The OPEC Monthly Oil Market Report is out production data for January 2018. All data, unless otherwise noted, is through January 2018 and is in thousand barrels per day.
OPEC crude only production has held steady for three months. However, this chart masks the fact that November production was revised downward by 45,000 barrels per day and December production was revised downward by 107,000 barrels per day. January production was 76,000 barrels per day below last years 12 month average of 32,378,000 barrels per day and 247,000 barrels per day lower than OPEC’s 2016 12 month average of 32,549,000 barrels per day.
OPEC oil production was down just 8,100 barrels per day in January. November production was revised down 45,000 bpd and December production was revised down by 107,000 bpd. The largest revisions were for Venezuela. Their production was revised down 28,000 bpd in November and 98,000 bpd in December.
Algeria, like at least 8 other OPEC countries, is in continuous decline.
Angola peaked in 2008 at a 12 month average of 1,870,000 barrels per day are currently about a quarter of a million barrels per day below that number.
Ecuador’s crude oil production increased steadily for four and one-half years, from mid-2010 to January of 2015 and has been on a bumpy decline for the last three year
Equatorial Guinea’s chart speaks for itself. I really don’t know why they joined OPEC. Their production is clearly in decline but is not enough to make much difference either way.
Everything I said about Equatorial Guinea can also be said about Gabon.
Iran is obviously ignoring any OPEC request to cut production and are producing every possible barrel they can.
Iraq’s 12-month average peaked, so far, last year, at 4,440,000 barrels per day. Their January crude oil production was 5,000 barrels per day below that average. Are they deliberately cutting production? If so, not by much.
Kuwait’s chart looks strange to my eye. I believe Kuwait is one of two, and possibly three, OPEC countries that could increase production somewhat. The others are Saudi Arabia and possibly the United Arab Emirates.
Libya is struggling. If peace ever breaks out in Libya they could increase production somewhat. But peace doesn’t seem to be on the horizon in Libya.
Nigerian crude oil production has a general trend, down. How much of this trend is due to political problems? Some of it, no doubt. But definitely not all of it.
Qatar peaked in 2008. And I won’t say “so far” here. They are clearly in decline.
Saudi crude oil production has been holding steady for 13 months now. Saudi is the only OPEC nation that could increase production by any considerable amount. They could possibly increase production from one quarter to one half million barrels per day. But likely a lot closer to one quarter million per day… possibly.
The UAE is one of the other two OPEC nations that just might be able to increase production somewhat. But I have more doubts about the UAE than I do about Kuwait.
Venezuela is in the grasp of a full-fledged collapse. Their production has fallen 273,000 barrels per day in the last three months. Their November production was revised downward by 28,000 barrels per day and their December production was revised downward by 98,000 barrels per day.
Venezuela is in danger of becoming a totally failed state, like Somalia. The worse things get, the worse things get. That is falling income from oil exports increases the chance that production will continue to fall. All income from exports will have to be used to keep the public from total rebellion and none will be left for the oil fields.
Looking at a zero-based chart puts OPEC crude only production in a much clearer perspective. 2018 on this chart is January only. The point here is that so-called “OPEC cuts” are not making very much difference. World oil production is on that proverbial bumpy plateau.
Saudi, Kuwait and the UAE began to increase production in May of 2016 and peaked in November of that year. The other 11 OPEC countries peaked in July 2017, seven months after the OPEC cuts began. They were all, at that time producing flat out. And in my opinion, still are.
Although the three OPEC countries, Saudi, Kuwait and the UAE, are likely capable of increasing production, they, in my opinion, can in no way increase production to what they were producing in late 2016. That was a period where they made heroic efforts to increase production in order to establish a point from which they could “cut” production. That level was then, and is now, unsustainable.
And if you remove Venezuela from the mix, then the combined production of the other 10 are at an all-time high, or nearly so. The increase in production of the countries represented in this chart, for the last two years, has been all Iran recovering from sanctions and Libya recovering from rebel attacks. Iraq has been relatively flat over the last two years and everyone else has declined.
OPEC production in the above chart is crude only. It does not even include condensate. But world supply here is total liquids. So they are comparing apples to oranges. Natural gas liquids have increased, in the last few years, have increased far more than crude oil alone.
The above chart is from the EIA and is only through October 2017. World C+C has been on a bumpy plateau since July of 2015.
This is Russia thru January 2018. The data is from the Russian Minister of Energy. The data was in tons and I am using a conversion factor of 7.3 barrels per ton.
Algeria and Qatar both look like they might be starting to accelerate in decline – neither have had many big recent start-ups and the newer stuff that came online a few years ago, and managed to maintain a shallow decline against the depletion of the really mature fields, are likely to come off plateau soon.
Ecuador has had local shut downs from demonstrations so is likely to decline further in February.
Angola is likely to hold plateau for two more years with Kaomba starting up but then is virtually certain to hit at least 10% decline rates.
I think Nigeria is about at its maximum possible at the moment without shutdowns except for poor availability as their onshore infrastructure is falling apart and from pipeline thefts, but will add 200 to 350 over the next few years from new offshore projects; but their older FPSOs are about to start more rapid decline, so I don’t know what the net result will be.
It would be interesting to know how much of Venezuela upgrader capacity is still available – I think they had 800 kbpd in 4 cokers but wouldn’t be surprised if they are down to 200 or less net (i.e. with poor and declining availability). Once it’s all gone maybe the decline will slow down.
At some point one or more of the countries that rely on oil for almost all their foreign income and have declining exports are likely to tip over into something like Libya or Venezuela, that may be delayed with increasing oil price, but not for ever.
There are four upgraders. They have downtime, you can use 600kb/d of output for a round figure. The Petromonagas upgrader makes unstable synbit, the other three add more hydrogen, make a range from 24 to 38 API. Not all of the oil has to be upgraded, but the light crude production is cratering.
I don’t think Venezuela will be like Somalia, because the communists do have a very effective repression machine, they simply don’t care if people starve or if they have to mass murder to keep them more or less in line. The repression machine they have is an undisciplined version of what the Castro Mafia uses in Cuba: secret police with informants, regular police, and brown shirts (these are civilian clothed parapolice who play act as “outraged citizens” and beat, knife, and occasionally murder dissidents or anybody who protests). The military stays out of the way in Cuba, but in Venezuela the national guard has always been responsible for police response in rural areas or in cities when action gets heavy.
Lately the secret police has been waging a terror campaign, they kidnap individuals and make them disappear. This is also in line with Castroite practice (I believe I mentioned before my uncle was “disappeared” and taken to a death camp in Cuba by Castros police, but my mom managed to rescue him before he was killed).
I believe it’s possible to get the communists out, but it will require organizing a liberation army with venezuelan volunteers. 20 thousand should do it, but to get the country under full control it will be necessary to have a 500,000 strong police force using Venezuelans backed by outside air and naval support (I’m thinking of drones, a couple of Spectre gunships, a few ships able to control the coast and cut off supplies to surviving pockets of communist guerrillas coming from Cuba, and a some lily pads with helicopters and a good counterinsurgency drone fleet).
Ron:
Saudi’s and their compatriots pushed all the oil out of storage as they were negotiating the output cuts 2 years back in order to justify high output terms.
Yeah, that’s been my argument all along. But the game was only played by Saudi, Kuwait and the UAE. Iraq did increase a little but not enough to make much difference. Those three countries that did cut, could increase production for a short time, just like they did in the last half of 2016. But they could not maintain that level for very long. They are, for all practical purposes, producing flat out.
It was only a few % increase. You can do this for a few months simply by delaying maintainance intervals here, opening valves a little bit more there.
If it is only for a few months.
On the other hand: I don’t believe anybody they have big amounts of spare capacity left. Spare capacity costs money and brings not much – so why spend billions to do extra infill drilling, or tap a new field without producing the oil?
Spare capacity was easy with the old gulf giant fields, especially Ghawar before it needed secondary producing technic or creaming.
And if you have spare capacity and sign a production stop like OPEC – why not reducing capex and simply let decline work until you have used up the extra, for some extra $ billions. You can speed up capex at the end of the treaty again.
EIA balance sheet ending 02/09/2018 showing another record breaking production increase today. After last weeks blistering increase, making shale drillers great again and producing jobs. Supplying consumers with low cost fuel until transformation to EV’s and renewables is complete.
http://ir.eia.gov/wpsr/overview.pdf
Today’s ingenuity and technology in a free markets has embolden entrepreneurs to double Americas oil production since 2010.
God bless Adam Smith, Elon Musk and shale drillers making driving affordable again
Yes. Isn’t it amazing. EV’s are now so widespread on our roads and so cheap we can afford to blast them into space.
Huntington beach,
The production estimates in the weekly supply reports are often wrong by a large amount, based on past data. I ignore those estimates, the monthly estimates though not perfect, are far closer to reality and get revised as better data gets collected, the weekly estimates are not revised.
If the trend in US C+C output of the past 17 months continues (probably not a good guess) at an annual rate of increase of 821 kb/d (or 68.4 kb/d each month), then a new record for monthly output may be set in Dec 2017 (previous record 10,044 kk/b) and a new peak for trailing 12 month output (currently 9753 kb/d in July 1971) may be set by May or June 2018.
Whether output increases in other nations results in excess oil supply is difficult to guess, I expect that if OPEC and other non-OPEC nations maintain discipline that demand will outstrip supply and the oil market may be tight. I think there is about a 75% probability that oil prices will continue to rise in 2018, reaching $75/b or more by Dec 2018.
It is also highly unlikely that the US C+C output will continue to increase at an annual rate of 820 kb/d or more beyond 2018. The LTO resource is more limited than the EIA estimates, based on the scientific studies of the geophysicists at the USGS.
I will take the estimates of a geophysicist (at the USGS) over the estimates of an economist (at the EIA), every time. Neither estimate will be correct, but the geophysicist will be closer to reality.
Hi Dennis,
It’s a relative free country and you have the right to “ignore” whatever information you wish. There is no question that if you want to live in the past, you have a better probably of your information to be more accurate. But still no guaranty. Personally I’m more interested on being on the edge of the direction of the future. Making current daily financial decisions the latest information is nearly short term fact. It’s clearly fact that the EIA balance sheet can move the price of oil as much as 5% and oil company market value as much as 15% in a single day. That’s real. I prefer to use an exponential smoothing formula for error in the information to visualize future direction. There is a lot more information in the balance sheet than just production week to week fluctuation. For example, the balance sheet shows YTD production is up 1.2 mbpd and product supplied up nearly the same over last year. Which is more current than your .8 mbpd over the last 17 months
Clearly the estimates of geologist of the past have not done as good of job of explaining the last 10 years of US production as well as economist. The geologist didn’t see the rise in price increasing the rise in production we have seen.
Hi Huntington beach,
Believe what you wish, past weekly estimates have been far from the mark, that is simply a fact. Perhaps today is different, generally history repeats.
True that the balance sheet moves markets, mostly based on storage estimates, those are also not very good, especially the weekly estimates.
If one wants to gamble, better to have accurate information when placing bets.
I just invest long term, weekly ups and downs are of no interest to me.
I don’t understand how you go from “that is simply a fact” to “Perhaps today is different” in the next sentence ?
In the past the weekly estimates have been far from the mark.
Just look at the data, that is what I am calling fact.
Monthly data gets revised, so that it becomes quite accurate, weekly data is never revised.
One can assume that from now to any future point in time this will not be the case and that weekly data will be accurate.
It is not an assumption I would make.
Looking at 5 week centered average data vs monthly C+C data, it does not look terrible.
Often the weekly estimate is an underestimate and this sometimes makes trends look steeper.
Chart below.
Note in the chart below I cut off monthly data at June 2017 to eliminate most monthly revisions that might occur in the future, the weekly data is also cut off at the end of June 2017 for comparison.
“I cut off monthly data at June 2017 to eliminate most monthly revisions”
“Personally I’m more interested on being on the edge of the direction of the future” and “I prefer to use an exponential smoothing formula for error in the information to visualize future direction”
I’m sorry Dennis, but unless your a historian. I think your splitting hairs to live in the past. The weekly balance sheet seems pretty accurate showing the current trends 80 to 90 percent of the time. To me it makes more sense to follow the weekly, monthly and revisions to be in tune with the industry. In any point in your graphs, if you wait 3 months for revisions. I will know the trend before you with the weekly report.
