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cushing storage glut media nyth is closely related to the Great condensate con was aptly formulated by Jeffrey Brown in this
econbrowser.com post (
http://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595My premise is that US (and perhaps global) refiners hit, late in 2014, the upper limit of the volume of condensate that they could process, if they wanted to maintain their distillate and heavier output–resulting in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C (Crude + Condensate) inventories.
Therefore, in my opinion the US and (and perhaps globally) C+C inventory data are fundamentally flawed, when it comes to actual crude oil inventory data. The most common dividing line between actual crude oil and condensate is 45 API gravity, although the distillate yield drops off considerably just going from 39 API to 42 API gravity crude, and the upper limit for WTI crude oil is 42 API. . . .
Note that (in 2015) 22% of US Lower 48 C+C production consists of condensate (45+ API gravity) and note that about 40% of US Lower 48 C+C production exceeds the maximum API gravity for WTI crude oil (42 API).
Similar observations can be found in
http://www.reuters.com/article/2015/03/23/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323In a pressing quest to secure the best possible crude, U.S. refiners are increasingly going straight to the source.
Firms such as Marathon Petroleum Corp and Delek U.S. Holdings are buying up tanker trucks and extending local pipeline networks in order to get more oil directly from the wellhead, seeking to cut back on blended crude cocktails they say can leave a foul aftertaste. . . .
Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
The blends tend to produce a higher proportion of fuel at two ends of the spectrum: light ends like gasoline, demand for which has dimmed in recent years, and lower-value heavy products like fuel oil and asphalt. What’s missing are middle distillates like diesel, where growing demand and profitability lies.
For example as recently as February 2016 Art Berman argued in Forbes that the price of oil is controlled by the level of storage at Cushing. This hypotheses (or more precisely media myth) was also propagated by US MSM several time in 2015. Here is a relevant discussion:
oldfarmermac , 02/29/2016 at 6:01 pm
http://www.forbes.com/sites/arthurberman/2016/02/29/what-really-controls-oil-prices/#3aca881b71e4likbez , 02/29/2016 at 7:51 pmHere is a short excerpt from this article, in which Berman basically argues that the price of oil is controlled by the level of storage at Cushing. I agree at least to the extent than the price correlates closely with storage at Cushing.
For oil prices to increase, Cushing inventories must fall. That means that both U.S. tight oil production, chiefly from the Bakken play, and Canadian light oil production brought by pipeline to Cushing must decline.
Bakken production was consistent in 2015 at about 1.2 million barrels per day. Canadian oil imports to the U.S. decreased from April through July 2015 and may have contributed to the fall in Cushing inventories that lead to a $15 per barrel increase in WTI prices. At the same time, decreased production from the Eagle Ford and Permian basin tight oil plays would free up storage in the Gulf Coast that might allow more oil to flow out of Cushing.
... ... ...
OFM,oldfarmermac, 02/29/2016 at 6:21 pmFrom the previous Ron's post discussion:
http://peakoilbarrel.com/oil-price-and-its-effect-on-production/#comment-561326
See also a more valuable Art Berman presentation (PDF)
IMHO this presentation is more valuable then his interview.
http://peakoilbarrel.com/oil-price-and-its-effect-on-production/#comment-561368
One interesting take from Art Berman presentation is that he ignores "Great condensate Con" (and grossly overplays Cushing "storage glut" MSM meme). He also thinks that without OPEC cut $30 oil price range will last for the whole 2016:
• Energy markets have been characterized by low oil prices and over-supply since mid-2014.
• Supply deficit before Jan 2014, supply surplus after
• Prices fell from 2011-2013 average of $111 per barrel to average of $52 in 2015.
• Without an OPEC cut, 2016 prices will probably be in the $30 per barrel range.
… … …
U.S. crude oil produc4on has declined about 570,000 bopd since the peak in April 2014,
about 60,000 bopd per month.
• EIA forecast is for a total decline of 1.4 mmbpd by September 2016 ( ~100,000 bopd per month) before increasing again based on $43 per barrel WTI by year-end 2016 and $58 by year-end 2017.
• Price deck has WTI at $43 per barrel by December 2016 & $58 by December 2017.
• Forecast suggests that the oil market is sufficiently in balance now for prices to increase but that production will not respond to price signals until later in 2016-very optimistic.
… … …
Little chance that oil prices will increase beyond the head-fakes and sentiment-driven price cycles of 2015 and early 2016 until U.S. crude oil storage begins to decrease.
• Oil stocks are currently 152 million barrels above the 5-year average and 128 million barrels above the 5-year maximum.
… … …
• Cushing and Gulf Coast storage make up almost 70% of U.S. working storage.
• These areas are currently at 84% of capacity. Cushing at 89%.
• As long as storage volumes remain above 80% of capacity, oil prices will be crushed.
• Until U.S. oil production declines substantially, storage will remain near capacity.This article is a little on the long side, for those of us who are into sound bites, but folks with more patience will find it illuminating, and maybe even find a little something in it to improve their personal morale, if they are feeling really down about the future.likbez, 02/29/2016 at 8:08 pmhttp://www.scientificamerican.com/article/world-s-richest-man-picks-energy-miracles/
A note on "OMG Cushing is filling up hysteria" or negative correlation of oil price with Cushing recently discovered by Art Berman:http://www.forbes.com/sites/arthurberman/2016/02/29/what-really-controls-oil-prices/#3aca881b71e4
Here is a short excerpt from this article, in which Berman basically argues that the price of oil is controlled by the level of storage at Cushing. I agree at least to the extent than the price correlates closely with storage at Cushing.
… … …
That's what happens when good people get into bad company due to lack of employment opportunities caused by shale oil price crush :-)
I wonder whether this is Erik "know everything" Townsend (a retired software entrepreneur turned hedge fund manager; see http://www.macrovoices.com/podcasts/MacroVoices-2016-02-25-Art-Berman.mp3 ) or somebody else ;-)
rockman on Sat, 27th Feb 2016 7:56 am
And to add to some of the good points made: Cushing contains only 20% of total US oil storage capacity. Notice they don't mention the fill level of that total: last time I looked it was about 65%. That means 35% of the 450+ MILLION BBL CAPACITY is still empty.
And why are we still importing oil: lack of sufficient domestic AVAILABILITY…not production. The vast majority of oil going into Cushing IS NOT do to a lack of buyers as the import numbers indicate. It's largely do to speculators hoping to take advantage of f increases in future oil prices. The net effect is that these speculation OIL BUYERS are competing with the refiners for domestic production.
Which, again, explains why we still import a huge volume of oil despite the constant and foolish use of the word "glut". IOW if we are still importing oil how can there be a glut of domestic oil: the US lacks sufficient oil production to satisfy the demand from the refineries AND speculators.
rockman on Sat, 27th Feb 2016 9:39 am
A few more FACTS to offset the "OMG Cushing is filling up" hysteria. First, Cushing is in PADD 2 as they point out. But it isn't the only tank farm in that midwest district: it only holds 60% of that total capacity.
And now compare the 88 mm bbl capacity to the PADD 3 (essentially Texas and LA. where the bulk of the refineries are) capacity of 260 mm bbls. Between the speculator purchases and the smaller number of refineries combined with the large volume of Canadian imports seeing Cushing filling up is no surprise.
And we're just talking about tank farm storage.
So again compare the 88 mm bbl capacity at Cushing to the total storage capacity at US refineries: 179 mm bbls. No: the volume of oil held at refineries is not part of the total TANK FARM capacity. So how much is the Cushing storage capacity compared to tank farms + refinery storage: 13%.
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Apr 21, 2020 | www.moonofalabama.org
juliania , Apr 21 2020 15:43 utc | 61On the previous thread, Piotr Berman @ 417 did bring up the subject of this post by b, and had the following final comment: "...Actually, the most acute pain is among the clever folk who provided the so-called hedges, namely who sold the obligations to buy oil at a certain price. They are losing hundreds of billions -- my guess. Now they are forced to buy AND store, hence the negative price."
Thanks, Piotr. Some of what is happening makes a bit more sense to me as far as the strange dealings in the stock market are concerned.
Also, just above at 416, karlof1 had this to say: "...Was the West ever on the path to making its goal the improvement of the Common Man as advocated by Wallace and his political allies?..." His answer is NO (exclamation point.)
My answer is YES (exclamation point.) Even if you only progress as far as the creation of the UN, with the leadership of Eleanor, that is an important pivotal moment for mankind which we cannot ignore. But I will state uncategorically that the JFK administration had similar idealistic goals and would have carried them out, had it not been for divisive powers plotting against it. That such dastardly powers succeeded does not negate the previous effort.
And even the example of China proves that this is not an impossible dream for mankind in general. As also is the example of Russia. We are fortunate in this generation to have two role models instead of one.
I don't have the Frost poem at hand so I will thusly mangle the last lines (sorry)
Two paths lay in the woods, and I
Took the one less travelled by
And that has made all the difference.I've mangled it, but the meaning is there, I think. (I'll go find the correct version, and point of reference, I was a college student when Robert Frost came to Johns Hopkins and I heard him read his poems. He did so also at Kennedy's inaugural.)
gm , Apr 21 2020 10:36 utc | 8
What -$37/bbl oil means to you:arby , Apr 21 2020 12:10 utc | 17Oil futures paper contracts market (in normal times of stable->rising oil prices and plenty of tank storage capacity a simple safe "buy low, hold, sell high" investment vehicle used heavily by investment banks, hedge funds, ETFs and teachers', municipal employees', etc, retirement/pension funds) explained in 5 minutes by Chris Martenson starts at ~minute 35:00:
Emily, We may still be at or around peak oil. That does not mean that all of the heavily indebted countries and oil companies won't pump what's left as fast and hard as they can.William Gruff , Apr 21 2020 12:10 utc | 18Now you have to stir in a massive plunge in demand to the equation. Seems to me that all newer oil discoveries are deep sea or shale. All of which require much more energy to produce then say thirty years ago.
When it takes the equivalent of one barrel of energy to produce one barrel of energy it will be lights out.
dan of steele @2Emily , Apr 21 2020 12:56 utc | 24The petrodollar was not in and of itself the mechanism that the US used to "export debt" and enrich itself off global trade. Rather, the petrodollar was the mechanism used to lock-in the US$ as the global reserve currency. If you wanted oil, you needed US$. After that it was just convenient to use US$ for other internationally traded commodities as well. Of course, this made even more sense way back in the distant past of the middle of last century because most of the international trade in manufactured goods was for American products, for which you'd have to use dollars to buy anyway.
The empire fanbois will cook up all kinds of explanations for why the dollar will remain the Global Reserve Currency in order to reassure themselves of the empire's continued hegemony, but the fact is that all of the "locks" locking other countries into that regime are now gone. Countries can choose to walk away now whereas in the past that would mean giving up access to oil and no longer importing all of those awesome things that the US used to make. That is not a barrier anymore.
Arby 17.gm , Apr 21 2020 13:19 utc | 27
Thank you for taking the time to reply.
But something to ponder
Forbes
https://www.forbes.com/sites/michaellynch/2018/06/29/what-ever-happened-to-peak-oil/
Yergin
https://www.technologyreview.com/2011/09/22/191161/peak-oil-debunked/
Well good news for those of us who agree with Edgar Cayce.
'Russia is the hope of the world'.
Russia has 60 years worth left and thats with its known reserves.
Hasn't touched the Arctic yet.....
https://www.worldometers.info/oil/russia-oil/US/Western financial markets are a "musical chairs" game, where right now more chairs are being pulled out from the game faster than the FED and the central banks can 'digitally print' new chairs to keep the game going.Peter AU1 , Apr 21 2020 14:27 utc | 39Looks like energy dominance will get a bail out.juliania , Apr 21 2020 14:36 utc | 41
"We will never let the great US Oil & Gas Industry down. I have instructed the Secretary of Energy and Secretary of the Treasury to formulate a plan which will make funds available so that these very important companies and jobs will be secured long into the future!" Trump said via Twitter.
https://sputniknews.com/us/202004211079043543-trump-instructs-treasury-energy-depts-to-devise-plan-to-fund-us-oil-gas-industry/Is this a result of all the lockdowns? A sort of automotive general strike occasioned by the virus, aided and abetted by government enforcement of restrictions on industry, travel, general hulabaloo?Trisha , Apr 21 2020 15:27 utc | 56Peace has descended upon a weary world. Nature has commanded us to cease and desist from gigantic insults upon the earth. Stop digging! she says, Leave it in the ground! Cease and desist making war for oil!
What does it profit a man? It profits him nothing! I have no idea where this leads, but it is a delicious moment. Look, see the power we have to bring everything to a standstill, even when we only do it because we are forced to! What if we did it willingly?
Where are your trillions now, moghuls?
The earth has spoken. We should all listen. Me, I am going out to plant potatoes.
Peak shale has arrived. The energy inefficiency of fracking - directly related to the economic efficiency of producing shale - killed it off. This would have happened even without COVID-19.The same will (eventually) happen with oil. The global economy - already teetering - has now been pushed over the edge by COVID-19. The demand side of capitalist growth has been temporarily (and in some cases permanently) crushed - which is a good thing for the planet - as workers are idled for the foreseeable future, and many out of a job forever.
Bottom line is that we live on a finite world which capitalism treats as an infinite resource.
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Nov 10, 2017 | peakoilbarrel.com
Energy News says: 11/08/2017 at 12:18 pm
EIA weekly change in ending stocks (crude+products).George Kaplan says: 11/08/2017 at 4:26 pm
Overall stocks down 0.56%, pretty much inline with recent trends, crude up 2.2 mmbbls, gasoline down 3.3 and distillate down 3.4. But the only number that matters to the traders is the crude and because it is up price falls and it's reported we must be back in a glut. Bonkers.FreddyW says: 11/09/2017 at 3:55 amI think we are in refinery maintenance season now, so crude stocks should increase normally. Interesting to note is that gasoline and distillate stocks are back to normal levels. So they will have to draw a lot more from crude stocks going forward.Guym says: 11/09/2017 at 10:30 amSame principle drives lemmings, I think. They have to be over the cliff, before they will recognize it is there.
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May 30, 2017 | peakoilbarrel.com
Mike says: 05/30/2017 at 6:35 pmGot it tee-tee; America is still a net importer of crude oil. That's some good investigative reporting there.Look, inventory levels are still at an all time high in America and the bulk of that is light tight condensate. The export ban has been lifted in the US for over three years now; nobody afar wants to import LTO, or much of it, and we still can't lower those inventories. The price of oil is low, and volatile. In the mean time all those big wells you own in Oklahoma are just making the problem worse. And while all this is going on, hold onto your knickers .oil imports into America are going UP, not down. Google it.
Canada is the 10th largest oil consuming nation in the world, Mexico the 11th and the UK the 18th. America, on the other hand, is the largest oil consuming nation in the world, by a wide margin. We do not have the LTO resources to achieve, nor sustain, hydrocarbon independence. Forget the costs, and the additional burden that attempting to achieve hydrocarbon independence would place on our national debt, it can't be done. There is not enough of it.
I dislike the American shale oil industry, in general, because it cannot function without borrowed capital and it no longer has the ability, in my opinion, to pay back the hundreds of billions of dollars it owes. I understand that doesn't bother you, and I understand why.
I also dislike the lying the shale oil industry engages in that convinces other stupid people that we have all the shale oil we ever need in America, enough for ourselves, and anybody else in the world that wants to buy it.
Personally, I would rather sell my oil for a higher price than current prices, but then again I have to pay to get it out of the ground, unlike yourself, I am sure, who gets it free and clear of all costs.
I also embrace oil price stability as that leads to employment stability and a healthier oil industry for America's future. I also believe it is important to conserve our remaining hydrocarbon resources in America and to otherwise develop what is left of those resources at a pace that is commensurate with the world crude oil market.
Again, I understand completely why you don't get that. I can't help you.
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Watcher says: 01/09/2017 at 3:02 pmJan 11, 2017 | peakoilbarrel.com
SPR Drain - Buy High – Sell Low ?
http://www.zerohedge.com/news/2017-01-09/us-sell-8-million-barrels-oil-strategic-petroleum-reserve
Why? To fund the pumps and stuff that have rusted away.Boomer II says: 01/09/2017 at 5:53 pm
Even if the money is needed for repairs and infrastructure, why sell when prices are low? Why didn't they sell when the prices were high?Watcher says: 01/09/2017 at 6:10 pm
More SPR things:Fernando Leanme says: 01/10/2017 at 9:44 am720 million barrels in the US SPR when full. It's usually not 100% full and when it is (last happened Dec 2009) it's not really full because you can't recover 100% of what you store. Oil gets into pores in the rock and won't come out. Just like less than 100% recovery of oil from an oil field.
The usual calculation is 720 / 20 mbpd US burn = 36 days of consumption storage. With US production at about 8.5 mbpd that number seems to rise to a little less than double - call it 70 days.
But not true. Maximum extraction rate is only 4.4 mbpd (takes 13 days from the word go for the first barrels to enter the system). Not 11.5. So the total embargo of imports scenario because Canada wants to save it for their grandkids means the country goes from 20 mbpd consumption to 12.9 mbpd - for 160ish days (720/4.4) and then just the 8.5 is all we have to function.
Gonna have to compute oil consumption required to haul/deliver food to stores and for people to drive to stores to get it. Tricky for the haulage from central america (fruits).
Salt dome storage caverns don't have pores. They're caverns.Fernando Leanme says: 01/10/2017 at 9:51 am
The Venezuela figure is BS. The reserves outlook gets grimmer by the year, because the current development strategy is incompatible with enhanced recovery. The areas under development are mostly the "sirloin steak" in the Orinoco heavy oil belt, and these high graded areas are now being gutted by pdvsa and partners. They are going after quick kill primary recovery, ruining the reservoirs. This means that not only is the 300 billion barrel figure a poor number, the "real number" is gradually degrading as they continue to lower reservoir pressures and allow water to penetrate the developed reservoirs.Dennis Coyne says: 01/10/2017 at 4:11 pm
Hi Fernando,Based on what you know I think your estimate for URR for Orinoco is about 100 Gb, if I remember correctly, due to the poor development you outline above.
Please correct me if I am remembering incorrectly. Thanks.
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Jan 08, 2017 | peakoilbarrel.com
Ron Patterson says: 01/02/2017 at 1:20 pmSW, just curious but what do you think will cause this turnaround. That is from the current glut to demand outstripping supply. US storage is near its all time high and OECD storage is 300 million barrels above its 5 year average.Javier says: 01/02/2017 at 8:49 pmOECD commercial inventories fell in October for the third month in a row. They have drawn 75 mb since reaching a historical high in July, but remain 300 mb above the five-year average. Product stocks have fallen twice as quickly as crude during that period. Preliminary data show stocks falling further across the OECD in November.
How much confidence do we have on oil storage accounting? According to Art Berman much of it is unaccounted for oil. Looks like a very good way to manipulate oil prices.Ron Patterson says: 01/03/2017 at 7:08 amMy take is that the powers of the world are very much afraid of what a new global recession could do to the shenanigans they have been running at the Central Banks to keep the system from imploding and are very much decided to do everything on their power to prevent a new global recession, and a very important part of it is to keep oil price affordable to prevent the economy from stalling. They cannot control neither production nor demand except by staging a war, but as price is determined by the effect of the production/demand ratio on oil storage, they can control price by rigging the storage reporting. Unaccounted for oil could be the tool to do that.
For most of the world's oil storage, there is no reporting. We have only the USA and a wild ass guess at OECD storage. We have nothing for Eastern Europe, Africa or Asia.Don Westlund says: 01/03/2017 at 12:33 pmWTI jumps up and down a few cents when the US storage figures come out each week, but that's about it. And when that happens the price very quickly reverts to what the actual supply and demand dictates.
If there were actually storage reporting for most of the world's oil, then your conspiracy theory might hold water. But there is not and it does not.
https://www.energyaspects.com/company/events/amrita-sen-ons-2016-conference-appearance?utm_medium=bannerMatt Mushalik says: 01/03/2017 at 3:33 pmThis is a presentation by Amrita Sen at Energy Aspects a few months ago. At the 4:30 minute mark she discusses worldwide crude draws. She is claiming the only place in the world we are getting builds is in the U.S. Not sure where they are getting their information.
Our post was NOT about conspiracy theories. It has number crunching on the statistical fact that there is a huge discrepancy between US crude oil production, imports, exports and refinery intakes.Javier says: 01/04/2017 at 7:28 am8/10/2016
U.S. Storage Filling Up with Unaccounted-For Oil
http://crudeoilpeak.info/u-s-storage-filling-up-with-unaccounted-for-oilMatt,AlexS says: 01/02/2017 at 9:09 pmI know the article said nothing about intentional overreporting of crude oil stocks. It just occurred to me that if intentional it could have a clear effect on oil prices.
Ron,
That USA is the only one reporting crude oil stocks makes it easier to manipulate them, not harder.
Is the following correct?:
How do we know that there is a huge global excess in crude oil?
We know there is some excess from multiple sources, but we only know that there is a large excess from USA reported oil storage.Where is that large excess in USA crude oil storage coming from?
We don't know as 4 out of 5 barrels in USA crude oil storage are from unaccounted-for oil.I think the situation demands an explanation as large unaccounted-for oil is a new phenomenon that started when oil prices were very high.
"OECD storage is 300 million barrels above its 5 year average."SW says: 01/04/2017 at 9:44 amWhen the IEA and all other oil market observers compare current storage levels with 5-year average they miss two important things:
1) Global oil demand continues to increase. Therefore, in relative terms (inventories as % of annual demand) the volume of oil in storage is not as big as if we compare absolute volumes for this year and previous years.
Thus, according to the IEA, global oil demand in 2017 should average 97.51 mb/d. This is 7.94 mb/d higher than in 2011 (89.57 mb/d) and 5.39 mb/d higher than 5-year (2011-2015) average (92.12 mb/d).
7,94 mb/d = 2898 million barrels/year
5.39 mb/d = 1966 million barrels/year
Now compare this with the 300 mbbls surplus in crude inventories vs 5-year average.2) There are two "market buffers" that were always used as a measure of over/under supply in the oil market.
The first are crude and product inventories. They are indeed above 5-year average.
The second is OPEC spare capacity, which is well below historical averages.OPEC output cuts will result in decreasing inventories, but spare capacity will increase.
I was simply commenting on the chart at the top of the post. Perhaps I misread it?
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naked capitalism
Robert HahltegnostPerhaps the true purpose of financial austerity is to reduce oil consumption world wide.
Robert Hahlindeed perhaps, as our financial overlords have such clear benevolent foresight and care about people, not profits or perhaps demand has never recovered from $4/gal gas in 2007 and it's much simpier than that but perhaps the $4/gal gas was done on purpose in order to kill demand and reduce oil consumption, first by high price and then by austerity, perhaps they just wanted to find out what price of gas (apparently $4/gal) would crash the economy so they could save the world through austerity, but first they wanted to get some money in the bank so they could survive his "austerity period" because their kids can't take out student loans because they create an austerity rich environment that the children of the world benefit from but their kids were brought up right so they don't need austerity to be good global citizens, or perhaps crows communicate through quantum vibration and that's why we can't understand the meanings in their throaty calls .
rjsIf peak oil is a problem, austerity is a solution.
ambritit's not a demand side problem; it's supply, which built up as refinery margins were near record highs and contango made it profitable to store products
Isotope_C14Local fuel prices show a more 'nuanced,' which is business speak for rent extraction oriented, situation. Sunday, we went to Laurel, a town some twenty miles north of Hattiesburg. The cheapest gasoline in Hattiesburg cost $1.99 per gallon. Laurel had gasoline selling for $1.76 per gallon, all over town, not in isolated pockets. This price disparity was consistent across brands and types of location. Laurel does not have it's own refineries.
The Oil business has a few rules of it's own, which lowly consumers are not privy to.MLSSeeing as Hattiesburg is in the northern part of Forrest County, and Laurel is in Jones County, could the price disparity be a component of county taxes?
Also, EPA requirements include a variety of fuel formulations depending on desired pollutant reduction in a given air-space. Some formulations are for reduced volatile organics and they may have varying prices.
Chauncey Gardinerday-to-day fuel prices are heavily influenced by all sorts of factors like local tax rates, the cost of operating any convenience store or auto service on premises (local ordinances regarding wages, for example), the volume of business they do, whether a particular city or county has a specific ordinance relating to gasoline formulations, the cost of transporting the fuel from refinery to the station (generally speaking farther = more expensive), and so on. That you're seeing different prices 20 miles apart is not necessarily evidence of rent extraction.
NeqNeqPuzzling that the price of ethanol, a lower btu and more corrosive fuel that is added to and blended with petroleum-based gasoline by refineries, has been maintained in a tight price range since late 2015 and is currently priced near its all-time highs. This while the price of gasoline has fallen. Why?
ambritWasn't there a post a few days ago which showed the US EIA' weekly data was not lining up with actual monthly numbers? Meaning that there were large revisions being made to prior (2) month volumes?
Why should last weeks EIA inventory numbers be considered as anything but a noisy estimate subject to lots of revisions?
NeqNeqThe more cynical among us wonder in what direction the 'revisions' should really go.
PwelderI get that. And I am sympathetic. That doesn't change the fact that any prognostication (on the supplied info) is mood affiliation. Using your gut is fine. Hell, it might be instrumentally better than reasoned argument in certain situations. No need to claim its something other than your gut though. Unless, you are trying to sell something. Then its probably useful to engage in post-hoc rationalization.
a different chrisTwo points to remember about "glut" chatter in the Oil and Gas space:
1) The IEA – and to a lesser extent, the EIA – work for governments of nations which are net importers of crude and products. These governments prefer low prices. This doesn't mean that their published data is deliberately bad. It does mean that if there's a number that lends itself to a bearish interpretation, they'll make sure you know about it.
2) One way to generate such numbers is to shift inventories from jurisdictions with low transparency on storage levels (e.g. the Persian Gulf) to jurisdictions where reporting is somewhat better (US, Western Europe.) The Saudis have been doing quite a bit of this, as part of their war on Iranian/Russian oil revenues. This will be coming to an end within a year or so, as realities of supply and demand overwhelm operations aimed at "painting the tape".
>The Saudis have been doing quite a bit of this
Funny how oil has gotten so messed up – the major producers want to broadcast the fact that there is a glut. Ah Capitalism in all its contradictions
Something to point out to the goldish bugs – the people who just have to have currency attached to something physical, since gold is a hilarious currency anchor in this day and age* they have been switching to recommending oil as the baseline. Wonder how they will spin this?
*think about explaining to an intelligent and even sympathetic-to-backed-currency alien, without any historical reference, why you would pick gold
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Jun 14, 2016 | Bloomberg
Crude inventories fell by 933,000 barrels last week, according to the U.S. Energy Information Administration. A 2.33 million barrel decline had been projected by analysts in a Bloomberg survey ahead of the release. The American Petroleum Institute was said to report Tuesday that inventories rose 1.16 million barrels.
Crude output dropped to the lowest level since September 2014, the EIA data show
... ... ...
Nationwide crude supplies fell to 531.5 million barrels in the week ended June 10, according to the EIA. Stockpiles climbed to an 87-year high of 543.4 million barrels in the last week of April, EIA data show.
Oil-market news:
- Completion of drilled but uncompleted wells in the U.S. will accelerate at a WTI price of $50 a barrel, while $60 oil will trigger an increase in the rig count, according to a report from Citigroup Inc.
- The global market will be almost balanced next year as demand continues to rise faster than output, while the current glut is much smaller than previously thought, the International Energy Agency said.
- Venezuela and the U.S. will begin talks to normalize relations as President Nicolas Maduro said he's ready to exchange ambassadors.
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OilPrice.com
Official data released early on Wednesday confirms expectations of a U.S. crude oil inventory draw, with the Energy Information Administration (EIA) showing inventories down by over 3.2 million barrels for the week ending 3 June.
The EIA's latest weekly status report, released at 10:30am EST, reported a 3.226-million draw on U.S. crude inventories, while the consensus had called for a drop between 2.7 million to 3.4 million barrels. The new data puts U.S. crude oil inventories at 532.5 million barrels-a figure that is still historically high for this time of year.
The EIA's report follows Tuesday's inventory report from the American Petroleum Institute (API), which shows a draw of 3.56 million barrels, slightly more than the official figures just released.
Oil rose above $50 on Tuesday, following the API report, and was holding steady, close to $52 in early Wednesday trading prior to the EIA's weekly status report release.
The Weekly Petroleum Status Report showed gasoline inventories with a build of +1.01 million and distillate inventories with a build of +1.754 million.
U.S. Crude refinery inputs averaged 16.4 barrels per day, according to Wednesday's numbers. That number is 211,000 barrels per day more than the previous week's average. Refineries were at 90.9% of their operable capacity this past week, and gasoline production increased, averaging over 10.1 million barrels per day.
Related: India Putting Floor Beneath Oil Prices As Demand Continues To Soar
U.S. crude oil imports averaged 7.7 million barrels per day last week, which was down by 134,000 barrels per day from the week before. Total motor gasoline imports averaged 815,000 barrels per day. Distillate fuel imports averaged 167,000 barrels per day last week.
Total commercial petroleum inventories increased by 3.2 million barrels.
The EIA notes that total motor gasoline inventories increased by 1.0 million barrels last week, and are well above the upper limit of the average range.
By Lincoln Brown for Oilprice.com
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peakoilbarrel.com
shallow sand , 04/04/2016 at 12:12 amAlthough it makes little sense, US stocks make a huge impact on the worldwide oil price. Until US inventories meaningfully drop, the oil price will stay low, sub $50.Dennis Coyne , 04/04/2016 at 11:05 amNot seeing a sign of that happening yet. Hopefully will soon.
Hi Shallow sands,Ovi , 04/04/2016 at 8:19 pmIt is strange that anybody pays attention to US crude stocks, for the past 4 weeks average net imports of crude have been about 7.6 Mb/d, there are about 200 Mb of excess crude stocks (above normal levels), reduce imports by 1.6 Mb/d and the excess stocks are drawn down to normal levels in 125 days (about 4 months).
It would make more sense to look at the change in refinery inputs and US crude output.
I also do not understand the focus on inventory. Inventory change is a function of "Crude in less crude out". Inventory can be manipulated by importing more and as a consequence keep pressure on price.likbez , 04/04/2016 at 11:15 amWhy does inventory keep going up? It is related to the contango in the oil futures market. In the attached table the front month contango is $1.34, today. If an investor owns storage, he can take delivery today and sell one month forward for a gain of $1.34 less about 50¢ for storage costs. As long as the front month contango stays above $1, inventory will continue to grow.
Although it makes little sense, US stocks make a huge impact on the worldwide oil price.Very true.
