look like back in 2011? In 2012? In 2013? In 2014?
That 2.4 mmbopd in production, after all, was achieved between 2008 and 2014, and using Version 1.0 completions, not Version 3.0 or Version 4.0 completions.
.
–
Hi Glenn,
The more wells that are completed the more difficult it is to increase output further because the decline rates are so rapid. Eventually the sweet spots run out and well productivity will start to decline, this is universal in any oil field. It is why output in any given field always peaks, sometimes plateaus for a few years (very few in the case of small fields) and then declines. You will notice that my US LTO scenario has a peak that is about the same level as the EIA’s AEO 2017, the difference is that I don’t expect the 15 year plateau that the EIA predicts. That is just wishful thinking and requires about 100 Gb of LTO, which won’t happen at $120/b (in 2016$).
Dennis,
The wells currently being drilled in the Bakken and the Eagle Ford run circles around those drilled several years ago.
The well productivity in these mature basins has not declined, but on the contrary has greatly increased.
How do you explain that using your theory?
clueless,
Here you go.
.
–
BTW concerning Qatar.
If trends hold we’ll see that KSA is the 4th largest oil consumer in the world next week.
Quite a bit of their power generation is oil fueled generators.
Natgas producers US, Russia, Iran, Qatar and KSA a distant 9th.
KSA’s hopes to sequence to natgas power plants just slowed down. They weren’t going to get any from Iran, who they hate. Now, not Qatar either.
They’ll burn more oil, though this probably only serves to accelerate Apocalypse, rather than raise price, since they don’t really have to restrict exports to burn more.
I’m not sure, but it seems that KSA is not currently importing Qatari gas. Or at least is importing relatively small quantities. That seems strange, as it would cost less than burning their own oil for power generation.
Just scoped.
KSA burns about 6% more natgas than they produce, but oddly list themselves with zero imports or exports.
4th largest natgas consumer in the world, 8th largest producer.
The faith in non-opec supply is strong…any tension in the middle east in fhe last years would have caused oilprice spikes, now nobody cares.
Useful to keep in mind that as central banks have printed from thin air trillions upon trillions of dollars, euros and yen, and those units of money were the metric for oil, maybe they no longer are.
No physics reason they should be. Those units have been exposed as purely whimsical. Its all collective counterparty consent, that itself doesn’t have any basis in physics.
Worth reading.
This is how Big Oil will die – Seth Miller – Medium
Agreed. A 5-minute summary of Seba!
amazing!
there will be 100 million self-driving cars in the USA by 2023!
and they will be so cheap!
I can’t wait!
Yes, excellent write-up Boomer. Seems to be on solid footing to me.
U.S oil production has increased by nearly 1 M/d in 9 months.
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCRFPUS2&f=W
So it has already increased by well more than 500,000 year on year.
This future estimate may well be on the optimistic side, but considering how wrong naysayers have been about production in nearly every region I would not dismiss it outright.
https://www.eia.gov/todayinenergy/detail.php?id=27612
Russia has huge shale resources, it will only be time before they learn how to develop it.
https://www.ft.com/content/993512c6-c609-11e6-9043-7e34c07b46ef
At the moment no one can make any firm peak oil prediction.
By the end of 2019 OPEC spare capacity will be gone and then things will start to get interesting.
I suggested Russia had a lot of shale resources here once and got shot down in flames by people who seem to know what they are talking about. Apparently the rock isn’t so good for fracturing, if I remember correctly (something similar to China maybe where it’s too maleable to break).
Hi George
Are they the same people who said U.S. shale oil would only last a few years?
It is still early days for Russian shale, we will have to wait and see.
Hi Jan,
The resource is large, though they have not focused on it much as there is plenty of conventional resource that can be extracted far more cheaply.
I believe Alex S has commented to that effect in the past, though I may not be remembering correctly.
Doug is the Bhazenov guy. Clay content is the why, as I recall. As you said, bends and doesn’t frac.
My recall also is that we must not declare gazillion square miles of rock to all have this issue.