Huntington beach,
The point of cutting off the chart was to show “final” monthly data compared to weekly data.
You can assume the weekly data gives a correct trend, but the historical data shows this is true about 50% of the time.
Not a great bet, but I suppose better than no information at all.
Look at the chart below (2nd chart down in earlier post) and you can see the trend is different for weekly (5 week average) and monthly data from mid 2016 to mid 2017.
If we compare the trends over a longer 16 month period ending Nov 2017 (or 69 week period ending Feb 9) the linear trends have a slope of 870 kb/d or 900 kb/d respectively (weekly data with no averaging gives a slightly higher slope of 930 kb/d).
My point remains that the monthly data is more reliable based on the historical data, the weekly data will often show false trends as was the case in most of 2015.
Chart below can be enlarged by clicking on it.
Hi Dennis,
The two little dips in the fall of 2017 that look like a pair of boobs represents the production that was shut in because of hurricanes. We know this happened.
Today we know about 13,000 people per years die from guns or about 35 per day. But two days ago, 15 high school students and 2 adults were murdered in about 7 minute by a single person. If you turn on the news today the leading story is the death of the 17. Six months from now, if you graph the death toll of gun deaths in America. You wouldn’t even know of the third largest mass murder in a school happened.
I’m sorry but I’m really not that interested in the Los Angeles Times delivering a 3 month old news paper on my driveway.
Huntington beach,
You are welcome to use inaccurate information, as you said it’s a free country.
I find information of dubious accuracy has little value.
Yes we know some production was shut in due to hurricanes, the estimate of how large the effect was is the important question, the weekly estimates are just not very good, there are many data artifacts that remain uncorrected, so any trend based on that bad data is garbage.
GIGO.
If we focus in on the Jan 2015 to June 2017 period as in the chart below, one can see the difference in trend for the weekly vs monthly data over the late summer 2016 to early summer 2017 period. The weekly trend looks steeper due to the underestimate in Sept 2016 and the overestimate in June 2017.
Today’s News
Another downside threat is U.S. shale. As widely noted, U.S. output is expected to exceed 11 mb/d this year, a year sooner than previously thought. The wave of output is expected to lead to another buildup in inventories, which keep oil prices at the lower end, especially if demand disappoints.
Which brings up another threat to prices. Demand is strong right now – the IEA puts demand growth at 1.4 mb/d, OPEC says 1.6 mb/d – which will prevent U.S. shale from crashing prices. But if demand disappoints, there is much more room for prices to fall.
https://oilprice.com/Energy/Crude-Oil/OPEC-And-Shale-Keep-Oil-Prices-Between-60-75.html
No data in, no data out
Huntingtonbeach,
We can try to guess which forecasts are correct as well as which output estimates are most accurate. Often optimistic forecasts are based on inaccurate data, or optimistic models (drilling productivity report).
If we assume most of the increase in US output will be from the Permian basin, for the past 13 months the annual rate of increase in output has been about 600 kb/d. Other LTO plays besides Permian, Bakken, and Eagle Ford increased at an annual rate of 200 kb/d (Jan 2017-Jan 2018). I expect Bakken and Eagle Ford output will be relatively flat and “other LTO” plays to increase more slowly and think a 700 kb/d annual rate of increase in US LTO will be roughly correct for 2018.
Other US output will be relatively flat (no increase).
Much depends on future oil prices which are difficult to predict. Will the rest of the World be able to increase output by 700 to 900 kb/d in 2018? I believe it will be a struggle and tight oil markets may drive oil prices higher.
Huntington beach,
The economists also did not predict the rise in LTO output. See for example the EIA’s AEO 2006, see figure 84 of the page below, data is under figure data link.
https://www.eia.gov/outlooks/archive/aeo06/gas.html
The forecast is compared with actual EIA annual C+C data through 2016, both geologists and economists missed how fast LTO output would rise.
“have not done as good of job of explaining the last 10 years of US production as well as economist”
“ingenuity and technology in a free markets has embolden entrepreneurs to double Americas oil production since 2010”
It is basic economics that when prices rise. Suppliers will invest more capital and labor to meet demand to maximize profit and increase production. Hence, shale oil comes on line. I think I saw Ron write a couple of days ago something like, pretty much everyone was surprised by shale.
Huntington beach,
Yes higher prices can lead to higher investment and output.
Technological advancement is difficult to predict in advance. LTO increases were not expected, by the economists at the EIA.
Consider the EIA’s AEO 2009 High Price case
https://www.eia.gov/outlooks/archive/aeo09/aeohighprice.html
Actual output data through 2016 also included.
The increase in output due to high oil prices was much higher than expected by anyone.
The USGS has very little petroleum expertise.
They miss most things if relevance in the oil and gas sector.
Timthetiny,
The USGS does a better job than the EIA in my opinion.
There are many with petroleum experience who believe the EIA estimates are not reasonable such as Art Berman, David Hughes, Mike Shellman, shallow sand, and Fernando Leanme.
Again I will take the estimate of a physical scientist (geologist or geophysicist) over a social scientist (economist), every time.
The economists just take any expected level of demand that they forecast based on past rates of economic growth and rate of change of oil intensity (barrels of oil per $GDP) and assume oil supply will meet that level of demand.
The thing they miss is that depletion will drive costs up when tier one areas for LTO become saturated with wells, this drives up oil prices and reduces demand by increasing the rate of decrease in oil intensity.
The data for Chinese commercial oil inventories is very strange for December. It dropped during the autumn and then suddenly it increased by 18,6 mb in December. That´s close to 1 mb/d difference MoM. Net imports dropped by 1,1 mb/d on top of that MoM. So either there was a massive 2 mb/d drop in consumption in December or the data is incorrect or they released oil from the SPR or some other reason. Consumption doesn´t change more than 100-200 kb/d MoM normally, so 2 mb/d cannot be right.
Data and China are at best good fiction, kinda like Greek Ferry Schedules.
Not sure, there is a seasonal pattern in products, if that’s any help?
China’s commercial oil stocks (million barrels)
Subscription available from Xinhua news agency (weekly)
Chart: https://pbs.twimg.com/media/DWGjRuWW4AI7jOa.jpg
Thanks. Then it´s expected. But it doesn´t explain why the data doesn´t match. I suppose there is no point in analysing it too much.
US ending stocks February 9th
Crude oil up approx +1.8 million barrels
Oil products up +2 mb (shown on chart)
Overall total, up +3.8 mb
Natural Gas: Propane & NGPLs down -5.7 mb
https://pbs.twimg.com/media/DWBwhpKWkAU5vOs.jpg
The overall total change (crude oil + 7 products) up +3.8 mb in the week
https://pbs.twimg.com/media/DWByFz_XcAA_ZB5.jpg
US Net Imports of Crude Oil & Petroleum Products (without propane)
Down -3.8 million barrels in the week from the previous week
https://pbs.twimg.com/media/DWBxDPRXcAE-Ii-.jpg
The big surprise is the 3.6 Mb drop in Cushing to 32.7 Mb. This level is half of where it was last year and two years ago. At this rate it will be dry in 10 weeks. Makes one wonder if the EIA production numbers are right.
As an aside, is the Cushing inventory separate from the commercial reserves reported by the EIA or are they included.
They might just be trying to make room because there’s a lot of planned maintenance on th refineries down there through March, and there has been an increase in some pipeline capacity from the Permian so perhaps Cushing storage is becoming less critical.
Ovi,
The cushing storage is part of commercial inventory.
2018-02-14 – ClipperData – India crude imports reached a record in January, helped in no small part by a big jump in arrivals from Iraq. Total Persian Gulf arrivals were up over 700,000 bpd on the prior month.
By 2022, India is expected to more than double its current renewable electricity capacity.
Chart on Twitter: https://pbs.twimg.com/media/DWBg-T0VoAASw_7.jpg
ClipperData Blog: http://blog.clipperdata.com/a-passage-from-india
There was a report that Venezuelan vice president has left for India and “talks” there. Note that India was the consumer of Iranian oil during their sanctions. The thinking would be that they know how to get around them.
Pennsylvania’s December production report just released.
Chesapeake’s McGavin 6 has produced 6 1/2 Billion cubic feet first 5 months online. This is the energy equivalent of way over 1 million barrels of oil.
Two Howell wells from Cabot have produced 9 Billion cubic feet in under 4 months production.
The Appalachian Basin will continue to exert a large and growing influence on global energy markets for decades to come.
Actually at 7 TCF per year the appalachian basin will likely roll over in short order.
Nope.
About 6 to 10 Bcfd pipe due online 2018.
Bout 500,000 bbld NGLs heading to Marcus Hook if both Mariners make it across the finish line this year.
If you are in the industry and follow the AB closely, you must be aware of the growing NW to NE expansion of the Utica, which is bridging the NE to SW from Tioga and Potter counties.
XTO ready to bring online an Indiana county Utica.
Seneca focusing exclusively on Utica in north central tier.
CNX is touting their Aikens 5M Utica as the second best AB well of all time.
Projected 20 MMcfd flatline production for 18 months is their hope.
8,700 psi FCP at outset may prove them correct. We will see.
AB is Ghawar in gas form.
Cabot drilling – supposedly – the Templeau in Ashland county, OH, could be the sleeper of the year if successful.
The App Basin is the “Ghawar” of gas only if one ignores completely that it will take 100 times more wells and several trillion dollars more to develop than Ghawar and that its annual decline rates are 15 times more than that of Ghawar. And only if one ignores well economics at $2.70 per MMBTU, the threat of gross oversupply that will drive the price even lower, and only if Wall Street keeps funding it’s development.
Mike. Does anyone in App Basin actually get anywhere near Henry Hub for dry gas.
I recall seeing as low as 53 cents per MCF. But they kept on drilling and completing wells at that price.
Not a lot of consequences for any of this. Sandridge paid its previous CEO a $90 million severance right before it went BK, and just followed that up by paying the next CEO $26 million as the board shows him the door. Looks like the Sandridge board is competing with the Halcon board with regard to seeing how high CEO pay can be for a BK company where the shareholders lost almost all or all, and creditors also lost a lot.
Speaking of MS lime, also read that CHK just sold most of its holdings in this once touted play. Sold interests in over 3,000 wells producing net of 24,000 BOEPD, 25% oil. Don’t know how many conventionals were in those packages and also don’t know CHK GWI and NRI, but looks like they pretty much had a bunch of $3 million hz stripper wells there.
Mike, today was a big chemical day for us. How do they chemical treat these deep hz wells?
Why would they chemical treat a deep horizontal well? One would assume they just run a liner with suitable metallurgy and complete tubing with a sliding sleeve, a nipple, and a packer, also with the right metallurgy. Otherwise they have to run coil tubing to treat the well, and that’s a nightmare.
Shallow, I am unclear what they get for their gas in the AP at the moment, if they can sell it; a lot of it is quite dry and you are correct for the first 3/4 of the play’s existence a lot of gas was being sold for less than 75 cents. CHK, the poster child for shale gas, is now nearing, or north of $10 B in debt and the ONLY way for it to keep trucking is to sell most of its assets.
They do of course treat deep HZ wells with various production chemicals, particularly shale oil wells, for scale, corrosion, paraffin, and with de-emulsifiers. A lot of shale oil wells have two string completion designs, a lot require 3 strings and/or liners. Once shale oil wells go on AF they are chemically treated, big time. Flowing gas wells are different, of course.
I assume if an Ap Basin well reports IP with FCP there is no production tubing in the hole and they are gutting it, post frac, up the casing. EOG likes that plan as it makes for spectacular, glittering, Times Square like results for the public. What a plan, however. Imagine being puffed up about gutting a well at a BCF per month, at $2, when proper reservoir management would ultimately result in much greater EURS, at $4.
For most folks there appears to be only two ways to look at shale resource plays: one is that it is simply a miracle of existence and a great boon to society. Period. Economics and financial condition of the industry mean nothing. The 2nd is that it is all a great speed bump in the road to depletion but it’s decline rates are incredibly steep, it is horribly expensive, and, racked with debt, it is marginally profitable, at best.