At this stage of oil price cycle I do not think that the size of inventories is a material factor, affecting the oil price. It is played as such by Wall Street, but that's just reflects the power of "paper oil" producers. They can choose something else (S&P transportation index readings, for example) and use it to depress the oil price.
What it probably reflects at this stage of the cycle is the level of pure greed.
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fuelfix.com
4) The drop of 4.5 million barrels for gasoline inventories was split betwixt PADD 1 (East Coast) and PADD 3 (Gulf Coast). While the drop can in part be attributed to winter blend stocks being drawn down, the driving force (pardon the pun) has been rising demand. On the more-reliable, less-noisy four-week moving average, gasoline product supplied is up 7% year-on-year. Robust.
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peakoilbarrel.com
Rush of demand for oil storage while oil is available at below $40 prices:With available storage facilities for oil filling up in Houston, Fairway Energy Partners said the time is right for the 11 million barrels of crude storage space it's currently developing.
Fairway Energy Partners plans to convert three salt dome caverns more than 2,000 feet under Southwest Houston into crude oil storage. The company, which is backed by Haddington Ventures, is targeting a completion date of late 2016.
… … …
The Texas Gulf Coast has about 128 million barrels stored at refineries and terminals. It's also about 60 percent full, Genscape said.
… … …
"We're seeing storage levels that we've never seen across the U.S.," Hilgert said. "Crude is piling up everywhere, Cushing is effectively full, and that's started to domino down to the Gulf Coast."
I think frenzied hoarding of oil in anticipation of higher prices is the phenomenon that MSM does not cover. They try to sell it under "oil glut" banner.
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Gaurav , 03/06/2016 at 11:29 pmRon, I am a regular reader of your blog and find it very insightful. I have not seen much written about Oil super contango and reasons for oil storage at multi decade high so would like to highlight below.When there is a temporary over supply, it fills up storage, as more and more storage get filled up it leads to an increase in storage cost. This in turn lead to a contango, meaning future oil prices being at premium. Currently premium stands at 20% for 1 year forward contract. This is super contango and a bonanza for oil traders. If you can find a place to store oil you can make risk free returns of 20% – (storage cost). So, why storage space are filling up so fast its because commodity traders are scrambling to make this trade. It's a positive feedback loop. It can only end when supply falls below the consumer demand.
So, bottom line is, filling up of oil storage early in the cycle is an indicator of oversupply. But in the current late cycle of low oil prices [1.5 yrs already] it is a useless indicator of future oil price movement, oil demand or supply.
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January 20, 2015 | finance.yahoo.com
Traders are in a mad dash to rent some of the world's biggest oil tankers so they can store crude while prices remains in record-low territory.
The Wall Street Journal reports that TI Oceania, which has been booked by oil traders Vitol, is stationed off Singapore and is likely to remain there for most of 2015.
China's Unipec booked Oceania's sister ship, TI Europe, way back in September, when oil prices dropped below $100 per barrel (let's hope they didn't buy the oil then).
The ships are giant. Here's the TI Europe, for example:
Christelle Hall, YouTube
As oil prices continue to plunge amid a supply glut and weaker demand, companies reckon they can make more money from simply hoarding the oil and selling it at later date, when prices rebound.
This phenomenon is known as "contango," a term for when the price of commodity futures is higher than the current price. In this case, traders believe there is more money to be made from simply sitting on oil, if they can bear the costs of storing it.
Euronav
Oil prices will stay low if there continues to be space to store it. However, once storage is full, producers will finally be forced to slow output because there will not be anywhere to put the surplus. From that point, the price has a chance to rebound, assuming demand doesn't keep falling.
According to Goldman Sachs, however, that turnaround probably won't happen as quickly while more firms decide to store rather than sell oil. The investment bank is expecting a slow "u-shaped" recovery, rather than a rapid "v-shaped" bounce in prices:
Not only has the US expanded storage capacity significantly, but Europe has also shuttered refining capacity that can be used as storage, and the global crude tanker fleet has grown by 100 million dwt since 2008 - while oil at sea has remained stagnant given the dominance of onshore drilling. We believe at least a 1.0 million barrel per day surplus can be maintained for a year before any significant problems would arise.
Goldman Sachs
NOW WATCH: This Video Of The Largest Breakage Of Ice From A Glacier Ever Filmed Is Absolutely Frightening
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peakoilbarrel.com
Amatoori, 02/28/2016 at 11:31 amA good but long podcast with Art Berman, not so much new stuff for the people here but gives a great over all picture on the oil market right now.http://www.macrovoices.com/podcasts/MacroVoices-2016-02-25-Art-Berman.mp3
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peakoilbarrel.com
Amatoori , 02/25/2016 at 11:40 am
http://in.reuters.com/article/oil-demand-kemp-idINL8N1644QUJef , 02/25/2016 at 6:28 pmNice piece of the puzzle Amat. Distillates is the glut.likbez , 02/25/2016 at 8:25 pmSO diesel demand has been tanking but gas remains strong. The economy is tanking but people are still driving around in circles.
Amatoori,Toolpush , 02/25/2016 at 10:40 pmVery good --
Some (albeit vague) support for a growing day-by-day "glut deniers" movement :-) . The newer part of the the argument revolves on fixed ratio of gasoline to distillate in refining process. Which supposedly caused a growth of distillate inventories due to weather induced low demand :
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
Amatoori,likbez , 02/25/2016 at 11:46 pmIt always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
I would have thought, the EROI boys would be all over it. As I feel this is where the theory of EROI being very low for unconventional oil and gas, actually starts to show up in day to day numbers.
Hi Toolpush,It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
You made a very good point -- Thank you.
As EROEI boys are lazy bunch let me fill in. Let's assuming EROEI 10 for shale oil (which might be charitable; some sources claim 3-5)
https://en.wikipedia.org/wiki/Oil_shale_economics#Energy_usageA 1984 study estimated the EROEI of the different oil shale deposits to vary between 0.7–13.3:1.[21] More recent studies estimates the EROEI of oil shales to be 1–2:1 or 2–16:1 – depending on if self-energy is counted as a cost or internal energy is excluded and only purchased energy is counted as input.[20][22] According to the World Energy Outlook 2010, the EROEI of ex-situ processing is typically 4–5:1
So we need 4.2 gallon per bbl.
The EIA estimates in the Annual Energy Outlook 2015, that about 4.2 million barrels per day of crude oil were produced directly from tight oil resources in the United States in 2014.
So we are talking about 0.4 Mb/day of diesel consumption. Which is respectable 10% out of 4 Mb/d total US distillates consumption. So 2% drop (which amount to 20% drop of diesel consumption in oil patch) might be fully attributable to the lower activity of shale patch.
In other words you are right --
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Amatoori , 02/25/2016 at 11:40 am
http://in.reuters.com/article/oil-demand-kemp-idINL8N1644QUJef, 02/25/2016 at 6:28 pmNice piece of the puzzle Amat. Distillates is the glut.likbez, 02/25/2016 at 8:25 pmSO diesel demand has been tanking but gas remains strong. The economy is tanking but people are still driving around in circles.
Amatoori,Very good --
Some (albeit vague) support for a growing day-by-day "glut deniers" movement :-) . The newer part of the argument revolves around the fixed ratio of gasoline to distillate in refining process. Which supposedly caused a growth of distillate inventories due to the weather induced low demand :
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
Toolpush, 02/25/2016 at 10:40 pm
likbez, 02/25/2016 at 11:46 pmAmatoori,
It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
I would have thought, the EROI boys would be all over it. As I feel this is where the theory of EROI being very low for unconventional oil and gas, actually starts to show up in day to day numbers.
Hi Toolpush,It always surprises me, that when people talk about the year on year drop in diesel consumption, nobody mentions the fact of 1000 less drilling rig working, plus the lower demand from less fraccing, the transport of train loads of sand per well, etc.
You made a very good point -- Thank you.
As EROEI boys are lazy bunch let me fill in. Let's assuming EROEI 10 for shale oil (which might be charitable; some sources claim 3-5)
https://en.wikipedia.org/wiki/Oil_shale_economics#Energy_usageA 1984 study estimated the EROEI of the different oil shale deposits to vary between 0.7–13.3:1.[21] More recent studies estimates the EROEI of oil shales to be 1–2:1 or 2–16:1 – depending on if self-energy is counted as a cost or internal energy is excluded and only purchased energy is counted as input.[20][22] According to the World Energy Outlook 2010, the EROEI of ex-situ processing is typically 4–5:1
So we need 4.2 gallon per bbl.
The EIA estimates in the Annual Energy Outlook 2015, that about 4.2 million barrels per day of crude oil were produced directly from tight oil resources in the United States in 2014.
So we are talking about 0.4 Mb/day of diesel consumption. Which is respectable 10% out of 4 Mb/d of the total US distillates consumption. So 2% drop (which amount to 20% drop of diesel consumption in oil patch) might be fully attributable to the lower activity of shale patch.
In other words you are right --
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Watcher, 02/23/2016 at 3:02 pmYes, has anyone noticed swimming pools filled with oil in their neighborhood?Dennis Coyne , 02/23/2016 at 3:41 pmI haven't.
Why would anyone let oil go on a tanker and leave port unless they were paid for it? Answer: They wouldn't. They get paid for it because they had an order for it and filled the order. Why would they cut output and refuse to fill customer orders?
So who placed an order for oil they weren't going to sell to someone else who would then burn it? Answer: No one did. They had customers and the customers placed orders for it because they needed to burn it, and then took possession of it and burned it.
Why contort thinking on this? It's simple and clear.
Hi Watcher,AlexS , 02/23/2016 at 4:05 pmYes it is very clear that there is an excess of oil being produced and that is why prices are so low, to everyone except you.
Watcher , 02/23/2016 at 5:22 pm"Why would anyone let oil go on a tanker and leave port unless they were paid for it? "This is a common practice. The tankers leave ports and can several times change directions as the owner/seller of oil is trying to find the best buyer.
Interesting. How about offloading? That ever happen without paying the producer? Because if the theory proposed here is all the storage is in tankers, you're going to have to find about a billion barrels sitting unpaid for - all whilst KSA says they produce what they have orders for.AlexS , 02/23/2016 at 5:46 pmRead, for example, this article:Watcher , 02/23/2016 at 6:18 pmWhy oil speculators are turning to ships as floating storage
The Globe and Mail, Monday, Feb. 22, 2016
http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/why-oil-speculators-are-turning-to-ships-as-floating-storage/article28846311/Other recommended reading:
IEA Oil Market Report, January 2016, p.33
AlexS , 02/23/2016 at 7:14 pmAbout 20 to 25 of the world's 650 supertankers, which can hold two million barrels and are called very large crude carriers, are in use as floating storage,That's 2 X 25 = 50 million barrels. The alleged oversupply of 3 mbpd for 20 mos (since June 2014) is 20 X 30 X 3 = 1.8 billion barrels.
Do they offload without paying the producer?
There was never 3 mb/d oversupply, not to say for 20 months. The oversupply peaked at 2.2-2.4mb/d in 2Q15, according to various estimates (see the chart below).Watcher , 02/23/2016 at 9:52 pmFrom IEA OMR, January 2016:
"A notional 1 billion barrels of oil was added to global inventories over 2014 – 2015 and our latest supply and demand balances suggest builds will persist with up to 285 mb expected to be added to stocks over the course of 2016. Despite estimations of current space storage capacity and the outlook for significant capacity expansions over 2016, this stock build will likely put midstream infrastructure under pressure and could see floating storage become profitable. "
The volume in floating storage is a small part of total global inventories. It can belong to producers (particularly, the NOCs) or to large traders.
One more time. Do they offload without paying the producer? "I don't know" is an entirely solid answer.AlexS , 02/23/2016 at 10:41 pmWho "they"?likbez , 02/23/2016 at 10:50 pmOil stored in tankers may belong to:
- Oil producers, particularly the NOCs (national oil companies). For example, Iran's ~40 million barrels of crude and condensate stored in tankers belongs to the Iranian national oil company.
- Oil traders, who have bought that oil and are storing it in tankers in a hope that they could sell it later at a higher price.
Alex,AlexS , 02/23/2016 at 11:35 pmCan you please explain how in oversupplied Europe Iran suddenly found customers for more then 0.3 Mb/d (Italy, Greece and France; Spain is next).
You should see inventories rising by the same amount because according to the "oil glut" theory this oil can't be consumed, don't you ? And 0.3Mb/d is 9 Mb/month. Most large oil contracts are long term and you can't break them without penalties.
Also in the USA no producer with reasonably good quality oil ("sweet" with reasonable API gravity) has any difficulties selling any volume he can produce. Moreover buyers ask for additional volumes. Note the word "selling", not putting in storage at his own expense.
Theoretically within "oil glut" framework there is no place for this oil to go other then in storage. And storage costs now are very high in Continental US so there should be reasonable attempts to minimize losses due to large amount of stored oil, which should limit "new" oil buying.
So it looks like "glut theory" (which is essentially an extension of neoclassical supply/demand model) has some serious holes in it.
Ves , 02/24/2016 at 12:12 am"Can you please explain how in oversupplied Europe Iran suddenly found customers for more then 0.3 Mb/d (Italy, Greece and France; Spain is next). "Iran is selling its oil in Europe at a big discount trying to regain its market share in this region. The customers are happy to buy Iranian oil at a lower price than the Saudi or Russian oil. The market is oversupplied, therefore part of oil supplies goes to storage.
"You should see inventories rising by the same amount because according to the "oil glut" theory this oil can't be consumed, don't you ? And 0.3Mb/d is 9 Mb/month."
1) Inventories in Europe are rising. Thus, according to the IEA, in December, even prior to the restart of Iranian exports, they have increased by 0.29 mb/d, or 9 million barrels.
2) Oil exporters are constantly adjusting their geographical mix of oil supplies. So with increasing volume of Iranian oil directed to Europe, Russia and others may have redirected part of their supplies to China.
"Most large oil contracts are long term and you can't break them without penalties."
Oil is not natural gas. Contracts are much shorter than typical take-or-pay contracts for gas supplies. A lot of oil is sold in the spot market. In general, the oil market is very flexible.
"Also in the USA no producer with reasonably good quality oil ("sweet" with reasonable API gravity) has any difficulties selling any volume he can produce. Moreover buyers ask for additional volumes. Note the word "selling", not putting in storage at his own expense."
When a customer in US or any other country buys oil, it may consume (process) it or put in storage. With the current low price of oil and a steep contango, it makes sense to put oil (or refined products) in storage. Therefore, oil and product stocks in the US are increasing.
"Theoretically within "oil glut" framework there is no place for this oil to go other then in storage. And storage costs now are very high in Continental US so there should be reasonable attempts to minimize losses due to large amount of stored oil, which should limit "new" oil buying."
The contango in the oil market justifies storing oil even at a high cost. If not, customers are ready to buy oil only at a lower price. That explains the current downward pressures on the oil price.
"So it looks like "glut theory" (which is essentially an extension of neoclassical supply/demand model) has some serious holes in it."
The oil glut in the market is empirical reality and has nothing to do with the neoclassical theories. You and Watcher are the only ones who deny this.
@likbezSynapsid , 02/24/2016 at 12:44 am"Glut" is emotional word and it is has negative connotation if you are oil producers and very likely it is misused in the press in order to provide certain perception of abundance.
or pick word "Oligarch" or "Businessman" which is more emotional to you?
Better word would be "over-supply" of oil. But the real question is how much of over-supply there is?
AlexS,Watcher , 02/24/2016 at 2:19 amSome of the tankers being used for storage hold gasoline, not crude. (You may already have mentioned this elsewhere.)
This is going circular, despite some good procedural information. The issue is this. Does KSA put oil on a tanker and send it to . . . whatever destination with no order for it. Now that's rhetorical in that the correct question could be Does KSA let oil leave that tanker without being a promise of payment.Dennis Coyne , 02/24/2016 at 11:51 amSimply that, and you seem to be dodging. Is oil coming out of the ground - or if you're happier, coming out of the tanker, without agreement to pay. And again, your reference made clear you're talking about 50 and only 50 lousy million barrels. The decline in prices started June 2014. Quotes of oversupply have been up to 3 mbpd. Even that graph you posted would add up to hundreds upon hundreds of millions of barrels.
You're not making your point. Are you saying KSA and other exporters pumped that much oil out without being paid for it?
Hi guys,The oil of course is paid for, but the price is very low. A "glut" means an oversupply, how do we know there is an oversupply? Because many producers are selling their product at a loss.
For a commodity like oil which does not deteriorate in storage (like apples) there can be oil traders that buy and store oil in hopes of selling later for a higher price.
To make things simple glut=low price.
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Alberto, 02/24/2016 at 1:36 pm
Every single business in the world must increase its inventory when it increases it sales unless it is somehow able to get more efficient with its inventory turns. When growth is very fast like it has been in the US oil industry over the past few years, inventory turns almost always get less efficient, particularly if there are bottlenecks in product flows due to insufficient infrastructure or logistics which struggles to catch up with that growth. So when you are producing and selling record or near record amounts of a good then your inventory of that good should be at or near record levels. Also, when you build more inventory capacity you are going to carry more inventory particularly if you don't like the price that you can sell that inventory now as is the case in the oil business.The inventory in the US will turn much quicker than people think as the production declines accelerate or more importantly the price goes up. Assuming either of those things ever happen again….
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Ron Patterson , 02/24/2016 at 12:45 pmThe Weekly Petroleum Status Report came out earlier today. The biggest news is that oil inventory levels increased by another 3.5 million barrels. They are at an all time high.Jeffrey J. Brown , 02/24/2016 at 1:41 pmI understand that there are some folks out there who do not believe that there is currently a glut in the oil supply. I wonder how they would explain this record in stored oil. Of course this is just not in the US, there are similar stories around the world. We are running out of places to store oil. That's not a glut? Then what the hell would you call it.
US crude oil production dropped by 33,000 barrels last week, according to the EIA's algorithm that tries to track production. Understand that this is not an actual measurement of oil produced but a mathematical equation that tries to figure it out.
A glut of condensate?shallow sand , 02/24/2016 at 1:54 pmAs US C+C inventories increased by 100 million barrels from late 2014 to late 2015, US net crude oil imports increased:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
The most recent four week running average data (through Mid-February), show that US net crude oil imports increased year over year, from 6.8 million bpd in 2/15 to 7.4 million bpd in 2/16. And US net crude oil imports, as a percentage of C+C inputs into refineries, rose year over year from 44% last year to 47% this year (four week running average data).
And links to articles from last year and this year that discuss refiners' unhappiness with "Synthetic WTI" blends of heavy crude and condensate:
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323
https://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
Ron, do we know what worldwide C + C storage levels have done since 2013?Ron Patterson , 02/24/2016 at 2:29 pmIf I am a US refiner, I would be filling every available inch of storage at sub $30 oil.
Are oil exporters doing the same?
Well we have the OECD storage levels for the last 6 years, courtesy of the IEA Oil Market Report And, as you can see they are at a high since January 2010.Chris , 02/24/2016 at 4:06 pm
If you substract US storage increase from OECD numbers, I think you should see a plateau. So the majority of the increase in oil storage is in the US, at least for OECD.shallow sand , 02/24/2016 at 4:33 pmI have tried in the past to find information about non-OCED and OPEC storage. I have been unable to do so. If anyone has this information (AlexS?) I would appreciate it very much.Urs, 02/24/2016 at 2:54 pmPer IEA, total supply, including refinery gains and biofuels stood at 97.1 million bopd. Of that, OCED was 24 million bopd, with refinery gains and biofuels in OCED making up another 4.6 million bopd.
This means that a little over 70% of world wide supply (production) is non-OCED and OPEC. So, without storage information for non-OCED and OPEC, seems it is a little difficult to obtain a clear picture of how much higher worldwide storage is now than it has been in the past?
It would seem if non-OCED exporters and OPEC desired to sell into this market and draw down crude oil storage inventories, they very well could do so, as refiners in importing countries would be inclined to buy as much oil as they could store, assuming that low prices will not remain forever. OTOH, when oil shot up to $140, clearly refiners in importing countries tried to keep from buying anymore crude than necessary, as there is much more risk in storing $140 oil losing value than $30 losing value.
Also, when we get right down to it, strategic petroleum reserves should be included into the mix. However, what weight they should be given is difficult, given the uncertainty of if and when they would be accessed.
The inventories for countries producing 29.5% of C + C, including refining gains and biofuels, have increased from about a five year average of 58 days, to 65 days supply. I wonder what has happened with regard to storage for the remaining 70.5% of world wide production?
I will give you an example of what I mean through a stripper well oil producer. Stripper well production is separated from water and goes into a stock tank. When the stock tank is full, the tank is picked up by a tanker truck and driven to a refinery.
In January, a stripper well operator may start with 1,000 barrels of oil on hand, produce 1,000 barrels in the month, sell 1,200 barrels in the month, and end the month with 800 barrels on hand. The next month, the operator may start with the 800 barrels, produce another 1,000 barrels, sell just 600 barrels, and end the month with 1,200 barrels on hand.
We know the operator produced 1,000 barrels each month. However, if I had not told you that, you might very well think the operator produced 1,200 barrels in January and 600 barrels in February.
Is it not possible that this game is occurring with regard to large producers for which we have no storage data?
For example, I sincerely doubt KSA suddenly shuts in wells to cut production, or opens up wells to increase production. I assume they have considerable storage, and when they ramped up production greatly, they really didn't, they put a lot of stored oil on the market. I think it would be tough to suddenly increase or decrease production by 1 million bopd. Maybe they do, but I doubt it happens immediately.
Of course, I really do not know the above re KSA for a fact. However, it would be much easier for them, or any other producer, to manage supply, at least in part, through the use of storage.
Please understand, I have no idea what is really going on with worldwide oil storage. But that is my point, unless someone can point me to some good data, no one does. For all we know, storage levels in non-OCED and OPEC could be low?
Hi
Thanks for the weekly graph – always great to see your data presentation.Careful with the increase in crude stocks, because, as you surely know gasoline, distillates (the low sulphur part) and the propane are all down the double,
so that total stocks (bottom line in top part of "data overview table 1" EIA) are DOWN 5 mb last week!I think people are gonna start reacting, 4 week averages are down, yearly cumulative production is down, the tide is turning. And as Mr Brown writes, imports are up too. The show goes on…
Best,
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Reuters
According to the U.S. government, there are over 1.3 billion barrels of crude oil and refined products in commercial storage around the United States, an increase of more than 300 million barrels in the last two years.There is a tendency to assume all these barrels of crude and products are "excess" inventories, the result of overproduction, but most of them are held for operational reasons.
The best way to distinguish excess inventories from normal operational stocks is to adjust reported inventories for time of year, consumption of crude by refineries, and consumption of products by end customers.
Other things being equal, the more crude refineries process every day, the more crude they need to hold on site, at tank farms or en route to the refinery in pipelines and on ships to keep their distillation towers supplied.
And the more fuel supplied to customers, the more refined stock refineries, blenders and distributors need to keep on hand to deal with seasonal swings, maintenance and unexpected disruptions in the supply system.
Since the start of 2015, U.S. refineries have been processing record amounts of crude to meet strong demand for gasoline as continued growth, rising employment and cheap fuel prices have encouraged increased driving.
U.S. crude stockpiles are currently 47 percent higher than the average over the last 10 years but if stocks are adjusted for the higher rate of processing the surplus falls to around 34 percent.
The reported surplus in crude stocks over the long-term average is around 162 million barrels but if stocks are adjusted for higher processing the surplus falls to around 128 million barrels (tmsnrt.rs/20WQt9F).
U.S. gasoline stockpiles are currently 11 percent higher than normal for the time of year but if they are adjusted for strong gasoline demand then the surplus shrinks to 7 percent.
The reported surplus in gasoline stocks over the long-term average is 26 million barrels but adjusted for higher demand falls to 17 million barrels (tmsnrt.rs/20WQzhl).
Crude and gasoline stocks are somewhat less excessive than the unadjusted data suggests because refinery processing and gasoline consumption have been so strong.
But distillate demand has been much weaker than normal thanks to sluggish demand from the freight sector and El Nino.
Distillate stocks are much higher than the raw numbers suggest, once they are adjusted for the current weakness in demand.
Distillate stockpiles are currently 24 percent higher than the long-term average but once adjusted for weak consumption they are 43 percent higher than normal for the time of year.
The reported surplus in distillate stocks over the long-term average is 31 million barrels but adjusted for weak demand the surplus surges to 48 million barrels (tmsnrt.rs/20WQE4M).
At this time of year, U.S. gasoline stocks are normally around 26 days worth of consumption, and they are currently a bit higher at 28 days.
Distillate stocks should be around 32 days worth of consumption but are currently at a massive 46 days worth of demand.
CONTINUOUS PROCESSING
Early U.S. oil refineries processed crude in batches, with each batch of oil loaded separately into a still, where it was heated until the distillates were boiled off, condensed and collected for sale.
Early refineries were really just simple distilleries: the equipment would be instantly recognisable to anyone who has been on a tour of a whisky distillery ("A practical treatise on coal, petroleum and other distilled oils", Gesner, 1865).
The first U.S. refineries established during the 1860s and 1870s processed up to 2,000 barrels per day, though most were much smaller and produced less than 1,000 barrels per day ("Early and later history of petroleum", Henry, 1873).
Refineries were geared to produce a middle distillate boiling around 300-600 degrees Fahrenheit which was sold as kerosene or paraffin oil and used for illumination.
Gasoline, with its lower boiling point, was too volatile to be used safely as lamp fuel and was mostly considered a nuisance and waste product.
U.S. oil refineries eventually switched from processing crude in discrete batches to feeding oil into distillation towers and drawing off the fractions in a continuous process.
Modern U.S. refineries process up to 600,000 barrels per day, 300-1200 times as much as the first batch-based plants, though a more typical refinery has capacity of around 100,000 to 200,000 bpd.
The objective has switched from producing kerosene for lighting to producing gasoline for use as a transportation fuel.
In the first decades of the 20th century, electric lighting began to reduce demand for kerosene while the massive expansion in car ownership stimulated consumption of gasoline.
From 1915-1920 onwards, refineries were increasingly geared to produce gasoline as the main product, while middle distillates became a by-product.
With the shift to continuous processing and the prodigious growth in demand for gasoline as a road fuel, the oil industry's need to hold stocks of unrefined crude and refined products surged.
To ensure an uninterrupted flow of oil from the wellhead to the refinery and the end customer, stocks of crude and refined fuels are held at every stage along the supply chain.
Refineries hold substantial stocks of crude to ensure a continuous flow of carefully prepared (de-watered and de-salted) as well as blended crude into their distillation towers.
The industry also needs substantial stocks of refined fuels, lubricants and petrochemicals to ensure a continuous supply to distributors and end users.
Refineries hold crude and refined products to meet routine operational requirements as well as to deal seasonal variations in demand, planned maintenance and unexpected disruptions.
The amount of oil involved is enormous.
At the end of 2013, with the oil market more less balanced, more than 1.05 billion barrels of crude and refined products were being stored at refineries, distributors and oilfields as well as in pipelines and on tank farms.
By February 2015, with the oil market clearly oversupplied, crude and refined products in storage had climbed to more than 1.33 million barrels, according to the U.S. Energy Information Administration ("Weekly Petroleum Status Report", EIA, Feb. 24).
OPERATIONAL PLANNING
In the last year, U.S. refiners have been fairly successful in matching gasoline production and stockpiles with demand. Gasoline production remains at the centre of their operational planning.
Crude stocks have continued to increase, reflecting worldwide oversupply, though stockpiles are rising somewhat more slowly than at the start of 2015.
But refiners lost control of distillate stocks in the second half of 2015 as freight demand slowed and El Nino ensured a warmer than normal winter across the United States and other parts of the northern hemisphere.
Winter heating demand across the United States has been around 17 percent below average, according to the National Oceanic and Atmospheric Administration.
And by the end of 2015, the volume of freight being moved across the United States by road, rail, pipeline, barge and air had fallen by more than 2 percent compared with the same period at year earlier.
Over the last four weeks, U.S. implied distillate consumption has averaged just 3.5 million barrels per day, which is 12 percent below the long-term average and 16 percent below the same period in 2015.
The fact that refiners have lost control of distillate stocks should come as no surprise because distillate is essentially a by-product of gasoline production.
Refineries have operated to maximise gasoline production but in the process created an enormous and growing oversupply of distillate.
There is some limited flexibility in the refining system to switch from distillate production to gasoline but it is typically only on the order of a few percentage points.
Massive overproduction of distillate has pushed gross refining margins for the fuel to the lowest level since 2010.
But refining margins for gasoline have been much healthier, at least until recently, which has encouraged refiners to continue maximising crude throughput.
As long as gasoline demand remains strong, refiners will continue to meet it, which is why the outlook for U.S. gasoline consumption is so critical for the oil market in 2016.
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peakoilbarrel.com
Jeffrey J. Brown, 02/24/2016 at 1:41 pm
A glut of condensate?As US C+C inventories increased by 100 million barrels from late 2014 to late 2015, US net crude oil imports increased:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
The most recent four week running average data (through Mid-February), show that US net crude oil imports increased year over year, from 6.8 million bpd in 2/15 to 7.4 million bpd in 2/16. And US net crude oil imports, as a percentage of C+C inputs into refineries, rose year over year from 44% last year to 47% this year (four week running average data).
And links to articles from last year and this year that discuss refiners' unhappiness with "Synthetic WTI" blends of heavy crude and condensate:
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323
https://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
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peakoilbarrel.com
Watcher, 02/24/2016 at 6:39 pm
WTI definition was changed to allow more shale output flow into Cushing. Inventory definition similarly changes and loses all valid comparison to history. There's no valid data on most of what's going on.clueless, 02/24/2016 at 10:17 pmWatcher: "There's no valid data on most of what's going on."One of your best observations.
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February 10, 2016 | Griz's Trading Blog
It seems that EIA is doubling down on their faulty model for weekly US oil production estimates. EIA continues to drive monthly production estimates up, at least through February, and in turn this is supporting weekly overestimates of US production. In fact their latest monthly report estimates production in the major US shale basins will exceed their previous January production estimate by 68k bbl/day. This is in direct conflict with dropping rig counts and more importantly falling well completion rates reported by the states of Texas and North Dakota.
... ... ...
The conclusion is US shale production is far less robust than the world of oil traders currently believes. If we have now moved into a mode where Unaccounted for Oil tends to be negative, say -150k bbl/day every week, opposed to the normal +150k bbl/day every week, and this is just week 2 of a much longer streak of back to back negative values for Unaccounted for Oil, US production could already be well under 9MM bbl/day and very rapidly falling toward 8MM bbl/day.