And . . . Russia has been fracking longer than the US and doesn’t have to learn anything so that guy above needs to recalibrate. Expertise did nothing. The Fed’s 0% interest rate was a different expertise.
Watcher
Russia have been fracking longer than the US?
Really when did they start then? Before 1949?
http://aoghs.org/technology/hydraulic-fracturing/
and how advanced are their horizontal drilling technology?
This came up before. The Soviets were fracking all the way back to the late 40s and 50s. It was not new to them. You can search for it. It’s out there somewhere, but a cursory look runs afoul of google page after google page of conspiracy theories about Russian money funding anti fracking protests.
The expertise is only American theory just doesn’t work anymore for more or less anything. Rosneft is huge. If they need expertise and don’t for some reason already have it, they buy/hire it and then they do. You can put that American technology concept to bed.
Watcher obviously knows more than Gazprom Neft director of exploration.
“It’s not a question of will we do it or not: it’s a question of time,” says Alexei Vashkevich, the company’s director of exploration. “It might take a little bit longer but we will get there.”
In other words Russia is somewhat behind the US in fracking experience and technology.
but what would he know next to you?
Hi jan,
There is more than one way to interpret that quote.
He could mean that the Russians have plenty of conventional gas and they don’t really need the shale gas right now. They will get to that when they need to.
I do agree that it is likely that there have been innovations in the US that have not been necessary in Russia because their remaining conventional oil and natural gas resources are far larger than in the US.
Alex S knows far more than I do as I believe he might be from Russia or at least he may be able to read Russian so he has access to more information than I do.
Hi Jan,
Of course nobody can make a firm peak oil prediction. It will depend on oil prices, politics, technological development, concern over global warming, and many other factors (the World economy).
I would say 2020 to 2030 is about the best one can guess. The LTO resources are not unlimited and they are expensive, Russian LTO might reduce the overall World decline rate a bit, that is all. Kerogen will never be a viable resource, oil sands will be slow to develop and expensive (CAPP estimated a 2 Mb/d increase in Canadian oil sands output from 2016 to 2030 in its June 2016 report).
I agree 2020 to 2030 will be very interesting. The question will be, how long can a plateau be maintained or possibly how fast will the decline in output be? My guess is a 5 year plateau followed by 1 to 2% annual decline in World C+C output from 2025 to 2030.
The weekly estimates for US output should be ignored, they are often wrong by 200 to 400 kb/d.
Looking at the monthly estimates from the past 9 months (July 2016 to Match 2017), the increase in C+C output has been 400 kb/d and about half of this has been from increases in the Gulf of Mexico. The annual average increase in US C+C from 2016 to 2017 (average for 2016 compared to the average for 2017) will be under 500 kb/d. The 2016 US average C+C output was 8.875 Mb/d, I expect the 2017 US annual average output will be under 9.375 Mb/d.
Note that the most recent 12 month average US C+C output was 8.878 Mb/d (Feb 2016-Mar 2017), similar to the 2016 average output level.
Output will increase, but not as fast as many seem to believe, my guess is 400-500 kb/d (2016 average to 2017 average).
Demand is the key.
Oil’s been priced out of all markets except transportation already, way back in the 1970s.
It’s cheaper to run ground and sea vehicles on batteries than on oil.
Upfront vehicle costs are equalizing as EVs reach large scale production.
So oil demand can be predicted by predicting EV production levels. So far the best prediction I have for that is a mindless exponential projection of 50% EV production growth per year, but I wish I had a bottom-up projection.
Jan,
Not to be forgotten is China, with its huge shale gas resources.
According to an ancient and outdated EIA study (2011 – 2013), China had the largest shale gas resource in the world.
https://www.eia.gov/analysis/studies/worldshalegas/
China too, it appears, will eventually “get there.”
This from a recent article in the Oil & Gas Journal:
China’s shale gas production outperforms expectations
http://www.ogj.com/articles/2016/11/china-s-shale-gas-production-outperforms-expectations.html
But another reason to keep prices down, if China can reduce imports.
Glenn said:
Glenn has 100% commonality with people such as Trump — they can never admit they were wrong about anything.