You will notice that you, and Fernando, and myself, people IN the business, worry about the latter quite a bit. It is, after all, a business, this shale gig, and the business has to be profitable to be sustainable. At some point there will not be anymore money to throw at this stuff and the chickens will come home to roost with regards to debt. The shale industry will be forced to stand on its own financial feet and grow from net revenue. Is it un-American to be concerned about the shale industry’s sustainability and the role it will play in our energy future? I think not. I think one has to be deep in denial not to worry about that.
Mike,
Yes the profits are a big problem.
Chesapeake lost 5 cents per share in the most recent quarter (ending Sept 30, 2017) reported, they are the biggest Marcellus producer. Cabot (2nd largest producer in the Marcellus) earned 4 cents per share in the most recent quarter reported (10/30/2017). Range Resources (3rd largest in Marcellus) lost 52 cents per share in the most recent quarter (reported 10/24/2017). EQT (4th largest in Marcellus) earned 13 cents per share in the most recent quarter (9/30/2017).
For all four of these companies together, the losses for the quarter that ended 9/30/2017 were about $128 million dollars. Those 4 companies produced about 7 BCF/d of the 18.5 BCF/d produced in the Marcellus in Nov 2017 (about 38% of the total Marcellus output).
The industry ( a mature shale gas industry operating since 2008 or so) does not seem very profitable, at least in the Marcellus (producing 38% of US shale gas output).
Chesapeake realized about $2.50 per MCF of natural gas in the quarter that ended Sept 30, 2017. In barrels of oil equivalent (assuming 5800 cf= 1 boe), this equates to $14.53/boe for natural gas sales. They did very poorly on their derivatives for oil which reduced their realized oil price per barrel from $47/b to $40/b.
Thank you, Dennis. Sadly that is actually an uglier picture than I realized.
What an amazing thing unconventional resource plays have been for America. Truly; its awesome stuff. What a damn tragedy it has been to be so poorly mismanaged that private enterprise cannot make money engaged in it. Where this is all going can’t be good.
Eventually the worst offenders will become bankrupt and investors may become smarter.
Smarter producers may develop the remaining resource in a more conservative manner (operating out of cash flow with reasonable levels of debt).
In the future oil and natural gas prices will probably go up (2 years for oil and maybe 5 for natural gas).
Both of these factors together may help the petroleum industry until other types of energy (wind and solar) and transportation (plugin hybrids and EVs) potentially reduce demand (around 2035-2040 is my guess).
Hopefully oil prices won’t fall below $55/b for WTI.
A few numbers from Antero’s release the other day.
2016 showed a $850 million loss, while 2017 had $615 million net revenue.
Proved reserves over 17 Tcf, with 3P (Proved/Probable/Possible) 54+ Tcf. Of that, 46 Tcf is Proved/Probable.
Development costs of Proved Undeveloped is 37 cents/Mcfe.
Resource estimates exclude Upper Devonian and West Virginia Utica, which could be extremely large.
Chesapeake has always been somewhat of an outlier in these types of comparisons due to its massive size, first mover status in plays all over the country, and being grossly overextended since the drop in HH from $12 mmbtu to $3.
There should be no doubt that several operators have come through the precipitous drop in both WTI and HH and are poised to position themselves as flexible producers in the global markets.
The gas (and NGLs) from the Appalachian Basin will fuel a transformation the likes of which many of us have never seen with rock bottom feedstock being processed by the lowest cost electricity on the planet.
Quick note on AB size …
The WVU Utica study “Geological Playbook …” pegged recoverable Utica resource at almost 800 Tcf, comparable to the Marcellus.
With a combined 1,600 Tcf at last year’s US consumption of 27 Tcf, the AB – excluding Upper Devonian – has 60 years total US supply.
Note … Questerre’s resumed Utica drilling southeast of Montreal may vastly expand the Utica’s future footprint.
Coffeeguyzz,
“Recoverable resource” means technically recoverable rather than economically recoverable.
There may be a few companies making money in Shale gas, but the biggest 4 producers in the Marcellus ( responsible for 38% of Marcellus natural gas output as a group in Nov 2017) lost money in the third quarter of 2017 (ending Sept 30, 2017)..
There are some crazy estimates out there for oil and natural gas resources, the EIA estimate for all US shale gas is 622 TCF (from April 2015), the USGS estimate for all continuous resources (including coal be methane) is about 1000 TCF.
Typically peak output is at roughly half the resource produced, say around 500 TCF.
If US consumption does not increase and there is no increase in exports of natural gas and within 5 years all US natural gas comes from shale gas, then the peak would be reached in 23 years in 2041 (assuming the USGS 1000 TCF of “continuous” gas is correct).
For the EIA 622 TCF estimate and the same 5 year assumption for 100% natural gas from shale (conventional depleted), the peak natural gas output would be 2034 (50% of cumulative reached in 2034).
Again an assumption of either increased consumption (or combined consumption plus exports) would move the peak to an earlier date.
An alternative is to assume shale gas output increases at the 2013-2016 average rate in the future, increasing 130 BCF each year from Jan 2017 until a peak is reached.
Output from Jan 2007 to Dec 2016 was about 92 TCF, this is added to the EIA and USGS estimates for a URR of 714 TCF or 1092 TCF respectively with the assumed peak at 357 TCF or 546 TCF cumulative output. The peak for such a simple linear scenario would be 2027 (EIA) or 2036 (USGS), with peak shale gas output at 91 BCF/d in 2027 or 113 BCF/d in 2036.
For reference, in Dec 2016 shale gas output was 46 BCF/d and total US natural gas output (gross withdrawals) was 96 BCF/d.
Also cumulative US natural gas output from 1936 to 2016 (gross withdrawals) was 1482 TCF and marketed production from 1900 to 2016 was 1305 TCF.
Increases in consumption or exports would move the peak to an earlier date.
Mike, I thought the discussion was about deep horizontal wells drilled to produce Utica and other deep gas zones. I’m assuming they can avoid wax (I’ve seen waxy condensates but they are rare), the corrosion can be handled with metallurgy. Scale production in gas wells can be hard to deal with. A long time ago I had a 15000 ft well with scale, and got rid of it by circulating a small amount of filtered oxygen free fresh water down a speed string. This works if the well doesn’t need a safety valve. It’s also possible to control the scale by soaking. But soaking a horizontal well requires bull heading to the toe. And this requires a preset string or a coil unit. In either case I would be extremely careful purchasing a deep gas well which makes small amounts of salt formation water (the ones making less water seem to be nastier, some wells make fresh water condensed from the gas stream, those are fine). .
coffee, good to see you back posting some “facts” for the readers to consider. Clearly the “market” is pricing in what you are saying, and I must add what sweet revenge it must be, as most of my career, ‘freeze’ them yankees was a battler cry to sell them our gas. As nat gas makes up 50% of our revenue, it is distressing to see current pricing for nat gas considering it has been such a cold winter with historic demand and much below normal storage. I could of course result to bitching and whining and ask for intervention from fascist eco terrorist and their compatriots in the government to shut them down. But the way i see it, despite the opposition in certain corners up there, the North east now has a stable, economical source of “on demand energy” to meet their energy needs. We down here will just have to suck it up and figure out how to compete. The good news is if you read the EIA long term report I posted , nat gas WILL BE the dominate energy source world wide for the next 4 decades. The gas coming for the AB guarantees I will be able to market my gas for the rest of my life as NO OTHER FREAKIN source of energy can compete. It’s a win win even if i don’t get to sell my gas at a price I had hoped for.
There is a price point where you cannot just suck it up. We hit that in Q1, 2016 when oil was in $20s and low $30s.
We also hit that in 1998-1999 when oil was $8-12.
Fortunately those times haven’t lasted long. But when you are in them you have no idea how long they will last.
I’m not advocating price controls or anything other than spacing rules.
Just because I would like oil to trade in a $55-65 WTI range hopefully doesn’t mean I’m some kind of facist, communist or whatever. To be very clear, I am not advocating government to set a price.
I have seen gasoline in the $2.20s and $2.30s in my area. That is very fair IMO. Thirty years ago it was a little less than half that. Lots of stuff costs way more than double what it did thirty years ago.
TT
Quick followup using today’s numbers combined with – potentially – tomorrow’s technology …
HH right now $2.58/mmbtu
WTI. $61.50/bbl
Using 5.8 factor for boe energy equivalence, $14.96 (5.8*$2.58) worth of natgas has energy potential of $61.50 worth of oil … about one fourth the cost of energy in gaseous form.
With the recent explosion surrounding MOF technology, it is more a matter of when – not if – the fuzzy heads will enable the bean counters to commercialize transportation on a vast scale using Adsorbed Nat Gas fuel.
Further, residential locations will be able to fuel their CNG vehicles at their houses with 20 Gallon Gasoline Equivalent (GGE) tanks at sub 500 psi.
Laboratory conditions already are doing this.
Just as natgas is pushing out both coal and nuclear in the electricity generation arena (and greatly inhibiting renewable implementation), vehicular transportation is heading towards natgas-fueled more quickly than one might think.
(As an aside, the operational challenges associated with unconventional wells are greatly minimized when gas, rather than oil, is the targeted hydrocarbon).
The BOE thing is bullshit, Coffee; you know that. Yet you keep using it over and over and over again. The energy equivalent of gas is only relevant if that gas is actually being used. There is oodles of AP gas shut in not being used, because of really dumb oversupply, keeping the price of natural gas artificially propped up. What do you think is going to happen when more takeaway capacity occurs, that the price of gas is going to go UP? Check out Raw Energy’s take on that.
Gas cannot be used profitably now as a transportation fuel. So who cares about what gas means in terms of BTU’s (Well, the shale oil industry does. Its real handy for them). The monetary value of gas to oil is like 23:1, and going down. Speaking of good grief…
Imagine an imaginary Texas “oil man” being happy to sell his natural gas at $2.50, instead of $4.50, so that “Yankees” back East will always have enough gas and so the AP Basin can drive the price back down to 80 cents an MCF. Because it is good for America? He’s got so much of it to sell, let ‘er go down. Right. Who believes that dookey?
This shale thing has now become so “politicized” 90% of the shit being said about it doesn’t even make sense anymore.
Hi Coffeeguyzz,
If oil use is replaced with natural gas for all uses and that energy demand remains at today’s level that’s 36 TCF per year to replace oil, plus the 27 TCF per year we already use, a total of 63 TCF per year. If we take the USGS estimate for continuous natural gas resources of about 1000 TCF, and divide by 63 TCF, we have enough for 16 years, if we assume decline starts when about 50% of the resource is used, that would occur in 8 years.
Or we could have a ramp of 27 TCF to 63 TCF over 10 years (180 TCF of cumulative output), then 5 years of output at 63 TCF would take us to 500 TCF, possibly another couple of years staying close to 63 TCF would be 17 years (with 626 TCF of cumulative output) and then decline, which if it is linear over 12 years would be a steep decline of 5.25 TCF per year (8% in first year and an increasing rate of decrease each year (at year 5 it would be a 14% rate of decrease).
The resource may not be as large as you believe, especially if it is used to replace current oil uses (mostly transportation), in which case we would see a peak in 2035 with rapid decline to follow.
Putting aside the numbers for a moment, Dennis, US has genormous amounts of natgas, its uses will continue to expand due – partially – to the ridiculously low cost, and competing sources of energy will be hard pressed to overcome gas’ advantages.
I well realize that many people on this site hold operators’ presentations in low regard, despite the wealth of hard data frequently presented.
However, the AB operators are on the cusp of recovering stunning amounts of natgas and NGLs at extremely low cost.
17,000 foot laterals are to be routine in 2018.
Eclipse drilled the 20,800′ lateral – Mercury – in 13 days with 100% in the target zone.
The barge port at McKees Rock on the Ohio river is expanding from 4 to 20 simultaneous offloadings of frac sand.
The massive expansion of takeaway pipe in 2018 will dwarf the output of the Haynesville.
Dennis, Mark this down …
When the USGS gets around to releasing the Marcellus assessment, You. Will. Be. Shocked.
When the Utica is presented – still VERY much a work in progress – a paradigm shift in supply will be recognized.
Tellin’ ya, it’s just that big.
Anything past a 9000′ lateral cannot be stimulated effectively. Smart operators and those of us in the business know this.
Your being impressed with that shows how little you know.
