Oil and Gas thread Only. Please post comments on all other subjects on the “Other Subjects” thread below.
Russia oil output at post-Soviet high on foreign projects, Rosneft
Russian oil output, one of the world’s largest, reached a new post-Soviet monthly high of 10.74 million barrels per day (bpd) in September thanks to foreign-led projects and Rosneft, Energy Ministry data showed on Friday.
Output rose from 10.68 million bpd in August and eclipsed the previous record of 10.71 million bpd reached earlier this year, adding to a global glut that has battered oil prices.
This answers a question I have been asking for years, “why is Russian reported production always at least half a million barrels per day higher than EIA or JODI reported Russian production”? Russia is reporting foreign production as if it were produced in Russia! What if the United Kingdom were to do this? Then the BP Alaskan production and much of the production in the Gulf of Mexico would be reported as United Kingdom production. But then the US would get to count all the oil Exxon produces around the world.
Oil Production in Russia to Drop to 310Mln Tons by 2035
Oil production in Russia may fall to 310 million tons from the current 525 million tons by 2035 given a tougher tax regime amid low oil prices and sanctions, according to LUKoil Vice President Leonid Fedun.
That is a 2.6 percent drop per year. That’s what Lukoil is saying will happen if Russia keeps the current tax structure. Of course they are lobbying for a much lower tax rate, saying that is the only way they can have enough money to invest in enough new production to hold production to only a slight decline, down to only 502 million tons a year.
Ron
‘Foreign-led’ projects on Russian soil are not the same as ‘Rosneft’ (i.e. ‘Russian’) projects in foreign / other countries. (I am not sure whether there are any of the latter, so I stand to be corected.)
In British North Sea, earlier developments were almost entirely ‘USA-led’ projects but still counted as ‘British production’.
best
Phil
The headline says “foreign projects”. The text says foreign led projects and Rosneft. A little confusing to say the least.
Ron,
You should ask Reuters journalists about confusing words.
The Russian statistics have nothing to do with this.
Phil Harris,
You are absolutely right
I think Ron was confused by the words “Foreign-led’ projects, which actually means projects with foreign participation (such as Sachalin 1, Sachalin 2 and several others). Quite obviously, Russian oil companies’ production outside Russia is not included in Russia’s oil production. Russia’s Energy Ministry provides very detailed information, which includes output by ALL producers, including large vertically integrated companies, small and medium-sized independents and companies with foreign participation.
Russia’ oil production is followed by hundreds oil experts worldwide, including the IEA, Argus, Energy Intelligence, analysts of investment banks, etc. Nobody ever have doubts about accuracy ofthe Russian oil data.
Ron probably missed my comment from the previous thread:
“The IEA’s numbers for June and August are the same, as Russia’s Energy Ministry’s preliminary estimates (they were slightly revised up).
From the September OMR (p.27):
“Russian oil production continued to defy low oil prices and international sanctions, posting nearly 150 kb/d annual gain in August. Crude and condensate output inched up 20 kb/d from July, to 10.68 mb/d, supported by high drilling rates. Russian producers have been benefitting from the rouble’s depreciation against the US dollar, with the dollar-based returns largely compensated for by rouble-based investments. The country’s flexible tax system is also sheltering producers from the price drop, with the government taking the brunt of the decline.”
Note, that in the text, the IEA mentions C+C production.
In the table, the numbers are for C+C+NGLs:
June July August
11.06 11.00 11.02
I do not know why JODI’s numbers differ from the official Russian numbers. I had already said in one of the threads 2 or 3 months ago, that JODI probably uses different ton/barrel conversion ratio.
Okay, the official Russian web site, CDU TEK in July reported production well over 600,000 barrels per day higher than JODI reported. JODI and the EIA are always very close, within a few thousand barrels of each other on Russian production numbers. They are all three reporting crude + condensate.
So who is credible, Russia or JODI and the EIA? Either Russia is exaggerating their numbers or JODI and the EIA are under reporting Russian production. Since JODI and the EIA are counting barrels and Russia’s numbers likely have political influence, I tend to believe those counting barrels rather than the politically reported numbers.