In this case, Glenn will never admit that the Peak Oil phenomena was predicted correctly years ago, and so goes off with the same old shtick on a new topic, trying to pull the rug over everyone’s eyes.
The Peak Oil soothsayers have been prophesying the imminent demise of the Age of Oil for almost 20 years.
In 1998, Colin Campbell published The Coming Oil Crisis and in 2000 convened a network of “interested scientists and government officials” that called itself the ASOP and began to advocate the theory of peak oil.
And yet here we are in 2017, and peak oil still has not occurred.
But even more stunning is the fact that the United States is on the cusp of blasting through it’s previous oil production peak, which was set in 1970.
One would think that the peak oil prognosticators, after having been so wrong for so long, would have become a little bit more modest, not so violently certain in their predictions.
But no, with a few isolated exceptions, just the opposite seems to be occurring.
See what I mean? Glenn is no different than Trump — unable to admit that he was wrong.
And it’s such a simple thing to realize — that non-renewable natural resources such as fossil fuels are finite in scope. It should be easy to admit, but Trump-like people have a psychological disorder.
I thought this thread was to discuss the nuts and bolts of the oil and gas business, not these sweeping, overarching theological and philosophical arguments about beliefs, values, fears, prejudices, reflexes and commitments.
You have no clue what goes into a deep analysis of oil depletion.
All you are doing is cherry-picking results in a desperate attempt to show yourself to be correct. Like Trump you are showing a level of aggrievement that gets in the way of objectivity.
Hi Glenn,
It is quite possible that the US might surpass it’s previous peak by 500 kb/d, but it will last a year and then be followed by decline. For the World a couple hundred billion barrels will have very little effect on the peak date, but might mitigate decline a bit.
A good paper at link below
http://rsta.royalsocietypublishing.org/content/372/2006/20130179
and also
http://www.ukerc.ac.uk/publications/global-oil-depletion-an-assessment-of-the-evidence-for-a-near-term-peak-in-global-oil-production.html
It is pretty likely we will see a peak between 2020 and 2030 according to these authors.
Bloomberg Briefs, energy capex, charts on twitter, direct links…
Global oil & gas capex, BofAML: https://pbs.twimg.com/media/DBo50ntXoAA80ZY.jpg
Global renewables capex: https://pbs.twimg.com/media/DBlLd6jXYAEBo_O.jpg
.
Houston economy still waiting for oil – Houston Chronicle
U.S. oilfield service firms lag shale recovery; old deals hold | One America News Network: “Law firm Haynes and Boone LLP said the U.S. oilfield sector experienced 127 bankruptcies between 2015 and April 2017.
Among the 10 largest oilfield service providers, just five were profitable last quarter, the same number as a year ago. In contrast, seven of the top shale oil producers posted a first quarter profit, up from just one a year ago.”
Hi Boomer II,
There could be a shortage of service providers which will drive up costs for those services. The first quarter producer profits may only last a short time if oil prices remain flat.
http://www.zerohedge.com/news/2017-06-06/more-solar-jobs-curse-not-blessing
“In reality, it’s not a good thing at all, and certainly not a positive trend. In fact, as Climate Depot and the Washington Examiner point out — citing an American Enterprise Institute study — the job numbers actually underscore how wasteful, inefficient and unproductive solar power actually is.
That is glaringly obvious when you look at the amounts of energy produced per sector. (This tally does not include electricity generated by nuclear, hydroelectric and geothermal power plants.)
398,000 natural gas workers = 33.8% of all electricity generated in the United States in 2016
160,000 coal employees = 30.4 % of total electricity
100,000 wind employees = 5.6% of total electricity
374,000 solar workers = 0.9% of total electricity”
government at work?
I looked at the article, and without a breakdown of what those solar workers are doing- whether they were installing and manufacturing panels, say, as opposed to all 374,000 with feather dusters cleaning panels- these numbers are meaningless.
Of course, you didn’t do any math, or think about what the different types of energy jobs entail…you cut and paste and throw in a snide, unsupported comment.
And an Emoji.
Shale Oil Capitalism at its finest.