Diminutive One
Must be a lot of dumb operators in the AB, then.
Public production numbers from Pennsylvania and Ohio are viewable by anyone and the numbers do not lie.
As for the Bakken, 10,000 foot laterals – or close to it – have been the norm since 2010.
11,000 or so well production numbers are also viewable.
Dumbness must be pervasive.
On this Mr. Tiny and I agree, longer laterals simply expose more rock to the wellbore but frac stages past about 9-10,000 feet do not get treated very effectively and will prove, are proving, to be grossly uneconomical. No amount of horsepower and fluid rheology can carry sufficient sand concentrations that far toward the lateral toe. The bulk of the production will generally always come from stages closer to the heel; there are several SPE papers to research about this.
Once frac’ed, and gutted up the casing for big flashy IP’s and IP180’s, what longer laterals do-do is create bigger type curves for over exaggerated EUR’s. So the USGS can come up with ridiculous reserve estimates and impress people who wish to “put aside the numbers (economics). Its a business, one cannot “set aside the numbers.”
People do dumb stuff when they use OPM and are trapped by debt and poor economic performance like those of the biggest Ap Basin operators outlined by Dennis Coyne.
Investor hype is just that. Its fun to read and get all excited about, I guess. This shale gas thing in the NE is good for the US. No need to keep lying about how amazing it is. Is the point to entice people to buy stock in Ap Basin public shale companies? I believe if I felt this amped about unconventional shale gas I get off POB and go to New York and convince those folks.
Thanks Tim and mike for the perspective on these laterals.
Are they economically worth it (leaving aside the whole economics of shale) just because you are already in the hole and lower production from the distant end is still production at only incremental drill/frack cost? Or do you think they are more done for PR ?
coffeeguyzz,
I don’t believe investor presentation hype.
When the USGS says Marcellus and Utica are as big as you claim, I may believe it.
Keep in mind that USGS estimates technically recoverable resources, low prices mean less will be recovered, because much of the resource will not be economically recoverable.
… And the LNG market is poised to greatly favor US producers as two factors – modularization and floaters – will give Texas, Louisiana and Appalachian Basin sourced gas significant economic advantage in global markets.
Some cost/capacity numbers …
Yamal $27 billion for 16.5 million tonnes per annum (mtpa)
3 Gladstone projects, Queensland. ~$60 billion for 25 mtpa.
Telurian’s Driftwood project. ~$16 billion/27 mtpa using Bechtel’e modularization approach
Project from Delfin using Golnar’s FLNGs hooked up to existing Louisiana pipe ~$8 billion for 13 mtpa.
The floaters are especially intriguing as the regassification units can be placed in remote areas with minimal onshore infrastructure. This will expand potential LNG markets worldwide including, potentially, Melbourne.
If you follow what the companies say in their investor presentations then you don’t know the actual story.
Are you referring to natural gas, oil or both?
Thanks Ron.Untiring. It is vital to monitor production.
My latest incremental graphs are here:
http://crudeoilpeak.info/latest-graphs
Hi Matt,
The 2nd image on the latest-graphs page isn’t showing up for me.
The jpeg
http://crudeoilpeak.info/wp-content/uploads/Crudel_Rest_Decline_2000-Oct2017.jpg
gets a 404 not found.
edit:
Oh, and thanks for your charts and site.
The Nigerian chart is actually looking kind of perky.
Global oil production at the moment is more than enough to meet needs. That is why OPEC and Russia have cut back on production, if they had not done so oil would be at $35.
Globally we are not at peak oil.
https://en.wikipedia.org/wiki/Peak_oil
Peak oil is the decline in oil production due to reservoir depletion.
What we are witnessing in many countries is oil production being impacted by sabotage, wars and low oil prices.
http://www.shell.com.ng/media/nigeria-reports-and-publications-briefing-notes/security-theft-and-sabotage.html
What is happening in Nigeria is not peak oil in a geological sense, and it needs to be clearly stated that there is a big difference between peak oil in the UK and Norway for example and falling production from countries such as Venezuela, Libya, Nigeria, Sudan etc.
Grouping them all together does an injustice and also catches people out.
When people were talking about peak oil in 2000, hardly any time or effort was spent by these people talking about what Iraq could produce if it were allowed to.
https://www.reuters.com/article/us-oil-opec-iraq/iraq-nears-oil-output-capacity-of-5-million-bpd-committed-to-opec-cuts-idUSKBN1F20E6
Iran with the lifting of sanctions is another country that has dealt a blinder to those who do not distinguish real peak with peak induced by war, corruption or sanctions.
If a country can’t produce oil for political reasons, and there’s no end in sight to such conditions, then it’s likely that if, over the long term, they can recover production, the rest of the world will be so depleted that overall production will never reach the peak.
In Venezuela’s case the communists have destroyed the country, and are in a process of what I call “social cleansing”, they are driving out the portion of the population with brains. There’s also signs of a low intensity genocide. People with kidney problems, cancer, high blood pressure,mdiabetes, and AIDS aren’t receiving medicines, so they die in bunches. This is similar to the Nazi elimination of mentally retarded and homosexual individuals. The end result is that I’m not seeing a way to ever return production to its previous peak. That place will remain a sore where communists can visit to celebrate their victory.
Fernando
What is happening in Venezuela is heartbreaking.
https://en.wikipedia.org/wiki/Venezuela#20th_century
Corruption, coups and dictatorships have blighted the country and as always ordinary people suffer.
My general point is that the political system can change and wars do come to an end. Therefore, as has been seen in Iraq, Iran oil production can increase where countries have not reached a geological limit.
When the communist block was at it’s height of power, countries like Poland were under a ruthless military dictatorship. Now they are democracies and Poland is in NATO. Who would have thought that possible in the 1970s.
Peter what happens in Venezuela today is worse than you can imagine.
Most oil producing countries in the world are past peak. This includes most OPEC members. Both above and below ground issues are important. The price will not rise to infinity, at least not for any length of time, and so the relationship between production cost and market price/demand (and access to finances/investor with money and risk appetite) will impact the date of P.O.
You assume that the entire “cut” is voluntary. This may be correct but I think not. Saudi Arabia just pledge to cut some more: https://www.reuters.com/article/us-saudi-opec/saudi-arabia-says-prefers-tighter-oil-market-to-early-exit-from-cuts-idUSKCN1FY0NB. 100 kbd is not enough to make much of a difference for the global balance and no other exporter follow their example so why do they bother? Their “commitment” will probably wane a bit when Khurais expansion comes online…
I don’t know when PO will occur. I do, however, find the lack of new major discoveries and low investment as clear warning signs that it is more likely to happen in the next few years than centuries ahead. The exact date is unimportant to me. Also, I’m skeptical to what KSA, other OPEC-members and Russia say concerning future production. They will do whatever they can to make sure there is demand for the oil they can export and the price is enough for them to balance their budgets.
Peak oil is the decline in oil production due to reservoir depletion.
Price, supply, and demand are part of the equation that will determine when crude oil peaks.
Peak oil is the point in time when oil production peaks regardless of the cause.
Sure Ron
But those who claimed peak occurred in 2005 and again in 2008 were wrong because they were too lazy to delve into the various factors that curtailed oil production in a large number of countries. Those reasons ended leaving 2005 and 2008 peakers looking silly.
As you say price is also a factor, but no one know what prices will bring on what additional production. The likes of Deffeyes, Tertzakian never mentions tight oil around that time. If they could miss that, what else did they miss?
https://www.youtube.com/watch?v=_2aE2gdvM0U
That was from 2005
and Jeff Brown had Saudi Arabia exports declining from 2007
https://www.youtube.com/watch?v=O7h4VjZhe_w
but fuel tax changes could alter this.
Brown’s Russia predictions are so badly out as to be embarrassing to even listen to.
Oh? Just where are your predictions Peter? No one but no one foresaw the explosion of shale oil.
Two things and two things only kept 2005 from being the year of peak oil. First it was the creaming of old giant fields. That is, as these fields started to decline they figured out that they could drill thousands of infill wells with laterals that just skimmed the top of the reservoir. This decreased, and in some cases, even stopped the decline in production of these wells. Russia, in 2009, was drilling 6,000 infill wells per year in Western Siberia.
Alex Burgansky: Russian Oil and Gas Industry
There are plenty of projects in Russia, both, new projects and existing brownfield projects. Russia is a very mature producer. If you exclude all the drilling activity taking place every year, then Russian organic decline in production is close to 19%. To compensate for that organic decline, Russia drills somewhere between 5,000 and 6,000 wells every year.
And then there are two important questions. One, is there enough oil in Russia for 5,000 or 6,000 wells to penetrate? In my view, the answer is yes. As I explained, we are dealing with a very large reserve base. And the second question: is there enough money in Russia to do that, and can it be done economically? The answer to this question is not so obvious.
The same thing is happening in every supergiant field in the world. This has dramatically slowed the decline of production but has dramatically increased the depletion of these supergiant fields. It is just a matter time before the water hits those laterals… then it is all over.
And the second thing was the shale revolution that seems to be happening in the US only. And that is about to peak.
So don’t give me this shit about some people being so wrong. Just post your predictions from 2005 where you were so right.
My prediction. We are currently on peak’s bumpy plateau. Production could go slightly up or slightly down in the next two or three years. But then we will fall off that bumpy plateau and the decline will be dramatic.
Hi Ron,
Can you define “dramatic” decline in numerical terms?
Annual decline rate for World C+C output will be x+/-y% in year z.
Fill in x, y, where z=2020 or 2021, or correct my estimate of z if I misunderstood.
Anything in the neighborhood of 2% per year. That would not be dramatic for one nation but it would be very dramatic for the world as a whole.
In fact a 1% decline would have a dramatic effect on our economy.
Thanks Ron,
2% sounds reasonable, I think we will see a gradual increase from plateau to 2% World decline in output over about a decade. Oil prices are likely to rise sharply so that demand falls to match supply and it may lead to a dramatic fall in economic output. After 10 years or so the World economy may adjust (2030-2040). A panic and financial crisis in 2030 seems likely as most are not expecting oil output to peak in 2025 (or sooner).
So we are roughly on the same page for decline rates (except you may expect there will be no economic recovery and a slow or fast crash).
Dennis, we may want to mention infill drilling as a reserve growth mechanism in revisions.
Hi Paul,
The increased infill drilling is essentially an increase in the rate of extraction, it probably has little effect on reserve growth, imo.
Either way I’m pretty sure things would have worked out much better if we’d all acted as if those earlier peak predictions were certain than they are going to.
Ron
I bought into the Oildrum hysteria in 2005, but by 2008 I had done enough research of my own to realise Peakoil was at least 10 to 15 years away.
I said so many time on the oildrum and the people there were abusive as ignorant people often are.
I have said several times I think US tight oil will peak between 2022 and 2024. By that time there will be few countries increasing production, being Canada, Brazil, Saudi Arabia, Iraq, perhaps Iran. Kazakhstan perhaps. There are uncertainties over Libya, Nigeria, Sudan.
China and Russia have large tight oil reserves and no one knows what may be possible there.
All that said I think Peak oil will be around 2025 and decline rates from old fields will exceed new oil, by how much is impossible to say.
I have said several times I think US tight oil will peak between 2022 and 2024.
Well no, you did not say that in 2005. The shale oil explosion did not begin until 2011. Shale oil has been produced since the 50s but no one paid any attention to it until 2011 when it exploded on the oil front.
As I said, I think we are on the peak bumpy plateau right now. It could go a little higher but it will only be a short bump if it does. We shall see who’s prediction is closest.
Ron
Try and read again what I said.
By 2008 I realised peak oil was at least 10 to 15 years away.
Peak oil has not been delayed just by US Shale.
Saudi Arabia’s production has been much higher than the oil drum posters said it would be. At the time, from what I read, it was obvious that Saudi Arabia were developing enough new fields to increase production for at least 10 years. Which they have done. I said so at the time.
Also Russia has increased production far more than the likes of Brown said.