Below I'm including my updated 2016 US production + Unaccounted for Oil projection. I've included a couple of my own linear projections as well as a couple polynomial trend lines. My belief is US production is declining at a rate best described by Projection 2. This means the decline is trending in the lower channel and possibly the lower half of the upper channel. The less steep poly trend line also likely describes the situation well.
Unknown, February 11, 2016 at 5:13 AM<
I think you are correct. When I look at how some of the upstream mlps have now entered panic mode even with good hedging this yr is telling
Kirt
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peakoilbarrel.com
George Kaplan, 02/23/2016 at 3:14 amIn the discussions here and concerning Bakken LTO has either of these two articles been mentioned? They are by David Hughes and Jean Laherrere.Heinrich Leopold, 02/23/2016 at 5:00 amThe David Hughes one in particular looks to have predictions close to what has been happening. They both question EIA estimates of the amount of oil recoverable. For example from Hughes:
"The U.S. Energy Information Administration's (EIA) forecasts regarding tight oil production-published in its Annual Energy Outlook (AEO)-are commonly viewed by industry and government as the best available assessment of what to expect in the longer-term, with the EIA's reference case typically viewed as the most likely scenario for future production. In my Drilling Deeper1 report published last October, I developed alternate production forecasts for two major tight oil plays, the Bakken and Eagle Ford, and reviewed the credibility of EIA AEO20142 forecasts for other major plays based on the fundamental geological characteristics of each play. In most plays the AEO2014 production projections were found to be highly to extremely optimistic when reviewed in the light of play fundamentals. For the Bakken and Eagle Ford plays, AEO2014 overestimated the likely recovery of oil by 2040 by 42% compared to my "Most Likely" drilling rate case found in Drilling Deeper."
http://www.postcarbon.org/wp-content/uploads/2015/09/Hughes_Tight-Oil-Reality-Check.pdf
This is from the Laherrere article (posted at POB) and looks, for something 18 months ago, as prescient as anything I've seen in the light of subsequent events:
"It seems that most oil companies are spending more than their revenues by increasing their debts. Countries can live for a long time with huge debt increase, not companies. They count on the stock market by delivering optimistic reports and keep drilling to avoid the production to decline. With shale oil or shale play, in contrary with conventional where wells are dry or producing, oil can be produced even for a while if not economical.
Such behavior explains why most peak forecasts are wrong. But the main question is about the slope of the decline after the peak. EIA forecast a LTO (light tight oil = shale oil) peak in 2017 it is not too far after my forecast, the big difference is the slow EIA LTO decline."George KaplanGeorge Kaplan, 02/23/2016 at 5:48 amAlthough these reports are very interesting, they ignore in my opinion financial conditions – mainly the bond market – and oil prices as major drivers for oil production. Jean Laherrere is fully aware of this fact, yet does not provide oil production scenarios at different oil price and bond market conditions.
So, if oil prices would fall below 20 USD per barrel for a long period I am pretty sure, oil production for Bakken and Eagle Ford would tend to zero within a short time and all above production scenarios would be irrelevant.
If oil prices would recover, production will start again.
Yet it is in my view not possible to sustain horrendous losses for a long time. Somebody has to pay the bill. It is already clear now that high US oil production supports the US dollar, yet brings the bond market to its knees. The bond – and equity holders are paying currently the bill, yet for how long?
This comes especially on the background of the US bond market facing a maturity wall of USD 4.1 trn over the next four years. http://www.highyieldbond.com/the-2020-maturity-wall-4-1t-of-bonds-to-mature-and-13-of-that-is-high-yield/.
Companies can roll over the debt, yet at much higher interest rates.
Might be so. If the production continues to follow the Hughes predictions though, I'd say that will cast a lot of doubts over how much impact short term price swings have had. Possibly the availability of cheap money through most of 2015 overrode any price signals and they just kept on drilling no matter how much losses they incurred. You talking about a maturity wall now – how would that have impacted production in the past, especially when in the beginning of the price fall producers were expecting prices to recover at any time and later were concentrating solely in staying alive for the next month and couldn't afford to look much further ahead.With data currently available the main message I've got from this is that there is probably a lot less oil in the Bakken and Eagle Ford than EIA are saying – at any price.
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peakoilbarrel.com
AlexS, 02/22/2016 at 12:04 pmThe IEA has actually increased its medium-term global demand projections compared with the previous year's report. This reflects a much higher 2015 base, but also slightly higher growth rates in 2016-2020.AlexS, 02/22/2016 at 12:44 pm
As a result, projected demand in 2020 is now almost 1.5 mb/d higher than in MTOMR-2015 (100.5mb/d vs. 99.05mb/d).From the new report:
"…our forecast for oil demand to 2021 is for annual average growth of 1.2 mb/d (1.2%) which represents a very solid outlook in historical terms. Oil demand breaks through the 100 mb/d barrier at some point in 2019 or 2020. A major change from the 2015 MTOMR is the higher base from which our forecast begins. In 2015 world oil demand increased by 1.6 mb/d (1.7%), one of the biggest increases in recent years stimulated to a large extent by the rapid fall in oil prices that began in the second half of 2014 and gained momentum in 2015. However, any expectations that the most recent fall in oil prices to USD 30/bbl oil will provide further stimulus to oil demand in the early years of our forecast and send annual rates of growth above 1.2 mb/d are likely to be dashed. In the first part of 2016 we have seen major turmoil in financial markets and clear signs that almost any economy you care to look at could see its GDP growth prospects downgraded.
Since 2014 the non-OECD countries have used more oil than OECD countries and the gap will widen in years to come. However, the rate of demand growth in the non-OECD countries is vulnerable to being pared back as the cost of energy subsidies becomes a major burden and governments take action. This will probably not have an immediate impact on demand in the early part of this forecast, but later on we might see that the reduction in expensive fuel subsidies in many countries, including the fast-growing Middle East, does have a significant effect on growth. Also, rising energy use has brought with it terrible environmental degradation, particularly in the fast-growing Asian economies, and oil's part in this is recognised by measures to limit vehicle registrations and use. Although reducing subsidies and tackling pollution will affect the rate of demand growth, it should be stressed that non-OECD Asia will still remain the major source of oil demand growth with volumes increasing from 23.7 mb/d in 2015 to 28.9 mb/d in 2021."Global liquids demand (mb/d): IEA Medium-Term Market Reports 2016 vs. 2015
The IEA's non-OPEC C+C+NGLs production estimate for 2015 in last year's MTOMR proved too pessimistic. They have underestimated the resilience of high cost oil production, particularly that of the US LTO. As a result, actual non-OPEC production was 1.1 mb/d higher than in last year's report.AlexS, 02/22/2016 at 1:07 pmStill, the agency expects non-OPEC production to decline by 0.6mb/d in 2016 and 0.1mb/d in 2017 before a gradual recovery from 2018. Projected decline in 2016-17 should be mainly driven by LTO. Expected non-OPEC production in 2020 is 0.4mb/d lower than in the MTOMR-2015.
From the new report:
In the year since the 2015 MTOMR was published, the supply side has provided many surprises. By far the most significant has been the resilience of high cost oil production and in particular that of light, tight, oil (LTO) output in the US. As oil prices cascaded down from more than USD 100/bbl it was widely predicted at various milestones that the extraordinary growth in total US crude oil production from 5 mb/d in 2008 to 9.4 mb/d in 2015 would grind to a halt and move rapidly into reverse. Growth certainly ceased in mid-2015 but the intervening period has seen a relatively modest pull-back and total US crude oil production in early February 2016 was still close to 9.0 mb/d, aided by expanding production in the Gulf of Mexico.
In our base case outlook, there is an element of the "straw breaking the camel's back" and we expect US LTO production to fall back by 600 kb/d this year and by a further 200 kb/d in 2017 before a gradual recovery in oil prices, working in step with further improvements in operational efficiencies and cost cutting, allows a gradual recovery. Anybody who believes that we have seen the last of rising LTO production in the United States should think again; by the end of our forecast in 2021, total US liquids production will have increased by a net 1.3 mb/d compared to 2015. Such has been the element of surprise provided by the resilience of US oil production, and the wide divergence of views as to the future, that we have added a High and Low Case to our non-OPEC production analysis and plotted the impact on the global oil market balance of US LTO production falling by more than in our base case or, conversely, less. The eventual outturn is one of the most important factors – if not the most important – in assessing when the oil market will re-balance.
Non-OPEC liquids production (ex biofuels) (mb/d): IEA Medium-Term Market Reports 2016 vs. 2015
(Note: excludes Indonesia)
The IEA expects the oil market to re-balance in 2017, which is in line with the EIA's and many other forecasts. However the accumulated excess inventories will return to long-term normal levels only by 2021, which should dampen the recovery in oil prices.From the report:
For some time now analysts have tried to understand when the oil market will return to balance. A year ago it was widely believed that this would happen by the end of 2015 but that view has proved to be very wide of the mark. In 2014 and again in 2015 supply exceeded demand by massive margins, 0.9 mb/d and 2 mb/d respectively, and for 2016 we expect a further build of 1.1 mb/d. Only in 2017 will we finally see oil supply and demand aligned but the enormous stocks being accumulated will act as a dampener on the pace of recovery in oil prices when the market, having balanced, then starts to draw down those stocks. Unless we see an even larger than expected fall in non-OPEC oil production in 2016 and/or a major demand growth spurt it is hard to see oil prices recovering significantly in the short term from the low levels prevailing at the time of publication of this report.
It is very tempting, but also very dangerous, to declare that we are in a new era of lower oil prices. But at the risk of tempting fate, we must say that today's oil market conditions do not suggest that prices can recover sharply in the immediate future – unless, of course, there is a major geopolitical event.
Global balance base case: IEA MTOMR-2016
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February 18, 2016 | Griz's Trading Blog
The EIA weekly estimate of production is still too high as indicated by Unaccounted for Oil and production estimates based on well completion rates. However, the weekly estimate is starting to move down in a big way. Last week down 30k bbl/day, this week 50k bbl/day. 50k bbl/day is huge, that is 200k bbl/day/month The reality is US production has been falling 20k-30k bbl/day for weeks or even months already, now it is likely falling 30-37k bbl/day/week not 50k bbl/day/week. 50k bbl/day/week would imply almost zero well completions, when around half of each months shale decline is currently being replaced monthly. But EIA is so far behind, with likely production levels already below 9 MM bbl/day compared to the official estimate of 9.135 MM bbl/day, that they are being forced and will continue to be forced to show huge weekly declines for awhile to catch up. Won't be surprised to see 100k bbl/day cut reported next week and potentially the week after as well.
Unaccounted for oil has been running dramatically negative since Dec. 4. We have now just seen 3 back to back weeks with negative unaccounted for oil. This week it was -500k bbl/day or 3.5MM bbl for the week. Imagine what happens when -500k bbl/day in Unaccounted is zeroed out and put in production instead.
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www.bbc.com
The International Energy Agency (IEA) is warning consumers not to let cheap oil lull them into a false sense of security amid forecasts of a price spike by 2021.
In a report, the IEA said it expects prices to start recovering in 2017. But it forecasts that will be followed by a sharp jump in price as supply shrinks following under-investment by struggling producers.
Brent crude touched a 13-year low of $28.88 a barrel in January. It has since recovered somewhat, but is still far below a high of $115 in June 2014.
On Monday the price was up around 4.9% at $34.62.
Fatih Birol, executive director of the IEA, said: "It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but they should heed the writing on the wall: the historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in the not-too-distant-future."
... ... ...
The policy advisor expects global oil supply will grow by 4.1 million barrels of oil per day between 2015 and 2021, down from an increase of 11 million barrels of oil per day between 2009 and 2015.
It also expects investment in oil exploration and production to fall by 17% in 2016 following a 24% decline last year.
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peakoilbarrel.com
Daniel, 02/22/2016 at 8:00 amFrom IEA medium-term oil market report 2016:Jeffrey J. Brown, 02/22/2016 at 8:46 amFurther, it is becoming even more obvious that the prevailing wisdom of just a few years ago that "peak oil supply" would cause oil prices to rise relentlessly as output struggled to keep pace with ever-rising demand was wrong. Today we are seeing not just an abundance of resources in the ground but also tremendous technical innovation that enables companies to bring oil to the market.
Added to this is a remorseless downward pressure on costs and, although we are currently seeing major cutbacks in oil investments, there is no doubt that many projects currently on hold will be re-evaluated and will see the light of day at lower costs than were thought possible just a few years ago. The world of peak oil supply has been turned on its head, due to structural changes in the economies of key developing countries and major efforts to improve energy efficiency everywhere.
I fear that there will be a rude awakening for some in the next few years.
The WSJ has an article on the IEA outlook, with an interesting chart (do Google Search for access):Jeffrey J. Brown, 02/22/2016 at 11:53 amWSJ: IEA Sees Global Oil Markets Rebalancing Next Year
IEA says 'supply and demand will gradually rebalance by 2017, with a corresponding recovery in oil prices from around $30 a barrel'Copy of an email I sent to some Oil Patch folks:Frugal, 02/22/2016 at 8:52 amAttached is an article in today's WSJ about the IEA's most recent outlook, for the balance between global total liquids supply & demand. There is a very interesting chart in the article. Apparently, oil prices were trading up today, because of the report.
However, the IEA outlook does not take into account two critical factors: (1) The composition of the global Crude + Condensate (C+C) inventory oversupply (mostly condensate, in my opinion) and (2) Even as production increases, net exports can fall, because of domestic consumption in net oil exporting countries.
Some of my comments on net oil exports:
Following is a link to a discussion, in three sequential comments, of the Export Land Model (ELM, a simple mathematical model which assumes a 5%/year rate of decline in production and a 2.5%/year rate of increase in consumption, in a net oil exporting country), the Six Country Case History (major net exporters that hit or approached zero net exports from 1980 to 2010, excluding China) and the (2005) Top 33 Net Exporters, with graphics for each item:
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-556985
Note that what I define as the ECI Ratio (Export Capacity Index) is the ratio of production to consumption, and CNE = Cumulative Net Exports (for a defined time period).
Based on the mathematical model, which is confirmed by the empirical data (Six Country Case History), a declining ECI Ratio tends to correlate with an accelerating rate of depletion in remaining CNE.
For example, about the only metric that most analysts focus on is the top line production number in a net oil exporting country, and from 1995 to 1999, Six Country production rose by 2%, but in only four years they had already shipped 54% of their post-1995 CNE.
I estimate that Saudi Arabia may have already shipped in the vicinity of half of their post-2005 CNE. Note that annual Saudi net oil exports fell from 9.5 million bpd in 2005 to 8.4 million bpd in 2014 (probably remaining at about 8.7 mililon bpd in 2015, EIA + BP data). In other words, Saudi net exports, after increasing very rapidly from 2002 to 2005, have almost certainly been below their 2005 rate for 10 straight years. But the hidden danger, which almost no one is focused on, is the ongoing–and accelerating–rate of depletion in remaining volume of post-2005 Saudi and Global Cumulative Net Exports of oil.
Regards,
Jeffrey Brown
Jef, 02/22/2016 at 11:02 amThe world of peak oil supply has been turned on its head, due to structural changes in the economies of key developing countries and major efforts to improve energy efficiency everywhere.Increasing the extraction rate simply increases the depletion rate. I can't see how anything humans do can change that fact. In other words, nothing can turn peak oil on its head.
"… structural changes in the economies…"Dennis Coyne, 02/22/2016 at 11:50 amYea, its called tanking.
Hi Frugal,Correct. I think what has surprised many, including the IEA is that a few years ago they worried that high oil prices would be a problem as oil supply growth would struggle to keep up oil demand growth.
That has not proven to be the case from late 2014 until today as oil supply growth has outpaced oil demand growth. This is mostly due to a change in strategy by OPEC to focus on market share rather than oil revenue.
I believe that high oil prices will be back, but have been convinced by AlexS that it will not be as soon as I have been predicting. Long term projects that will come on line and be ramping up in 2016 and 2017 may keep oil prices under $80/b through mid 2018, we may not see prices rise to $100/b or more (2015$) until 2019, when the current delays in long term oil investment will start to affect oil output in a big way (2 to 3 Mb/d less output than if the projects deferred had been completed).
To me the undulating plateau scenario looks somewhat plausible, unless there is a financial crisis, in which case demand and price will fall along with output. I have no prediction for when such a crisis might occur, but the scenario below ignores that possibility.
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peakoilbarrel.com
Coolreit, 02/21/2016 at 11:23 am
Why wouldn't we call the EIA liars in reporting far more Texas oil production than the RRC?Critics say they are not lying as their difference with the RRC is initial reporting vs. final estimated reporting. If that critique were valid, then why is the oil production drop by the RRC from peak triple the fall that the EIA reports for Texas?
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www.theoildrum.com
RockyMtnGuy on November 22, 2012 - 8:49pm Permalink
Well, apparently the EIA and IEA are counting only liquid fuels, but it's not a legitimate accounting technique. They should be doing a mass and/or energy balance. There is quite a lot of mass and energy in the coke a refinery produces, and they don't actually throw it away, they sell it as fuel. Looking at only liquid fuels is really a very simplistic approach which gives a misleading picture.Black_Dog on November 22, 2012 - 10:09am Permalink | Subthread | Parent | Parent subthread | Comments top As you note, "processing gains" aren't something which one can measure directly. The markets deal in volumes and as a result, governmental reports (such as those from the EIA and the IEA) present data in volumes, not energy content or mass. Processing gain only serves to keep the "green eye shade" crowd of corporate and financial types happy, since they are trained to look at various balance sheets in which every thing neatly adds up. In reality, "processing gain" is simply the calculated difference between the volume of product and the volume of input liquids.
The volumes reported on both sides of the calculation have numerous sources of error, not to forget the non-technical situations, such as the Saudis, where production is a state secret and various unauthorized diversions, such often reported in Nigeria. For countries (and companies) with a larger fraction of such gains, the cause might be more efficient refining or differences in the output fraction of each product type. Refiners which have access to natural gas may use that instead of crude to provide the thermal or electrical energy to run the refinery, resulting in more product output. The results might also reflect differences in emissions where a country which has strict standards and enforcement might end up with more product actually making it to market. Then too, it's always going to be difficult to contain these liquid and gaseous materials, especially in countries with warmer climates. There's also the possibility that "processing gains" might turn out to be negative, if losses are extreme.
Ideally, from a scientific or thermodynamic point of view, the accounting should be carried out in energy terms, presenting the information rather like that found in the various markets for natural gas or electricity. With such accounting, there would not be any "processing gain", only the losses during extraction, refining and distribution. The efficiency of each link in the processing and delivery chain would be clearly apparent and the market(s) would be able to include this information in various corporate valuations. Sad to say, our markets don't work that way...
E. Swanson
The former tells us that after the Shale bump 'native' production will go back to decline, and the later shows us that replacing it with imported oil is going to get harder, or at least more expensive.
So. Be nice to Canada now, and/or probably better sabotage any attempts by those pesky northerners to build infrastructure that liberates the Alberta resource either east or west and onto the global market.
Related: Is the Alberta product dependent on US inputs to lighten it? If so that is a way that that Bitumen, once it hits the station forecourt, could at least in part accurately be described as a 'North American' product?
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energyblues on November 22, 2012 - 5:44am PermalinkLet's suppose that one accepts the premise that obtaining accurate figures for total world crude production is going to be problematic at best, and that we are dealing with ballpark figures, to use that term lightly. And this premise is based on the idea that statistics on oil production are undoubtedly politically motivated, and that even if transparency was as good as former American standards, we would still be dealing with rough estimates.Alright, if one accepts this premise, then one must conclude that dealing now with "world total liquids" will be even more problematic, especially in an era of permanent economic contraction and what will inevitably be defunding of areas thought to be secondary or academic.
I suspect this is largely true now. I do enjoy these posts, but what we should admit is that only country by country production and import/export stats have any meaning now, and even those may be largely tampered with.
It is possible and in fact likely that world production could soar while entire countries find themselves out of the market, or that world production could plummet even while a select few are always able to fill their cars and jets.
This was always the danger of peak oil, wasn't it? That the forces it would unleash would in fact undermine any attempts to properly categorize, understand, and deal with it.
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Jeffrey J. Brown , 02/13/2016 at 3:54 pm
I'm estimating that global crude oil production* was about 69 million bpd in 2005 and 68 million bpd in 2014. I would assume around 69 million bpd for 2015. Global total liquids production was 85 million bpd in 2005 and apparently about 96 million bpd in 2015.Oldfarmermac , 02/13/2016 at 6:49 pmSo, I estimate that actual global crude oil production, as a percentage of total liquids, fell from about 81% in 2005 to about 72% in 2015.
In regard to the US, I estimate that actual crude oil as a percentage of total liquids fell from about 57% in 2005 (4.7/8.3) to about 49% in 2015 (7.3/14.8).
*45 API Gravity & Lower Crude Oil
If the collective or average energy content of "other liquids" IS only seventy percent of the energy content per barrel of conventional crude oil, then ten million barrels of conventional are worth about twelve and a half barrels of "other liquids".If it turns out that conventional crude HAS hit it's ultimate upper limit, as indicated by the plateau in production of it, for the last decade, even with the price skyrocketing, then each MILLION new barrels of "other liquids" are will be worth be worth only seven tenths of a million barrels of actual OIL.
Of course the impact will not be quite so bad , in terms of the energy of the total liquid fuel supply, because the total supply already consists of about twenty eight percent "other " according to JBB's estimate.
Something tells me net energy per capita per barrel of liquid fuel is in the rear view mirror and receding from view at a steady clip, given the growth of population.
That might not matter as much, except at a moral and humanitarian level, as we think however, because most of the poor people of the world are never going to own and drive automobiles.
But it is reasonable to assume that even the poorest parts of the world will see substantial percentage point increases in oil consumption, so long as oil can be bought at any price, because the less oil you use, the greater the utility of each barrel.
A gallon burnt in a heavy truck delivering food from country side to city is worth twenty or thirty or even forty or fifty bucks, once the truck and the road are in existence, in comparison to the alternative of hauling it with draft animals or human muscle power.
It could turn out that the world wide economy will go downhill FASTER than the available supply of oil, even as high cost producers drop out. If NO new oil is brought into production, the supply will decline at somewhere between four and eight percent annually, according to all the estimates I have seen.
Personally I find it hard to imagine the world wide economy WILL go downhill FASTER than oil supply,barring global level Black Swan events, so I am convinced the price of oil will go up.
This is not to say the economy can't go downhill faster than oil production in the SHORT term . It might, and so the price of oil might stay low for some time yet, until depletion takes it's toll.
Oil producers are stubborn bastards, and will give up no faster than they go broke. Some of them can generate some cash for decades yet to come, even at thirty or forty bucks per barrel. If they go broke,due to not being able to pay off loans, whoever buys their wells will buy them cheap enough to continue to produce them.
I will personally gladly pay twenty bucks per gallon, so long as I can get diesel fuel, before I even CONSIDER going back to horses and mules.
Ya feed a car or truck PER MILE you drive it, and a farm tractor PER HOUR you run it. Ya feed draft animals three hundred sixty five days per year. NO CONTEST, unless you CANNOT buy diesel and gasoline at any price.
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likbez, 02/15/2016 at 1:36 pm
Some questions about accuracy of EIA statistics. My impression is that in certain areas they has been playing fast and loose. I might be wrong. Among areas of some concern:Ron Patterson, 02/15/2016 at 2:26 pm1. Is not the net effect of usage of volume instead of weight result in approximately 6% inflation of gross totals (which include all types f fuels) and thus EIA is distorting the "peak oil" situation? ("Great Condensate Con")
2. Is not the same concern true about accounting of gasoline in those EIA totals which include both oil and refined products ?
3. Is not (1) and (2) make EIA "mixed totals" statistics completely bogus (inflating the data by up to 12%) ?
4. Is EIA accounting of refiner gains just an artifact of usage of volume as the metric?
a. The whole concept might be viewed as a mirage created by usage of volume as a metric (the first law of thermodynamics).
b. How refiner gains on imported oil should be accounted? Should they be classified as domestic production like EIA does?5. Is EIA usage of volume acceptable in case of ethanol production? A unit of volume of ethanol contains approximately 55% of energy in BTUs in comparison with WTI. Huge difference: 76,000 Btu/gal vs. 138,000 BTU/gal. That affects mileage and all other usage metrics.
6. How dilutants for Canadian tar sands imported to Canada from the USA are accounted by EIA. They are first exported to Canada and then imported as a part of Canadian oil import? So part of the volume of Canada production was already "produced" in the USA.
7. The same question about Venezuela heavy crude.
IMHO Ron's graphs would be definitely twice more convincing if they were constructed in weight metric instead of volume.
Well, volume is all that I have so my charts are in volume. But I am not really concerned with NGLs, process gain or biofuels. In fact I would never post "total liquids" if I had crude, or C+C for that data.But all that being said, C+C is a pretty good indicator, even though it is not perfect. It will tell us when the peak occurs, or more correctly, it will tell us when the peak occurred in the past.
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Javier, 02/13/2016 at 8:11 pmHi Ron,AlexS, 02/13/2016 at 9:22 pmOn the issue of EIA's predictions accuracy, I updated this graph from Mason Inman and added actual oil US production.
What this graph shows is a typical very conservative estimate system. This means that on the way up, they greatly underestimate production and on the way down, they are going to greatly overestimate production.
This clearly shows how credible their predictions are. Although the graph is only for the US, clearly they are going to be equally conservative (and thus equally wrong) about world oil production.
Javier,Javier, 02/13/2016 at 9:56 pmThe long-term projections of U.S. LTO production are from various issues of the EIA Annual Energy Outlook. They indeed were very conservative, even though none of them (even the AEO-2015) did not assume such a big drop in oil prices.
As regards the actual production data (the black line), it is from the Drilling Productivity Report and include almost 1 mb/d of conventional output, primarily from the Permian basin.
U.S. LTO production had never reached 5.5 mb/d, as the black line shows. According to the most recent EIA presentation, the local peak (In March 2015) was around 4.6 mb/d
OK, thanks. The black curve needs correction.But the issue continues being that EIA underestimated production so much that it had to raise its predictions by about 100% each year.
Look at the prediction for 2020:
AEO 2012: 1.3 mbpd
AEO 2013: 2.8 mbpd
AEO 2014: 4.7 mbpd
And all this without any significant change in oil price.So if the question is, as Ron is posting, how much value have EIA predictions? The answer clearly is none. EIA predictions are useless. Evidence indicates that they are going to overestimate production by a large amount for as long as production goes down.
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Guy Minton, 02/13/2016 at 5:47 pmThe big deals against oil prices are, now, the drop in (the increase) in future demand from 1.6 to 1.2%, per IEA, and the massive amount of oil that Iran is getting to lay out with unknown capital input. Supposedly glutting the market with 1.5 million more barrels with magic, I presume. However, I figure it, the drop in demand seems to indicate only about a 300k to 350k difference.Jimmy, 02/13/2016 at 6:37 pmAh, the magic of OPEC will prevail, then. Even though to fully ramp up more, Saudi has to drill in the offshore area, which I am sure is NOT $10 barrel cost of production. Iraq has to end their internal strife to gain some traction. Venezuela is sucking wind, badly. Ecuador, while not the massive producer of other OPEC members, currently has only one well drilling from 50 something rigs. It is hard to keep up with the news from every country, and it is clear that neither EIA nor IEA are really putting much effort into real data accumulation. I think OPEC is strapped for production for the next two years, with the exception of the magical production from Iran.
On the other hand, I read Canada has some smaller oil sands shut in, while larger ones are scheduling to cut back, or have extended periods of overhaul on production equipment. As rigs for conventional oil have dropped significantly, I fail to see were Canada will not have a decrease in production in 2016. Over a year ago, I said the shale production could drop by over one million, but didn't anticipate the increase before the drop. Still from the high in March of last year, it is still projected to drop by 1.2 million by 2017 by EIA. I still thing they are low in their estimate of the drop, but not as much as they used to be.
I read where China's production is expected to drop from 100k to 200k in 2016, base upon the current prices and capex. A recent post by the author indicates that up to 1.5 million barrels may be lost from in field drilling of offshore wells in 2016. All of South America, Africa, and Asia, including Russia, expect drops in 2016, and 2016 is just the tip of the iceberg.
Where are all of these figures in the garbage the EIA and IEA put out? Far as I can tell, the magical numbers put out for Iran, roughly match the drop in infield drilling offshore. But then I am not an expert, because I am not paid by a highly efficient and omniscient government entity.
While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Jimmy, 02/13/2016 at 7:49 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
Intro sentence should have read: "While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. "Jimmy, 02/13/2016 at 6:37 pmWhile what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the non-OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Adam Ash, 02/13/2016 at 6:51 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
With tank farms, strategic storage, rows of rail tankers and flotillas of super tankers filling up all over the planet, producers will now have to match production to demand much more closely, else they will have to 'spill their seed upon the ground'. And there is not much money to be made doing that.Watcher, 02/14/2016 at 3:29 amSome producers with no where to deliver their oil to must be in very difficult positions; going from normal production to zero in a day. From cashflow positive yesterday to being the proud owner of a pile of useless junk and pipes wth zero income today.
Interesting times.
Try this.Adam Ash, 02/14/2016 at 5:38 amTry listening to what is said by KSA. "We are not going to produce oil out of the ground for which we have no orders."
This has been policy all along. Now think about what you just said, and about where you heard it.
Yes Watcher. The interesting moment arriving herewith is that we will now discover actual global consumption without the smoke n mirrors of production filling tanks somewhere.Watcher, 02/14/2016 at 12:31 pmI would imagine that the impacts will be neither selective or nice. Some good paying fields may have to be shut in if the tanks at the end of the pipe are full. Or it could be the final straw that pricks the light tight oil bubble. We shall see.
Tanks aren't filling. No one is placing orders for oil they would put in a tank. That makes no sense. And note, btw, that filling a tank is demand itself and thus would not justify a price decline if you're a supply/demand disciple.Adam Ash, 02/15/2016 at 1:49 amThe price is low because sellers are willing to sell for that lower price. Period. Even if buyers would pay more, the seller insists on less.
Wrap your mind around that and you understand pursuit of victory.
Oh! Silly me. A helpful piece re Cushing storage:-Jeffrey J. Brown, 02/15/2016 at 8:22 amhttps://rbnenergy.com/just-my-imagination-how-full-is-cushing-crude-oil-storage-capacity-really
'… many storage operators [at Cushing] may be turning prospective customers away. Not because they don't have available capacity but because they don't have enough heavier crude to make WTI lookalike blends with incoming light shale grades.'