Wait. What? Doesn’t EIA take government numbers of the various countries and report them? How can there be propaganda on one report and not the other?
No Watcher, in most cases that is not what happens at all. Though in some cases it is, Norway, Mexico, United Kingdom and a few others. But they do not take such information from any OPEC country or most non-OPEC countries. Some countries do not report their production numbers to anyone.
Most information the EIA gets comes from the oil firms working in those countries or from other agents working in those countries. Others are estimates from a number of sources such as Platts. Only a very few countries can be relied on to produce accurate production numbers.
hmm are not the oil companies often nationally owned?
In general this is ridiculous. The most vital parameter of civilization, after 100 years, and we have measurement doubts?
hmm are not the oil companies often nationally owned?
Often yes but I would guess far more are not nationally owned. I have no idea what the percentage is.
In general this is ridiculous. The most vital parameter of civilization, after 100 years, and we have measurement doubts?
I am not shocked at all that this is the case. It has always been this way and we do not have a world government that can dictate that it be otherwise. It’s not really all that bad. The OPEC MOMR uses “secondary sources” for it’s data and they have been pretty close for years now. This does not create any real problems to my knowledge.
Measuring large things is its own artform. Since you can’t reliably see oil and have to estimate reserves to a certain extent based on sampling…
Hi Ron,
The density of the oil produced may be different from what you are assuming.
What do you use for barrels per metric ton of oil?
It may be that the CDU TEK website is reporting crude plus NGL even though it clearly says crude plus condensate. Or it may be that Russian crude is heavy (6.8 barrels per ton).
Hi Ron,
The IEA reports Russian crude plus condensate as 10.68 Mb/d in August 2015, slightly less than the 10.8 Mb/d reported by CDUTek (assuming 7.33 barrels per metric ton.)
The IEA also reported Russian crude oil output at 10.7 Mb/d in April 2015, about 680 kb/d higher than the EIA. Often the JODI numbers are not consistent with other agencies, as is often the case, it is hard to know which numbers to believe. The real number is likely between 10.1 and 10.7 Mb/d, call it 10.4 Mb/d until we get better data.
AlexS follows this pretty closely and probably has the best guess on Russia.
It may be that the CDU TEK website is reporting crude plus NGL even though it clearly says crude plus condensate.
You mean they may be lying? No, that is not possible for Russia to do such a thing. Oh, I am so disappointed.
The IEA reports Russian crude plus condensate as 10.68 Mb/d in August 2015, slightly less than the 10.8 Mb/d reported by CDUTek (assuming 7.33 barrels per metric ton.)
Obviously the IEA trust the Russian reported numbers far more than the EIA or JODI. I am not at all surprised.
The real number is likely between 10.1 and 10.7 Mb/d,…
The margin of error is 600,000 barrels per day? Really Dennis, do you find that reasonable? Is that the best they can do? A monkey could give us a better guess.
Hi Ron,
If the correct number was 10.4 Mb/d then the error would be +/- 300 kb/d or about 3%. Note that this is much better than the RRC does, they make an estimate of final production which is typically off by 10%.
Also see AlexS’s post below, the Russian numbers are probably best, and may be no more political than EIA numbers, perhaps they are better, we just do not know.
You can choose to believe the numbers that fit your narrative better, but its only a guess.
the Russian numbers are probably best, and may be no more political than EIA numbers, perhaps they are better, we just do not know.
Fucking nonsense! Political means the numbers are deliberately fudged for political reasons. Do you actually believe the EIA is deliberately fudging the Russian production numbers for political reason? What possible motive could they have for doing that? If so, then we may as well fold our tent and go home because the EIA numbers are worthless.
You can choose to believe the numbers that fit your narrative better, but its only a guess.
Goddammit Dennis, I don’t have a narrative. I only want the truth. Why in hell would you accuse me of having a narrative, meaning an agenda, and choosing only the numbers that fit my agenda?
If you choose to believe that a 600,000 barrel per day difference is meaningless then that is your opinion. But I have followed this discrepancy over several years. There has to be a reason for it!
Hi Ron,
Well we can speculate that it is political or say we don’t know what the reason is. I choose the latter.