Iraq has also done far more than dire 2008 peak pessimists said.
https://www.reuters.com/article/us-oil-opec-iraq/iraq-nears-oil-output-capacity-of-5-million-bpd-committed-to-opec-cuts-idUSKBN1F20E6
Iran has done better also. Canadian production is far better than the naysayers predicted.
https://www.ft.com/content/83bf9a26-5b6c-11e7-b553-e2df1b0c3220
Practically every single country where oil drum posters saw imminent declines have done the exact opposite.
http://www.opec.org/opec_web/static_files_project/media/downloads/publications/ASB2005.pdf
https://asb.opec.org/index.php/pdf-download
By the end of this year global oil production will be 6 million barrels a day higher than 2005. Total liquids will be 12 million barrels a day higher.
Peter,
Note that at the end of this year LTO output is about 5 Mb/d. Yes, the peak oil predictions at the oil drum in 2008 proved incorrect and the forecasts by the EIA in the 2007 International Energy Outlook proved far closer to reality from 2008 to 2016.
Note in the chart below, I expect a peak around 82-86 Mb/d in 2020-2030 with my central estimate for the peak in World C+C output at 84+/-2 Mb/d in 2025+/-5 years.
I am skeptical of the World hitting 93 Mb/d for C+C output in 2030.
Dennis
I would not be surprised that global production reaches 86. I cannot see where 93 would come from either. It would require Russia and China to duplicate what the US has done developing tight oil. At the same time OPEC, Brazil and others would have to reach quite optimistic levels.
Unfortunately I think we will be living in interesting times.
Peter,
Hard to guess, there will be declines elsewhere in US, North Sea, some OPEC nations, Mexico, that have to be offset by increases elsewhere, perhaps we will reach 86 Mb/d, but I doubt the 12 month average World output will get to that level, I would say about a 30% probability it will get to 86 Mb/d or higher for any 12 month period (average output over the 12 months).
If one considers the EIA’s International Energy Outlook 2017, the forecast looks reasonable through about 2026 (83 Mb/d) after that there is a steep rise to 100 Mb/d in 2050 with cumulative World output through 2050 at 2400 Gb. If we assumed 2050 was the peak and that occurred at 50% of URR a World C+C URR of 4800 Gb is implied, the scenario is just not credible.
See
https://www.eia.gov/outlooks/aeo/data/browser/#/?id=17-IEO2017&cases=Reference
Hi Peter,
Most experts in 2005 and 2008, including the EIA and IEA did not expect tight oil would be as significant as it became. You are correct that output remained more resilient to high oil prices than many expected.
Eventually depleting resources and higher oil prices will lead to a peak in output somewhere between 2020 and 2030, with a potential undulating plateau between 83 and 84 Mb/d from 2023 to 2027 (centered 12 month average of World C+C output). Too many unknowns for an accurate guess, peak could be 81 to 86 Mb/d (for 12 month average centered peak output) anywhere from 2020 to 2030 with about an 80% probability in my opinion.
Dennis
I have looked at the EIA link. They assume OPEC will increase production from 36 to 37 by 2025, this is well within the realms of possibility.
However from 2025 to 2050 they have OPEC producing 50 million a day.
I cannot see a breakdown of where they think another 14mb/d will come from, but I think those expectations are bordering on the fantasy.
Especially by then many old fields will be depleted.
Peter,
Agree.
Peter,
Yes there is currently enough World oil output to meet demand and the market is roughly in balance (slightly more demand than supply and falling stocks). Within 6 to 12 months storage levels of C+C (data is pretty poor at the World level so hard to know where we stand) might reach their 5 year average level. Whether supply is able to meet demand after that point is reached is an open question, but I do expect that output may increase as the oil price increases in a tight market, probably until 2022 to 2026 (this will depend on oil prices, political developments, technological development, and geology so is difficult to predict with any precision).
It takes time to develop new projects (Arctic and deep water) and LTO output is likely to peak by 2023 in the US, I think it unlikely LTO will develop quickly enough in other nations to fill the gap of rapidly declining US LTO output after 2024 (probably at 4% to 6% annual rates of decline for all US LTO).
Dennis
I cannot fault anything you have said there.
I think by 2022 the limits of US tight oil will be apparent. With US oil production flat or declining it is unlikely increases from Canada, Brazil, Saudi Arabia, Iraq and Iran will meet demand.
I don’t think we need many fingers and toes to guess what is going to happen. While EIA and IEA are relying on other increases to add to US shale to get to their 1.5 or 1.7 mbpd increase to balance 2018 production to demand, the great Black hope is US shale to rise over 1.1 million barrels a day by the end of 2018. I think it is more of a pink elephant, than it is the great black hope. Then, we have 2019, and another one million plus barrel increase in demand, forcing the great black hope to exceed the demands of even Mohammed Ali. Expecting supply to keep up with demand in the next two years, absent a depression, is pretty far fetched. Ok, part of that 1.1 million is not just shale, but includes a 300 thousand barrel increase from the GOM. It’s one of EIA’ hangover pink elephants from prior LSD trips that won’t go away.
Guym
OPEC cut oil production by 1.8mb/d so the spare capacity there will easily cope with any shortfall from other sources this year and next.
Also the two agencies think oil demand will increase by between 1.2 and 1.4 which will put less pressure on supply.
Oil prices fell to lows of $29, not seen since 2002, so make no mistake global supply far exceeded demand and did so for 2 years until OPEC and Russia cut production.
I see no supply problem in 2018, nor 2019. After 2020 things will become more interesting and by 2022 supply will fail to meet natural demand of 1.2 to 1.5mb/d
Considering industrial oil production has been going for 150 years what is 3 or 4 between people who are aware there is a looming problem.
By shortage, I mean that inventory level that will support prices closer to $100 than to $60. Opec did not cut production. They increased to their max, at the time, for several months and then “cut” it back to regular production. If they wanted to, they have enough spare capacity to add to world production in 2018, to keep the ending price in the $60 to $70 range. I don’t think they could for 2019, but anyone who thinks they want it at $60 to $70, believes in the Easter Bunny. They are committed, right now, to “cutting” until there is an over correction, last I heard.
The basis of that opinion of OPEC capabilities, and world capabilities, I get from the excellent posters here on POB, in addition to what I follow on Texas production. You say 2020, I think prior to that, but surely by 2020.
Sure they did. Do the math and show me where 1.8 m/d comes from. There is realistically 500 to 600 k/d from the GCC and maybe 150 k/d FSU that could be counted as realistic spare capacity.
Oilbull,
Let’s say there is 700 kb/d of extra capacity and US LTO output increases by 700 kb/d, that would be enough to meet the 1400 kb/d increase in demand, at least in 2018. By 2019, if your estimate is correct, there may be considerable upward pressure on the oil price as even a 1000 kb/d increase in US LTO may not be enough to meet demand without increases from Canada, Brazil, or somewhere else (Iraq or other OPEC producers?)
OPEC capacity has often been underestimated in the past, it has always seemed a black box to me.
Saudi will add 300 kbpd with Khurais due in May, but they specifically said this would only replace declines on other fields, which would have been hidden by the cuts. Over the last two or three years whenever there there was a period without too much maintenance or new production it looked like they were hitting about 4 or 5% decline, so Khurais could make up for almost a year’s loss. Saudi also has different definitions of spare – some they can bring on immediately and some would take six months. I suspect some also would only be possible for a short time without risking reservoir damage or reduced availability (everywhere has some spare capacity – it’s called equipment redundancy and there’s a good reason it’s not normally utilised).
Hi George,
To be clear, you believe Saudi Arabia is producing “flat out” and aside from the expansion you noted, their spare production capacity is zero?
I don’t think there is enough clear data to come to a black and white conclusion, nor do I think it particularly helpful to do so.
George,
Guess I just didn’t understand your previous comment, interested in your opinion, but I guess you don’t have one or do not want to reveal it, if it exists.
It appears LOOP’s first test VLCC is heading for Singapore.
Baked production released. Dec down 18kb/d and 16 fewer wells
Too much rushing. Bakken production released
Some guys here are too modest.
In truth, those that predicted at 2005 peak were extremely well informed and right as far as the mechanics and production of conventional production was concerned. And eventually the IEA admitted that.
It’s been detailed on numerous occasions how various unconventional oils and gases and residues were added to the figures to keep them going up.
Unconventional oil was only possible because the shortage or anticipated shortage of conventional oil forced up the price sky high after 2005. Then unconventional took off.
If peak oilers made any mistake at all in respect of the mechanics and production of shale it was assuming that nobody would be so mad as to undertake or finance shale production to the extreme extent that it has been, madness so clearly exposed by Mike.
And of course, no one denied that certain countries were not yet at peak but instead looked at world production as a whole.
And on that basis we are on an undulating plateau since the end of 2015 and – basically because of declines – we may never see a higher average world production.
Thank you, Mr. Mason. Historically the world has relied entirely on vast conventional hydrocarbon resources whose recoverable reserves were fairly well known (even in the absence of full disclosure) and whose decline rates were predictable. The onslaught of unconventional shale resource development in America has, unfortunately, created an “illusion” of abundance that many consider the end of peak oil production concerns. The illusion stems from production rates created entirely by the mass manufacturing of shale wells, all of which has occurred on credit and very little of which has been paid for yet. 10 MM BOPD of US production is an enormous milestone, for instance, and cause for great celebration. Peak oil? Pfttttttt.
Cut off the funding for the plant like manufacturing of shale wells, however, and production falls like an anchor dropped at sea. The reserves we are forced to rely on now are little more than individual shale containers drained and defined by the length of the horizontal lateral and the extent of a frac radius. There are no more Prudhoe Bays, or Clairs, or Burgans, there are only 400K BO shale wells to rely on, that decline by over 80% the first three years of existence, I might add; each requiring their own unique capital expenditure scheme, each totally dependent on other people’s money to come into existence.
It is a very tenuous situation, at least to me, and I think we are going to find how tenuous in a few more years, and a few more hundred billion dollars.
Peter, you changed your handle, added your last name. Why?
You continue to criticize those who made predictions in 2005 or later. But you still do not post your own predictions?
Peter, it is just so goddamn easy to criticize someone else’s predictions when you have not the courage to make any predictions of your own.
Stop it! You have no right to criticize other predictions that were slightly off when you have not the courage to make any predict any predictions of your own.
Those who made predictions, like Jeffrey Brown and me, were 1000 tunes more correct than anyone, like you, who had the not the courage to make any prediction whatsoever. Hell, all you have to do is wait to see who were the ones who missed their predictions and say: Yah nanna yah yah, you were wrong.
Well, fuck off asshole. I am on my fourth toddy tonight. They say a drunk man’s talk is a sober man’s thoughts. Well, you now have my drunk talk as well as my sober thoughts.
Ok dude.
Peter Mason,
If we consider “conventional crude” everything except LTO, Canadian Oil sands, and Venezuelan Orinoco Belt oil (these last two Laherrere groups together as “extra heavy” oil), the chart below estimates “conventional” C+C as I have defined it.
A problem with this estimate is that the Venezuelan output from Orinoco is difficult to estimate,
I use the estimates from CAPP for Canadian oil sands output and get LTO output from the EIA (US output only), in any case my estimate is below, a slight increase above the plateau in 2015 and 2016, but conventional has pretty much been constant since 2005 (roughly 72 to 73 Mb/d).
Yes, precisely, an undulating plateau since 2005, and the slight increase presumably due to Saudi Arabia producing at its maximum during the period when OPEC went full out against shale briefly, before reversing policy, plus an unexpected extended run by Russia due to huge EOR efforts. I’d remove palm oil which makes a very small difference I believe and I recall something about the official figures adding distillates to the mix at some point, which peak oilers pointed out was counting the same figures twice. Just to keep the figures going upwards.
Palm oil duh. Meant ethanol.
Peter Mason,
Those estimates are based on crude plus condensate from the EIA, no ethanol, palm oil, or diesel is included in those figures to my knowledge, NGL is also not included.
Maybe Fernando has better estimates of Orinoco output, I can’t find good estimates.
http://foreignpolicy.com/2018/02/15/the-trojan-horse-of-russian-gas/
It’s not just gas.
If the renewable energy industries and the electrification of transportation aren’t progressing fast enough, once oil and gas production come off the expected plateau, the handful of countries that have oil and gas to export are going to have the rest of the world by the testicles.
And of all the countries that have oil and gas to export, only one is a super power. Russia. If the chips are down, sanctions won’t mean shit to the Russians. They can and will get by ok without importing or exporting much of anything at all, for quite a while, in the event they need or want to.