Do those full-to-the-brim mega-tankers slow-steaming in circles in the Sargasso Sea and swinging at anchor off Singapore and Malaysia with no where to go waiting for a better time to sell into the market in the face of rising production and exports from Iran make sense?
http://abcnews.go.com/International/wireStory/iran-exports-oil-shipment-europe-nuclear-deal-36929921
Not to me…
Producer-sellers are desperate for cashflow at any price, and the glut in supply means the competition to be the one who gets the sale is intense. Yet at the same time the near capacity storage available to some producers makes the potential for an individual field to be locked in because it has nowhere to send its product to much higher, no matter how hysterical the bean counters get.
The low price of crude is cutting the throat of many producers, who will not easily come back on line even if the price recovers. Its going to be an interesting year
Interesting article on the RBN Energy website, about Cushing. Note that the author touches on two key issues: (1) Insufficient heavy crude to offset the flood of condensate, thus making it more difficult to create their "Synthetic WTI" blend and (2) Weak demand for the Synthetic WTI blend itself.Jimmy, 02/14/2016 at 10:09 pmThe Reuters article from last year discusses the second point:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
Link to my Oilpro.com article on crude versus condensate: http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
As I have previously stated, IMO the global total liquids oversupply is a house of cards, built on an unstable foundation of actual global crude oil production* that requires vast amount of capital every year, in order to keep global crude oil production from crashing.
Up the thread, I noted that a plausible estimate is that it may have taken about a trillion dollars in 2014 and 2015 combined to keep global crude oil production around 68 to 69 million bpd, versus my estimate of 69 million bpd in 2005.
*45 API Gravity and lower crude oil
Maybe KSA is FOS? Maybe that statement is not true.Heinrich Leopold, 02/14/2016 at 10:25 amAlexS,Jeffrey J. Brown, 02/14/2016 at 10:31 amIn my view the past surge in shale production was based on the favorable conditions of the bond market ('search for yield'). As long as the bond market has been liquid, production could surge. However, as the recent collapse of the bond market starts affecting production (see below chart) we could see another 'black swan' event on the downside of production.
An analyst on CNBC had an interesting quote, which he attributed to John D. Rockefeller, to-wit, there has been more money lost to the ill advised search for yield, than in all of the bank robberies in recorded history.Heinrich Leopold, 02/15/2016 at 12:56 amJeffrey,AlexS, 02/14/2016 at 11:26 amAll the three bubbles of the last decade – internet bubble, housing bubble and now the shale bubble – reflect deeply the American approach how to respond to challenges in the economy and society: It is better to ask for forgiveness than to ask for permission. Greenspan famously said when the internet bubble burst: You can only recognize a bubble when the bubble has burst. This approach has probably avoided also some damage ( for instance an escalating oil price surge), yet has also done some huge damage to investors.
The lesson for investors is to recognize and understand the thinking behind Wall Street's motivation and adjust the investment strategy accordingly. As the bond collapse is far from over, we have not yet seen the bottom of the production decline. The bond market is the major driver of oil and gas production. Any forecast which ignores changes of capital markets is very likely irrelevant.
Heinrich,Ron Patterson, 02/14/2016 at 12:14 pmYes, access to cheap money (not only bonds, but also bank loans) was one of the key factors that contributed to the shale boom.
As regards the 'black swan' event on the downside of production, we will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat.
TechGuy, 02/15/2016 at 3:27 amwe will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat.I agree if you are talking about the money the bankers and investors already have invested in shale. But the bankers and investors will not likely be looking for ways to lose more money. New investment in shale will be difficult to come by.
Ves, 02/14/2016 at 12:23 pm"Nationalize it and this annoying little issue of profit pursuit disappears."US banks were not "nationalized" during the 2008-2009 crisis. I very much doubt the gov't will nationalize the Oil industry, unless there is a very drastic event that cause the price to skyrocket suddenly (ie above $200). A KSA/Iran hot war would probably do that.
Collapsing Oil prices is just a symptom of a mounting global economic crisis. Even if the US nationalized its Oil industry it still not going to fix problems overseas: The Middle East, China and Europe.
The period of kicking the can with ease has reached its end. Now the World's gov't will need to resort to ever increasing drastic actions to avoid a global depression.
likbez, 02/14/2016 at 1:03 pm"we will see which financial tricks the shale guys, their bankers and investors will invent to keep shale production afloat."Maybe they start investor focused campaign "World is running out of oil" meme :-) LOL … similar to "We are running out of land" meme during Housing bubble :-) Just kidding. :-)
Heinrich,Heinrich Leopold, 02/15/2016 at 2:56 amI think we should view "surge in shale production" not as something "based on the favorable conditions of the bond market" but as yet another "boom and bust" cycle which is the hallmark of neoliberal economy. Third in the sequence dot.com-real estate-shale oil, if you wish.
In all three cases it was reckless financing using new instruments which became available after deregulation which initiated the bubble. In this case covenant-light loans -- the crappiest kind of junk.
Like in all previous bubbles the deflation of the shale bubble might take some banks (this time regional) with it and result in a real extinction of shale companies. Technological progress achieved will remain intact and will be picked up by survivors.
The wave of bankruptcies will depress new drilling and might serve as another catalyst of the decline of shale oil production in 2016 and 2017 (despite takeover of properties). The decline that was not accounted for in the current forecasts.
Unlike two previous bubbles, this is a more localized disturbance and the size of CCC and lower junk bond market is just around one and a half trillion, but it will likely spread to the broader economy at least in six affected states due to links to mortgages, commercial real estate, municipal bonds, etc.
And it coincides with the weakening of the US economy.
likbez,Dennis Coyne, 02/14/2016 at 10:39 amCCC and lower is just the canary in the mine. It is a sign of strength or weakness in the sector. It affects also private equity, loans….
The big question now is: How far will this go? Can it escalate? As this is impossible to predict, it is also impossible to make an accurate production forecast – even for the next two years.
It is ironic that even the FED -- having thousands of economists on its payroll -- has been a very bad forecaster. Greenspan did not recognize the internet bubble, Bernanke had to deal with the housing bubble ( the housing crisis is contained) and now Yellen has to face the shale bubble, which she did not foresee (in December there was still talk about escape velocity and inflation).
It is still open how deeply the burst of the shale bubble will affect the US economy. There could be some political events which brings out some oil production worldwide and the shale industry will be saved for a while. However, my gut feeling tells me that this will go very deeply. It looks like the FED has painted itself into a corner again.
Hi AlexS,R Walter, 02/14/2016 at 10:51 amI agree. Also your point about oil prices is important, oil prices are very difficult to predict and eventually they will affect output, though there is a significant time lag (maybe 18 to 36 months) between a change in oil prices and a change in the oil supply. I have not yet figured out what this time lag is, but my current guess is about 24 months on average.
This will vary depending on the oil field (deep water projects have a longer lag and onshore conventional and LTO may be somewhat shorter than the global average).
http://www.theoildrum.com/files/PeakOil1.pngAlexS, 02/14/2016 at 11:28 amAnother forecast that was incorrect.
Who were the authors of those forecasts?R Walter, 02/14/2016 at 1:44 pmRon Patterson, 02/14/2016 at 2:12 pmEdit
So Ace got it wrong. We have been knowing that for a long time. That's history. What's your point?likbez, 02/14/2016 at 7:02 pmOil production will definitely, one day, peak. The fact that past predictions of peak oil were wrong only means they were too early. People who are predicting peak oil now, or at any time in the future, will be 8 years closer to hitting the date than Ace did.
I am reminded of insider traders in the stock market. That is company executives buying or selling stock in their own companies. The saying is, They are almost always right. But… They are almost always too early.
That is, they see that something is definitely happening so they act. But they just expect it to happen way before it really does. The same can be said about peak oil prognosticators. We saw that peak oil was definitely going to happen. But most of us were way too early with our prognostications, about 8 years too early. :-)
Ron,AlexS, 02/14/2016 at 11:44 amI am reminded of insider traders in the stock market. That is company executives buying or selling stock in their own companies. The saying is, They are almost always right. But… They are almost always too early.
An excellent point --
Dennis,George Kaplan, 02/14/2016 at 4:26 pmYes the time lag is different for different type of resource, different type of projects, different producing fields, different countries and different companies.
A big question is how to calculate this time lag.LTO was expected to be the first to react, and it indeed reacted the most. But I was expecting much bigger declines last year.
Conventional output was almost unaffected last year (low short-term price elasticity). There will be some negative supply-side impact this year, but the biggest cumulative impact from low prices should be felt by 2020.
With LTO the production was accelerating y-o-y at a high rate, more in percentage terms than has been seen in fields before, at least since the very early days of the industry. The cut has been from that high rate to a slow decline. If the LTO production had been steady or a growth rate that was more representative of previous new fields then the decline would have been pretty steep by now. That and the different impact, and decoupled timing, of drilling and completions compared to conventional fields is what through off a lot of the predictions in my opinion.Dennis Coyne , 02/14/2016 at 7:11 pmHi AlexS,AlexS, 02/14/2016 at 8:00 pmI read your reply on the previous thread and I appreciate your insight. I think I mostly agree with your take.
One place that I may not agree is that you think $45/b is high enough to keep output flat. I think that in the LTO plays $45/b is not enough to make the completion of drilled uncompleted (DUC) wells financially viable so we will see a fairly steep decline in LTO output if the EIA oil price forecast is correct.
In addition there are no doubt fields throughout the World where there are few long term projects in the works, but have continual infill drilling that either maintains a plateau or reduces the overall field decline rate. I would expect that even $45/b may not be enough to justify the continued drilling of new wells in many fields.
Note that the EIA STEO predicts Brent at $46/b in the fourth quarter of 2016. This is the reason that I believe the EIA's oil supply forecast is too high (assuming their price forecast is correct). I would expect at least a 1 Mb/d drop in 2016 average annual World C+C output compared to 2015 average output levels if the EIA's most recent oil price forecast for Brent crude is correct.
Dennis,Dennis Coyne , 02/14/2016 at 8:20 pmI didn't say that "$45/b is high enough to keep output flat". I said that $40-45/b is enough to cover operating costs and maintenance capex in a vast majority of the world's currently producing conventional fields (as well as oil sands operations).
That doesn't mean keeping production flat. Where production was falling due to natural declines at $90-100, it will continue to decline (probably, at higher rates) at $40-45.
Project delays and lower upstream capex will also have a negative impact on new conventional production. But as project start-ups scheduled for 2015-17 are generally not postponed, the overall impact on global conventional production will be relatively modest this year. However the effects of low prices will gradually increase in the next few years and peak by 2020, even if oil prices recover by that time.
As regards LTO, I agree that $45 is not enough to keep production flat. I guess the required price is closer to $60.
Finally, I certainly do not expect global C+C production to drop by 1 mb/d y-o-y in 2016. Barring unlikely OPEC cuts and unexpected large-scale supply outages, the increase in OPEC output (Iran) should partially offset declines in non-OPEC production.
Hi AlexS,Ron Patterson, 02/14/2016 at 10:27 pmSorry I misunderstood. Let's assume the EIA STEO oil price predictions are correct.
What would you expect for the average annual C+C output level in 2016, if that assumption were correct?
Note that I also do not expect C+C output will fall by 1 Mb/d, but the reason will be that the EIA's oil price prediction will be too low. I expect an average annual Brent price level for 2016 of about $55/b+/-$5/b and at that price level average annual C+C output will decline by about 500 kb/d in 2016 (about 79 Mb/d for an average output level) relative to the average 2015 output level (about 79.5 Mb/d).
average annual C+C output will decline by about 500 kb/d in 2016 (about 79 Mb/d for an average output level) relative to the average 2015 output level (about 79.5 Mb/d).likbez, 02/14/2016 at 1:07 pmThrough the first ten months f 2015, world C+C production has averaged 79.94 Mb/d. If we have the decline that I expect in November and December, I believe the average for 2015 will be around 79.85 to 79.9 Mb/d.
I expect 2016 C+C production to be about 78.9 Mb/d or a decline of about 1 million barrels per day.
Below is the 2015 C+C production, through October, according to the the EIA. The Peak so far, was in July 2015 at 80,525,000 million barrels per day.
Jan-15 Feb-15 Mar-15 Apr-15 May-15 79,379 79,371 80,175 79,988 79,369 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 80,038 80,525 80,439 80,038 80,071
The time lag probably also depends on when financial spigot that inflates the bubble is shut down.clueless, 02/14/2016 at 6:44 amFuture accounting problems – There have been many posts here over the past 2 years analyzing the cost incurred by the O & G companies to produce LTO. In my opinion, some of the ability to do that may go away.Enno, 02/14/2016 at 8:18 amMost companies have had to write down the balance sheet value of their LTO reserves (costs incurred) in 2014, 2015 and probably will again in 2016. If the price of oil increases, write ups to reinstate the value back to where it was are not permitted. So the true costs become invisible. So, if in 2017, if the price of oil is back to $50, companies could produce income statements that show a profit. But, some of that will be because much of the cost was written off in previous years due to "one time, extraordinary valuation write offs."
The companies offset the oil being sold with a DD&A [depletion, depreciation and amortization] cost. In general, that means that they ratably deduct their capitalized costs over each barrel of oil produced. But, if they have already written off half of their capitalized cost due to a valuation write off, then future DD&A will be one half of what it would have been without the write off.
And, it will likely be very difficult in 2017 to separate out their 2017 operations.
Clueless,shallow sand, 02/14/2016 at 11:15 amExcellent point. That is why careful investors, like e.g. Warren Buffett, don't accept accounting profit.
They calculate something like "owner earnings", in which you ignore accounting DDA and include your own conservative estimate of the depletion/depreciation of assets.In my opinion, there is a seriously flaw in the calculation of the accounting profit for LTO companies. The depletion/depreciation amount doesn't fully reflect the actual reduction of the NPV of the assets over a year. In other words, the very fast decline in production of shale wells, and the larger variable costs later in the life of a well, are not fully accounted for. LTO companies are in general getting away with a much smaller DDA amount, and therefore front loading profits. Normally lowering DDA is a bad corporate strategy, because it leads to more corporate taxes, but these companies in general also benefit from major tax deductions to compensate for this. I think this accounting flaw has played a big role in the shale boom.
Most retail investors unfortunately take book profits and book value too seriously. Like Shallow sand, you, and others have shown, there are much better ways to make value estimates.
Good points, as we have discussed previously. If oil prices don't return to 2011-14 levels, tough to see how loan principal gets paid.clueless, 02/14/2016 at 1:18 pmAsset sales to pay principal are self defeating. Due to IDC elections, depletion and depreciation, would seem that shale asset sales would generate a lot of tax liability. A $1 billion sale may generate only $600 million after tax?
Also, assets sales cause company wide production to fall.
Interesting how all of the companies in 2015 are reporting year over year production growth AFTER excluding the effects of asset divestures. So we are selling production to drill more wells to grow production. Our production is falling, but by gosh we have more new wells with 1 million EUR.
The production they are selling tends to have higher OPEX, but lower decline, and therefore, despite the higher OPEX, more PV per BOE.
A prime example would be Whiting, who last summer tried to sell its North Ward Estes CO2 flood.
As I recall, NWE accounted for less than 10% of company wide BOE in 2014, yet almost 20% of PDP PV10. This despite having much higher current OPEX than the Bakken and Nirobrara assets.
I have never understood how long term value is being created by these companies. One thousand 200 BOE average wells will be 40 BOE average in 5 years, for example, yet little to no ability to pay down debt principal.
PV10, 9, 8, or whatever discount value is appropriate does matter. Now that PDP PV10 is greatly less than long term debt, I hope some investors pay attention to it.
SS – I believe that current asset sales generally are unlikely to result in any cash taxes being paid. Especially since prices have fallen so much in the last year and a half. Further information below, for those who might want to delve a little deeper, but not fully into the complexities.shallow sand, 02/14/2016 at 2:44 pmAs you know, the companies deduct most of their drilling/fracking costs on their tax returns in the year that the money is spent. But, for their financial presentation books, following the GAAP principle to match expenses with revenue, these expenses are capitalized and included in their Oil & Gas Assets. For the financial statements these costs are rateably amortized as production occurs as DD&A expense.
Generally speaking, the companies create significant net operating losses on their tax returns because of those deductions. However, because in the future they will eventually deduct the costs [DD&A], but they cannot again deduct them for tax purposes, they are required to book deferred taxes payable as a liability.
Looking at PXD. At year end they have a $1.776 billion long term deferred tax liability. Using a 32% tax rate, this can imply a tax net operating loss of up to $5.55 billion. Assume that they have a producing field on the books at $500 million [GAAP using $49/bbl], with future drilling prospects, and a zero tax basis. They sell it for $1 billion, a $500 million book profit. A 32% tax on the book profit is $160 million, which is recorded in the income statement, but, which does not have to be paid. It offsets some of the net operating losses. The tax return shows a gain of $1 billion, an extra $500 million. The 32% tax on that extra $500 million offsets their deferred tax liability of $1.776 billion, reducing their deferred tax liability to $1.616 billion.
Clueless. Yes, have to work it through to get a clear picture.simon oaten, 02/15/2016 at 7:23 amEnnoR Walter, 02/14/2016 at 7:59 amone of the "things" that the shale industry has given the oil industry is lower "finding costs" ……at the "expense" of greater variability in outcomes (EUR / IP / PV10). Again – thankyou for your site – outstanding work
rgds
simonMore accurate than this one:Matt Mushalik, 02/14/2016 at 8:08 amMy latest graphs using EIA update to October 2015clueless, 02/14/2016 at 12:26 pm15/2/2016
World outside US and Canada doesn't produce more oil than in 2005
http://crudeoilpeak.info/world-outside-us-and-canada-doesnt-produce-more-crude-oil-than-in-2005Thanks! Much more than an excellent presentation!Jimmy, 02/14/2016 at 4:34 pmAwesome article Matt! Thanks for fleshing out the EIA report data!!Hickory, 02/14/2016 at 5:37 pmExcellent site Matt!clueless, 02/14/2016 at 12:12 pm
http://crudeoilpeak.info/One question- I see that you have US crude imports at about 7Mbpd, where as Jan data from iea have US net liquids import at about 5 Mbpd.
Is this difference because we export things like refined product and condensate?A big 2 page story in the business section of today's Daily Oklahoman. Oklahoma's oil production is up over 100,000 bbl/day starting in December – over 25%. Well, actual production is not up, but the EIA started doing their surveys last year to get more accurate production numbers. After months of consultation with the Oklahoma Tax Commission, they agreed that the EIA #'s are the correct ones. The OK Tax Comm claims that they have been collecting the right amount of tax.Ron Patterson, 02/14/2016 at 12:30 pmApparently, the data is loaded into a 30 year old mainframe system and computer program. Any data that does not match is kicked out of the system. That data is then processed manually but, has never been able to be loaded back into the existing computer system. So, numbers from Oklahoma have been understated for a long time. The Tax Comm says that they have one year left [estimate] on a four year project to put in a new computer system that will fix their problem. Meanwhile, the EIA is going with their survey.
Is this really the 21st century?
The EIA explains their new methodology here:StuckinWalkerWorld, 02/14/2016 at 2:09 pmUpdating Monthly EIA Crude Oil Production Estimates for Oklahoma to Use Survey Data
Good afternoon–JAt the risk of hijacking of this thread, I have several questions to pose to this group, starting with why are petroleum imports from Canada continuing to increase? (See link to EIA below). Is it caused in part by the anemic Canadian dollar, the need to keep pumping because cash flow generation trumps all other considerations, or something else? Which leads to another question How much further must the price of petroleum decline before petroleum imports from Canada start to dwindle? Until it does–and who knows when that will happen -- I have a hard time believing that oil prices will move higher in the current cycle.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=W_EPC0_IM0_NUS-NCA_MBBLD&f=W
George Kaplan, 02/14/2016 at 3:54 pm
I haven't seen this discussed, but my apologies if it is a duplicate. Paragon Offshore to file Chapter 11 – is this the largest bankruptcy for offshore drillers so far?Frugal, 02/14/2016 at 7:12 pmhttp://splash247.com/paragon-offshore-set-declare-chapter-11-bankruptcy/
Oil crisis leaves the East barrelling out of controllikbez, 02/14/2016 at 9:11 pm"It's sad. These people never thought the day would come where a barrel of oil would be below $30 (U.S.)," he said. "They were just living for the moment and they were making a huge amount of money and just thought it would continue on."
The oil price collapse is also hitting the opposite side of Canada.
A very good article. Thank you!Frugal, 02/14/2016 at 10:27 pmThe fallout from the oil crisis - compounded by potential government job cuts - could hit the province worse than the infamous cod moratorium of the 1990s, said Wade Locke, an economics professor at Memorial University.
"A 30 per cent cut in government expenditures over three years at a time when the economy is weak because of oil prices and less remittance income from people working in the oilfields in Alberta?
"Yes, it's fair to say it could be harder than the moratorium," he said.
Those affects are being felt now. Fewer blue and orange ice-class cargo ships leave the narrow entry to the St. John's harbour, loaded with supplies for the rigs 350-kilometres offshore.
And with declining output from the three producing rigs and two of four exploration rigs temporarily shut down - two more are scheduled for shutdown in July - helicopters are bringing fewer workers back and forth right now.
Still, resilient Newfoundlanders are quick to list off the reasons they believe the downturn could be relatively short-term; that this is the bottom of a typical, albeit particularly painful, commodity cycle.
After all, there's still a great deal of interest in Newfoundland's offshore oil, which is cheaper and cleaner to extract than oilsands crude. A government land sale in the Flemish Pass basin took in a record $1.2 billion of new oil company spending commitments. There are an estimated 12 billion barrels of oil reserves in that area alone. The province believes the number of job openings will increase beginning in 2019, when it anticipates major project expansion will resume.
… … …
….new home construction has dropped by 20 per cent.
…Insolvency filings are up 22 per cent over the last year at accounting and insolvency firm Noseworthy Chapman.
…Two of the seven offshore rigs that the base supplied in 2014 have shut down temporarily. The marine base is taking a revenue hit, but so far there have only been a few layoffs, he said.
…Food banks in the province provide food to nearly five per cent of people in the province, the second highest level in the country.
…8.2% - Percentage of Newfoundland workers projected to lose their jobs in next three years, amounting to 24,000 job losses
… $1.9B - Deficit projection in 2015-2016 fiscal update, nearly twice what was expected in the budget
… $12.4B - Newfoundland's net debtLooks like everything is connected those days. Or "over connected". A lot of common people suffer consequences of those big boys games. Business bankruptcies lead to personal bankruptcies.
I wonder where they got the 12 billion barrels of reserves from. Wikipedia gives the following numbers for the estimated oil in place:Doug Leighton, 02/14/2016 at 11:36 pm
Hibernia = 2.1 billion barrels with 700 million already produced by 2010
Terra Nova = 400 million barrels
White Rose = 440 million barrelsAs far as I can tell, these are the only major oil fields off Canada's east coast.
Dead on Frugal,George Kaplan, 02/15/2016 at 8:42 am"A government land sale in the Flemish Pass basin took in a record $1.2 billion of new oil company spending commitments. There are an estimated 12 billion barrels of oil reserves in that area alone."
So what is it, 12 billion barrels or 300 to 600 million barrels? Total production 1977-2005 at Prudhoe Bay = 11 billion barrels with perhaps two billion barrels of recoverable oil remaining. Let's be generous and say 0.5 billion barrels total in the Flemish Pass Basin; 12 billion, no bloody way.
"In late September 2013, Statoil ASA and its 35 per cent joint-venture partner, Husky Energy Inc., announced two back-to-back light crude discoveries in the deepwater Flemish Pass Basin, offshore Newfoundland. The larger of the two discoveries, the Bay du Nord exploration well, confirmed the existence of 300 to 600 million barrels of 34 degree API oil recoverable."
http://www.albertaoilmagazine.com/2014/01/light-crude-discovery-newfoundland/
Hebron – comes on line 2017, maybe 700 million barrels or more of heavy oil. BP and Shell each paid about $1 billion for exploration rights offshore Nova Scotia. Shell is drilling at the moment The author might also be considering 'equivalent' oil offshore Labrador which might have a lot of gas (but very difficult to develop). There are a couple of areas on the border with USA which are off limits at the moment. Against this Terra Nova and WhiteRose are well into their run down phases and don't have much left.Green People's Media , 02/14/2016 at 11:30 pmSay, Ron, have you looked at the most recent Drilling Productivity Reports? A couple days ago, they showed the major frack-oil fields having a reversal of legacy well declines. Bakken, Eagle Ford, etc. all show an UPWARD move in the legacy graphs (in other words, they're losing less production monthly than they were previous few months).Econ, 02/15/2016 at 2:47 amI thought that looked really odd.
What is your thinking on this?
Bobby G,
at the GPM
I think that is due to the decline rate being very high initially for new wells followed by a long period of slower decline and more steady production over the course of a well's life. As new producing wells were only enough in quantity to keep production flat (rather than increase it like previous years), there was less proportionally of this initial production spike and steep decline, and more proportionally of the slower more gradual declining production due – the composition of the wells now being mostly older rather than many new wells.AlexS, 02/15/2016 at 3:33 amAlso as production had fallen a bit, the decline should naturally be smaller even at the same decline rates. For instance a 10% decline on 1,000,000 mbpd will be higher than the decline at 10% on 900,000 mbpd
New shale wells have much higher decline rates than the old ones.Ron Patterson, 02/15/2016 at 8:32 am
The less the number of new producing wells, the lower is the average decline rateIt does not look odd at all. That is exactly what you would expect, as Alex and Econ pointed out. Production is declining and therefore you have less oil to decline. And fewer wells are coming on line and older wells have a slower decline rate than new wells.Oldfarmermac, 02/15/2016 at 9:37 amI didn't get back to say thanks for the answers to my question about condensate energy content yesterday, or day before but thanks everybody.Ron Patterson, 02/15/2016 at 9:49 amMaybe somebody who can still remember their math will calculate the loss of energy per average barrel of so called total liquids as the percentage of condensates increases, with the quantity of conventional crude decreasing.
At first glance it looks as if the rising percentage of condensate is cutting significantly into the energy of an "average" total liquid barrel.
I have not run across any research yet performed with the intent of designing internal combustion engines to run mostly or entirely on condensates, but it would appear at first glance that using straight condensate, or a very high percentage of condensate as ice fuel would be practical and economic, so long as it continues to sell for substantially less than ordinary crude- at least in the case of large stationary engines, or engines powering equipment that mostly stays very close to a home base, such as farm machinery and heavy construction equipment. The condensate could probably be hauled to a big construction job or large farm at no more trouble and expense than LP .
Why blocking Obama's pick to replace Scalia could cost Republicans their Senate majorityshallow sand, 02/15/2016 at 11:21 amAssuming the president picks a Hispanic, African American or Asian American – bonus points if she's a woman – this could be exactly what Democrats need to re-activate the Obama coalition that fueled his victories in 2008 and 2012. Even if he does not go with a minority candidate, the cases on the docket will galvanize voters who are traditionally less likely to turn out.
That is exactly what I have been saying.
Keep in mind that a quarter of Nevada's population is Hispanic. Beyond being a battleground in the presidential race, there is also an open Senate race to succeed Harry Reid. Democrats will nominate a Latina and Republicans will nominate a white guy who is already in Congress.
This will absolutely assure that Harry Reid's seat will stay in Democratic hands.
More broadly, this could also undermine efforts by Senate Republicans to show that they are capable of governing and not just "the party of no."
Ron, looks like a leading choice is Sri Srinivasan. I know nothing about him, other than what I have just read. 48. Born in India, raised in Kansas, Stanford graduate. Was appointed to DC circuit and confirmed by senate 97-0, in 2012.Ron Patterson, 02/15/2016 at 11:27 amGood question shallow. But I don't think he will be shot down. Even if he is the nominee McConnell will not allow it to come up for a vote. He will just sit on it until the next president is elected. And sit on it longer if a Republican is elected. Which is not likely.clueless, 02/15/2016 at 4:59 pmThat is just what they do. They are the party of NO!
I know that this is useless to point out, but Harry Reid said "no vote" to almost every single proposal passed out of the Republican controlled House.Fernando Leanme , 02/15/2016 at 1:55 pmThe question is how many of those Hispanic "Nevadans" have the right to vote. I bet less than less than half of that quarter.shallow sand, 02/15/2016 at 11:32 amAnd my guess is you'll see republicans very motivated to avoid an imperial presidency ruling by decree backed by an activist court. That reminds me of Venezuela.
I think a post of mine might have been lost.shallow sand, 02/15/2016 at 12:40 pmIn summary, I was comparing PXD (Pioneer) with CLR (Continental).
PXD produced 204K BOEPD in 2015, 53% oil. PV 10 12/31/15 $3.2 billion at $50 WTI, 89% PDP.
CLR produced 222K BOEPD in 2015, 63% oil, PV10 12/31/15 $8 billion at $50 WTI, 43% of proved reserves are PDP.
PXD enterprise value much greater, plans to grow BOEPD in 2016.
CLR enterprise value less, plans to shrink BOEPD in 2016.
Big difference, PXD well hedged, CLR is not.
Why the great disparity in PUD PV10? PXD supposedly has the most core acreage in Permian?
I really would like to see these reserves reports. I don't see how CLR has much in the way of PUD PV10.
Note, proved reserves % PDP doesn't necessarily equal % of PV10 that is PDP.dclonghorn, 02/15/2016 at 2:57 pmI will wait for 10K. I think we will find at $50 WTI, almost all have less PDP PV10 than long term debt.
Further, I hope we get indication in 10K what PV10 is at $30 WTI.
Something has looked fishy to me with CLR reserves and production every time I looked at it. I just stay away from that one.shallow sand, 02/15/2016 at 5:58 pmdclonghorn.dclonghorn, 02/15/2016 at 7:16 pmIronically I used the "fishy" word too discussing CLR today.
Don't know anything they report is not correct, just seems OPEX is always very low compared to peers operating in the same areas.
Seems odd that PUD BOE would be 57% given terrible economics for new wells.
Again, BOE reserve category percentages do not equal PV10 value percentages, but 2/3 of OAS BOE reserves are PDP. Assume PXD is high % PDP reserves, given almost 90% of PV10 is PDP.
Also, never have figured out why all the $10+ million non core wells in places like Divide, Stark, Elm Coulee, etc, haven't caught up with CLR. EOG, WLL, QEP and others seem to have better wells/ locations companywide in Bakken.
Oh well, it's just speculation. Maybe the 10K's will give us more clues.