No, no, no, that is not at all what you said originally. You said:
the Russian numbers are probably best, and may be no more political than EIA numbers,
Do you actually believe that the EIA numbers are every bit as likely to be political as the Russian numbers? Do you believe that the Russian numbers likely to be more accurate than the EIA numbers?
If someone is lying, who is more likely to be lying, Russia or the EIA? I would sincerely like your opinion here Dennis.
Hi Ron,
I am not back tracking. I think it equally likely that their could be political influence in a US agency such as the EIA or in a Russian energy agency.
When I said perhaps they are better, I meant there is an equal likelihood that Russia’ s numbers are better or that the US EIA’s numbers are better for Russian C+C output.
In the absence of further information it is a coin flip. That is my opinion. It seems to me that you would prefer lower output numbers for Russia as you believe that that is the truth.
It is far from clear in this case where the truth lies, so I would use the average of JODI and Russian data until things become more clear.
Hi Ron,
On the Russian numbers being best, they have the best access to the data, so for Russian output I think they would have the best estimate. Likewise I think the EIA would have the best estimate of US output.
One problem is the estimate of Russian average barrels per metric ton, often it is assumed that this is 7.3 or 7.33 barrels per metric ton. If 7.33 barrels per ton is correct the average API gravity would be 33.4 degrees.
The Urals blend is about 31.7 degrees API or 7.25 barrels per metric ton.
On political motives for reporting less Russian output, possibly the US government wants the sanctions to affect Russian oil output and has some influence on what is reported by the EIA. Likewise the Russian government wants to show that sanctions are not affecting them and might influence the Russian oil ministry to report higher output.
Possibly this could happen or the average API gravity of Russian output may be different than we think, if API gravity is 7.25 degrees (Urals blend) then output in April would have been 10.55 Mb/d, JODI had about 10.1 Mb/d in April.
AlexS showed that the NGL numbers reported by the EIA and Jodi may be about 350 kb/d too high (perhaps some condensate is being included in NGL that should be part of C+C output). If we added 350 kb/d to JODI’s April 2015 estimate of C+C output we get about 10.45 Mb/d for Russia, now the difference is only 100 kb/d, take the average and call it 10.5 Mb/d+/- 50 kb/d. That is a better explanation than “politics” in my opinion.
On political motives for reporting less Russian output, possibly the US government wants the sanctions to affect Russian oil output and has some influence on what is reported by the EIA.
The government is people, people who man the different agencies. Sanctions were imposed by the European Union and the President agreed to join them in sanctions on Russia. Now I have a question for you:
So you believe someone from the presidents office called over to the EIA and said something to the effect, “Hey guys, we need you to start fudging the numbers on Russian oil production. We want you to make them lower”. Do you actually believe that? A simple yes or no will do.
Also the president would also have to call JODI, in Riyadh, and tell them to fudge their numbers also because as you know the JODI and the EIA numbers are very close.
But wait, the president would have had to do this well before sanctions were imposed because this has been going for as long as I have been tracking the CDU TEK reports, way, way before sanctions.
At 9:21 Dennis says: “Russian output may be different than we think, if API gravity is 7.25 degrees (Urals blend) then output in April would have been 10.55 Mb/d”
Typo?? – probably should be “if API gravity is 31.7 degrees (7.25 barrels/ton Urals blend)”
Hi Clueless,
Thanks.
Yes, that was a typo I should have said the Russian oil has an API gravity similar to the Urals blend (about 7.25 barrels per metric ton)…
The API gravity of the Urals blend is about 31.7 degrees, not 7.5 degrees.
Hi Ron,
I doubt there is political influence in either case to be honest. Do you think that someone from the Russian’s presidents office called and asked the Energy ministry to report higher output? If so, why do you think it is more likely to occur in Russia than in the US.
Different countries have different ways of reporting oil output, in fact Canadian output numbers from the NEB are usually different from the EIA’s numbers. Perhaps the more important thing to pay attention to is the change in output.
We could also look at BP data, OPEC data, but generally most agencies report C+C+NGL, as AlexS has pointed out the line between condensate and NGL may be the problem. Some countries report all pentanes plus (PP) as condensate and some (like the US) report PP from an NGL plant as NGL and PP that condense in the field (usually at the wellhead) as condensate. These differences can cause data problems.