When the chips are down, any large industrialized country with ample natural resources CAN go it more or less alone, for quite some time, by going to a war time economic footing.
Considering that the Russian government is obviously in the hands of people who believe in expansion and empire, the people of western Europe are going to be in one hell of a fix, when oil peaks, unless they can wean themselves off of oil and gas, and they don’t have a whole lot of time left to do so.
I can’t even guess how high the price of oil and gas might go, in the event the Russians for some reason, any reason, decide to just turn off their pipelines.
The economic crash that would accompany such a cut off would make 1929 look like a Sunday School picnic.
Any body who owns a contract to buy oil at the usual price will get rich……. if his contract is honored.
“Considering that the Russian government is obviously in the hands of people who believe in expansion and empire”
Actually, they are not. As someone who lives in Slovakia, a country hugely impacted by all this, it pisses me off to see this propaganda everywhere. Russia already has the whole of Europe by the balls, as a result of our consumption and need for natural resources. They are already the largest country in the world, with the largest natural resources. They have precisely zero need for any “expansion” or “empire”. Their only motivation is PROTECTING those resources so they can make all the money they can from selling them to us in the future. And after all the experience with resisting western expansion in the past 200 years, can you blame them for being protective? The last time the west tried to take Russian resources, instead of paying for them, the result was tens of millions dead people and a destroyed continent.
You live in Slovakia, so you should know that your wages are lower than for example in France, because of “Russian expansion and empire”. After WW2, the Russians just forgot to go back to their country.
Strummer, your assumptions are too simplistic.
Even with low prices for oil and NG the Russians generate 50% of their export income with these two items, they are highly dependent on these exports. To weaponize NG/oil is not possible for them without cutting deep into their own flesh.
Europe (EU) is in a perfect situation to go the RE-route and decrease the primary energy consumption within one generation by more than 50%. Europa can afford higher energy prices which BTW drive investments into alternatives.
I do not see a dramtic urge for empire building on the Russian side, they are busy to hold what they have. OTOH the attempts to diversify the Russian economy have not been successful and this may become an real issue in future.
Lol, Sorry to cause confusion Ron. Different guy. Should have said. Was posting my criticism of the Peter with no last name. No relation… I’ve published my support for peak oil predictions, for instance at http://www.socialismtoday.org/142/oil.html where i support the 2015 peak. just the first icould find. Elsewhere I’ve stated, as above, based on your work Ron and other Oil Drum colleagues that 2005 marked the peak of conventional as strictly defined. I hope I’ve given credit where it’s due. Mike makes an appearance in one of my articles and I did post it here to acknowledge my debt. Keep up the good work all.
This shale push is the last grasp of a dying industry—–
But I’ll take it, as long as most are willing to lose money trying.
It is a interesting twist of capitalism– profit is not necessary currently– but investment is.
But, with my limited knowledge, I could be reading it totally wrong.
(my great grandfather worked on the Drake Well, and my father was into oil in the 1950’s, so I have somewhat of a history)
Baker Hughes U.S. Oil rig count: +7 rigs week/week to 798 rigs total. Natural Gas -7 to 177.
Oklahoma +5, Alaska +4, GoM +2, New Mexico -3, Texas 0 and Permian -4
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother
https://oilprice.com/Energy/Energy-General/The-Most-Bullish-Indicator-For-Long-Term-Oil-Demand.html
Don’t sell your oil wells, yet.
EOR is not dead in the Eagle Ford, and they are looking elsewhere.
https://www.spe.org/en/jpt/jpt-article-detail/?art=3391
Significant to me. EOG leased 95% of my interest in the Eagle Ford.
Outstanding article.
The graph showing 100% recovery using ethane is in line with North Dakota’s EERC folks, especially the work by Steve Hawthorne, claiming that ethane may be the most effective component for Bakken EOR.
One of the big advantages with ethane is the very low – relatively speaking – mean miscibility pressure.
Lowered, controlled pressure injections coupled with effective diversion products could point the way to successful EOR in these plays.
Although the geology is somewhat different, Granite Oil has succeeded in EOR in their Viewfield Bakken wells in Canada via re-injection of field gas.
Dissolving the asphertenes prior to doing any EOR looks critical, probably for any shale field. Moving forward slowly, but that’s good, because only 7% of my lease is drilled, although all five of the 640 acres have one well with good production. 30-50% is a WHOLE lot.
Ah, what am I talking about, with my luck they will outlaw horizontals before they get to mine, or oil will be at $10 a barrel.
Here are my Bakken updates. After a couple of months of increasing or flat production in the older wells they now start to decline again. Some of the years are still flattish though. That was of course expected that the older wells should start to decline again. I don´t follow the other shale basins closely, but I had a look at the Permian production in shaleprofile.com and it also had a small increase in pre 2016 production. So it seems like this may also have happened in the other shale basins.
2016 is still not visible in the graph (as it is zoomed in) but had a big drop from 170 bopd to 152 bopd. If that decline rate continues, then it will show up in the graph in a few months time.
Here is the GOR graph.
Thanks Freddy,
How many wells were completed in North Dakota in Dec (wells with first production in Dec 2017)?
Usually your estimate is better than what is in the Directors cut (that estimate was 93 wells).
Yes I forgot to mention that. There were 105 new wells in December compared to 82 in November (including any conventional ones) and the initial production continues to be very high. Average number of production days decreased only a little in December. So the change in decline rates in older well explains a lot of the difference between the fast increase in total production earlier in autumn and the stagnation in November and December.
FreddyW,
Thx. Maybe cold weather resulted in many marginal wells being shut in due to deferred maintenance during winter months. Typically Bakken output suffers a bit due to brutal ND weather during winter.
No as I said, average number of producing days declined only a little. The same for percentage producing wells.
Perhaps wells choked due to operational difficulties in bad weather. This would reduce output without reducing days of operation.
Directors cut did not mention about any problems. There could however be a problem that there is not enough gas capture capacity which could force them to choke wells. Flared gas has gone down in Dunn since October, but so has oil production by some 20 kbopd.
Although oil production in November and December has been flat, my guess is that it will increase slowly during 2018.
FreddyW,
I agree a gradual increase in production is possible in 2018, especially after the spring thaw, muddy roads can be a problem in spring. It will depend on oil prices and the rate of new well completion and if new well EUR remains steady, eventually they will run out of room in the tier one areas and EUR may decrease for new wells.
Impossible to predict this in advance.
Dennis,
Yep, I agree with everything you said.
Is the “Red Queen” about to have a coronary? She is obviously in a big sweat over at Encana! ECA reported annual earnings of 800 million. Huh? Alas, they didn’t make it selling oil and gas. Rather gains from asset sales and hedges. Free cash flow for the year was a negative 800 million. Talk about eating your “seed corn”! BTW, take a look at the “Standardized Measure” at Pioneer Resources (PXD) and EQT for 2017 and then to be very conservative recalculate it for a 5% discount rate. Compare it to the enterprise value of these companies. But,when you do it, make sure you hold your hand over your mouth so no one can see you laughing!
She has already had a triple bypass and can’t take too much more, I think. Thanks for your refreshing insights, Financier.
Selling assets is going backwards; there is a lot of that going on behind the façade to create funky non-GAPP cash flow, buy back stock plans and to raise dividends, all to appease angry shareholders demands. I particularly like the mid-stream change over in accounting methods to recoup previous reserve impairments to re-exaggerate assets.
Understanding well economics and financial plight of the shale industry is complicated; that’s why so many folks ignore it. But relying on an industry to meet our future hydrocarbon needs that is so deeply mired in debt and misrepresentations is an enormous, dangerous mistake. All one has to do is compare investor enhanced EUR’s to actual realized production data and immediately anyone with an IQ higher than the price of oil would know they are being lied to, and thereafter be skeptical of almost anything the shale industry says about itself.
PXD reported standard measure PV10 of $8.2 billion using SEC WTI of $51.34 and gas of $2.98.
Interesting only $700 million of income tax expected to be paid on all reserves.
Enterprise value is several times that.
Pioneer has some huge holdings in the Eagle Ford, which they say they are going to sell. Based on where the old maps show they have holdings is primarily within the gas/condensate zone. Doubt any one company will gobble that up at one time. Keep seeing all these little companies financed by stupid money, who buy up “non core” assets, which may yield an average of 100-150k EUR wells, that I cannot see getting a profit at $90 a barrel. North of $110, maybe. Gas/condensate is hard to profit on with gas prices south of $3.
Wonder why PV10 isn’t much higher for PXD given company representative statements that their wells work at $20-25 WTI and costs for horizontal wells are competitive with KSA costs?
No idea. Their pdf on the site concerning earnings has not one piece of information that looks like an income statement, balance sheet, or cash flows statement. Just a lot of disjointed charts and hoopla.
However, if their costs were that low, then $60 oil should have given them a killer profit, instead I find they are trying to sell off assets to make ends meet. Doesn’t compute, does it?
Guym,
There’s a good reason why shale oil companies are publishing their financial results in a convoluted way. They are hiding something.
The market is going to be stunned by the amount of fraud, corruption and criminal activity that has taken place in the Shale Oil Industry.
steve
That PXD acreage got a mention last month before publicly being put on the block by PXD. A minnow, Sundance Energy was apparently going to buy it with the help of those private equity guys, Elliot Management, who were previously giving BHP grief about their shale holdings.
Nothing came of it though.
A comparison of crude oil inventories in Europe & USA
There is a January number for Europe but looking at the history of revisions it’s only an estimate.
The latest weekly number for the USA is included for week ending February 9th
This is the same data: OPEC MOMR – Table 9 – 2: EU-15 plus Norway’s total oil stocks, million barrels – Sources: Argus and Euroilstock
I really like this chart. It’s up, slightly, in Feb., which is expected. But only slightly. Drop started in March of last year, looks like. Europe was never the problem.
I keep reading in various shipping articles, that US exports are averaging 2 million bpd. The EIA weeklies do not tell the same story, and not sure why there is a disparity. Before LOOP started the other direction, I kept reading that US export capacity was over 3 million bpd. US demand is going up, with an expectation of a big increase in demand for US finished products. I don’t see where an increase in US production will make a lot of difference in the current direction of where the graph is heading.
Yes it’s only really the USA & Saudi Arabia that have a large amount of spare storage capacity, along with floating storage. There are also private storage tanks around the world that don’t publish their figures.
I’ve not looked at OPEC’s oil on water statistics before. I guess this includes both floating storage and tanker traffic (oil in transit).
Significant, as the scale is in one million barrels. About a hundred million barrel drop since the last quarter on 2016. Down two thirds, with about a third left to go (including US). Looks like the EIA and IEA are WAY off on their projections. Even using EIA’s projection of 1.1 million barrels would not affect the continued drop much. It increased almost 900k barrels from May to Nov. and still did not slow the drop.
It’s almost simple mathematics. If we are short by over .5 million a day, which the drop depicts, then if we add the conservative increase in demand by the IEA of 1.4 million, it results in almost 2 million more needed of increase to equal demand. 1.1 million more by the US would not cut it. I know IEA uses liquids plus gas, but still, I don’t see another build in 2018, like the “estimators” project.
I think our airplane just ran out of fuel, and is capable of gliding for awhile. The pilot just does not want to create panic with the passengers, yet.
Or, going outside of Mike’s estimators, and using refinery expectations:
https://www.cnbc.com/2018/02/01/refinery-ceo-sees-global-gasoline-demand-rising-in-2018.html
That’s 1.5 million in liquids (average) a day more, plus the .5 million (approximate) that we were short in 2017 give 2 million more needed. Probably, that is a better estimate than a bunch of economists, who are not in the oil business.
One month into 2018, we had an implied drop of 20 million barrels. January is usually a 14 million barrel build, and we had a six million barrel drop. So, yeah we will have a lot of hoopla on the magical Permian increases until summer, no doubt. Sometime by then, there will be enough people look out the window and note the propellers are not turning anymore.
So carry this logic further into 2019. George will not comment on excess OPEC capacity, which I fully understand. But, I assume the wording of Ron and George saying “producing flat out”, would give a clue to their thoughts of excess capacity. There is not much, right now. Russia has some, but probably not significant in the short run. So, we will be short from 2018, because OPEC will carry it through the end of the year, because there is not much alternative. Another 1.5 million in demand for liquids, and people start seeing the ground look closer, faster. Will SuperPermian fly under the plane to keep us from crashing? Stay tuned for our next series, but the oil sponsor for this program says there is too much kryptonite in the oil at $60 a barrel for that to happen.