If you look at Enno's shaleprofile.com, you can get actual production curves for them and compare them with their presentation production. I made that comparison when Enno's site first came up. It is a remarkable difference. I don't know how much NPV they assign to any of their reserves, but I've seen enough to know that I don't trust their reserves for volumes or dollars.dclonghorn, 02/15/2016 at 3:27 pmNorth Dakota should be releasing their December production numbers soon. A lot of people consider North Dakota's reporting as an indicator of the trends for all shale oil. Their reporting is much more timely than waiting 8 months to see what Texas looks like after revisions.Oskar DiSilvo, 02/15/2016 at 6:28 pmNorth Dakota surprised with small production gains for October and November. The EIA's November Drilling Productivity Report forecast a 27 kbopd decline from November's estimated 1137 kbopd to December's estimate of 1110 kbopd. North Dakota's report for November was 1119 kbopd. It may be that they trade some accuracy for timeliness as their monthly numbers seem to be very erratic. That said, I think they are due for a decline of over the forecast 27 kbopd.
Is KSA's strategy succeeding?http://fivethirtyeight.com/features/saudi-arabia-is-winning-its-war-against-the-u-s-oil-industry/
This article from Quartz is much more in-depth:
I have given up any pretense of trying to understand what will happen next, then further down the road. Except to understand, that at some point, depletion becomes unequivocally evident to all…then it will get 'interesting'.
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Javier, 02/13/2016 at 8:11 pmHi Ron,AlexS, 02/13/2016 at 9:22 pmOn the issue of EIA's predictions accuracy, I updated this graph from Mason Inman and added actual oil US production.
What this graph shows is a typical very conservative estimate system. This means that on the way up, they greatly underestimate production and on the way down, they are going to greatly overestimate production.
This clearly shows how credible their predictions are. Although the graph is only for the US, clearly they are going to be equally conservative (and thus equally wrong) about world oil production.
Javier,Javier, 02/13/2016 at 9:56 pmThe long-term projections of U.S. LTO production are from various issues of the EIA Annual Energy Outlook. They indeed were very conservative, even though none of them (even the AEO-2015) did not assume such a big drop in oil prices.
As regards the actual production data (the black line), it is from the Drilling Productivity Report and include almost 1 mb/d of conventional output, primarily from the Permian basin.
U.S. LTO production had never reached 5.5 mb/d, as the black line shows. According to the most recent EIA presentation, the local peak (In March 2015) was around 4.6 mb/d
OK, thanks. The black curve needs correction.AlexS, 02/13/2016 at 10:27 pmBut the issue continues being that EIA underestimated production so much that it had to raise its predictions by about 100% each year.
Look at the prediction for 2020:
AEO 2012: 1.3 mbpd AEO 2013: 2.8 mbpd AEO 2014: 4.7 mbpdAnd all this without any significant change in oil price.
So if the question is, as Ron is posting, how much value have EIA predictions? The answer clearly is none. EIA predictions are useless. Evidence indicates that they are going to overestimate production by a large amount for as long as production goes down.
These are projections for LTO, a new resource type. Its emergence as a new important source of global supply and its rapid growth was a "black swan" event, which nobody could predict.This is a good example why all such projections are just a snapshot that reflects our current knowledge of geology, technology and other factors affecting energy supply
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Jeffrey J. Brown, 02/15/2016 at 8:22 am
Interesting article on the RBN Energy website, about Cushing. Note that the author touches on two key issues: (1) Insufficient heavy crude to offset the flood of condensate, thus making it more difficult to create their "Synthetic WTI" blend and (2) Weak demand for the Synthetic WTI blend itself.The Reuters article from last year discusses the second point:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
http://www.reuters.com/article/us-usa-refiners-trucks-analysis-idUSKBN0MJ09520150323Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
Link to my Oilpro.com article on crude versus condensate:
http://oilpro.com/post/22276/estimates-post-2005-us-opec-global-condensate-production-vs-actua
As I have previously stated, IMO the global total liquids oversupply is a house of cards, built on an unstable foundation of actual global crude oil production* that requires vast amount of capital every year, in order to keep global crude oil production from crashing.
Up the thread, I noted that a plausible estimate is that it may have taken about a trillion dollars in 2014 and 2015 combined to keep global crude oil production around 68 to 69 million bpd, versus my estimate of 69 million bpd in 2005.
*45 API Gravity and lower crude oil
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November 19, 2012 | The Oil Drum
Black_Dog on November 19, 2012
I think the EIA has been playing fast and loose with the petroleum statistics. As noted last week, the EIA Annual Review for 2010 states that the US produced a total of 9,443 mbbls/d, of which US crude production at 5,512 mbbls/day (which includes lease condensate), NGPL's at 2,001 mbbls/d and processing gain of 1,064 mbbls/d. The difference of 866 mbbls/d appears to be made up by biofuels.
Total product supplied is said to have been 19,148 mbbls/d, with imports minus exports totaling 9,434 mbbls/d of that. The amount of crude imported was 9,163 mbbls/d. From these data, the total crude supplied to the refineries was 14,675 mbbls/d, of which 62% is imported.
I've previously suggested that assigning all the processing gains to US production is factually incorrect, instead the processing gains resulting from refining imported crude should be added to the total for imports. For a rough guess, using the fraction of crude imported given above, 664 mbbls/d should be subtracted from the US production and added to the import side of the accounting. This revision reduces US production to 8,779 mbbls/d and increases imports to 10,098 mbbls/d, increasing the fraction imported from 49% to 53%.
Of course, the EIA misses the whole discussion about biofuels, especially ethanol, which require a large input of fossil fuels to produce the final product. The EIA ignores this fuel input, showing biofuels as an input to the front end of the refining process. With ethanol production now using about 40% of the US corn crop, it would be more accurate to consider this portion of the US agricultural system to have been added to the energy supply system and the energy used would thus become an internal consumption which would be subtracted from the petroleum energy available to the rest of society. Doing this calculation would increase the fraction of energy imported, which would give a more realistic picture of our situation...
E. Swanson
carnot on November 22, 2012
xoddam on November 20, 2012 - 7:21amSorry Guys but you have missed the point on refinery gains. It is a mirage. Remember the 1st law of thermodynamics.
Energy cannot be created or destroyed. US refiners continue to quote their refining capacities and products in barrels - a unit of volume which is meaningless unless a density unit is also quoted. What you should consider is the mass unit. In ALL refineries if you measure in units of mass it should add up to 100% plus the mass of hydrogen and other inputs added which increase the mass. ( methanol for an MTBE unit for instance).
When the crude is distiller in the crude unit it will produce a number of products with different densities and therefore different mass per barrel. Measure the products in barrels and you will have the following barrels per tonne.
Butane. 11
Naphtha 9
Gasoline 8.7
Jet 8
Diesel 7.5
Vacuum gas oil 6.8
Fuel oil 6.5In a cat cracker, with no hydrogen addition the mass of products is constant but because the volume of LESS dense light products exceed the total volume of HEAVY dense products , hey presto there is a refinery gain - in volume but not in mass.
Some refinery gain is due to the addition of hydrogen but typically this is 2-3% of the overall mass flow. Refiners love to sell in units of volume as they can benefit form the sleight of hand of selling a less dense and lower energy product to unsuspecting drivers. When energy density is compared in mass units there is NO significant difference between gasoline, jet or diesel. It is about 42-44 MJ per Kg but very different in volume units.
That is why diesels appear 30% more fuel efficient on volumetric terms but in reality the difference is much less.
A number of people have posted the same argument each time "refinery gains" are mentioned, but it does not universally hold true.Cracking can be done without addition of hydrogen, either by separately coking the heavier fractions of the crude before cracking (producing large volumes of solid carbon-rich petroleum coke, frequently a desirable byproduct which is further improved for use in metallurgy), or coking by deposition on the catalytic cracker unit itself (usually simply burned off in batches).
In neither case does any non-crude-oil energy input contribute to the increased volume of the light hydrocarbon products. Indeed the liquid products are of considerably less mass and energy than the input crude petroleum.
Indeed to the best of my knowledge hydrogenation in cracking units is not the norm. The main use of hydrogen in petroleum processing is in fact to remove sulfur and nitrogen from the fuel -- in which process it does not add energy to the desulfurised fuel product, but rather to the sulfuric and nitric acid byproducts.
http://en.wikipedia.org/wiki/Hydrodesulfurization
The hydrogen may be generated by steam reformation of natural gas, but coke from crude oil is also used as feedstock for steam reformation.
mbnewtrain on November 20, 2012 - 10:42am PermalinkYes, thank you for clarifying that. I've tried to clarify it for people before, but your explanation is much better. People tend to assume that "refinery gain" comes from adding hydrogen, but that's not generally true - in most cases it comes from removing carbon, ie "coking". Refineries prefer to do it that way because hydrogen is very expensive, and petroleum coke is a valuable product. In either case, the EROEI is much less than unity - in the case of coking, it is less than zero.
Darwinian on November 20, 2012 - 9:18am PermalinkFrom a chemistry standpoint:
If the refinery is breaking H-C bonds in the hydrocarbon chain molecule and producing free C (which you call coke), then the liquids produced have shorter chain molecules (total number of carbons reduced). Fewer H-C bonds mean lower energy. So using catalytic cracker that produces coke removes energy from the resulting liquid.
My claim of lower net energy in the oil product still stands regardless of refining method. In either case refinery gains should not be counted as energy production.
The US has refinery process gains of over one million barrels per day. That is almost as much as the rest of the world combined. They have to be counting refinery process gains on imported oil.
Black_Dog on November 20, 2012 - 10:59am PermalinkThat is correct. The EIA is counting "refinery gain" on imported oil as "US oil production". It is a totally bogus product by any standard, and the only reason I can imagine them doing it is to artificially inflate US oil production statistics. This has to be politically motivated.
RockyMtnGuy on November 20, 2012 - 12:18pm PermalinkAnd the IEA bought into the EIA's misinformation (call it a lie) with their latest report, which means either that they don't understand the EIA's reporting or they are complicit in the act of overstating US production. Your choice...
E. Swanson
Black_Dog on November 20, 2012 - 1:08pm PermalinkThere is an addition factor which the EIA is not going to want to make clear. US oil imports are increasingly coming from Canada, and most Canadian oil production is now from the oil sands as Canadian conventional oil production declines and oil sands production increases. Canada now exports more oil to the US than it consumes itself.
The product which is exported is mostly bitumen, which is not "tar" as some people would have you believe, but it is about the heaviest grade of oil you can buy. Midwest oil refineries no longer have sufficient domestic oil to keep running, but there is lots of Canadian bitumen and it is very cheap to buy (although not to produce). They upgrade it using coking, and make a ton of money turning it into gasoline.
Despite the fact that the EROEI of coking is negative (there is an energy loss), there is a huge refinery gain in going from very heavy bitumen to much lighter gasoline. The EIA counts this as "US oil production" despite the fact it comes from the Canadian oil sands and involves a net loss of energy.
That's another factor in the huge "refinery gain" the EIA and therefore the IEA is counting in predicting the US will exceed Saudi oil production. It's not really oil, in physical terms it's some kind of an extreme vacuum, or a form of negative energy.
Furthermore, importing extra heavy oil from Canadian bitumen (aka, tar for those who don't understand that tar is derived from coal) sands requires the addition of some dilutant to the mix to reduce the viscosity enough to allow the mix to flow thru pipelines. Looking quickly at the EIS for the Keystone XL pipeline from the US State Department, one learns that the chemical makeup of those dilutants are company proprietary information. It's likely that these are made up of lighter fractions of crude oil, such as naphtha or even some NGPLs. The fractions with the lowest boiling point temperature would most likely be mixed in during the coldest months of the year when the oil would be most viscous.
The source of those dilutants is unknown, but there have been comments about building a pipeline from the US to Alberta to provide those chemicals. If this is done, the dilutants would be (are?) added to the export column of the EIA data, but would then be returned to the US along with the heavy oil and then recovered at some point during the refining process. The result could be like a loop within which (almost) no change in the total quantity of material occurs, but which appears as a reduction in total imports due to double counting in the EIA volume based data...
E. Swanson
Looking quickly at the EIS for the Keystone XL pipeline from the US State Department, one learns that the chemical makeup of those dilutants are company proprietary information.
Proprietary, shmoprietary, it's only the State Deparment that doesn't know what's in it. If you Google, "Western Canadian Select", you'll find out more than you ever wanted to know about it. They're trying to sell it, after all.
speculawyer on November 20, 2012 - 10:08pm PermalinkWhat is Western Canadian Select crude?
Western Canadian Select is a Hardisty based blend of conventional and oilsands production managed by Canadian Natural Resources, Cenovus Energy, Suncor Energy, and Talisman Energy. Argus has launched daily volume-weighted average price indexes for Western Canadian Select (WCS) and will publish this index in the daily Argus Crude and Argus Americas Crude publications.
...followed by a chemical analysis of the most recent sample of it.
What is going down the pipelines is a mixture of oil sands bitumen, conventional heavy oil, synthetic crude oil, condensate, and pentanes plus. The mixture varies from day to day. The buyers don't really care where it came from or how it was mixed, they only care that it meets specs, i.e. the chemical analysis is right.
There are pipelines carrying diluent from the US to Canada, and it is getting to be a big business with the increase in Canadian bitumen and heavy oil production. There are also rail cars full of bitumen going south, and carrying condensate and pentanes plus on the backhaul.
"Refinery gain" is definitely a misleading statistic but there is a point there. It is good to do your own refining. Jobs, value-add, refinery gain, etc.
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Guy Minton, 02/13/2016 at 5:47 pm
The big deals against oil prices are, now, the drop in (the increase) in future demand from 1.6 to 1.2%, per IEA, and the massive amount of oil that Iran is getting to lay out with unknown capital input. Supposedly glutting the market with 1.5 million more barrels with magic, I presume. However, I figure it, the drop in demand seems to indicate only about a 300k to 350k difference.Jimmy, 02/13/2016 at 6:37 pm
Ah, the magic of OPEC will prevail, then. Even though to fully ramp up more, Saudi has to drill in the offshore area, which I am sure is NOT $10 barrel cost of production. Iraq has to end their internal strife to gain some traction. Venezuela is sucking wind, badly. Ecuador, while not the massive producer of other OPEC members, currently has only one well drilling from 50 something rigs. It is hard to keep up with the news from every country, and it is clear that neither EIA nor IEA are really putting much effort into real data accumulation. I think OPEC is strapped for production for the next two years, with the exception of the magical production from Iran.
On the other hand, I read Canada has some smaller oil sands shut in, while larger ones are scheduling to cut back, or have extended periods of overhaul on production equipment. As rigs for conventional oil have dropped significantly, I fail to see were Canada will not have a decrease in production in 2016. Over a year ago, I said the shale production could drop by over one million, but didn't anticipate the increase before the drop. Still from the high in March of last year, it is still projected to drop by 1.2 million by 2017 by EIA. I still thing they are low in their estimate of the drop, but not as much as they used to be.
I read where China's production is expected to drop from 100k to 200k in 2016, base upon the current prices and capex. A recent post by the author indicates that up to 1.5 million barrels may be lost from in field drilling of offshore wells in 2016. All of South America, Africa, and Asia, including Russia, expect drops in 2016, and 2016 is just the tip of the iceberg.
Where are all of these figures in the garbage the EIA and IEA put out? Far as I can tell, the magical numbers put out for Iran, roughly match the drop in infield drilling offshore. But then I am not an expert, because I am not paid by a highly efficient and omniscient government entity.While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea!Jimmy, 02/13/2016 at 7:49 pmIt seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
Intro sentence should have read:While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the OPEC production prediction is more of what I'd call an assumption.
Reply
Jimmy says: 02/13/2016 at 6:37 pm While what is called a prediction of non-OPEC production seems to meet the definition of the word 'prediction' it seems that the non-OPEC production prediction is more of what I'd call an assumption. The methodology used to predict future OPEC production is basically as follows: world demand minus non-OPEC production equals OPEC production. That's some pretty weak tea! It seems to me that there is a bunch of strange and interesting things all going on at once here, several of which are as follows; global peak oil production occurring as we speak is significantly probable, the price of oil is low, Cushings is full of condensate but the market calls it crude and it drops the price of crude, imports of crude to USA have recently increased despite 'the glut', Saudi is likely producing flat out yet production is down month over month for 6 of the last 7 months, upstream investment is down 2 years in a row, demand is up, production is going to decrease. I don't know exactly how it's gonna play out but whatever it is the word 'train wreck' is likely an apt description.
As well this 'total liquids' thing bugs me. It takes energy to produce biofuels and refinery gains. That seems like double counting to me. Like counting the global beef production once when it's on the 1/4 of beef and once again when it's cut with pork fat and called Ukrainian Sausage, to use Mr JJ Browns beef analogy.
I figure in a few short years it'll be pretty clear where all this is going and it'll be a whole new paradigm aka Hobbesian scramble.
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Oldfarmermac, 02/13/2016 at 3:46 pmHopefully somebody handy with a calculator will try to figure out roughly how much of total world production consists of condensates, natural gas liquids biofuels, etc.... ... ...
Jeffrey J. Brown, 02/13/2016 at 3:54 pm
I'm estimating that global crude oil production* was about 69 million bpd in 2005 and 68 million bpd in 2014. I would assume around 69 million bpd for 2015. Global total liquids production was 85 million bpd in 2005 and apparently about 96 million bpd in 2015.Doug Leighton, 02/13/2016 at 7:27 pmSo, I estimate that actual global crude oil production, as a percentage of total liquids, fell from about 81% in 2005 to about 72% in 2015.
In regard to the US, I estimate that actual crude oil as a percentage of total liquids fell from about 57% in 2005 (4.7/8.3) to about 49% in 2015 (7.3/14.8).
*45 API Gravity & Lower Crude Oil
Mac,likbez , 02/13/2016 at 8:34 pmI was chatting with my Norway niece (Nicole/Nikki) this morning and, I recalled, you were asking about the distinction between "oils" and their relative energy value. Remember, I'm 75 now and the grey cells are evaporating rapidly but we had a decent connection so this is (basically) her comment: all errors mine.
She said that any distinction between oil and condensate is artificial and arbitrary. They're both crude in that compositions are whatever came from the well with no processing other than simple separation. Apparently some oil people simply use five classifications for reservoir fluids: black oil, volatile oil, retrograde gas-condensate, wet gas, and dry gas. And, since most hydrocarbon liquids are close to the (CH2)n formula, the energy content/pound is fairly constant (roughly 17,000 BTU/lb).
Really heavy crudes can be difficult to refine because they're more likely to be contaminated with sulfur and heavy metals that can poison refinery catalysts, they're hard to pump, they can leave fouling on the process equipment, and they need more processing (cracking, reforming, alkylation) to produce light fuels (gasoline, diesel, jet fuel). According to her, the bigger concern would be the percentage of heavy industrial gunk which is useful only for big power plants, ships, and industrial furnaces or even road asphalt.
When she got into C12+ hydrocarbons, aromatics, benzene rings, alkenes and branched isomers I got bored and asked about her new boyfriend. Is that any use?
Doug,Dennis Coyne, 02/13/2016 at 8:35 pmThis actually is a pretty complex topic.
Please note that while the number of BTUs per unit of weight is equal for condensate and oil, the energy content per unit of volume (barrel) is not. It is approximately 12% lower for condensate (on average). So when you measure total production in volume units not weight units, and most of your production is condensate you inflate the amount of energy extracted. With 50/50 mix of oil and condensate the inflation is around 6%. That means that to get proper comparison with, for example, Europeans data where most production is Brent crude or heavier, you need to multiply US data with factor 0.96 or so to equalize the energy content. That also imply that any claim of world petroleum liquids production glut using volume comparison is unscientific. And any claim about "oil glut" which is less then 1% of total volume of petroleum liquids produced (around 1 Mb/d) is pure propaganda.
As Steve from Virginia aptly noted
http://peakoilbarrel.com/opec-january-production/#comment-559218What Jeffrey Brown points out over and over is the so-called 'glut' is simply another finance industry -slash- media narrative, a pleasant lie that glosses over the fact that fuel supply is declining, that purchasing power is declining along with it and that no easy solutions to these declines exist. The only solution is stringent conservation…
Repeating after Steve: "so-called 'glut' is simply another finance industry/media narrative". Or, if you wish, another noble lie in Leo Strauss style. See http://peakoilbarrel.com/collapse-of-shale-gas-production-has-begun/#comment-558479
Looks like the US elite is afraid to go full force into oil conservation mode and was unhappy with "secular stagnation" of the economy. It preferred to drop oil price to solve the problem of "secular stagnation" or at least to postpone the day of reckoning: yet another financial crash which is immanent under neoliberalism, but which might undermine their political power.
Instead, Obama administration adopted Madame de Pompadour "Après nous le deluge" ("after us deluge") mentality…
Also the mix of refined products you get from the unit of weight of each type of oil is different and you can never get even close in the amount of aviation kerosene and diesel from condensate as from WTI or Brent.
See Jeffrey Brown's post about rejection of some blends by US refineries for details.
Hi Doug,Fred Magyar, 02/13/2016 at 8:42 pmThanks that is very useful.
Below I show World liquids consumption in Mb/d and Mboe/d using BP data from the Statistical Review of World Energy.
To find Mboe/d I took world consumption in metric tonnes and assumed 7.33 b per metric tonne. Sorry about the typo on the chart, too late to correct.
We hit the peak in World output per capita in 1979.
When she got into C12+ hydrocarbons, aromatics, benzene rings, alkenes and branched isomers I got bored and asked about her new boyfriend. Is that any use?Watcher, 02/14/2016 at 1:25 amWell, compared to colliding black holes and gravitational waves, and E=MC^2, organic chemistry is pretty cut and dried…
Got a small problem with this.Fernando Leanme, 02/14/2016 at 6:26 amDiesel became used for a reason. Ditto jet fuel. Problems arose that were only solvable by changing to that fuel. There's a sort of overly glib presumption that energy content for condensate is only down and not zero, applied to . . . not a diesel engine but to the problem addressed by the diesel engine.
The volume/weight thing is a pretty big deal, too. Fuel tank capacity is not defined by weight.
Sorry, but Nicole is wrong. Oil is found as a liquid phase fluid in the reservoir, while condensate is found in the gas phase in the reservoir under static conditions. "Some oil people" isn't the right description. Petroleum engineers consider the initial conditions and composition of the hydrocarbon system to define how it would behave under different development and operating schemes. These groupings you listed are a very sensible and technically sound system to describe system behavior as the reservoir is produced.Doug Leighton, 02/14/2016 at 10:14 amFor the non specialist the separation of the crudes by API will do. Use 45 degrees, it seems to do the job. And don't worry too much about the other details. As we can see, even petroleum engineers can get s bit lost in this area, which is mostly the purview of hard core reservoir engineers and process equipment designers.
Nicole responds: "With respect, the term black oil is particularly imprecise and context-dependent; to a reservoir simulation engineer like me, that means the simplifying assumption that the fluid can be characterized by only two components, one of which can exist in only one phase whose properties we can characterize the other component dissolves in that phase; that phase is black as in "black box", not color. Usually the non-partitioning phase is the heavy component (separator oil may contain dissolved gas, but the gas phase contains no oil), but it works the other way, too (separator gas can contain condensate vapor, but condensate can dissolve no gas). When it's applicable, the black-oil assumption saves "lots" of computational effort."Dennis Coyne, 02/14/2016 at 11:09 amThank you Nicole and Doug for the information.Doug Leighton , 02/14/2016 at 12:16 pmIt seems if we are interested in the amount of liquid energy produced in terms of exajoules we would pay attention to the tonnes of liquids produced and just convert to Exajoules.
So for oil consumption data in BP's Statistical Review of World energy we would focus on the data by weight and use a conversion to Joules (or Exajoules).
One billion metric tonnes of oil equivalent are about 41.87 EJ.
Chart below with World Liquids consumption in Exajoules per year using BP Statistical Review of World Energy 2015.
Nicole left for her bi-monthly platform tour so I'll say if you stick to weight when doing your rough oil/condensate energy conversions your numbers will be OK. My Proviso: I'm NOT an oil guy. Don't include NG though, which is mostly methane (22,000 BTU/lb) ????Dennis Coyne, 02/14/2016 at 6:42 pmThanks Doug,Longtimber, 02/14/2016 at 12:59 pmYou know far more than me, just from your conversations with Nicole, and I believe you are also a geophysicist, and have worked in the industry. You may not be up to date on the latest oilfield tech, but you are very knowledgeable nonetheless.
The "liquids" are biofuels, NGL, and C+C in my chart. Methane is not included.
Barrels, BTU's, mcf, CMO, enough dungpiles -- Save us. Remember http://www.theoildrum.com/node/2320.Fernando Leanm, 02/15/2016 at 10:22 am
Real Energy, as in MT, Calories, EJ would be so clear.Nicole is still wrong. She answered the point I made with a rather pedantic point which failed to address my comment: the distinction between oil and condensate is whether they are found in the liquid or gas phase in the reservoir. Condensate is found as a gas in the reservoir. The distinction isn't artificial nor is it arbitrary. She has a bit to learn, probably because she's too much into her specific experience. Comments in a blog have to teach the audience whenever possible. Hers didn't.Doug Leighton , 02/15/2016 at 10:59 amRight, I'll suggest she forgo future comments. Nicole lacks confidence in her English anyway so it won't be difficult to muzzle her.Dennis Coyne, 02/15/2016 at 12:06 pmI disagree.notanoilman, 02/15/2016 at 3:06 amThe important point was energy per unit mass is the same. In Nicolas view if we are concerned about energy just look at mass produced. I agree.
Please keep the comments coming Douglas
Fernando knows more than me but not more than your niece.
I am a little puzzled over condensate. If it exists in the gas phase, in the reservoir with, presumably, high pressure, how does it condense to liquid when extracted and the pressure is reduced? I would have expected the reverse. Am I mis-understanding something, confused or just lost the thread?George Kaplan, 02/15/2016 at 4:04 amNAOM
At high pressures, as found in gas reservoirs, things don't work the same as at atmospheric pressure on the earth's surface. There is a phenomena known as retrograde condensation where as the pressure is reduced at constant temperature, liquid condenses out of the gas (.e. condensate). If the pressure is further reduced then it will start evaporating again (which is what we are used to seeing).Fernando Leanme, 02/15/2016 at 10:27 amIf the gas is cooled at the same time (which happens naturally when gas is let down in pressure with no heat source present, or if it cools from the hotter reservoir to ambient conditions, say in a pipeline) then there is relatively more liquid formed. In the past condensate was sometimes called drip gas as it dripped out of pipelines from a combination of these effects.
http://www.jmcampbell.com/tip-of-the-month/2007/06/why-do-i-care-about-phase-diagrams/
That was a pretty good explanation. Several years ago I had to explain the way this works to my boss, and I resorted to explaining that a multi component system had molecules bouncing around, and that at high pressure we saw the lighter molecules kicking the heavier ones into the gas phase if they ever decided to settle down into a liquid. It worked.George Kaplan , 02/15/2016 at 4:09 amI posted a long explanation that seems to have got lost, so try this:Forbin, 02/15/2016 at 5:36 amhttp://www.jmcampbell.com/tip-of-the-month/2007/06/why-do-i-care-about-phase-diagrams/
because it also hot and will exist as liquid at ambient temperatures.http://www.naturalhub.com/slweb/defin_oil_and_natural_gas.html
forbin
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Feb 12, 2016 | Oilpro
Global Condensate Versus Crude Oil Production EstimatesGlobal dry natural gas production rose from 270 BCF/day in 2005 to 335 BCF/day in 2014. In 2014, combined US + OPEC gas production accounted for 41% of global gas production in 2014.
If the US + OPEC condensate production estimates per BCF of dry gas production are similar to global values, it implies that global condensate production rose from about about 5 million bpd in 2005 to about 10 million bpd in 2014, an increase of about 5 million bpd. Note that global C+C production increased from 74 million bpd in 2005 to 78 million bpd in 2014, an increase of 4 million bpd.
Of course, the foregoing implies that actual global crude oil production (45 API Gravity and lower crude oil) declined from about 69 million bpd in 2005 to about 68 million bpd in 2014, as annual Brent crude oil prices doubled from $55 in 2005 to $110 for 2011 to 2013 inclusive (remaining at $99 in 2014).
Note that the global oil and gas industry spent trillions of dollars on global upstream capex after 2005, for 2006 to 2014 inclusive (on both oil and gas projects). But if it took trillions of dollars to keep us on a post-2005 "Undulating plateau" in actual global crude oil production, what happens to global crude oil production given the large and ongoing cutbacks in global upstream capex?
What's Actually in Those Storage Tanks?
We have seen a large year over year increase in US and global Crude + Condensate (C+C) inventories. For example, EIA data show that US C+C inventories increased by 100 million barrels from late 2014 to late 2015, and this inventory build has contributed significantly to the sharp decline in oil prices.
The question is, what percentage of the increase in US and global C+C inventories consists of condensate?
Four week running average data showed that US net crude oil imports for the last four weeks of December increased from 6.9 million bpd in 2014 to 7.3 million bpd in 2015. Why would US refiners continue to import large–and increasing–volumes of actual crude oil, if they didn't have to, even as we saw a huge build in US C+C inventories? And again, what the EIA calls "Crude oil" is actually C+C. And as noted above, based on the EIA analysis it appears that about 40% of US Lower 48 C+C production in 2015 exceeded the maximum API Gravity for WTI crude oil, 42 API Gravity.
The most recent four week running average EIA data shows US net crude oil imports remained at 7.3 million bpd, with net total liquids imports at 5.5 million bpd, up 17% from the 2015 average annual value of 4.7 million bpd.
I frequently cite a 2015 Reuters article that discussed case histories of refiners increasingly rejecting blends of heavy crude and condensate that technically meet the upper limit for WTI crude (42 API gravity), but that are deficient in distillates. Of course, what the refiners are rejecting is the condensate component, i.e., they are in effect saying that "We don't want any more stinkin' condensate." Following is an excerpt from the article:
U.S. refiners turn to tanker trucks to avoid 'dumbbell' crudes (March, 2015)
In a pressing quest to secure the best possible crude, U.S. refiners are increasingly going straight to the source.
Firms such as Marathon Petroleum Corp and Delek U.S. Holdings are buying up tanker trucks and extending local pipeline networks in order to get more oil directly from the wellhead, seeking to cut back on blended crude cocktails they say can leave a foul aftertaste. . . .
Many executives say that the crude oil blends being created in Cushing are often substandard approximations of West Texas Intermediate (WTI), the longstanding U.S. benchmark familiar to, and favored by, many refiners in the region.
Typical light-sweet WTI crude has an API gravity of about 38 to 40. Condensate, or super-light crude that is abundant in most U.S. shale patches, ranges from 45 to 60 or higher. Western Canadian Select, itself a blend, is about 20.
While the blends of these crudes may technically meet the API gravity ceiling of 42 at Cushing, industry players say the mixes can be inconsistent in makeup and generate less income because the most desirable stuff is often missing.