For the US in 2014 there were about 400 kb/d of pentanes plus included in US NGL output. Russia had a similar level of natural gas output as the US and if their natural gas was equally “wet” might have had similar levels of pentanes plus output.
The Russians may include these with C+C (as Canada does) and the EIA and JODI might put these in the NGL category, that would explain the data discrepancy that you have seen for years.
From a chemical perspective the way the Russians and Canadians do this makes far more sense to me.
Hi Ron,
You said:
JODI and the EIA are always very close, within a few thousand barrels of each other on Russian production numbers.
The difference between the EIA and JODI is often about 100,000 barrels or more (such as Jan 2015), so if 100 is “a few”, I usually think of few as a number less than 10.
ok Russians have projects made abroad then several questions:
1) These are the only ones to do it?
2) Why JODI where the EIA does not account?
Thomas, the EIA and JODI does count. They count production produced in every nation as oil produced by that nation regardless of of the nationality of the company who produces it.
OK Russia production reported by government is credible ?
No. If they are then both the EIA and JODI are not credible.
I didn’t realize that the book and movie The Martian started off as a serialization of a collection of blog articles.
That is actually how I put together the book The Oil ConunDrum, from a series of posts to the blog http://mobjectivist.blogspot.com and occasionally to http://TheOilDrum.com.
The only difference is that one deals with fiction and the other with peak oil reality 🙂 …. true dat, and the fact that one earned some serious coin.
And the topic of the other has implications for ALL the coin!
And your doesn’t have a happy ending.
It isn’t positive/optimistic/Homo Sapiens back-slapping enough
And the action takes decades to unfold.
All that being said, I did enjoy the book and movie, for what it is…science fiction. ‘Hard’ science fiction, but SF nonetheless.
I enjoyed your as well, for I live with the truth and work with the facts.
Ron
A political influence ?
Are you asking me what the term means? If you don’t understand that politics can influence production numbers a government puts out then just look at difference between what Venezuela and Iran say they produce and what the OPEC MOMR says they produce.
Thomas, the term simply means that a government would like to say their production was actually higher, or on rare occasions lower, than they actually were, so they just put out a number and say that was what they produced.
Really, I thought everyone was aware of these occasional political shenanigans.
How will this pipeline reversal affect US inventory builds and the WTI Brent price spread?
Canada has been waiting for the reversal of this pipeline so that the export of Canadian oil to the US can be reduced. The line is also expected to take Bakken oil to two refineries in Montreal.
Line 9 originally started flowing from Sarnia to Montreal in 1976. It was reversed in 1998 as foreign oil from areas such as West Africa and the Middle East became more affordable (Remember that famous Economist front page, Oil going to $5). Quebec’s two remaining refineries, Valero and Suncor currently process 90% foreign-sourced crude.
However, Western Canadian and Bakken crude is now priced significantly lower than foreign oil. As a result, Enbridge successfully applied to the NEB in November 2012 to reverse the flow of Line 9 once again back to its original direction.
The environmental reviews to get the approvals were very challenging. See story below.
========================================
Canada regulators green-light Enbridge crude Line 9
By Nia Williams
CALGARY, Alberta, Sept 30 (Reuters) – Canadian regulators approved the hydrotest results of Enbridge Inc’s Line 9 crude oil pipeline on Wednesday, clearing the way for the delayed 300,000-barrel-per-day route to the east of the country to start operating.
The newly reversed Line 9 will ship mainly light inland crude from Sarnia, Ontario, to Montreal, Quebec. It previously flowed in the opposite direction, taking imported crude to Ontario.
The line, originally expected to start up in late 2014, was held up after the National Energy Board ordered hydrostatic tests at three locations along the line in June.
Prior to that, regulators had asked for additional data on shut-off valve placements at major water crossings.
The NEB on Wednesday said there were no further pre-operation requirements on Line 9.
“The successful hydrotests confirm the NEB’s confidence in the integrity of the pipeline and its confidence that the line can safely be returned to operation,” the regulator said in a statement.