As said before, KSA and some other OPEC members do have “spare capacity”. It’s possible for them to increase production at a short notice. However, they are in it for the long game and it would be a bad idea for them to go flat out (reservoir management).
That being said, there are some strange stuff surrounding KSA and their oil and I don’t know what to make of it. For example: an increased number of rigs seems to be needed to keep up the production but from what I remember rig count in KSA has dropped lately, their reported inventory is declining but the satellite data tells a different story, KSA claim to voluntarily withhold production although the market is in a deficit and a higher market price gives US LTO breathing room, KSA’s reserves should be enough for many more years of flat output at today’s level but they have not advertised new major projects (at least not what I heard) to compensate for decline in mature fields, and then the story about privatization/listing a few percent of Aramco and selling it to foreigners?
I agree completely. I’d add they recently were concentrating on shale gas as the main new development and it doesn’t seem to be going well – is that really the best bet if you have all that conventional oil readily available? They have continual redevelopment of offshore wellhead platforms to add ESPs – you add them at the end of life. This year they are starting on Al Marjan. There are no green field upstream projects for oil.
I am certain that they are limited on water injection and produced water handling capacities – unless they announce some new developments for those, drilling new production wells doesn’t help (and such facilities take a few years to build, they are very high end pumps to procure).
Look if they change their ‘voluntary reduction’ stance after Khurais starts up.
(p.s. to Guy – “flat out” came from Ron and Dennis, not me. Flat out to me means burning the furniture: running all on-line spares, minimising planned maintenance, flaring gas if needed, maybe compromising on voidage replacement – actually closer to what US tight oil companies seem to be doing.)
George,
I am just repeating Ron’s flat out, I consider Saudi Arabia a black box, no idea what’s going on there, besides reported output.
I think when Ron says “flat out”, he simply means they are producing at maximum sustainable short term output capacity.
On developing gas, this seems to make sense for electricity output rather than burning oil in power plants. Currently with low oil prices, they may see no reason for new projects (or announcing them) as that might drive oil prices lower.
Perhaps they are waiting for some oil price ($80-90 per barrel) before they announce new projects.
I don’t think they are too worried about US LTO output, they may realize the resource is quite limited, no threat over the long term (5 to 10 years).
Now you got it, Dennis; tank ye!! While China, Russia and the KSA are in constant communication with each other about the future of world oil supply, and securing those world oil supplies, in unilateral cooperation with each other, America has its head up its ass about shale abundance. As I have said before, OPEC has computers, they know what the deal is with US shale and just how much rope to give it. They’ll own us again soon enough.
That is my understanding of KSA, also. It’s not that they can’t extract more oil at a given time, but that extended extract for a long period of time could damage the reservoirs.
The analogy above was for the world, as a whole, and not the US. Obviously, with our current and probable future production, we would have sufficient resources to last 5 to 10 years more without significant problems. It just won’t be at $60 a barrel for that much longer, as it is no longer land locked. Nor, will gasoline remain at $2 a gallon for very much longer. Seriously, the pump at a local station had gas at 2.03 a gallon, yesterday. Just my opinion.
Sorry, George, didn’t mean to misquote you. Khurais is only anticipated to be around 300k more to primarily offset decline rates?
Platts are talking about OPEC spare capacity at some conference, this is their chart on twitter
https://pbs.twimg.com/media/DWY9rqKWsAEEmH_.jpg
The questions Jeff and George asked above still leaves valid unknowns. Leaving out Sauds, there is barely any OPEC spare capacity per their chart.
Guym,
I agree, the true Saudi Capacity numbers are usually about 1.5 Mb/d less than claimed.
Or they are set at levels that would do long term damage to reservoirs and are levels that are unlikely to ever be reached.
From Jan 1973 to Oct 2017 the KSA’s highest centered 5 month C+C output was 10,628 kb/d in Sept 2016. The highest centered 13 month output was June 2016 at 10,435 kb/d, the chart suggests spare capacity of 1200 kb/d in 2016.
I would suggest that actual spare capacity in 2016 might have been 200 kb/d, and currently may be about 400-500 kb/d, possibly less due to natural decline, though the new development, Khurais (Sp?) might bring spare capacity back to 500 kb/d, bottom line we do not know.
You may notice on the Pioneer website on their pdf on 2017 earnings, that they plan on using two rigs to just expand DUCs into 2019. Increase in production expected to be a little over 20%. Probably pretty close to what all will be doing (15 to 20%). Sounds reasonable to me. At these prices, it’s a little more profitable. But not worth going nuts over doing it. That will be mostly in the Permian, so 20% times 3 million would be about a 600k increase, and certainly in line with Dennis’ prediction of 500 to 700k.
https://btuanalytics.com/2018-permian-production-trajectory-impacted-changing-spud-sale-times/
Article on changing spud to completion time with larger pads now being drilled. Wow, 24 months! So, if they drill it this month, we could see it in Feb 2020. Bound to screw up the drilling productivity report. Even more than it already is.
Encana drilled a 64 well pad site. No wonder they are having cash flow problems.
Texas RRC preliminary from December
78,085,085 bbls oil
7,668,617 bbls condensate
Not that much different from November, but condensate is higher by over 400k
I will try to get the pending lease data this week
It seems that all the new production must be going into the pending file
https://pbs.twimg.com/media/DWZAVUEW0AY3h2j.jpg
Haven’t paid for, pulled, and sorted the Dec. pending file, but for the three previous months the increase was primarily in the pending file, yes.
What I am working at, in my spare time during tax season, is trying to prove a theory that most Texas production is reported within three months, either within the pending file, or regular production. I only have one month, September, which I can use to justify this, so far. Obviously, that would not be conclusive, but I did come within 9k bbls of the EIA monthly with that. That is actual production reported, no estimates included. That was the month that had all of us scratching our heads over, because RRC data was so low that month. I’ll share all that data and procedures, probably within the next two weeks.
Posted twice. Ignore
The mismatch between the API gravity of US production and the API gravity of US refinery intake
Chart on Twitter: https://pbs.twimg.com/media/DWYFXJtX4AAMbSh.jpg
It is still possible to make a blend of light oil and heavy/medium oil to achieve the refinery preferred 32 API gravity. But product yields will suffer I guess, too light oil is not preferred and this is reflected by price discounts.
Yes refineries can blend it. And so I guess the story is that the domestic refinery intake of light oil is limited by the amount they can blend?
I thought this old Baker Hughes article from 2014 was interesting
The advantages of shale oil to the refiner – The higher volumes of naphtha and distillates, with minimal conversion unit processing, can reduce operating costs per barrel of distillate produced
Many of the refineries in operation today were designed for processing heavier crudes, so crude distillation columns and associated equipment were designed around a higher quantity of heavy fuels – The lighter shale oils, therefore, may produce an overloading in the lighter ends processing in the crude column and associated equipment.
pdf file: https://assets.www.bakerhughes.com/system/00/ed8e0094a211e6809c4fad20864324/Shale-Oil-Processing-White-Paper.pdf
from here: https://www.bakerhughes.com/capabilities/shale-oil-processing
http://www.rasmussenreports.com/public_content/politics/current_events/environment_energy/46_say_yes_to_fracking_but_want_oil_to_stay_here
American can never become hydrocarbon independent because of its need to import heavier crudes; in the mean time more and more light tight oil goes out the back door by an ever increasing amount. Why not re-tool our refineries to be able to reduce exports, use more of America’s oil and reduce heavy imports? Because it would bite into downstream profit margins. So onward we go, until we can’t go no ‘mo.
https://www.oilystuffblog.com/single-post/2018/02/16/Cartoon-Of-the-Week
Hi Mike,
Here’s more food for thought along the same basic lines.
http://www.resilience.org/stories/2018-02-18/lng-comes-boston-harbinger-future/
LOOP – one VLCC adds approx 300 kb/day to the weekly export numbers – The Saudi supertanker SHADEN has now departed the Louisiana Offshore Oil Port (LOOP) for Rizhao, China, carrying 2 million barrels of crude oil.
LOOP LLC has successfully completed the first Very Large Crude Carrier (VLCC) crude oil loading operation at its Deepwater Port, 18 miles offshore of Port Fourchon, La
https://www.loopllc.com/Announcements/Announcements/LOOP-LLC-has-successfully-completed-the-first-Very
Is the schedule going forward some kind of corporate secret? Would be nice to have a rough idea of how many VLCCs were to be loaded.
The first VLCC was said to be a trial run, just testing, not heard of a loading schedule.
I guess the start of exports from LOOP might take some export business away from other ports?
Depends on what they are selling. In this LOOP case, as I remember, they said Louisiana Sour. Pretty sure that does not compete with Houston or Corpus Christie. Getting Eagle Ford or Permian to Loop, as I remember reading, is a problem. So, Loop will probably be selling Mars, or Louisiana Sour. My guess.
2018-02-20 Bloomberg – Shell Says Loaded Mars Crude on First LOOP Supertanker Export
It’s a 300k per day fill rate, but the VLCC will first need to be offloaded. About one week for unload, and one week to load, my guess. Meaning an up capability on exports, of at best, 150k a day. Still substantial.
Price of Oil
Some people think that oil over $100 will crash the economy. Yet the evidence they produce is circumstantial at best. Recessions have occurred over the centuries and oil price had nothing to do with most of them.
https://en.wikipedia.org/wiki/List_of_recessions_in_the_United_States
At $100 oil would represent about 4% of everything people bought. If you consider a loaf of bread for £1.00. All the cost of planting wheat, pesticides, harvesting, transportation to factory and transportation to the shops would only amount to 4p.
When you consider the average mortgage in the UK at being £1,300 per month, which is a whopping 50% of average income. It makes the argument that a family paying 6% of their income for everything oil delivers instead of 4% rather ridiculous.
If people bought slightly more efficient cars, such as these.
http://www.autoexpress.co.uk/best-cars/62048/most-economical-cars
An oil price of $150 – $200 would have little effect.
If people bought more electric cars such as these,
http://www.autoexpress.co.uk/best-cars/electric-cars/86169/best-electric-cars-on-sale
the price of oil would eventually be irrelevant. Just sayin’.
Hi Peter, Island Boy,
My thinking is that while most people who are reasonably secure, economically, can easily adjust to high oil prices, there are too many people and industries who cannot, for various reasons.
On the one hand, we have all the people who are living more or less hand to mouth, paycheck to paycheck. I know a LOT of people in this situation. They get by as best they can, and getting by often means sacrificing their own health, and that of their kids. When it comes down to getting to work and paying for groceries and rent, or fixing one’s teeth or eating right……. cheap groceries and a roof count more than a balanced diet and dental health.
There are millions of people in this situation, and when they slip past the line of being self supporting to being on relief……….
Then there are the positive feed back effects to be considered. When gasoline goes up, even moderately well off people tend to cut back a little on unnecessary trips such as out to eat, or shopping. This feed back can feed on itself, with retail clerks and waitresses losing their jobs or being put on reduced hours. The effect may be especially pronounced in the case of businesses that depend on cheap travel, meaning tourist traps of all kind.
These effects spill over into the rest of the economy, like ripples from a stone dropped in still water.
We sure as hell can learn to buy more economical cars, but unfortunately the people who need them most are in the worst circumstances in respect to being able to buy such cars.
They just don’t have either the money or credit necessary.
OFM,
All of that is true, but the oil price where the overall economy is affected significantly may be $150/b or more. High oil prices (around $110/b rough average) from 2011-2014 had little negative effect on overall economic output. Higher World GDP may allow even higher prices in the future (maybe $160-$170/b) without significant problems. Above $200/b in 2020, would likely cause an economic slowdown, but it will depend on the response of supply and demand to the higher oil price, tricky to predict, but potentially oil price never gets to $200/b as supply increases (or decreases more slowly) and demand falls in response to higher oil prices.
Hi Dennis,
You are probably right in that high priced oil is not in and of itself a big enough problem to cause another major economic downturn.