My premise is that US (and perhaps global) refiners hit - late in 2014 - the upper limit of the volume of condensate that they could process if they wanted to maintain their distillate and heavier output. This resulted in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C inventories.
Therefore, in my opinion the US and (and perhaps global) C+C inventory data are fundamentally flawed when it comes to actual crude oil inventory data. Note that according to Iranian sources, the bulk of their floating offshore storage consists of condensate, which they were permitted to export under the sanctions. In my opinion, this suggests that we may be seeing both a US and a global glut of condensate in storage.
In any case, here is the critical point: If it took trillions of dollars to keep us on a post-2005 "Undulating plateau" in actual global crude oil production, what happens to global crude oil production given the large and ongoing cutbacks in global upstream capex?
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Daniel , 02/12/2016 at 7:44 am
Not sure how reliable this is, but drillinginfo index has the "new US production capacity" (oil and gas) dropping by 24% from January to February; which would be biggest drop since the collapse of the oilpriceRon Patterson . 02/12/2016 at 8:44 amThis headline shocked me: The Oil Industry Got Together and Agreed Things May Never Get BetterSW , 02/12/2016 at 9:10 amThousands of industry participants gathered in London for their annual get-together, only to find a world awash in crude and hardly a life jacket in sight.
The thousands of attendees seeking reasons for optimism didn't find them at the annual International Petroleum Week . Instead they were greeted by a cacophony of voices from some of the largest oil producers, refiners and traders delivering the same message:
There are few reasons for optimism. The world is awash with oil. The market is overwhelmingly bearish.
No Hope
Producers are bracing for a tough year. Prices will stay low for up to a decade as Chinese economic growth slows and the U.S. shale industry acts as a cap on any rally, according to Ian Taylor, chief executive officer of Vitol Group, the world's largest independent oil trader. Even refiners, whose profits have held up better than expected, are seeing a worsening outlook.
Perhaps their only hope is depletion?likbez , 02/12/2016 at 1:51 pmIs not Bloomberg simply a GS propaganda arm ?Jeffrey J. Brown , 02/12/2016 at 9:41 amI especially enjoyed the following statement
"As the world runs out of places to store oil, "I wouldn't be surprised if this market goes into the teens," said Jeff Currie, head of commodities research at Goldman Sachs Group Inc."
I think there should be is a special place in hell for Goldman commodity traders.
IMO, the global oversupply is a house of cards built on an unstable foundation of actual global crude oil production* that requires massive capital investments to keep crude oil production from crashing.Doug Leighton , 02/12/2016 at 10:00 amQatar is basically the poster child for post-2005 production. OPEC 12 data show that Qatar's reported crude oil production, despite billions of dollars spent on enhanced oil recovery, fell from 0.8 million bpd in 2005 to 0.7 million bpd in 2014 (OPEC crude only data), while EIA data show that Qatar's C+C production increased from 1.0 million bpd in 2005 to 1.5 million bpd in 2014.
Production of condensates rising in Qatar http://www.oxfordbusinessgroup.com/analysis/production-condensates-rising-qatar
*45 API Gravity and lower crude oil
Jeffrey J. Brown , 02/12/2016 at 10:32 am"IMO, the global oversupply is a house of cards built on an unstable foundation of actual global crude oil production* that requires massive levels of investments to keep crude oil production from crashing."Please provide a scale Jeff. Not that I don't agree with you; my buddy (petroleum engineer) who works in Kuwait from time-to-time insists their production rate is maintained by massive infill drilling BUT how long will the party last: a decade? Longer? Shorter?
I would think the second half of 2016 for a price recovery, but I thought we were in a price recovery phase this time last year. As for the duration of a price recovery, I don't have the foggiest.Ron Patterson , 02/12/2016 at 11:16 amAs an example of low probability events, two years ago if someone had asked us what we thought the chances were that Donald Trump, in early 2016, would be the most likely GOP nominee, and that oil prices would be in the 20's to low 30's, I wonder what we would have said.
Incidentally as noted up the thread, an interesting difference between the last oil price decline and the current (much more protracted) decline: Global liquids consumption fell by 2 million bpd from 2007 to 2009, whereas global liquids production reportedly rose by 3 million bpd from 2013 to 2015.
my buddy (petroleum engineer) who works in Kuwait from time-to-time insists their production rate is maintained by massive infill drilling…That is what is keeping two thirds of the world's oil fields from a 5 to 6 percent decline rate. Massive infill drilling is happening in Kuwait, Saudi, the UAE, Russia, the Gulf of Mexico and just about everywhere else in the world.
Normally the production profile of a field would resemble a bell curve with the top of the curve being the 50% depletion point. But with massive infill drilling, the top of the bell just levels out with only a slight decline, if any. But the depletion curve, if you could see it, would be dropping like a rock.
What infill drilling does is delay the decline curve until it too starts dropping like a rock.
BUT how long will the party last: a decade? Longer? Shorter?
My guess is about a decade. Saudi began their infill drilling projects over a decade ago and I believe the fields where this began is already dropping fast. But they have managed to keep production up by bringing on three giant fields, Khurais, Manifa and Shaybah.
But it depends entirely on the size of the field. Giant and super giant fields can maintain infill drilling and keep production up much longer than smaller fields, like those in the GOM.
But Kuwait's production has already started to drop and UAE production is just on the cusp. Russia also has, for almost a decade, had a program of massive infill drilling in their Western Siberia fields where about 60% of their oil is produced.
And folks wonder why I think peak oil is at hand. Geeze, isn't it obvious?
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crudeoilpeak.info
This recent forum was about how to transition away from fossil fuels, after the UN conference on climate change in Paris in November 2015. Moderator Yergin – who is a known peak oil denier – started by asking Fatih Birol what low oil and gas prices mean for the development of renewable energies. Fatih responded by first warning about the impact of lower oil prices on investments in the oil and gas sector:
(video 3:24)
Fatih Birol: "For the oil markets what worries me the most is that: last year we have seen oil investments in 2015 decline more than 20%, compared to 2014, for the new projects. And this was the largest drop we have ever seen in the history of oil. And, moreover, in 2016, this year, with the $30 price environment, we expect an additional 16% decline in the oil projects, investments. So, we have never seen 2 years in a row oil investments declining. If there was a decline 1 year, which was very rare, the next year there was a rebound"Daniel Yergin: "What does that lead you to?"
Fatih Birol: "this leads me to the very fact that in a few years of time, when the global demand gets a bit stronger, when we see that the high cost areas such as the United States start to decline, we may well see and upward pressure on the prices as a result of market tightness. So my message, my 1st message is: don't be misled that the low oil prices will have an impact on the oil prices in the market in a few years' time"
Daniel Yergin: "Just to put a number on that. Our numbers at IHS, 2015-2020 we see a 1.8 trillion dollar decline in upstream oil and gas investment"
... ... ...
The graph shows that conventional crude oil production is supposed to be basically flat. This is designed by adjusting the yet-to-be-found wedge. Unconventional tight (shale) oil and heavy oil/bitumen increase only slightly up to 2020. NGLs go up but these don't play a big role for transport fuels (except LPG).
If 80% of investments are needed just to offset decline, then the additional 2016 drop leads to such a low investment level that yet-to-be-developed projects are in danger, not to mention the assumed production from yet-to-be-found fields. An example of the latter is Shell ending its exploration in the Chukchi sea.
ConclusionChanges in investment projections were already underway before the 2014 oil price drop. To the extent that oversupply of US shale oil (including condensate filling up US inventories) has contributed to currently low oil prices, the drama evolving now is that unconventional oil – which was originally intended to be added to stagnating conventional supplies in the 1st phase of peaking oil production (2005-2008) – is now endangering this much larger conventional base production, including higher cost offshore fields.
Even if oil prices go up again US shale oil has already destabilized global oil markets by increasing volatility. Is that what we call a swing producer? Yes, swinging oil prices and investments. And for those who hope that oil markets will "rebalance" at $60-$70 there is no statistical evidence in the last 10 years that oil prices stayed for very long at these levels.
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peakoilbarrel.com
Doug Leighton , 02/09/2016 at 12:03 pm
OIL PRICE RECOVERY WILL BE SHORT-LIVED, SAYS IEAdaniel , 02/09/2016 at 12:41 pm"A recent rise in oil prices is a "false dawn" and the oversupply of crude is set to worsen, according to the International Energy Agency (IEA)….
The IEA forecast that stock building could continue in the second half of 2016 at a rate of 300 million barrels a day. It said: If these numbers prove to be accurate, and with the market already awash in oil, it is very hard to see how oil prices can rise significantly in the short term."
300 mm bbp per day – wow :-)Watcher, 02/09/2016 at 1:04 pmThis is what happens when a theory is accepted as fact.If there's too much oversupply for storage to exist, well then, the oversupply must have been less than thought. In fact, find how much storage capacity there is, and essentially manufacture that number too, and then derive backwards how much is required to fill it, and then subtract another essentially imaginary number as to how much of the capacity was already filled on some arbitrary date - and you can declare how much oversupply "there must be".
They would be laughed out of the room at any physics seminar.
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U.S. Energy Information Administration
- North Sea Brent crude oil prices averaged $31/barrel (b) in January, a $7/b decrease from December and the lowest monthly average price since December 2003. Brent crude oil prices averaged $52/b in 2015, down $47/b from the average in 2014. Growth in global liquids inventories, which averaged 1.8 million barrels per day (b/d) in 2015, continues to put downward pressure on Brent prices.
- Brent crude oil prices are forecast to average $38/b in 2016 and $50/b in 2017. Forecast West Texas Intermediate (WTI) crude oil prices are expected to average the same as Brent in both years. However, the current values of futures and options contracts continue to suggest high uncertainty in the price outlook. For example, EIA's forecast for the average WTI price in May 2016 of $36/b should be considered in the context of recent Nymex contract values for May 2016 delivery (Market Prices and Uncertainty Report) suggesting that the market expects WTI prices to range from $21/b to $58/b (at the 95% confidence interval).
- The U.S. retail regular gasoline price is forecast to average $1.98/gallon (gal) in 2016 and $2.21/gal in 2017, compared with $2.43/gal in 2015. In January, the average retail regular gasoline price was $1.95/gal, a decrease of 9 cents/gal from December and the first time monthly gasoline prices averaged below $2/gal since March 2009. EIA expects the monthly average retail price of U.S. regular gasoline to reach a seven-year low of $1.82/gal in February 2016, before rising during the spring.
- U.S. crude oil production averaged an estimated 9.4 million b/d in 2015, and it is forecast to average 8.7 million b/d in 2016 and 8.5 million b/d in 2017. EIA estimates that crude oil production in January was 70,000 b/d below the December level, which was 9.2 million b/d.
- Natural gas working inventories were 2,934 billion cubic feet (Bcf) on January 29, 20% higher than during the same week last year and 18% higher than the previous five-year average (2011-15) for that week. EIA forecasts that inventories will end the winter heating season (March 31) at 2,096 Bcf, which would be 41% above the level at the same time last year. Henry Hub spot prices are forecast to average $2.64/million British thermal units (MMBtu) in 2016 and $3.22/MMBtu in 2017, compared with an average of $2.63/MMBtu in 2015.
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www.iea.org
Price forecast:
2014 2015 2016 projected 2017 projected WTI Crude Oila (dollars per barrel) 93.17 48.67 37.59 50.00
Having peaked, at a five-year high of 1.6 million barrels per day (mb/d) in 2015, global oil demand growth is forecast to ease back considerably in 2016, to 1.2 mb/d, pulled down by notable slowdowns in Europe, China and the United States, the newly released IEA Oil Market Report (OMR) for February informs subscribers. Early elements of the projected slowdown surfaced in the last quarter of 2015.
Global oil supply dropped 0.2 mb/d to 96.5 mb/d in January, as higher OPEC output only partly offset lower non-OPEC production. Non-OPEC supplies slipped 0.5 mb/d from a month earlier to stand close to levels of a year ago. For 2016 as a whole, non-OPEC output is expected to decline by 0.6 mb/d, to 57.1 mb/d.
OPEC crude oil output rose by 280 000 barrels per day in January to 32.63 mb/d as Saudi Arabia, Iraq and a sanctions-free Iran all turned up the taps. Supplies from the group during January stood nearly 1.7 mb/d higher year-on-year.
OECD commercial stocks built counterseasonally by 7.6 mb in December to stand at 3 012 mb at month end, 350 mb above average. Refined products covered 32.3 days of forward demand, 0.1 day above the level at end-November. Preliminary information indicates that inventories have continued building into January.
Global refinery runs fell by 1.3 mb/d in January to 79.8 mb/d, as the onset of seasonal maintenance in the United States and weakening refinery margins curbed runs. Global throughputs nevertheless stood more than 1.7 mb/d above a year earlier, with gains particularly strong in the United States and the Middle East.
Global Crude Oil Prices
Brent crude oil spot prices decreased by $7/b in January to a monthly average of $31/b, the lowest monthly average price since December 2003. Ongoing growth in global oil inventories and uncertainty over future global demand growth continued to put downward pressure on oil prices during January. After growing by an estimated 1.8 million b/d in 2015, global oil inventories are forecast to grow by 1.4 million b/d in the first quarter of 2016.
During January, daily changes in crude oil prices were highly correlated with daily changes in global equity indexes. The increased co-movement and higher volatility likely reflect increased uncertainty about future global economic growth. Changes in overall demand for risk assets, such as commodities and equities, by investors and market participants may also be playing a larger role in price discovery across global asset markets compared with previous months.
With global oil inventory builds expected to continue in 2016, upward pressure on crude oil prices will be limited. Forecast Brent prices will average $38/b in 2016, $3/b lower than forecast in last month's STEO. The largest inventory builds occur in the first half of 2016, helping keep Brent prices below $40/b through August.
Brent prices are forecast to average $50/b in 2017, with upward price pressure concentrated later in that year. At that point, the market is expected to experience small inventory draws, with the possibility of further draws beyond the forecast period. Brent prices are forecast to average $56/b in the fourth quarter of 2017.
Forecast West Texas Intermediate (WTI) crude oil prices average the same as Brent crude oil prices through the forecast period, compared with $2/b lower than Brent in 2016 and $3/b lower in 2017 in the prior STEO. The price parity of WTI with Brent in the forecast period is based on the assumption of competition between the two crudes in the U.S. Gulf Coast refinery market, as transportation differentials are similar to move the crudes from their respective pricing points to that market.
The current values of futures and options contracts continue to suggest both heightened volatility and high uncertainty in the price outlook (Market Prices and Uncertainty Report). WTI futures contracts for May 2016 delivery, traded during the five-day period ending February 4, averaged $35/b, while implied volatility averaged 57%. These levels established the lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in May 2016 at $21/b and $58/b, respectively. The 95% confidence interval for market expectations widens over time, with lower and upper limits of $19/b and $85/b for prices in December 2016. At this time last year, WTI for May 2015 delivery averaged $52/b, and implied volatility averaged 52%. The corresponding lower and upper limits of the 95% confidence interval were $33/b and $81/b.
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peakoilbarrel.com
Jeffrey J. Brown, 02/08/2016 at 9:27 amHere's the link to the EIA's Annual (US) Energy Review data, through 12/15:http://www.eia.gov/totalenergy/data/monthly/pdf/sec3_3.pdf
Note that total product supplied for 2015, 19.5 million bpd, was up by a million bpd from 2012 and it was the highest since 2008 (also 19.5 million bpd).
Annual total liquids net imports were down year over year, from 2014 to 2015, but monthly total liquids net imports were up from 4.5 million bpd in 12/14 to 5.1 million bpd in 12/15 (as we saw a 100 million barrel increase in US C+C inventories).
US net crude oil imports rose from 6.9 million bpd at the end of 2014 (four week running average data) to 7.3 million bpd at the end of 12/15.
Here's a link to the most recent four week running average Weekly Supply Data (ending 1/29/16):
http://www.eia.gov/dnav/pet/pet_sum_sndw_dcus_nus_4.htm
Based on the four week running average weekly data (through end of January, 2016), total product supplied was up to 19.7 million bpd, and the pattern of increasing net imports continued. Net crude oil imports were up to 7.5 million bpd, and total liquids net imports were up to 5.7 million bpd.
In other words, it would appear that the US is becoming increasingly dependent on imported oil, especially imports of actual crude oil, as total product supplied last year was at a seven year high.
As I have occasionally opined, I suspect that US refiners (and perhaps global refiners too) in late 2014 hit the upper limit of how much additional condensate that they could process, if they wanted to maintain their output of distillates and of heavier products.
And I suspect that much, if not all, of the build in US and global C+C inventories in 2015 consisted of condensate. Therefore, IMO, oil traders are acting on fundamentally flawed data when it comes to the inventories of the product that actually corresponds to the price indexes, i.e., WTI and Brent crude oil.
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peakoilbarrel.com
Jeffrey J. Brown, 02/05/2016 at 10:16 amOf course, the big production decline will come from investments not made. However, as I have once, or twice, or thrice noted, it seems very likely that despite trillions of dollars in upstream (oil & gas) global capex since 2005, we have seen little or no increase in actual global crude oil production (45 API and lower crude).An except from a memo I'm preparing for some industry guys:
Perpetually Low Oil Prices Versus The Laws of Physics
Some of you may recall the Economist Magazine cover story, published in early 1999, which predicted–because of advances in technology and productivity gains (sound familiar?)–that we were looking at an extended long term period with oil prices in the $5 to $10 range.
While I suppose it's possible that this time the conventional wisdom is right, i.e., that we are looking at perpetually low oil prices, my bet is that the laws of physics will prevail, especially in regard to the high, and rising, rates of decline in existing US oil & gas production.
In any case, here is an excerpt from the March, 1999 Economist Magazine cover story on oil prices:
Here is a thought: $10 might actually be too optimistic. We may be heading for $5. Thanks to new technology and productivity gains, you might expect the price of oil, like that of most other commodities, to fall slowly over the years. Judging by the oil market in the pre-OPEC era, a "normal" market price might now be in the $5-10 range. Factor in the current slow growth of the world economy and the normal price drops to the bottom of that range.
Enclosed is a chart* showing constant dollar monthly WTI Crude oil prices, in 2016 dollars. Note that the March, 1999 Economist Magazine article corresponded pretty much to the all time record low constant dollar oil price for the past 40 years.
I think that I have made a strong case that the trillions of dollars spent on upstream global oil & gas capex since 2005 have only been sufficient to keep us on an undulating plateau in actual global crude oil production (45 API Gravity and lower crude oil), and because of the large and ongoing declines in global upstream capex, even the Wall Street Journal is expressing concerns about a future oil price spike, as supply falls.
The Cornucopian Crowd, which is basically making the same argument as the Economist Magazine writer in 1999, is arguing that advances in technology have indefinitely postponed any kind of production peak to the distant future.
I think that the reality is much more prosaic.
In my opinion, the reality is that global crude oil production has probably effectively peaked, while global natural gas production and associated liquids (condensate and natural gas liquids) have so far continued to increase.
Furthermore, I suspect that all, or virtually all, of the large build in US (and probably global) Crude + Condensate (C+C) inventories in 2015 consists of condensate, and therefore oil traders are trading on fundamentally flawed data when it comes to the inventories of the product that actually correspond to the index prices.
In the case of WTI (light/sweet) crude oil contracts, the maximum API gravity is 42, and recent EIA data suggest that about 40% of US Lower 48 C+C production in 2015 exceeded the maximum API limit for WTI crude oil, i.e., 42 API Gravity.
Last year, Reuters ran a story about US refiners increasingly rejecting "foul" blends of heavy crude and condensate that technically fell below the upper API limit for WTI crude oil, but that were deficient in distillate content.
In my opinion, these two items, i.e., the estimate that about 40% of US Lower 48 C+C production exceeded the maximum API Gravity limit for WTI crude oil in 2015 and case histories of US refiners increasingly rejecting blends of heavy crude and condensate, go a long way toward explaining why US refiners increased their net oil imports (from 12/14 to 12/15) as we saw 100 million barrel build in US C+C inventories from late 2014 to late 2015.
Furthermore, Iranian sources claim that the majority of their floating storage consists of condensate, which they were permitted to export under the sanctions. This of course suggests that we might be seeing both a US and a global oversupply of condensate–but not necessarily of actual crude oil (less than 45 API gravity crude oil).
*Prepared by AlexS
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peakoilbarrel.com
Watcher, 02/05/2016 at 2:03 pmUseful to remember that accuracy is not the goal of reports reported by . . . almost anyone. If a study says something that suggests a client company is going to be destroyed, do you really think such a study is going to see the light of day? That's like expecting a management consultant to come in and tell management they are incompetent.No more contracts for that consultant.
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Peak Oil News and Message Boards
shortonoil on Thu, 4th Feb 2016 4:18 pm"A deal is not only "highly unlikely," in the estimation of Goldman Sachs, but "self-defeating" for the Saudis. By cutting production now and boosting prices, Saudi Arabia would effectively bail out U.S. shale producers just as the Saudi strategy of keeping prices low to squeeze them out of the market is beginning to work, Goldman's Jeff Currie argues."
The media puts forth a continuous stream of completely unadulterated crap to its readership. Saudi Arabia is not going to spend $175 billion per year to put out of business producers that produce an entirely different product, and which sells to an entirely different market. LTO is as much like Saudi crude as Shetland Ponies are to an Arabian race horses. The similarities stop at horse.
LTO is a very light hydrocarbon that is used as a diluent, and feed stock. Its API is > 45. It is used to thin heavier hydrocarbons like Canadian bitumen to allow it to be transported by pipe. It is used as a feedstock to make hundreds of different products from paint to plastic pipe.
Saudi's light sweet crude has an API 45, and the heavier ones, API < 40, deliver entirely different products as show in the graph below:
Saudi's light sweet crude, and LTO are entirely different products that sell to entirely different markets. Saudi's crude is no competition to LTO and LTO is no competition for Saudi's crude.
Goldman Sachs is an unscrupulous pack of thieves who have no qualms about lying to their clients, or the public if it serves their purposes. They, and others in the shale financing business will continue to push the Saudi/ US LTO myth for as long as they can find investors that are credulous enough to believe them.
makati1 on Thu, 4th Feb 2016 7:59 pm
Some see only what they want to see. Others see the whole forest. Bloomberg and Goldman are both habitual liars and thieves. Goldman says it and Bloomberg backs it up, as if either have any credibility left.
Short has it correct. All you see in the US MSM is bullshit in ever higher and smellier piles. As we approach the end, the cries will be louder, shriller and continuous. Wait and see.
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peakoilbarrel.com
The IEA Oil Market Report, full issue, is now available to the public. Some interesting observations:Non-OPEC oil supplies are nevertheless seen sharply lower in December. Overall supplies are estimated to have slipped by more than 0.6 mb/d from the month prior, to 57.4 mb/d. A seasonal decline in biofuel production, largely due to the Brazilian sugar cane harvest, of nearly 0.4 mb/d was the largest contributor to December's drop. Production in Vietnam, Kazakhstan, Azerbaijan and the US was also seen easing from both November's level and compared with a year earlier. Persistently low production in Mexico and Yemen were other contributors to the year-on-year decline.As such, total non-OPEC liquids output slipped below the year earlier level for the first time since September 2012. A production surge in December 2014 inflates the annual decline rate, but the drop is nevertheless significant should these estimates be confirmed by firm data. Already in November, growth in non-OPEC supply had slipped to 640 kb/d, from as much as 2.9 mb/d at the end of 2014, and 2.4 mb/d for 2014 as a whole. For 2015, supplies look likely to post an increase of 1.4 mb/d for the year, before contracting by nearly 0.6 mb/d in 2016. A prolonged period of oil at sub-$30/bbl puts additional volumes at risk of shut in as realised prices fall close to operating costs for some producers.
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peakoilbarrel.com
Fernando Leanm, 02/04/2016 at 9:34 amThey insist on lumping biofuels with crude oil etc. I would call them the Energy Disinformation Agency.AlexS, 02/04/2016 at 4:22 pmFernando,Fernando Leanm, 02/05/2016 at 6:47 amThey include separate numbers for biofuels production and refinery processing gains
Alex, they lump everything in the discussions and most tables intended for public distribution. I spend a lot of time explaining to people their graphs and most data tables are covering up what happens to crude oil and condensate. I consider their practices to be deceitful.shortonoil on Thu, 4th Feb 2016 2:27 pm
Some of this data looks very anomalous. For instance, if one looks at the US rig count vs Us C+C production between June '09 and Sept '11, rig count increased by 800 or 500%.
During that same period US C+C production stayed flat.
What were these guys doing, playing poker for 26 months? From spud to IP was no more than 8 months even back in the dark ages (2009) of shale production.
Assuming 4 wells per year per rig that would have been about 1500 new wells.
The decline rate of conventional US wells was probably about 5% or 250,000 b/d per year. Without some kind of explanation it is hard to take this data seriously.
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OilVoice
The changes can be very big. Look at the line that comes to a halt in April 2015, these are the numbers from the May 2015 Short Term Energy Outlook, those estimates were about 340,000 bbls per day less than what the EIA now think. About as much as people are estimating Iran might be able to add to the market and which is now causing fear and trepidation amongst oil bulls. On that point I am a tad sceptical, not having been born under a gooseberry tree.
The same then happened on the way down. As the oil price collapsed and rigs were stacked, it seemed in September that the decline was well established and that the US would soon be producing less than 9 million barrels per day. I confidently tweeted that projection, but I was dead wrong. Month after month the previous estimates were raised and the impending collapse was deferred. This continued right up to the last estimate of historic monthly production, published at the end of December, and used in the January 2016 Short Term Energy Outlook, the pale blue line on the graph. At that time, virtually the whole of 2015 was revised upwards by nearly 100,000 bbls per day.
But on the 27th January the EIA published a revision to the numbers (which will be used in the February 2016 STEO) which bucked that trend and started to revise the past downwards. That is the dark blue line on the chart, which tracks the pale blue line for most of the year but includes a 140,000 bbls per day reduction in the estimate of November 2015 production.
We can be confident of one thing the revisions to the past aren't finished, and given the dramatic fall in the oil price from November to January, and the drastic cuts in US operators budgets for 2016 it seems to me that US production will soon decline below 9 million barrels per day, my estimate is that that threshold will be crossed in February and that the US will exit 2016 producing about 8.4 mmbbls/day.
But take that all with a pinch of salt. It is hard enough estimating the past let alone, predicting the future.
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peakoilbarrel.com
Ron Patterson , 02/02/2016 at 8:34 am
Crude oil peaked ~2005: ExxonMobilJeffrey J. Brown , 02/02/2016 at 8:59 amDavid Hagen has posted a great commentary on ExxonMobil's The Outlook for Energy: A View to 2040
ExxonMobil released its 2016 Outlook for Energy: A View to 2040. Buried on page 62, its Liquids Outlook by Type clearly shows conventional crude oil ("Crude + Condensate") peaked about 2005. Global conventional oil ("Crude + Condensate") declines through 2040. ExxonMobil asserts "Growth comes mostly from non-conventional supply" but actually shows declining conventional supply – even after including "Deepwater" production.
Only increasing use of higher priced Nonconventional hydrocarbons shows some global growth – but much lower than historical growth. Only by adding Bitumen (aka "Oil Sands"),"tight oil", natural gas liquids (NGL), "other" and biofuels does ExxonMobil project about 20% total growth over 25 years (from the current 93 million bbl/day to about 112 million bbl/day.)
I think ExxonMobil's estimate of future tight oil production is way overly optimistic. But not nearly as overly optimistic as their estimate of "new conventional crude and condensate development".
Here's a somewhat different approach to my attempts, using available data, to differentiate between actual crude oil, generally defined as 45 API Gravity and lower crude oil, from condensate, generally defined as Crude + Condensate (C+C) with an API Gravity greater than 45.Jeffrey J. Brown , 02/02/2016 at 10:12 amSince condensate, like Natural Gas Liquids (NGL), is a byproduct of natural gas production, it occurred to me that what is important is the estimated condensate yield per BCF of global dry natural gas production.
US & OPEC 12 Condensate Production Estimates as Indicators of Global Condensate Production, 2005 to 2014
Natural Gas Data
US Natural Gas Production (BP):
2005: 50 BCF/day
2012: 71 BCF/dayOPEC 12 Natural Gas Production (BP):
2005: 42 BCF/day
2014: 68 BCF/dayUS + OPEC 12 Natural Gas Production (BP):
2005: 92 BCF/day
2014: 139 BCFdayGlobal Natural Gas Production (BP):
2005: 270 BCF/day
2014: 335 BCF/dayCondensate Data & Estimates
Implied OPEC 12 Condensate Production
(EIA OPEC 12 C+C less OPEC Crude Only)
2005: 1.2 million bpd
2014: 2.4 million bpdEstimated US Condensate Production (45+ API Gravity C+C Production)
2005: 0.5 million bpd
2014: 1.7 million bpd
(EIA puts US Lower 48 45+ API C+C production at 2 million bpd in 2015, and they estimated that US 45+ API Gravity C+C production increased by about one million bpd from 2011 to 2014)Implied OPEC 12 Condensate + Estimated US Condensate Production
2005: 1.7 million bpd
2014: 4.1 million bpdOPEC 12 + US Condensate Estimates Per BCF of Dry Gas Production
2005: 18,000 barrels/BCF
2014: 29,000 barrels/BCF
(In terms of gallons of condensate per MCF of dry gas, it would be 0.8 gallons/MCF in 2005, rising to 1.2 gallons per MCF in 2014, if my math is correct.)Condensate, like natural gas liquids, is a byproduct of natural gas production. The US and OPEC 12 countries accounted for 41% of global dry gas production in 2014.
If US + OPEC 12 estimated condensate production numbers per BCF of dry gas production from 2005 to 2014 are approximately indicative of world trends, estimated global condensate production in 2005 would be 4.9 million bpd (rounded off to 5 million bpd), and estimated global condensate production in 2014 would be 9.7 million bpd (rounded off to 10 million bpd), an estimated increase of about 5 million bpd in global condensate production from 2005 to 2014.
Note that the increase in global C+C production from 2005 to 2014 was 4 million bpd (74 to 78 million bpd, rounded off to the nearest one million bpd).
The foregoing analysis would of course suggest that actual global crude oil production (45 API and lower gravity crude oil) was down slightly from 2005 to 2014, down from about 69 million bpd in 2005 to about 68 million bpd in 2014–as annual Brent crude oil prices doubled from $55 in 2005 to $110 for 2011 to 2013 inclusive, remaining at $99 in 2014.