I doubt solar and wind components will be manufactured to any large degree in USA. Mexico and other post China nations seem more likely. USA jobs will be in installing and maintaining the imported equipment.
The advantage of installation jobs is that they can’t be outsourced. They have to be done at site.
Here’s the breakdown.
“More than half of all US solar jobs were in the installation segment; followed by manufacturing (15%), project development (13%), sales-and-distribution (12%) and other categories such as research-and-development (6%).”
Installation could be considered similar to infrastructure jobs. Once the project is finished, the labor required will be minimal. So the needed labor per energy generated should go down considerably once most houses and buildings have solar panels on their roofs.
The operative theory behind wind and solar…….
“If the Treasury were to fill old bottles with banknotes, bury them at suitable depths in disused coalmines which are then filled up to the surface with town rubbish, and leave it to private enterprise on well-tried principles of laissez-faire to dig the notes up again (the right to do so being obtained, of course, by tendering for leases of the note-bearing territory), there need be no more unemployment and, with the help of the repercussions, the real income of the community, and its capital wealth also, would probably become a good deal greater than it actually is. It would, indeed, be more sensible to build houses and the like; but if there are political and practical difficulties in the way of this, the above would be better than nothing.” – John Maynard Keynes
The General Theory of Employment, Interest and Money
This is a dialogue pair.
It doesn’t actually address the line of discussion.
Meanwhile, Just like Trump promised, coal has staged quite a comeback.
If the nonsensical, counterproductive subsidies for wind and solar are eliminated and the EPA defanged, as Trump has promised, coal should be in for quite a 21st century renaissance.
.
For a guy promoting fracking, I am surprised you are cheering coal over natural gas.
Cheering Trump is the priority. Fracking is just one of the means to that end.
Yes, so I have figured. And I am skeptical about the rah rah royalties stuff. The comments don’t add up.
Why cheer low oil prices?
Why cheer increased coal use if it cuts into natural gas use?
Glenn claims to get a royalty check in the mail and thus all must be right in the world; Morning in America, The Best is Yet to Come, that kinda thing. It’s pathetically simplistic.
Why cheer increased coal use if it cuts into natural gas use?
Because Glenn is not rational.
Glenn cheers for a snowflake President who steals from a pediatric cancer charity.
https://www.forbes.com/sites/danalexander/2017/06/06/how-donald-trump-shifted-kids-cancer-charity-money-into-his-business/#72f56d26b4a3
Hi Survivalist,
The politics belongs in the non-Petroleum thread.
Thanks.
Boomer II,
I promote those things that increase the prosperity, individual freedoms, sovereignty, and wellbeing of the people.
Do you hear the people sing?
https://www.youtube.com/watch?v=4Tl39bi5kAA
Hi Glenn,
Politics should be in non-Petroleum thread only.
Thanks.
Hi Glenn,
Politics should be in the non-Petroleum thread.
Looks like it’s coal at the expensive of natural gas. Not so good for those oil and gas guys, is it? Oops, there go those royalties.
Yawn
http://energypolicy.columbia.edu/sites/default/files/energy/Center%20on%20Global%20Energy%20Policy%20Can%20Coal%20Make%20a%20Comeback%20April%202017.pdf
This graph from the study you link should scare the bejeebers out of the Democratic Party.
The white working class, once the exclusive property of the Democratic Party, is now up for grabs.
But it wasn’t the shift in the white vote that put Trump in the white house.
It was the shift in the black and latino vote.
Without the shift in the Hispanic vote, trump himself has admitted that he would not have won Florida, and therefore lost the election.
Hi Texas Tea,
Discussion of wind and solar should be in non-Petroleum thread. In fact even coal discussions should be in the non-Petroleum thread.
Renewables are growing. Countries and companies are moving in that direction. It’s really too late to stop the trends now. It’s like trying to stop the Internet. Once people saw the potential, they began to incorporate it into their lives and their businesses.
Venezuela item. Refinery complex at Puerto de la Cruz 10.5 Billion is said to be on schedule for first use 12 months from now. It is designed (by the Chinese) to be able to refine the ultra heavy Orinoco oil. This will end reliance on US refineries and further eliminate foreign currency involvement and not incidentally US leverage.