However, once the pipeline becomes operational the NEB has imposed conditions including biweekly patrols, quarterly integrity testing and an in-line inspection within the first year of operation.
Enbridge is also required to limit the pressure of the pipeline for its first year of operation.
It was not immediately clear how pressure restrictions would affect the capacity of the pipeline and Enbridge spokesman Graham White said the company was still reviewing the NEB notice.
He did not give an expected in service date for the pipeline.
Enbridge has previously said it expected additional testing to wrap up by the end of the year.
“There are still some technical preparations that are required and line-fill is not an exactly timed process, so we will not speculate at this time on a specific date for return to full service,” White said.
The Line 9 approval is a rare bright spot for backers of Canadian pipeline projects, which include TransCanada Corp’s Keystone XL and Enbridge’s Northern Gateway.
These projects have run into fierce environmental opposition, and last week Democratic U.S. presidential candidate Hillary Clinton said she opposed Keystone XL.
The approval is also likely to be welcomed by Line 9’s two biggest customers Suncor Energy and Valero Energy Corp , which each own a refinery in Quebec and will benefit from being able to replace imported crude with cheaper inland barrels.
Economic times have been pretty good in Canada for the most part in recent years, and the cost of gasoline has not been much of an issue.
But (wink) good times are ALWAYS eventually followed by hard times, and while oil is cheap now, it DOES deplete and the price will be going up- and going up a LOT. Only an incurable technocopian could possibly believe electrified autos etc will be ramped up fast enough to keep the price of oil down permanently.
Furthermore people and governments have near insatiable appetites.
Tar sand oil is apparently quite profitable at a hundred bucks and up -and the industry will be able to pay taxes enough for a WHOLE LOT of goods and services for all Canadians,ESPECIALLY those living in the cities and more developed areas who outnumber the ones out in the boonies by a huge margin.
Yogi sez predicting is hard, but given the survival of BAU, it is in my opinion a VERY safe bet that the tar sands oil WILL get to market.
It will get there a lot sooner if there is an oil crisis and Canadian urbanites find themselves standing in line for gasoline because there is a shortage of imported oil on the east coast.
The people who care about readily available and affordable gasoline probably outnumber the ones who really give a hoot about lines in the sand by fifty to one when you get right down to the nitty gritty.
Blocking the Keystone made and makes for political solidarity within the D party with the hard core green faction but it also had a hell of a lot to do with the R’s mopping the floors of Congress with D’s.
In the event of a real crisis we may wish like hell for a non existent Keystone after Canada makes arrangements to get that oil to market in Asia and Europe via eastern or western routes or maybe both.
An oil crisis is eventually inevitable- and it is inevitable that the oil will be burnt – somewhere. Where doesn’t matter in environmental terms.
The best imo we can hope for politically is to slow down oil consumption so it lasts a little longer.
We have a somewhat better shot at limiting coal consumption because wind and solar power plus gas can be readily substituted for coal.
This comment is about what WILL be rather than what OUGHT to be.
Robert Rapiers take on the Keystone and HRC’s politicking in regard to it:
http://www.energytrendsinsider.com/2015/10/04/president-hillary-clinton-will-oppose-crude-oil-exports/#more-18276
Given the current price of crude, I find it difficult to understand how the US would benefit long term from lifting the ban on crude oil exports at this particular juncture. What would make sense to me is to levy a substantial fuel tax on gasoline for private transportation in ICE automobiles, which would accelerate the transition to a shared EV based system. While simultaneously retooling many of our refineries to produce more high value petrochemical products and concentrate on exporting those instead.
Hillary Clinton is another example of why presidential relatives should not be elected. She voted for the Iraq war, and panders to just anybody she can find as long as the pandering is a stupid idea.
Hi Fernando,
For many it will be a question of the lesser of two evils.
OFM, As I said before, I see no evidence for a Canadian pipeline going either east or west. There are a lot of Canadians who don’t want those pipelines and have the power to say no. If Keystone XL is shut down then for the oil sands it will have to be largely rail which may not be economic.
The politics/speculation around the “No Keystone” decision are too many and varied and cover an extreme range, some real: CC impact, some extremely speculative: donations for the upcoming O library.