Note that I am estimating that US + OPEC 12 condensate production increased by about 2.4 million bpd from 2005 to 2014 (from 1.7 to 4.1 million bpd), with an estimated condensate yield of about 18,000 barrels per BCF of dry gas in 2005 and 29,000 barrels per BCF of dry gas in 2014 (note that the condensate yield per BCF of wet gas would of course be lower).likbez , 02/02/2016 at 1:19 pmIn any case, if the condensate yield for non-US + non-OPEC gas was the 18,000 barrels per BCF in 2005, but only rose to 24,000 barrels per BCF in 2014 (versus 29,000 barrels per BCF for US + OPEC), non-US + non-OPEC condensate production would have increased from about 3.2 million bpd in 2005 to about 4.7 million bpd in 2014 (again, if my math is correct).
Based on the foregoing scenario, total global condensate production would have increased from about 4.9 million bpd in 2005 (call it 5 million bpd) to about 8.8 million bpd in 2014 (call it 9 million bpd), in implied increase of 4 million bpd, which would of course mean that rising condensate production accounted for virtually all of the 2005 to 2014 increase in global C+C production.
In any case, note that the doubling in annual Brent crude oil prices from $55 in 2005 to $110 for 2011 to 2013 inclusive (remaining at $99 in 2014) provided an enormous incentive for global oil and gas producers to increase their liquids production, wherever and however they could. My principal point is that the available data strongly suggest that they weren't able to show a material increase in actual global crude oil production (45 API and lower gravity crude oil)–despite trillions of dollars spent post-2005 on global upstream oil and gas projects, Qater being a perfect example.
Jeffrey,Here is another argument supporting your position about distinguishing crude and condensate. They really should be reported separately in oil production statistics.
Condensate energy content per unit of volume is less that oil as API gravity is an inverse measure of a petroleum liquid's density relative to that of water.
In other words a barrel of, say, 60 API condensate (average of a typical 45-75 range) has less energy (in BTU) than a barrel of 39.6 API oil (WTI). Using standard formula for number of barrels in metric ton (API+131.5)/(141.5*0.159) we will get 8.5 barrels and 7.6 barrels per metric ton, respectively.
As the amount of BTUs per unit of weight is probably close to constant that means that energy-wise condensate with API 60 contains approximately 12% less of energy then oil with API 40.
In other words, mixing them in statistics inflates the total amount of energy produced. If uniform statistics is desirable they should be counted using factor 0.9. This recalculation will make peak oil phenomenon more visible in all graphs of world and countries production.
That also mean that countries and agencies reporting production in metric tons are doing better job then countries reporting production in volume measures such as barrels. In other words EIA sucks :-)
Jeffrey J. Brown , 02/02/2016 at 9:17 am
Here is an interesting article, I think that was published in 2015, on crude oil versus condensate production in Qatar (of course, Qater is a member of OPEC). As I have previously discussed, the crude oil versus condensate quality issue is not my principal point.My principal point is that the available data strongly suggest that actual global crude oil production has been on an "Undulating Plateau" since 2005, while global natural gas production and associated liquids, condensate and NGL, have so far continued to increase.
Note that the OPEC 12 data that Ron compiled for me show that Qatar's reported crude oil production fell from 0.8 million bpd in 2005 to 0.7 million bpd in 2014 (OPEC crude only data), while EIA data show that Qatar's C+C production increased from 1.0 million bpd in 2005 to 1.5 million bpd in 2014.
Production of condensates rising in Qatar
http://www.oxfordbusinessgroup.com/analysis/production-condensates-rising-qatarThe global market is far more competitive these days, and 2014 saw a dramatic decline in oil prices, which continued into 2015. In March 2015 Brent Crude was retailing at $57 per barrel. Behind this is a global oversupply – Bloomberg reported that the UAE and Qatar estimated this to be in the region of 2m barrels per day (bpd) in mid-January 2015. This is primarily the result of surging US output, which was at a three-decade high. However, this output seems likely to taper off, as falling prices make some of the fracking on which US production is based no longer economically feasible. Furthermore, in 2014 Washington decided to allow exports of condensates for the first time – oil exports having been banned since the 1970s oil crisis. Thus, the global condensates market is also seeing a major supply surge, with press reports suggesting that the US could add up to 1m bpd of these light oils to the export market during the next 10 years. This is particularly relevant to Qatar, as condensates have come to represent a larger proportion of the state's output than crude.
DEPLETION OF RESERVES: This has been for two main reasons. First, there is the depletion of existing oilfields. Qatar Petroleum's (QP's) Dukhan field, the oldest, sent out its first export cargo in 1939, although it remains one of the two largest fields in the country, along with Maersk Oil's Al Shaheen. Qatar National Bank (QNB) figures show that total output has declined continuously in recent years, from a peak of 845,000 bpd in 2007 to 733,000 bpd in 2010, 724,000 bpd in 2013 and 681,000 bpd in November 2014.
This is despite major investment in enhanced oil recovery (EOR). Some $6.6bn has been invested in crude oil projects under Qatar's 2010-14 development plan, with much of this going into EOR. At the same time, reports in local media state that Occidental is investing $3bn in water injection to sustain production at the Idd Al Sharqi field, while ExxonMobil has made further investments in Dukhan. Indeed, most of the investments currently ongoing in the oilfields are of this kind, with the aim of maintaining and stabilising production.
"Our overall objective for the field is more to minimise production decline," Guillaume Chalmin, the managing director and group representative of Total E&P Qatar, told OBG, referring to his group's Al Khalij field. "This takes priority over increasing production."
. . . . CONDENSATES: The second factor affecting the condensates/crude balance is the huge North Field, and the consequent expansion of natural gas output in the country. This has led to a surge in the production of condensates on the back of new wells and projects aimed at feeding Qatar's liquefied natural gas and gas-to-liquids sectors. Indeed, if the QNB figure of 724,000 bpd of crude is compared with the BP figure of 1.995m bpd of total oil production – which includes crude oil, light oil (from condensates), oil sands and natural gas liquids – then condensates are likely responsible for over 1m bpd of Qatar's oil production. QNB figures quoted by Business Quartermagazine in 2013 stated that while crude oil reserves were an estimated 2.3bn barrels in 2011, condensate reserves were an estimated 22.3bn barrels, with condensate production exceeding crude oil production in 2012, when it hit 900,000 bpd. . . .
HIGH-VALUE PRODUCTS: Condensates are hydrocarbons that exist in a gaseous state underground, but which liquefy during the production process. They are thus a low-density mixture of hydrocarbons and come from both oil wells, as associated gas, and from natural gas wells, where they exist alongside raw natural gas and are known as non-associated or wet gas. Condensates can also be produced from dry gas – natural gas that has no associated component – in gas processing plants; this variety is known as plant condensate.
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AlexS , 02/01/2016 at 3:52 pmShale Oil Production in Bakken, Eagle Ford Little Changed in December: Platts Bentek
Year Over Year, Output from These Two Prolific Shale Plays Fell More Than 6% from December 2014
Thursday, January 28, 2016
http://www.oilvoice.com/n/Shale-Oil-Production-in-Bakken-Eagle-Ford-Little-Changed-in-December-Platts-Bentek/459c3fe97203.aspxOil production from key shale formations in North Dakota and Texas dropped slightly in December versus November, according to Platts Bentek, an analytics and forecasting unit of Platts, a leading global provider of energy, petrochemicals, metals and agriculture information.
Oil production from the Eagle Ford was relatively unchanged in December, increasing about 11,000 barrels per day (b/d), or less than 1%, versus the previous month, the latest analysis showed. This marks the first time since March 2015 that the Eagle Ford shale did not decline. Conversely, crude oil production in the North Dakota section of the Bakken shale formation of the Williston Basin dipped by less than 1% month over month in December, or about 9,000 b/d, continuing the trend of marginal decline that began in the summer.
The average oil production from the Eagle Ford basin in December was 1.5 million barrels per day. On a year-over-year basis, that is down about 7%, or about 110,000 barrels per day, from December 2014, according to Sami Yahya, Platts Bentek energy analyst. The average crude oil production from the North Dakota section of the Bakken in November was 1.2 million b/d, about 6% lower than year ago levels.
'The small increase in crude production in the Eagle Ford shale is attributed to a slight resurgence in drilling activity in the region,' said Yahya. 'In December, the number of active rigs in the Eagle Ford reached 80, an increase of five rigs over the previous month. The brief rebound of active rigs is likely due to producers balancing their drilling programs and budgets for the fourth quarter and meeting their goals for wells drilled for the year.'
Recapping the year-on-year production drop in the Eagle Ford shale, Yahya emphasized the importance of efficiency gains realized in 2015. Back in January of 2015, the Eagle Ford shale utilized over 200 rigs, while now, in January of 2016, the number of active rigs shrunk to under 70 rigs, a drop of over 65%. And yet, production did not meet a similar fate. Producers back in January of 2015 could drill less than two wells per rig per month, compared to nearly three wells per month currently.
'It is survival of the fittest: the best and most efficient rigs and crews remain standing on the field,' Yahya noted. 'The number of active rigs in the Bakken shale formation of the Williston Basin went from nearly 150 rigs in early 2015 to around 50 rigs currently. At the same time, producers were able to increase their drilling rates from about 1.5 wells per rig per month to about 2.2 wells per rig per month.'
However, Yahya explained that going forward, crude production would need more than just efficiency gains to grow.
'Last year, optimization and hedging programs helped production stay largely afloat. But unless the pricing of the oil barrel improve, producers are in for a difficult year ahead. Based on latest Platts Bentek forecast data, both the Eagle Ford and the Bakken shales are expected to continue declining throughout most of the year. Certainly, the availability of wells in backlog inventory where drilling cost is already sunk would be a helpful factor in partially sustaining production volumes in both shales.'
'If prices remain sub-$40/barrel and producers are unable to further bring down completion costs, then they might defer completions until the pricing market makes a comeback,' said Yahya.
Platts Bentek analysis shows that from November 2014 to November 2015, total U.S. crude oil production has increased by about 265,000 b/d.
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It is interesting to compare Bentek data with the latest EIA Drilling productivity report.
According to Bentek, oil production from the Eagle Ford increased 11kb/d versus the previous month.
According to the DPR, it declined 71 kb/d.Bentek: "The average oil production from the Eagle Ford in December was 1.5 million barrels per day. On a year-over-year basis, that is down about 7%, or about 110,000 barrels per day, from December 2014.
EIA DPR: The average oil production from the Eagle Ford in December was 1.29 mb/d. That is down 22,4%, or 374 kb/d, from December 2014.
According to Bentek, "crude oil production in the North Dakota section of the Bakken shale formation of the Williston Basin dipped by less than 1% month over month in December, or about 9,000 b/d"
According to the EIA DPR, the decline in the Bakken was 19 kb/d .
The y-o-y decline, according to bentek was 6% vs. 9.6% in the EIA DPR statistics.
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Ron Patterson, 02/01/2016 at 2:30 pmHey, great article on the EIA. Revising the Past – US Oil Production DataAlexS, 02/01/2016 at 2:51 pmThis article is based on the EIA's Monthly Energy Review which was released on 27th January and which states November 2015 production was 9,181,000 bbls/day. Oddly, the Petroleum & Other Liquids monthly data which was released on 29th January says November 2015 production was 9,318,000 bbls/day. Which one is the one the EIA intend us to use?
As I have said before the US Energy Information Agency (the EIA) has a thankless task, compiling data from thousands of oilfields and operators to come up with an estimate of how much oil the USA actually produces. Some data is timely and accurate, Alaska is a case in point, some, not so much.
So every month as well as giving us a new estimate for the month just passed, we get revisions of the historic data. It is instructive to take a look at that data to see how far off the early estimates were. Big revisions are a sign of a dislocation in the system, a sign that the old rules of thumb aren't working any more. The EIA has suffered from this phenomenon on the way up, as US shale output outstripped any reasonable estimates of how it might perform; and now on the way down, as somehow the whole US oil industry did a passable impersonation of Wile E. Coyote, well beyond the edge of the cliff but somehow defying gravity.
Monthly Energy Review data for November and December is forecast. MER data for the most recent 2 month has never been reliable. By contrast, Petroleum Supply Monthly numbers released on January 29th are more correct, in my view.There were some revisions compared with the previous PSM: September 2015 -11 kb/d;
October 2015 +23 kb/d.The data for November was only -2 kb/d compared with the January STEO estimate.
In general, the EIA has been making mostly upwards revisions for 2015 C+C production
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Watcher, 01/31/2016 at 4:43 pm
Re: Ron's Ronpost . . . anyone have a source for NGL prices?Previous Ronpost - Doug noted that in his experience every geologist in China doesn't have their words filtered by Beijing. So there is truth to be found in provincial quotes of things oil related. If the matter became more overtly national security related, of course that would change.
I'm reminded of how often EIA and NoDak's DMR have quoted numbers in conflict with each other of late. Not that this need be conspiratorial. We somewhat know EIA numbers come from a model that likely is as worthless as most. This would be a case of provincial data having not been . . . filtered, or smoothed, or seasonally adjusted or whatever else is the change mechanism du jour.
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Patrick R, 01/30/2016 at 4:29 pmOf course the forecasts by WoodMac, IEA, EIA, etc are little more than posturing. Predictions, after all, are claims on the present, not information from the future. Whoever controls the image of the future controls resources now. Conservatives want you only to fear terrorism and not pollution, and Conservationists the reverse [I like those two words; they have the same root of course].likbez, 01/30/2016 at 8:06 pmHere for example are driving predictions from English Department for Transport and Washington State DoT. Like every single Transportation Dept [read; road builders] they constantly predict more driving for ever and ever. No matter how many years they get this wrong, they've got to predict more because these predictions set their budgets for ever more fancy-arsed road projects.
Are WoodMac really going to say growth in the sector is over? Haha. And the alphabet institutions [EEEEEIIIIAAA] are extrapolationists, they're never going to catch discontinuity.
Dang, won't accept the attachments again; here's the link:
http://transportblog.co.nz/2014/02/19/our-insane-traffic-projections/
Patrick,Patrick R, 01/30/2016 at 5:44 pm"Of course the forecasts by WoodMac, IEA, EIA, etc are little more than posturing. Predictions, after all, are claims on the present, not information from the future. Whoever controls the image of the future controls resources now. "
Well said. Thank you!
"Whoever controls the image of the future controls resources now. "
That's what propaganda is about. Agencies such as EIA and IEA are as much propaganda outlets as they are statistics gathering bodies. As we all know there are three types of lies: "Lies, damned lies, and statistics".
As Watcher observed: "Countries strive for victory over their enemies. They have nothing to gain by providing accurate information."
Always the argument is between the trend and the status quo. BAUists will insist we look backwards by demanding data which of course can only be historical. This is an important corrective to theory but never shows the whole picture, because it always of course supports no change, or at most an extrapolation of the past. Never fundamental change.likbez, 01/30/2016 at 8:27 pmWhy won't oil's future follow where coal is now? I find this at least a highly plausible possibility. It is not unlikely that a combination of electric supply and climate policies will strand a great deal of oil at any price. How, economics of course:
What is always less clear is how long this takes, if I have learnt anything following global change is that it usually both takes way longer than I first think, and then can also happen very suddenly: Straws do break camels' backs.
"Why won't oil's future follow where coal is now?"Because predictions are difficult, especially about the future. So far coal was partially replaced in the only role where new technologies are somewhat competitive - electrical power generation - and this happened not only because the rise of wind and solar, but also because the price of natural gas dropped so substantially. Without the last factor the situation might reverse itself. Not everywhere coal is replaced. High quality coal is indispensable in metallurgy.
Everything depends on technologies available. Actually the initial idea of diesel engine was to run it on coal powder. It failed. But now with the new level of technology achieved I wonder if something along those lines ("nanoparticles") might be feasible at least for large ships.
At some level of oil prices coal might also be used to produce liquid fuels for transportation like Germany did during the WWII.
Natural gas is also well positioned to penetrate heavy truck and marine fuel markets if the price remains low.
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AlexS, 01/30/2016 at 2:06 amOoops, wrong numbers!Ron Patterson, 01/29/2016 at 10:41 pmBelow is the corrected chart and numbers:
EIA Annual Energy Outlook 2015
Total global liquids supply in 2040: 121.7 mb/d,
or 118,8 mb/d excluding refinery processing gains.
or 114.5 mb/d ex. proc. gains and biofuels.Note, that AEO 2015 was issued in early 2015 and apparently prepared in late 2014, when oil prices were significantly higher.
The AEO 2015 projects Brent price at $71 in 2016 gradually rising to $141 (in $2013) by 2040.
I expect AEO 2016 global liquids supply projections to be lower than in last year's issue.
Enhanced recovery don't seem to get much credit here. ;-)AlexS, 01/30/2016 at 2:24 amNotice that the IEA don't have us reaching 80 mbd, C+C, until 2030, a point that the EIA says we are at today. They, the IEA, has us at about 75 million barrels per day today. My guess is that is about right.
Ron,Dennis Coyne, 01/30/2016 at 10:52 amThe IEA has conventional oil + tight oil+oil sands + GTL and CTL at ~75 mb/d and NGLs at @ 15 mb/d in 2014
Total (ex. biofuels and processing gains) ~ 90 mbThe EIA has conventional oil + tight oil+oil sands + GTL and CTL at ~79.4 mb/d and NGLs at @ 9.5 mb/d in 2014
Total (ex. biofuels and processing gains) ~ 89 mbThe IEA has included all OPEC NGLs and condensate in global NGLs number.
The EIA apparently classifies large part of OPEC NGLs and condensate as condensate (part of global conventional C+C).(Total OPEC NGLs and condensate production in 2014 was 6.36mb/d)
Same condensate vs. NGLs shit :-)
Hi AlexS,Thanks for the clarification. Looks like about 4-5 Mb/d of condensate is produced in the World. As long as this can be easily blended into liquid fuels (such as gasoline) at refineries, it makes sense to call it "oil" as there is a wide range of stuff we are willing to call oil (such as bitumen).
We have been counting crude plus condensate for a long time, excluding C2, C3, and C4 makes sense to me, but excluding C5 does not. Just one person's opinion.
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oldfarmermac, 01/30/2016 at 10:05 amAt times there are numerous comments questioning the reliability of oil production figures reported by various countries and by different outfits sucth as the IEA etc.AlexS, 01/30/2016 at 10:57 amNo doubt there are serious errors.
What I would like to know, is this.
How big do you guys who crunch a lot of numbers think the errors are ?
How much higher, or lower might the true total world wide production of C plus C be , if it were possible to know?
How big might the errors be in the worst case countries?
OFM,clueless, 01/30/2016 at 11:07 amThe errors can be very big.
In the World Energy Outlook 2008, the IEA projected global total liquids demand at 106.4 mb/d by 2030.
In the latest WEO-2015, they are projecting 103.5 mb/d by 2040.The trend in the past 10 years was towards lower medium and long-term supply and demand projections
Generally speaking, when dealing with massive amounts of data, the "errors" largely offset each other. That is, if almost every figure is subject to being either to high or too low, after adding them all up, the total is surprisingly close to what the "real" total should be. Obviously, if you could posit a situation in which every number is likely to be too high (or too low) that would not be the case.AlexS, 01/30/2016 at 11:19 amSo, with an individual country, like say Venezuela, maybe it is off by a significant amount.
clueless,Watcher, 01/30/2016 at 11:38 amAs regards global oil (liquids) supply and demand projections, there were not just statistical errors, but very significant conceptual errors. All agencies have been significantly overestimating global demand and supply.
These are the most important data points on earth, and they are not known to high confidence. This is what one would expect. Countries strive for victory over their enemies. They have nothing to gain by providing accurate information.Doug Leighton, 01/30/2016 at 1:16 pmIf I were China, I'd make oil production a state secret, too.
Hi Watcher,oldfarmermac, 01/30/2016 at 11:42 amI doubt China is playing games with reported oil production capability. I had an office in Harbin for many years where most of my time was spend assessing reserves for NA oil companies who wanted access to Chinese oil. As such I was in contact with numerous local oilmen who freely gave me access to their reservoir data. The Chinese were duplicitous in one respect, in my opinion, by leading American companies into believing they were entertaining potential JV partners when, in fact, they simply wanted to massage business contacts in general. On China's production I expect the following is accurate:
"… China's crude oil output has stagnated for the past two years despite intense drilling activity on land and offshore. In late 2014, CNPC essentially threw in the towel on its workhorse field, Daqing, announcing that it would allow the field to essentially enter a phase of managed decline over the next five years. Under this new approach, the field's oil production will fall from 800,000 barrels per day (kbd) in 2014 to 640 kbd by 2020: a 20 percent decrease. To highlight the importance of PetroChina's decision, consider that Daqing currently accounts for approximately one in every five barrels of oil currently pumped in China – on par with the role Alaska's massive Prudhoe Bay field has played in US oil production…"
http://thediplomat.com/2015/07/china-peak-oil-2015-is-the-year/
Thanks guys, but I did not mean to ask about PREDICTED oil production but rather about ACTUAL production, this year, and in past years.AlexS, 01/30/2016 at 11:58 amIf for instance Saudi Arabia says last years production was ten million barrels per day average, exactly, how far off do you think that might be, one tenth of a percent? two percent?
Some countries are going to be notorious liars of course, and their figures might be off by ten percent or more.
But even though the total reported world production might be wrong by a percent or more, in either direction, up or down, the TREND in reported production still ought to be accurate.
The trend in the reported quantity of oil available on international markets ought to be likewise accurate, even though the actual reported quantity of oil available on world markets might have been off by a percent or even two percent or more.
Historical demand and supply numbers are constantly revised, but in most cases revisions are not too big.likbez , 01/30/2016 at 2:21 pmRevisions of the US oil production numbers were relatively big in 2015.
I would assume that EIA has error margin close or above 100,000 bbls/day. So the accuracy of EIA data is just two significant digits maximum. The fact that they provide more digits is just an attempt to be a better Catholic then Pope, if you wish ;-).Generally they should have strong institutional bias toward lower oil prices and that bias can influence their oil production and consumption numbers. So it is rational to assume that they tend to overestimate the production and underestimate consumption growth. In other words they are predisposed to "revealing" oil glut even if it does not exists.
The margin or error is different for different types of oil with those areas that are served by pipelines more precise (offshore is one example here).
Some people like Steve Brown recommend reducing their production numbers by 100,000 bbl/day just in case :-)
http://oilprice.com/Energy/Energy-General/Is-The-EIA-Too-Optimistic-On-US-Oil-Output.html
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Jeffrey J. Brown, 01/28/2016 at 3:42 pmAPI: US December, 2015 Petroleum Demand Highest in Five Yearslikbez, 01/29/2016 at 1:12 pmEIA Annual Energy Review data complete for 2015 (subject to revision):
http://www.eia.gov/totalenergy/data/monthly/pdf/sec3_3.pdf
Based on foregoing, annual 2015 US net total liquids imports were still down in 2015, versus 2014, but US net total liquids imports rose from 4.5 million bpd in December, 2014 to 5.1 million bpd in December, 2015.
Note that US C+C inventories rose by 100 million barrels from late 2014 to late 2015. So, as we saw a 100 million barrel increase in US C+C inventories, US net total liquids were up by 13%, from 12/14 to 12/15? Almost makes one think that most, if not all, of the C+C build consists of something besides actual crude oil.
(As usual, there appear to be some discrepancies between the EIA Weekly Supply data and the Annual Energy Review data in regard to total liquids net imports. In any case, the four week running average data show that US net crude oil imports rose from 6.9 million bpd in December, 2014 to 7.3 million bpd in December, 2015. Net crude oil imports are not broken down separately in Annual Energy Review.)
This is yet another indirect confirmation of "Great Condensate Con" hypothesis.
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dmg555, 01/25/2016 at 1:43 pm
Dear Mr. Jeffrey Brown:Watcher , 01/25/2016 at 3:40 pmOf all the contributors on this site, you have highlighted the problems inherent in counting condensates as crude. I am not a petroleum chemist so am not so familiar with the limitations of condensates. Could you briefly tell me what you can and can not use condensates for? I get that one can refine 30-45 WTI into gasoline and other useful fuels like jet fuel, but: Can you drive on condensates? or am I correct in believing the condensates can only be turned into heating fuels.
Thanks for your answer in advance
Yeah, distillate yield is the big deal. Gasoline doesn't move food.likbez , 01/25/2016 at 5:18 pm> "Can you drive on condensates?"Yes, but it's illegal in most states (https://en.wikipedia.org/wiki/Natural-gas_condensate)
It is also harmful to modern engines due to its low octane rating ( about 30 to 50) and possible presence of cancerogenius additives (benzene) and sulfur. Before 1930 it was used as an ICE fuel in low RPM, low compression engines. Both Karl Benz engines, and early Wright brothers aircraft engines used it. It has a distinctive smell when used as a fuel, which allows police to catch people using condensate illegally.
The white gas sold today as a fuel for stoves is a condensate with the benzene and sulfur removed.
Adding ethanol improves the octane number (https://en.wikipedia.org/wiki/Octane_rating) and makes it possible to drive regular cars on distillate. You need E85 mix for that.
My impression is that the drive to blend ethanol with gasoline (most of the gasoline now sold in the United States contains some ethanol) and introduction of E10, E15, and E85 that happened in the USA was at least partially dictated by the desire to blend condensate (as a substitute for gasoline) with ethanol killing two birds with one stone. Moreover denaturized ethanol contains at least 2% of condensate. All gasoline engine vehicles can use E10 so some amount of condensate is present in US gasoline almost by definition.
E85 (used only in flexible-fuel vehicles (FFV) ) allows blending of considerable amount of reprocessed condensate (probably 40-50%) with ethanol and still getting acceptable octane number. E85 is an abbreviation for an ethanol fuel blend of 85% denatured ethanol fuel and 15% gasoline or other hydrocarbons by volume, although the exact ratio of fuel ethanol to hydrocarbons can vary considerably while still carrying the E85 label. The ethanol content is adjusted according to the local climate to maximize engine performance. ASTM 5798 specifies the allowable fuel ethanol content in E85 as ranging from 51% to 83%.
Condensate has a very low viscosity and often used to dilute highly viscous heavier oils that cannot otherwise be efficiently transported via pipelines.
Jeffrey J. Brown , 01/25/2016 at 1:55 pm
I'm actually not anywhere close to be a refining expert, and I think that Fernando can give you more detailed answers, but insofar as condensate is concerned, the biggest problem with too much condensate as a percentage of Crude + Condensate (C+C) refining feedstock is that condensate is deficient in distillate (jet fuel, heating oil, diesel, etc.) plus heavier components.Jeffrey J. Brown , 01/25/2016 at 2:00 pmHowever, the quality issue, in my opinion, is something of a Red Herring.
My principal point is not that the liquid partial substitutes for crude oil, i.e., condensate, natural gas liquids (NGL) and biofuels, are deficient in quality compared to crude oil; my principal point is that the available data, at least in my opinion, strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production (45 API and lower crude oil) since 2005, while global natural gas production and associated liquids, condensate and NGL, have (so far) continued to increase.
The obvious question is that if it took trillions of dollars in post-2005 global upstream capex (spent on oil & gas projects) to keep us on an undulating plateau in actual global crude oil production, what happens to global crude oil production given the large, and ongoing, cutbacks in global upstream capex?
But in regard to refinery yields, here is a chart of refinery yields by API Gravity. Note that Cat Feed + Distillate Yield drops from about 55% at 39 API gravity (approximately the average API value for Brent & WTI) to about 20% at 42 API Gravity (which is the maximum upper limit for WTI crude oil).Here's a link to, and an excerpt from, the source document for the chart:
http://www.nrcan.gc.ca/energy/crude-petroleum/4561
The figure below illustrates the product yield for six typical types of crude oil processed in Canada. It includes both light and heavy as well as sweet and sour crude oils. A very light condensate* (42 API) and a synthetic crude oil are also included. The chart compares the different output when each crude type is processed in a simple distillation refinery. The output is broken down into five main product groups: gasoline, propane and butane (C3/C4), Cat feed (a partially processed material that requires further refining to make usable products), distillate (which includes diesel oil and furnace oil) and residual fuel (the heaviest and lowest-valued part of the product output, used to make heavy fuel oil and asphalt).
As I have previously discussed, I suspect that US (and perhaps global) refiners hit, in late 2014, the upper limit of how much condensate that they could process if they wanted to maintain their output of distillates and heavier products, which plausibly contributed to the 100 million barrel build in US C+C inventories, from late 2014 to late 2015, as US refiners increased their net crude oil imports from December, 2014 to December, 2015.
*The more common dividing line between crude & condensate is 45 API Gravity, but EIA data indicate that about 40% of US Lower 48 C+C production in 2015 exceeded 42 API Gravity, which is the maximum upper limit for WTI crude oil.
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AlexS, 01/24/2016 at 10:54 am
There are still significant discrepancies between the EIA monthly and weekly data for U.S. C+C production.
Weekly numbers show an increase of 139 kb/d from September 25 to January 15, including an uninterrupted growth (of 71 kb/d) over the past 6 weeks from December 4.
likbez , 01/24/2016 at 3:07 pm
Alex,AlexS, 01/24/2016 at 7:04 pmThank you --
This large discrepancy between weekly and monthly data suggests that sources are at least partially different and somewhat incompatible. This also puts a shadow on the accuracy of EIA data in general, especially provided by the monthly short term energy outlook.
I think similar problems exist in other statistical data that EIA the short term energy outlook provides.
Previously I asked a similar question about reliability of their world C+C production and consumption data, but I did this from the point of view of accuracy individual country data (which are probably less then 1%):
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-557103
It is well known that OPEC countries used to cheat on their production data as their quotas depend on the current volume of production.
Amatoori also provided a link for the following article which is relevant to this discussion: http://www.reuters.com/article/us-oil-prices-kemp-idUSKCN0V0276?feedType=RSS&feedName=GCA-Commodities&utm_source=dlvr.it&utm_medium=twitter&dlvrit=1391616
See also response of Watcher to his comment:
http://peakoilbarrel.com/opec-except-iran-has-peaked/#comment-557074likbez,likbez, 01/25/2016 at 10:01 amWe have many times discussed the [un]reliability of the EIA U.S. oil production statistics. They have previously relied on the state-level data, which in many cases is uncomplete, with few exceptions (like North Dakota). The EIA was adjusting these numbers according to their old methodology. But their numbers were still inaccurate and had to be revised many times during the next 12 months.
The EIA now has a new methodology: they get production data directly from the largest companies, which account for about 90% of total output in each state. This survey-based approach now covers 15 individual states and the federal Gulf of Mexico, where the bulk of U.S. C+C is produced. The EIA claims that the new methodology has improved the quality of their estimates. But, as can be seen from the chart below, the numbers still need to be revised, and all of the revisions over the past 4 months were upward (see the chart below).