Maduro can hold off a referendum/recall to 1 Jan and thus ensure his Vice Prez takes control at that time, retaining power for the party. As of right now, Maduro’s popularity numbers exceed those of several other Latin American presidens.
The refinery is a big deal.
Nigerian Forcados Oil stream back after 15-month halt caused by sabotage. Shipments this month will average about 250,000 barrels a day, according to a loading program obtained by Bloomberg.
https://www.bloomberg.com/news/articles/2017-06-07/nigeria-s-forcados-oil-comes-back-in-fresh-blow-to-opec-curbs
“Caelus postpones appraisal well for big North Slope oil discovery”
Not looking so good for the ‘biggest’ recent oil discovery. I’d say they haven’t been able to find anyone who buys their hype and is prepared to back them at current prices. They should have flow tested the previous wells when they had the best chance.
“Last October — with great fanfare — Caelus Energy announced it found 6 to 10 billion barrels of oil beneath the North Slope’s Smith Bay, about 2 billion barrels of which is recoverable. If developed, the company said the field could increase the amount of oil going down the Trans-Alaska Pipeline by nearly 40 percent.
At the time, the company said it would release crucial final tests on the discovery in 2018 after drilling an appraisal well this winter. But today, Caelus spokesperson Casey Sullivan confirmed that those plans have changed.”
http://www.alaskapublic.org/2017/06/05/caelus-postpones-appraisal-well-for-big-north-slope-oil-discovery/
Is there any chance this post can go back to hydrocarbons only instead of all the part political broadcast crap?
Hi George,
I agree.
Politics belongs in the non-Petroleum thread.
Those who cross this line too much will be banned.
Thank you.
Yes, please.
I come here to get accurate info on oil and gas. I want to avoid the other stuff.
Op-Ed: Global Oil Market Trends, US Production Stump OPEC Strategy
http://www.rigzone.com/news/article.asp?hpf=1&a_id=150467&utm_source=DailyNewsletter&utm_medium=email&utm_term=2017-06-07&utm_content=&utm_campaign=feature_1
Glenn,
That is garbage article.
from article “Producers in Texas and across the U.S. will GLADLY take the market share …”
Why you should be concerned for the market share when scarping the bottom of the barrel of the finite product? You should be concerned for the price. Oil producers are not in business of producing “renewable” Bananas or Kiwis that grow every season. When oil product is gone it is gone.
Ves,
You’re arguments are more lawyerly than those the Pure and Humble lobbyists and attorneys used to push through the Connally Hot Oil Act in 1935.
Glenn,
Today oil is 5% down, $45 handle, how is that market share working for oil producers?
Someone has to be sane to see this insanity.
So you believe the government should step back in like it did in the 1930s and promulgate proration schedules, mandating allowables as to the maximum each well can produce?
That’s what the Pure and Humble lobbyists and attorneys argued back in the 1930s, all for the professed purpose of conserving limited and scarce natural resourses. Price fixing, of course, had nothing to do with it.
You could be right. With the advent of the shale revolution, it looks like the US’s role as swing producer may have been resotred, and it’s the US that now has the pricing power once again.
But the US isn’t using that pricing power to maximize profits for producers. And if oil becomes a low-profit or no-profit business. that changes the future, too. That’s what some folks are counting on. The oil will be there, but there won’t be the money to get it out of the ground.
In my area there is no longer talk of a boom because all the focus has shifted to the Permian, where it’s supposed to be more cost effective. I have no complaints that activity has slowed in my area. And I have no complaints that Arctic projects have been shelved because the risks and the costs are too high for the possible results.
Low oil prices certainly puts a damper on certain projects. Oil’s problem right now is of its own making. More oil on the market than is needed.
Hi all,
A new post is up (It is an Open Thread for Petroleum comments)
http://peakoilbarrel.com/open-thread-petroleum-june-7-2017/
The “Non-Petroleum” Thread is on the EIA’s Electric Power Monthly
http://peakoilbarrel.com/eias-electric-power-monthly-may-edition-with-data-for-march/