While the decision is clearly a CC driven issue, it accomplishes nothing from a CC perspective since it makes even less sense for the US to import more Venezuelan Ornico oil, which is as CO2 intensive as Cdn oil sands. Also shipping Cdn oil by rail to the US is more CO2 intensive. As OFM and the State Department report say, it will get produced.
The main reason for getting oil to tide water is to find its real value. At the current time, the US market dictates the price. Currently Western Canada Select is discounted by around $Cdn20 to WTI, while synthetic crude can trade ±$Cdn5.
What is interesting to note is the US environmental movement’s focussed opposition to Keystone/Oil Sands while there is no similar focus on US production of LTO and the flaring of natural gas. The movie stars that lead some of the protests don’t seem to know that one of the worst fields for CC impact is the Kern river field in their own back yard.
One of the unintended messages that the anti Oil Sands/pipeline lobby is sending to Canada is: You can’t ship this oil to tide water since it really belongs to the US and no one else is going to get it. We will need it in the future and we will build a pipeline then.
If Ron is right about Peak oil happening shortly, i.e. within a year or two, the tune might change. To quote OFM “In the event of a real crisis we may wish like hell for a non existent Keystone”.
If the environmental lobbies were really concerned about CC, they should be pushing for a North American approach on how to deal with all oil production, not just focused on Canadian oil.
If the environmental lobbies were really concerned about CC, they should be pushing for a North American approach on how to deal with all oil production, not just focused on Canadian oil.
They’d love to: a stiff fuel/carbon tax would be a good thing for everybody (but the FF/oil industry), but the Koch brothers and others have managed to push such ideas to the political margin. The only tool that’s working well right now is regulatory: CAFE regs, EPA CO2 regs, etc., and those things are facing white-hot opposition from republicans.
So, environmentalists fight largely symbolic battles over things like this.
Hi Don.
There’s been a lot of play in the Canadian press on the Energy East pipeline, which if approved and completed, would move 1.1 MBD from Alberta to Eastern Canada. (http://www.transcanada.com/energy-east-pipeline.html) My guess is that the approvals are more straightforward than the Keystone as the route is not international (though of course there is considerable internal opposition.) If I were in charge of Enbridge and was wearing my Canadian Evil Genius hat, Energy East is where I would spend my lobbying and bribing money.
-Lloyd
I think you are right about this. If a Canadian pipeline is going to be built it will be toward the east. The native population to the west have both a passion against a pipeline and the political power to say no. I guess we will see if those to the east will be able to shut this one down.
If recalled, a couple of summers ago, they burned a few cop cars in the eastern province of New Brunswick over issues related to fracking.
We’re all natives, and the native natives are getting more support than ever from the other natives.
In the pipelines’ path: Canada’s First Nations lead resistance
Where some issues are concerned, natives are fighting for everyone’s rights, ultimately, and, historically, they have been fighting the ‘state’/the ‘crown’ and suffering under it. Past time to change and help the natives out. Because you’re one too.
The Canada East pipeline, is mostly in place. Due to less Alberta gas being needed in the NE USA, they have spare gas pipelines heading west to east. They want to convert one of these gas lines to oil. There will be some new pipe laid, especially in the east.
Of course you have the French element to take into account, and their main claim at the moment is that some of the gas pipeline is still needed for gas, as in 2014 deep freeze. I believe by the time the conversion takes place, these gas lines will be even more redundant due to US Marcellus gas and the pipelines crossing the border into Canada.
Excellent point.
Also, in the long term Canada will benefit if it processes the extra heavy oil into a sweet 38 degree API syncrude. I have the diagram for two upgraders working in tandem, able to make about 500,000 BOPD syncrude and feed 120,000 B/D of diluent back to the field sites. This stream has very low viscosity, can be pumped very easily.
But if I were Canada I would limit national production to 4 mmbopd.
Blocking the Keystone made and makes for political solidarity within the D party with the hard core green faction but it also had a hell of a lot to do with the R’s mopping the floors of Congress with D’s.