In 2015, the EIA has not only underestimated U.S. oil production numbers for the past months, but its predictions for the next several months were also too low. As a result, the most recent numbers for some months are up to 0.5 mb/d higher than earlier estimates.
The EIA weekly numbers are based on completely different methodology, and they were always seen as very inaccurate. Furthermore, unlike monthly statistics, weekly numbers are never revised.
What is interesting, weekly statistics from my chart above show a rising trend in U.S. oil production from October to January, while monthly numbers suggest a declining trend. But monthly numbers for October may again be revised upward, while the numbers from November are forecast, rather than estimate. We may not know the more or less exact numbers for end-2015 until mid-2016.
U.S. C+C production estimates from the last 5 issues of the EIA Short-Term Energy Outlook
There are several hypothesis that can be advanced based on the data accuracy and a huge lag of EIA and IEA data (as somebody aptly noted: the main purpose of IEA data is to please Americans):1. Any talk about world glut below 1 Mb/d should be dismissed as statistical noise as the accuracy of supply/demand data for most countries does not allow to defect such a glut or oil shortage.
2. EIA is not only statistical outlet but also a propaganda outlet as well providing (sometimes false) signals to Wall street traders and as such having outsize influence on the dynamic of oil prices. They literally can move oil up or down.
3. "The Great Condensate Con" was probably intentional and essentially is equal to creating an artificial additional pressure on oil prices via manipulated statistics.
4. The only data that can counterbalance EIA/IEA bias can come from OPEC, but taking into account outsize influence of Saudis within the organization chances are slim.
5. Rebound of prices, if any, can be pretty abrupt as lack of supplies will be detected only when it becomes acute.
6. Repeating Watcher "It is indeed astounding that oil numbers, the most important numbers for all civilization, are not reliable."
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dmg555, 01/25/2016 at 1:43 pm
Dear Mr. Jeffrey Brown:Watcher , 01/25/2016 at 3:40 pmOf all the contributors on this site, you have highlighted the problems inherent in counting condensates as crude. I am not a petroleum chemist so am not so familiar with the limitations of condensates. Could you briefly tell me what you can and can not use condensates for? I get that one can refine 30-45 WTI into gasoline and other useful fuels like jet fuel, but: Can you drive on condensates? or am I correct in believing the condensates can only be turned into heating fuels.
Thanks for your answer in advance
Yeah, distillate yield is the big deal. Gasoline doesn't move food.likbez , 01/25/2016 at 5:18 pm> "Can you drive on condensates?"Yes, but it's illegal in most states (https://en.wikipedia.org/wiki/Natural-gas_condensate)
It is also harmful to modern engines due to its low octane rating ( about 30 to 50) and possible presence of cancerogenius additives (benzene) and sulfur. Before 1930 it was used as an ICE fuel in low RPM, low compression engines. Both Karl Benz engines, and early Wright brothers aircraft engines used it. It has a distinctive smell when used as a fuel, which allows police to catch people using condensate illegally.
The white gas sold today as a fuel for stoves is a condensate with the benzene and sulfur removed.
Adding ethanol improves the octane number (https://en.wikipedia.org/wiki/Octane_rating) and makes it possible to drive regular cars on distillate. You need E85 mix for that.
My impression is that the drive to blend ethanol with gasoline (most of the gasoline now sold in the United States contains some ethanol) and introduction of E10, E15, and E85 that happened in the USA was at least partially dictated by the desire to blend condensate (as a substitute for gasoline) with ethanol killing two birds with one stone. Moreover denaturized ethanol contains at least 2% of condensate. All gasoline engine vehicles can use E10 so some amount of condensate is present in US gasoline almost by definition.
E85 (used only in flexible-fuel vehicles (FFV) ) allows blending of considerable amount of reprocessed condensate (probably 40-50%) with ethanol and still getting acceptable octane number. E85 is an abbreviation for an ethanol fuel blend of 85% denatured ethanol fuel and 15% gasoline or other hydrocarbons by volume, although the exact ratio of fuel ethanol to hydrocarbons can vary considerably while still carrying the E85 label. The ethanol content is adjusted according to the local climate to maximize engine performance. ASTM 5798 specifies the allowable fuel ethanol content in E85 as ranging from 51% to 83%.
Condensate has a very low viscosity and often used to dilute highly viscous heavier oils that cannot otherwise be efficiently transported via pipelines.
Jeffrey J. Brown , 01/25/2016 at 1:55 pm
I'm actually not anywhere close to be a refining expert, and I think that Fernando can give you more detailed answers, but insofar as condensate is concerned, the biggest problem with too much condensate as a percentage of Crude + Condensate (C+C) refining feedstock is that condensate is deficient in distillate (jet fuel, heating oil, diesel, etc.) plus heavier components.Jeffrey J. Brown , 01/25/2016 at 2:00 pmHowever, the quality issue, in my opinion, is something of a Red Herring.
My principal point is not that the liquid partial substitutes for crude oil, i.e., condensate, natural gas liquids (NGL) and biofuels, are deficient in quality compared to crude oil; my principal point is that the available data, at least in my opinion, strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production (45 API and lower crude oil) since 2005, while global natural gas production and associated liquids, condensate and NGL, have (so far) continued to increase.
The obvious question is that if it took trillions of dollars in post-2005 global upstream capex (spent on oil & gas projects) to keep us on an undulating plateau in actual global crude oil production, what happens to global crude oil production given the large, and ongoing, cutbacks in global upstream capex?
But in regard to refinery yields, here is a chart of refinery yields by API Gravity. Note that Cat Feed + Distillate Yield drops from about 55% at 39 API gravity (approximately the average API value for Brent & WTI) to about 20% at 42 API Gravity (which is the maximum upper limit for WTI crude oil).Here's a link to, and an excerpt from, the source document for the chart:
http://www.nrcan.gc.ca/energy/crude-petroleum/4561
The figure below illustrates the product yield for six typical types of crude oil processed in Canada. It includes both light and heavy as well as sweet and sour crude oils. A very light condensate* (42 API) and a synthetic crude oil are also included. The chart compares the different output when each crude type is processed in a simple distillation refinery. The output is broken down into five main product groups: gasoline, propane and butane (C3/C4), Cat feed (a partially processed material that requires further refining to make usable products), distillate (which includes diesel oil and furnace oil) and residual fuel (the heaviest and lowest-valued part of the product output, used to make heavy fuel oil and asphalt).
As I have previously discussed, I suspect that US (and perhaps global) refiners hit, in late 2014, the upper limit of how much condensate that they could process if they wanted to maintain their output of distillates and heavier products, which plausibly contributed to the 100 million barrel build in US C+C inventories, from late 2014 to late 2015, as US refiners increased their net crude oil imports from December, 2014 to December, 2015.
*The more common dividing line between crude & condensate is 45 API Gravity, but EIA data indicate that about 40% of US Lower 48 C+C production in 2015 exceeded 42 API Gravity, which is the maximum upper limit for WTI crude oil.
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Jimmy 01/23/2016 at 7:02 pmA new post from Aleklettlikbez , 01/23/2016 at 7:37 pmHe does not ask himself an important question, what all those tankers contain. Is this crude or condensate? Or some refined products like heating oil too.Jeffrey J. Brown , 01/23/2016 at 7:52 pmFor what it's worth, Iranian sources say it's condensate and fuel oil. I guess we will find out.Matt Mushalik , 01/24/2016 at 5:09 amhttp://www.reuters.com/article/iran-oil-idUSL3N1021Z120150723
For comparisonJeffrey J. Brown , 01/24/2016 at 8:31 amUS condensate production increased from 231 mb in 2011 (start of shale oil boom) to 326 mb in 2014
https://www.eia.gov/dnav/ng/hist/rl2r57nus_1a.htmSo IEA's estimate of 36 mb x 0.67 = 24 mb would be 7.4 % of 2014 US condensate production
There are some reporting issues regarding "Lease condensate," i.e., I suspect that a good deal of condensate production is reported as crude oil production. And in fact, the EIA refers to Crude + Condensate (C+C) as "Crude oil."Synapsid , 01/24/2016 at 7:07 pmA survey that the EIA did last year estimated that 22%, or about 2 million bpd, of US Lower 48 C+C production consists of condensate (45 API +). And about 40% of US Lower 48 C+C production exceeded the maximum API Gravity for WTI crude oil (42 API Gravity).
My "Condensate Con" comment:
http://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595
Matt Mushalik,AlexS , 01/23/2016 at 8:27 pmI'm a little uncertain about the figures because your link takes you to a page, under the heading Natural Gas, titled Natural Gas Liquids Lease Condensate. To me, "lease condensate" means wellhead condensate and that is not associated with NGLs; condensate also comes out at the NGL-separation stage down the line. If it is the latter that the chart refers to, then the figure is not total production of condensate but only that recovered from the NGL stream.
Somebody help?
"At the end of November, roughly 36 mb of oil, of which 67% was condensates, was floating in 18 tankers."AlexS , 01/23/2016 at 8:37 pm
Source: IEA Oil Market Report, December 2015Iranian oil in floating storage
source: http://money.cnn.com/2016/01/18/investing/iran-sanctions-hoarding-oil-prices/index.html
"With no clear timeline for a restart at petrochemicals producer Dragon Aromatics, one of Tehran's key condensate buyers, after its April fire, Iran hoped new buyers in South Korea, Japan as well as in China would pick up the slack, traders said.The CNOOC-Shell petrochemical plant in southeastern Guangdong province could also be a replacement buyer for condensate, they said. The plant was forced to drop a regular supply pact in mid-2012 when the European Union put an embargo on trading Iranian oil."
http://www.reuters.com/article/2015/12/03/us-china-iran-oil-idUSKBN0TM0CN20151203
"Iran may roil global oil markets with plans to sell about 45 million barrels of fuel stored in tankers in the Persian Gulf within three months of the removal of sanctions on its economy, according to analysts.
Most of the stored oil is condensate that contains a sulfur compound, which complicates sales because many refineries can't process it, said Victor Shum of IHS Inc. and Robin Mills at Dubai-based Manaar Energy Consulting. To market this large amount of oil within three months - the equivalent of about half a million barrels a day - Iran will have to resort to offering deep discounts, they said."
The condensate … is pumped from the offshore South Pars natural gas deposit.
Iran may need to spur sales of its sulfur-heavy condensate by offering discounts of at least 10 to 15 percent, Shum said. Its main condensate customer, Dragon Aromatics Zhangzhou Co. of China, stopped buying after a fire at its plant in April and an Iranian refinery designed to use it won't be ready until 2017, causing stockpiles to build, he said.
"There will have to be a major impact on the market of selling that condensate," said Manaar Energy's Mills, who worked for Royal Dutch Shell Plc on projects in Iran from 1998 to 2003. "If they're already having difficulty shifting it, adding another half million barrels will be even more difficult," he said by phone. "They'll manage, but at what discount?"
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Jeffrey J. Brown, 01/21/2016 at 6:56 amhttp://econbrowser.com/archives/2016/01/world-oil-supply-and-demand#comment-194595Huckleberry Finn, 01/21/2016 at 1:34 pmMy premise is that US (and perhaps global) refiners hit, late in 2014, the upper limit of the volume of condensate that they could process, if they wanted to maintain their distillate and heavier output–resulting in a build in condensate inventories, reflected as a year over year build of 100 million barrels in US C+C (Crude + Condensate) inventories.
Therefore, in my opinion the US and (and perhaps globally) C+C inventory data are fundamentally flawed, when it comes to actual crude oil inventory data. The most common dividing line between actual crude oil and condensate is 45 API gravity, although the distillate yield drops off considerably just going from 39 API to 42 API gravity crude, and the upper limit for WTI crude oil is 42 API. . . .
Note that (in 2015) 22% of US Lower 48 C+C production consists of condensate (45+ API gravity) and note that about 40% of US Lower 48 C+C production exceeds the maximum API gravity for WTI crude oil (42 API).
Mr. Brown,Just so I understand what you are saying: Crude plus Condensate Inventory build have been higher because mainly of Condensate as EIA is no longer properly distinguishing the difference?
If that 100 Million number is true, we might see $100 oil this year I think.
BTW the last two weeks saw some massive builds in "Blending components for gasoline" while the market went wild because it looked like actual products were building.
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resourceinsights.blogspot.com
- Joe said...
- My guess is that the surplus of condensate and blended "dumbell crudes" has been stacking up in storage tanks, especially in the US, cutting the amount of working storage available to purchasers. Lack of storage increases the sensitivity of the market price to supply/demand imbalance magnitude. If a purchaser of oil has plenty of cheap storage, they might purchase oil they can't use today at a slight discount and save it for future use. If they have no storage they won't buy it at all, no matter how low the price.
- 9:42 AM
- energyskeptic said...
- Kurt, are you saying that the apparent oil glut is mostly NGL's and not oil? Also, are NGL's what make it appear that oil storage is full? I never could understand why NGL's are included in oil production in the EIA stats, since only 13% of NGL's can be blended with gasoline (the pentane).
The rest is ethane, butane, propane, and isobutane -- mainly useful for petrochemicals, plastics, and heating (propane).
By the way, I've just written a book for Charlie Hall's Springer Energy Briefs series called "When Trucks stop running: Energy and the Future of Transportation" where I look at all the possible ways trucks, rail, and ships could keep moving as oil declines, including NGL's, CNG, LNG, coal-to-liquids, biofuels, hydrogen, electrification, etc. More info at http://www.springer.com/us/book/9783319263731
or
http://energyskeptic.com/2016/when-trucks-stop-running-so-does-civilization/I think all the endless electric car nonsense is effective at distracting people from the heavy-duty transportation that really matters. Virtually everything in our homes, everything in our stores, got there on a truck. Prior to that, 90 percent of those items were transported on a ship and/or a train, which all run on finite oil. If trucks, trains, and ships stopped running, our global economy and way of life would stop too.
- 5:02 PM
- Kurt Cobb said...
- Alice,
First, I find myself hitting your site regularly since so many people refer to your work. So, thanks for the great work you are doing.
As for condensates and NGLs, terminology in this case is the enemy of clarity. For a good treatment of this problem How the changing definition of oil has deceived both policymakers and the public . NGLs generally refer to both natural gas plant liquids and lease condensate which originate from two different sources, i.e. gas wells vs. oil wells. And, yes, part of the storage issue is the storage of lease condensate since it is often, as indicated, mixed with crude oil. Natural gas plant liquids come from natural gas processing plants and so are not typically stored in combination with crude oil (though in gasoline refining, butane is usually mixed in with gasoline).
Yes, propane and butane, are used for transportation fuels. But their supply is limited by the amount of natural gas demand. No one withdraws natural gas from wells solely for the propane or butane it contains. There are practical limits to how many propane-powered vehicles we can have.
Now, if we didn't make certain chemicals from natural gas plant liquids, we would be making them from oil, and so in an indirect way this keeps more oil in the liquid fuels market rather than the petrochemical market. But I think the substitution effect here is exaggerated by those saying we should consider all liquids as part of the oil supply. As I said in the piece, the marketplace certainly makes distinctions between these products.
I think you are right about truck freight being crucial to our current way of living. I remember an exchange with an Italian reader who explained that while European passenger rail is far superior to that of the United States, one reason for this is often not understood. Much of the freight in the United States moves by rail at some point and so our tracks are filled with freight trains that delay passenger travel. In Europe 80 percent of the freight moves by truck. The rails are not so burdened with freight and so passenger trains move with fewer delays and at higher speeds.
But in both places truck freight remains crucial. Best of luck with your new book.
- 5:37 PM
- westexas said...
- Condensate is basically natural gasoline, and it is a byproduct of natural gas production. However, the issue of relative quality, between crude and condensate, is a little bit of a red herring.
The CC's (Cornucopian Crowd) argue that there is no sign of any kind of peak in sight. I would argue that this assertion is manifestly false when it comes to actual crude oil production (45 API and lower crude oil). In my opinion, the available data strongly suggest that we have been on an "Undulating Plateau" in actual global crude oil production since 2005, while global natural gas production and associated liquids, condensate & natural gas liquids, have so far continued to increase.
Again, what the EIA calls "Crude oil" is actually Crude + Condensate (C+C), and based on EIA data 22% of Lower 48 C+C production in 2015 exceeded 45 API gravity and about 40% of US Lower 48 C+C production exceeded the maximum API limit for WTI crude (42 API Gravity).
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finance.yahoo.com
Crude Oil Rally Short-Lived: Fundamentals Still Feeding the Bears
EIA's gasoline and distillate inventoriesThe EIA (U.S. Energy Information Administration) reported that the US gasoline inventory rose by 8.4 MMbbls to 240.4 MMbbls for the week ending January 8, 2016. This rise was less than the rise of 10.6 MMbbls during the week ending January 1, 2016. Similarly, the US distillate inventory rose by 6.1 MMbbls to 165.6 MMbbls for the week ending January 8, 2016.
EIA's gasoline and distillate inventories by region
The EIA added that of the five major US storage hubs, the Gulf Coast, the Midwest, and the East Coast recorded the highest gasoline inventories for the week ending January 8, 2016. To learn more about the US storage hubs, read the previous part of this series. Gasoline inventories in these regions came in at 82.6 MMbbls, 57.6 MMbbls, and 62.9 MMbbls, respectively.
Similarly, distillate inventories were highest in the Gulf Coast, the Midwest, and the East Coast regions. The US distillate inventories were 48.1 MMbbls, 33.3 MMbbls, and 64.9 MMbbls, respectively, in these three regions.
EIA's gasoline and distillate inventory estimates and impact
Reuters' surveys estimated that the US gasoline inventory would rise by 2.7 MMbbls and the US distillate inventory would rise by 2 MMbbls for the week ending January 8, 2016. The greater-than-expected rise in refined products inventories weighed on crude oil prices. Lower crude oil prices benefit US refiners like Phillips 66 (PSX), Western Refining (WNR), Alon USA Partners (ALDW), and Northern Tier Energy (NTI). On the other hand, higher refined products inventories put pressure on refiners. The refined products inventories rose due to the fall in retail demand this winter season. Read about refinery demand in the fifth part of this series.
The fall in retail and refinery demand also affects crude oil prices and oil producers like Chevron (CVX), Whiting Petroleum (WLL), and Continental Resources (CLR). ETFs like the ProShares UltraShort Bloomberg Crude Oil ETF (SCO), the Vanguard Energy ETF (VDE), and the First Trust Energy AlphaDEX Fund (FXN) are also affected by the ups and down in the oil market.
Read why US crude oil production is crucial for the global crude oil market in the next part of this series.
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Jan 19, 2016 | OilPrice.com
My favorite Texas oilman is at it again. In a recent email he's pointing out to everyone who will listen that the supposed oversupply of crude oil isn't quite what it seems. Yes, there is a large overhang of excess oil in the market. But how much of that oversupply is honest-to-god oil and how much is so-called lease condensate which gets carelessly lumped in with crude oil? And, why is this important to understanding the true state of world oil supplies?In order to answer these questions we need to get some preliminaries out of the way.
Lease condensate consists of very light hydrocarbons which condense from gaseous into liquid form when they leave the high pressure of oil reservoirs and exit through the top of an oil well. This condensate is less dense than oil and can interfere with optimal refining if too much is mixed with actual crude oil. The oil industry's own engineers classify oil as hydrocarbons having an API gravity of less than 45--the higher the number, the lower the density and the "lighter" the substance. Lease condensate is defined as hydrocarbons having an API gravity between 45 and 70. (For a good discussion about condensates and their place in the marketplace, read "Neither Fish nor Fowl – Condensates Muscle in on NGL and Crude Markets.")
Refiners are already complaining that so-called "blended crudes" contain too much lease condensate, and they are seeking out better crudes straight from the wellhead. Brown has dubbed all of this the great condensate con.
Brown points out that U.S. net crude oil imports for December 2015 grew from the previous December, according to the U.S. Energy Information Administration (EIA), the statistical arm of the U.S. Department of Energy. U.S. statistics for crude oil imports include condensate, but don't break out condensate separately. Brown believes that with America already awash in condensate, almost all of those imports must have been crude oil proper.
Brown asks, "Why would refiners continue to import large--and increasing--volumes of actual crude oil, if they didn't have to--even as we saw a huge build in [U.S.] C+C [crude oil plus condensate] inventories?"
Part of the answer is that U.S. production of crude oil has been declining since mid-2015. But another part of the answer is that what the EIA calls crude oil is actually crude plus lease condensate. With huge new amounts of lease condensate coming from America's condensate-rich tight oil fields -- the ones tapped by hydraulic fracturing or fracking -- the United States isn't producing quite as much actual crude oil as the raw numbers would lead us to believe. This EIA chart breaking down the API gravity of U.S. crude production supports this view.
Exactly how much of America's and the world's presumed crude oil production is actually condensate remains a mystery. The data just aren't sufficient to separate condensate production from crude oil in most instances.
Brown explains: "My premise is that U.S. (and probably global) refiners hit in late 2014 the upper limit of the volume of condensate that they could process" and still maintain the product mix they want to produce. That would imply that condensate inventories have been building faster than crude inventories and that the condensate is looking for an outlet.
That outlet has been in blended crudes, that is heavier crude oil that is blended with condensates to make it lighter and therefore something that fits the definition of light crude. Light crude is generally easier to refine and thus more valuable.
The trouble is, the blends lack the characteristics of nonblended crudes of comparable density (that is, the same API gravity), and refiners are discovering to their chagrin that the mix of products they can get out of blended crudes isn't what they expect.
So, now we can try to answer our questions. Brown believes that worldwide production of condensate "accounts for virtually all of the post-2005 increase in C+C [crude plus condensate] production." What this implies is that almost all of the 4 million-barrel-per-day increase in world "oil" production from 2005 through 2014 may actually be lease condensate. And that would mean crude oil production proper has been nearly flat during this period -- a conjecture supported by record and near record average daily prices for crude oil from 2011 through 2014. Only when demand softened in late 2014 did prices begin to drop.
Here it is worth mentioning that when oil companies talk about the price of oil, they are referring to the price quoted on popular futures exchanges -- prices which reflect only the price of crude oil itself. The exchanges do not allow other products such as condensates to be mixed with the oil that is delivered to holders of exchange contracts.
But when oil companies (and governments) talk about oil supply, they include all sorts of things that cannot be sold as oil on the world market including biofuels, refinery gains and natural gas plant liquids as well as lease condensate. Which leads to a simple rule coined by Brown: If what you're selling cannot be sold on the world market as crude oil, then it's not crude oil.
The glut that developed in 2015 may ultimately be tied to some increases in actual, honest-to-god crude oil production. The accepted story from 2005 through 2014 has been that crude oil production has been growing, albeit at a significantly slower rate than the previous nine-year period--15.7 percent from 1996 through 2005 versus 5.4 percent from 2005 through 2014 according to the EIA. If Brown is right, we have all been victims of the great condensate con which has lulled the world into a sense of complacency with regard to actual oil supplies--supplies he believes have been barely growing or stagnant since 2005.
"Oil traders are acting on fundamentally flawed data," Brown told me by phone. Often a contrarian, Brown added: "The time to invest is when there's blood in the streets. And, there's blood in the streets."
He explained: "Who of us in January of 2014 believed that prices would be below $30 in January of 2016? If the conventional wisdom was wrong in 2014, maybe it's similarly wrong in 2016" that prices will remain low for a long time.
Brown points out that it took trillions of dollars of investment from 2005 through today just to maintain what he believes is almost flat production in oil. With oil companies slashing exploration budgets in the face of low oil prices and production declining at an estimated 4.5 and 6.7 percent per year for existing wells worldwide, a recovery in oil demand might push oil prices much higher very quickly.
That possibility is being obscured by the supposed rise in crude oil production in recent years that may just turn out to be an artifact of the great condensate con.
By Kurt Cobb
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Huckleberry Finn, 12/25/2015 at 8:32 am
Does a barrel of NGL have the same BTU as a Barrel of Crude or Condensate?Ron Patterson, 12/25/2015 at 9:06 amIf not, converting all into BTU would show whether total BTUs provided are increasing or static.
Rune Likvern says: NGLs have around 60 – 70% of the volumetric energy (heat) content of crude oil.Jeffrey J. Brown, 12/25/2015 at 10:05 amHowever peak oil will happen when oil peaks, not NGLs. Liquid transportation BTUs should not be mixed with other types of BTUs. Otherwise we would need to count BTUs from coal as well.
Some EIA million BTU (MMBTU) conversion factors:Anton Koffield, 12/26/2015 at 12:49 pmhttps://www.eia.gov/forecasts/aeo/pdf/appg.pdf
Of course, what the EIA calls "Crude oil" is actually Crude + Condensate (C+C), and condensate can't be used to meet crude oil contractual obligations at Cushing. I assume that the listed value for gasoline, 5.2 MMBTU, is a pretty good approximation for an average value for condensate.
For the first nine months of 2015, the EIA estimates that the ratio of US Lower 48 condensate* to US Lower 48 "Crude oil" Production, i.e., C+C, was 22%, or 2 million bpd of Lower 48 condensate production:
EIA expands monthly reporting of crude oil production (i.e., C+C) with new data on API gravity:
https://www.eia.gov/todayinenergy/detail.cfm?id=23952These numbers are consistent with some estimates that I used in the following comment, where I tried to come up with an estimate of actual global crude oil production (45 API and lower crude oil, i.e., the stuff that corresponds to the global price indexes), versus global condensate production, using the only available data, some EIA API gravity estimates for the US and EIA/OPEC data for the OPEC countries.
My premie was and is that we have been on an "Undulating plateau" in actual global crude oil production, while global natural gas production and associated liquids, condensate and NGL, have so far continued to increase:
http://peakoilbarrel.com/jean-laherreres-bakken-update/comment-page-1/#comment-534101
After showing similar rates of increase from 2002 to 2005, global NGL production was up by 26% from 2005 to 2014, while global C+C production was up by only 6% over the same time period (EIA).
*Condensate with API gravity of 45 degrees or more
What is condensate used for?AlexS. 12/26/2015 at 12:55 pmmost of condensate is mixed with crude oils as a refinery input; some is used as petrochemical feedstockJeffrey J. Brown, 12/26/2015 at 8:17 pmCondensate is basically natural gasoline.Anton Koffield. 12/27/2015 at 1:57 pmMy principal point is not that condensate doesn't produce the full spectrum of refined products that we get from 38 API gravity crude oil; my principal point is that the available data strongly suggest that actual global crude oil production (45 API and lower gravity crude oil) has been on an undulating plateau since 2005, as annual Brent crude oil prices doubled from $55 in 2005 to the $110 range for 2011 to 2013 (remaining at $99 in 2014).
In other words, I think that actual global crude oil production effectively peaked in 2005, while global gas production and associated liquids, condensate and NGL, have so far continued to increase.
Note that based on the following chart, it's very likely that about 40% of 2015 US Crude + Condensate (C+C) production exceeds the upper limit for WTI crude oil (which has an API ceiling of 42):
I take your points.Jeffrey J. Brown , 12/27/2015 at 2:00 pmIf Condensate is basically natural gasoline, can one infer that the amount/effort of refining required to produce retail gasoline is fairly 'easy'?
If this is so, and if gasoline is the primary refined product from crude oil (measured in volume, sales price, and/or 'importance' to the economy) then is this not a 'good' thing? And does this help explain why gasoline prices are rather low in the U.S. presently? Is it not preferable to refine 'natural gasoline'; in to 'retail gasoline' rather than process heavy oils, some perhaps contaminated with sulfur and vanadium or whatnot?
Of course I don't posit that this situation will go on for the long term, not that it is a 'good' thing wrt long-term energy planning (or lack thereof due to short-term thinking referencing current low price signals).
As noted above, my principal point is not that condensate doesn't produce the full spectrum of refined products that we get from 38 API gravity crude oil; my principal point is that the available data strongly suggest that actual global crude oil production (45 API and lower gravity crude oil) has been on an undulating plateau since 2005, as annual Brent crude oil prices doubled from $55 in 2005 to the $110 range for 2011 to 2013 (remaining at $99 in 2014).Anton Koffield . 12/27/2015 at 3:48 pmI take your point.Ron Patterson , 12/27/2015 at 4:41 pmPerhaps either or both of these things have happened since mid-2014:
- The 'system' has adjusted somehow to effective use the current crude + condensate + NGL ratios being produced at the wellhead.
- The World economy has become unsound/fragile enough that it cannot support a crude oil price, not for long without lurching into recession or worse, than the current Brent market price of $37.89/bbl.
Perhaps since gasoline comprises some 53% of U.S. finished products from crude oil, then having a goodly amount of condensate which is 'natural gasoline' has contributed to the rather low prices for retail gasoline seen in the U.S. over the past year.
I wonder what the price trends have been over the past years for distillate fuel oil and kerosene and other non-gasoline products? Have they gone up in price (as opposed to gasoline)?
U.S. Petroleum & Other Liquids Product Supplied:
http://www.eia.gov/dnav/pet/pet_cons_psup_dc_nus_mbblpd_a.htm
The bumpy price plateau for Brent (which I take it as a marker for Brent production in your example?) has been a bumpy plateau from Q1 2011 through nmid-2014, after which it nosed-dived to the current $37.89 price.
http://www.nasdaq.com/markets/crude-oil-brent.aspx?timeframe=10y
Surely the actual global crude oil production (45 API and lower gravity crude oil) has not spiked since early 2014, has it? If not, then the Brent price is not a reliable proxy for such production. See my conjectures (#1 & #2) above. There may be other conjectures which may be valid. Of course none of these ideas may be mutually exclusive.
Please note that I am scoping much of my commentary to the U.S. situation…although Brent and WTI and other price constructs are supposedly indicative of the World's supply and demand situation, yes?
Perhaps since gasoline comprises some 53% of U.S. finished products from crude oil, then having a goodly amount of condensate which is 'natural gasoline' has contributed to the rather low prices for retail gasoline seen in the U.S. over the past year.53% is little high.
How many gallons of diesel fuel and gasoline are made from one barrel of oil?Refineries in the United States produced an average of about 12 gallons of diesel fuel and 19 gallons of gasoline from one barrel (42 gallons) of crude oil in 2014. Many other petroleum products are also refined from crude oil. Refinery yields of individual products vary from month to month as refiners focus operations to meet demand for different products and to maximize profits.
However condensate, or naphtha, or natural gasoline, three names for the same thing, is not really gasoline. Gasoline is primarily octane or C8H18. Naphtha is primarily pentane, or C5H12. (Though naphtha does contain a lot of other hydrocarbons.)
Condensate is the lightest liquid petroleum product. That is it is a liquid at sea level pressures and room temperature. You can burn it in your car like gasoline. But your car will knock terribly, and your motor will not likely last very long.
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