Expensive oil will be just one more straw on the economic camel’s back, and no one straw will break down the camel.
But there’s a lot of straw around and quite a bit of it is finding it’s way onto the camel’s back.
Maybe economic growth will out run our ever increasing obligations.
Maybe not.
Just the cost of supporting old folks, people like me, is probably enough to break the bank within the next decade or two.
High oil prices are highly correlated with high food prices and high food prices are highly correlated to social unrest. The majority of people in the world don’t really care about an economic downturn in OECD countries and would consider the poorest there, even if they are living with no savings, as being quite well off.
OFM
I agree, higher oil prices will be just another weight to carry that we could do without. The effect would be minor in a world that was economically robust. Unfortunately the opposite is true.
UK debt in the decade of the 1980s went up by only £40 billion to £151 billion. IN 2009/10 it went up by a staggering £200 billion.
https://www.ukpublicspending.co.uk/spending_chart_1900_2020UKb_XXc1li111tcn_G0t
Today paying the interest alone costs the tax payer £55 billion.
https://www.economicshelp.org/blog/3028/economics/interest-payments-on-uk-debt/
When you consider that we spend only £13 billion on all the police forces, one realizes how bad the debt actually is.
https://www.theguardian.com/uk-news/2017/nov/09/britains-police-budgets-to-lose-700m-by-2020-amid-rising
Most older people have paid tax, N.I. vat, council tax all their lives, the money should be there for them when they retire.
But I agree the costs are high and incompetent governments have not planned for the increasing number of older people.
DC Wrote:
“All of that is true, but the oil price where the overall economy is affected significantly may be $150/b or more. High oil prices (around $110/b rough average) from 2011-2014 had little negative effect on overall economic output.”
I think your analysis is flawed. The High energy prices was the trigger to the great recession. in 2009 Fed and other Central banks dropped rates to historic lows and started QE to prevent a deflationary spiral. The drop in rates and Liquidity provided the means for consumers, corporations & govts to service there debt. However, there was no significant debt reduction. In fact Debt is never been higher and continues to increase. The majority of western consumers still live paycheck to paycheck and use debt to subsidize their living standards. Even to this day, nearly after 10 years of the great recession, Interest rates remain extremely low. If the economy was on solid ground rates would have been normalize years ago. I suspect that as consumers continue to increase their debt load it will eventually trigger another crisis. Perhaps history will repeat itself and soaring energy prices will again trigger the next crisis.
As George Kaplan wrote, higher energy prices trigger increases in food prices which ended up triggering the Arab spring in the Middle East. China and India had be able to prevent mass social unrest by subsidizing energy and food prices. However this time, both China & India have substantially more debt and may not be able to sustain subsides if they persist over a long period.
That said, its likely that energy consumption will fall as prices rises. The West and Asia are facing aging populations, and business are moving toward automation to avoid rising labor costs (healthcare, rising minimum wages, etc). Its seems likely that employment will remain weak for the foreseeable future as automation outpaces job creation. Also increasing pension and entitlement obligations will be major economic drag, as gov’t continue to increase taxes to fund retirees pensions & entitlements. Its already happing in the US, Last year Puerto Rico went bust, unable to service its debts. There are several states that face the same debt & pension liabilties: Illinios, New Jersey, Connecticut, Pennsylvania, Kentucky, etc.
Higher oil price means higher inflation, which means higher interest rates, which means recession.
ktos,
Oil prices were high from 2011 to 2014, inflation was not high in most places, nor were interest rates. Generally inflation will be high when economic and wage growth are robust, typically this can be controlled with good fiscal (less government spending or higher tax rates) and monetary (lower money supply) policy.
Official inflation was not high, because world economy was weak.
ktos
The worst cases of inflation have occurred when essential goods are not available as in Germany in the 1930s. Food was scarce so the prices skyrocketed.
http://www.johndclare.net/Weimar_hyperinflation.htm
Venezuela is a case in point today, it has an inflation rate what most people can comprehend.
https://www.bloomberg.com/news/articles/2017-10-10/imf-sees-venezuelan-inflation-rate-rising-beyond-2-300-in-2018
This is caused mainly by government printing money far in excess of production. Producers start holding back on production to sell at a higher price tomorrow, this causes further inflation and the downward spiral.
Venezuela is not disintegrating due to high oil prices.
Oil prices were low in 1975
https://www.statista.com/statistics/262858/change-in-opec-crude-oil-prices-since-1960/
But inflation in Britain was at an all time high
http://news.bbc.co.uk/1/hi/uk_politics/4553464.stm
Venezuela is disintegrating because of low oil prices – they need about 130$ to finance their socialistic utopia and all the secret services.
If something is scare, prices will go to the sky even with non inflatable currencies.
My Uncles bought a small sack of potatoes after the war for a gold coin – and for silver you got an egg. Best things to have where cigarettes and booze.
Oil at 50$ represented something like 2% of GDP. This is quite low in regards of the average of the last 40 years (3.24%)… In the 60’s, it was nonetheless 1% of GDP. But 50$ was low enough to boost oil consumption in the last three years, and leave enough purchasing power to acquire other stuff, like cars.
And this is how it works. A fast increase in the oil price at 100$ won’t reduce oil consumption, but will reduce the consumption of other stuffs, by 2%… Yeah, growth will slow. And a 200$ price will put more pressure. If oil represents 8% of GDP, it’s 6% more than today, which will make a serious change in the flow of money and probably trigger a recession. Especially if the economy was stimulated for some years with artificial measures for economic recovery, like low interest rates and several QE.
Of course, a slow increase to 100$, over a few years, could be sustained. The economy would adapt, alternative energy would be developed, oil producers would search and develop expensive oil fields. This is what actually happened in the first decade of the century, which ended in the price plunge of 2014. The financial crisis was a temporary perturbation on oil prices, which quickly recovered. And the crisis was not directly related to the price of crude.
George, Peter, Dennis, Island Boy,
We all have a piece of the truth in this case.
Things might work out ok, economically, if our luck continues to hold.
Society CAN change, and does, sometimes, witness the fact that we have tobacco addiction on the run here in the USA and some other countries.
With luck, we well off westerners may come to understand that the one best possible ACHEIVABLE thing we can do for ourselves, personally, is quit the junk food diet that’s killing us slowly, individually, and by the tens of millions, collectively, but NOT FAST ENOUGH to solve the health care crisis.
Maybe we will get a couple of Pearl Harbor Wake Up bricks upside our collective head in the form of an oil supply crisis within the next few years. This would would have the effect of putting every electric car assembly line and battery factory on the planet on a twenty four hour schedule.
Maybe the real question is whether the technological ambulance will get us to the figurative society emergency room before it runs out of gas……… In that case, we die enroute.
The USA seems to trying a new method and switching from killing slowly to killing really quickly with opioids and methamphetamine – gotta keep those profits up for big pharma.
https://oilprice.com/Energy/Oil-Prices/Saudi-Arabia-Wants-70-Oil.html
So, they have set it up so oil goes way over $70 before exit. Any time it gets close to $70, and OPEC starts talking about exit, the price will crash. They are convinced over 1.8 million will immediately be thrown into supply. That’s ok, it will overcorrect radically by year end. But, they did create their own monster, with the “cut” slight of hand. They are stuck with it until year end, maybey longer. They probably will need to reconstruct a “cut” that more approximates to what is above what they can produce comfortably. Which is, I am guessing, around .9 million, or half.
Should be interesting to see what inventory levels are at by Dec. 31. But, they know by now, any talk of an exit, or reconstruction of “cut” will produce a drop in prices before year end, at this point. Even at $80 a barrel. Venezuela imploding would be a huge relief to them.
Guym,
Anyone can look at the numbers and see the “cuts” have been quite far from 1.8 Mb/d, probably about 1.2 Mb/d based on 5 month average output of OPEC and Russia.
Seems unlikely that more than 1 Mb/d will be brought back online by OPEC and Russia, maybe 500 kb/d at best, until there is more investment. No doubt OPEC will maintain quotas to keep up the illusion that they have a lot of spare capacity.
Do you have a sense for why they feel the need to keep up the illusion of spare capacity? Is this political pressure from governments not wanting social unrest of it were to come to light there is no spare capacity?
Saudi wants global investments in oil to be low I guess. Keeping the threat of mobilising spare capacity when they want to is kind of a soft power play.
Saudi Arabia wants a reasonable and steady oil price. This allows them to plan projects. Saudi Arabia in the past held a large spare capacity which provided stability of supply and price.
They got no thanks for it what so ever. The US suddenly finding a new source of oil produced flat out without any concern for price or what that would do to investment in future projects.
Back in 2005 people started saying. Why have the Saudi not kept spare capacity, we need it. Well you cannot have it both ways. You cannot have a free market and also demand someone else pay for capacity you may not want to use.
And the Easter Bunny, and Santa Claus are real.
Guym
So what was Saudi Arabia doing here then?
https://www.weforum.org/agenda/2017/01/argentina-and-inflation-what-the-rest-of-the-world-can-learn
If not dropping production from 10 to 4 million barrels per day to give price stability.
Jeffrey Brown just posted this. Full article is behind a pay wall.
FT: Shale oil will contribute to future crude price instability
https://www.ft.com/content/1b911cc8-1583-11e8-9e9c-25c814761640
US output is too small, too slow, and too competitive to play swing produce
The consensus view that crude oil prices will range around $60 a barrel in coming years, with
flexible US shale oil acting as a “swing producer” to prevent spikes, is comforting.
Neither the oil industry nor governments, consumers and investors have enjoyed the return of
boom-bust oil prices over the last 15 years.
But $60 is no more likely to be a “new normal” than $100 was thought to be five years ago.
Recent history, shale’s intrinsic attributes, and looming supply and demand trends strongly
suggest shale oil is likelier to contribute to price instability than dampen it.
It is crucial to distinguish between short cycle and swing production.
Short cycle shale production ebbs and flows faster than conventional oil production — quarters instead of years.
SNIP
Thus, barring an economic downturn, by early in the next decade the world economy will need but lack new oil production from longer-cycle conventional projects cancelled or delayed since the 2014 bust. Inventories will normalise amid wafer-thin spare production capacity (currently only about 2.5m b/d, or less than 3 per cent of world supply and likely to fall) that is dwarfed by the amount of oil supply at risk of geopolitical disruption (about 4.5m b/d currently). Prices will rise sharply, likely returning to the triple digits, to restrain consumption and reflect a varying risk premium.
I would also add that US shale oil production is heavily weighted toward the light end, condensate and NGL, with minimal distillate content.
“WTI oil prices are gaining on Brent as strong U.S. demand and Canadian pipeline issues tighten U.S. oil supply even further
Today’s FT lays out the case why shale oil will not be the global swing producer. Simply, they say it is because “U.S. output is too small, too slow, and too competitive to play swing producerâ€. The thought that somehow shale was going to put a cap on global oil prices is a folly. The reason being is that not only shales steep decline rate per well but also its cost.
The FT says that “U.S. shale production is comprised of many dozens of highly idiosyncratic public and private companies, each competing with each other to maximize reserves and production. Shale’s shorter cycle ebb and flow can stabilize prices, but only coincidentally and depending on prevailing, broader market fundamentals.
The FT writes that “true swing production is a very different animal: swing producers comprise a relatively small number of government-sanctioned entities controlling the bulk of low-cost wells that collude under a policy mandate to stabilize oil prices. They adjust production proactively, at lightning speed by oil industry standards – weeks – and indefinitely to reduce price volatility and anchor long-term price expectations.”
http://www.321energy.com/reports/flynn/current.html
JODI’s total products demand data – I thought this was worth a quick look. It seems that thanks to low oil prices & economic growth demand has managed to rise back above the trend line that started in 2004. (The data isn’t perfect, I used it almost as is but with gaps filled with the data copied from adjacent cells – I’ve been reminded that it’s called interpolation 🙂 )
You were asking earlier about the amount within the pending data file. Based upon December’s first amount of 724k per day, I am estimating the total to be close to 850k. By the second month of posting, actual RRC production (not estimates) is coming damn close to EIA monthlies. Nov and Oct were close within the second month, and Sept had to have three months to come within 9k of the EIA monthly. Current month is always an estimate, but I am guessing EIA numbers will be around 3940k per day for Dec.
The pending file makes all the difference