What makes you think that? I haven’t seen anything in mainstream media to suggest that (Bloomberg, NYT, Reuters, etc). Perhaps it’s a big point on Fox News and talk radio, but they’re preaching to their choir.
In the event of a real crisis we may wish like hell for a non existent Keystone after Canada makes arrangements to get that oil to market in Asia and Europe via eastern or western routes or maybe both.
Why would we care about very expensive imported oil from Canada? We certainly have enough domestic fuel to power our military and our essential freight transportation. We’d be far better off to transition to cheaper EVs and more efficient ICEs for passenger travel, and rail for some freight.
“What makes me think that” is that I actually talk to a substantial number of middle of the roaders and conservatives.
You have probably heard the old joke about the pipe smoking Earth shoes wearing corduroy with elbow patches humanities professor at the small New England liberal arts college who supposedly said,”I can’t understand how McGovern lost. Everybody I know voted for him.”
I can’t remember talking to a single R leaning voter who was not pissed about the Keystone.
We are COMPELLED by reality to wander another twenty or thirty years AT LEAST in the DESERT of BAU in order – if we are LUCKY- to emerge in the PROMISED LAND of a renewable energy economy.
In case you have not noticed, peak oil is NOW or will be soon. It is BEST to arrange having as much fuel and other expendables as possible, we are VERY likely to run short before we get to the other side.
We will be DAMNED lucky if we manage it even here in the richest and best situated country in the world.
I can’t remember talking to a single R leaning voter who was not pissed about the Keystone.
Why, specifically? Are they worried about national security? Raising sale prices for Canadian producers? Reducing refinery margins?
Why do they care about Canadian oil reaching the gulf?
46.1229101,-103.0506319
Latitude – longitude of the Keystone XL pipe staging site that has been in place since 2009. I guess the libs are fine with allowing all that to go to waste? How is that environmentally friendly?
How is bringing more Canadian oil into an oversupplied world market good for the domestic oil industry?
The Canadian crude replaces a Venezuelan import stream going to Houston by tanker. As far as I’m concerned the Venezuelan regime is a clear and present danger to the USA, and efforts should be made to displace that Venezuelan crude.
As far as I’m concerned the Venezuelan regime is a clear and present danger to the USA,
In what way?
they want to sap and impurify all of our precious bodily fluids.
The funny thing about the reversal of the line 9 reversal, they are actually putting it back to it original purpose. Taking light oil from Alberta to the east. The oil that will be passing through the line will be Bakken LTO. I believe they have proved it is better to pipe the light oil than have it blow up on the rail tracks and upgraded oil to 32 api from the oil sands.
Apart from making sure the pipeline is in good condition and safe to use, it is hard to imagine what all the fuss is about, except for the usual internal Canadian politics, of course!
Saw this: ” in Jun-2014 there was a total of about 3.5 mmbbl/day of spare capacity in the global system. The Mar-2015 data point proved that. Given this, there is only about 0.5 mmbbl/day of spare capacity in the global system… a rounding error given the 94+ mmbbl/day consumption currently going on.”
Ron said:
“Oil production in Russia may fall to 310 million tons from the current 525 million tons by 2035 given a tougher tax regime amid low oil prices and sanctions, according to LUKoil Vice President Leonid Fedun.
That is a 2.6 percent drop per year. That’s what Lukoil is saying will happen if Russia keeps the current tax structure. Of course they are lobbying for a much lower tax rate, saying that is the only way they can have enough money to invest in enough new production to hold production to only a slight decline, down to only 502 million tons a year.”
Lukoil’s VP actually said that production could drop NOT “if Russia keeps the current tax structure”, but if this tax system is replaced by a new system recently proposed by the Finance Ministry. But these proposals were rejected by the government. I had already posted this link, but Ron ignored it:
Russia Reconsiders Tax Proposals to Ease Oil Producer Fears
September 28, 2015
http://www.bloomberg.com/news/articles/2015-09-28/russia-may-slow-export-duty-cuts-to-soothe-oil-company-tax-fears
• Russia won’t change oil extraction tax: Medvedev spokeswoman
• Government discussion shifts to export duty on natural gas
Russia will weigh lowering oil-export duties at a slower rate than planned instead of raising an extraction tax as the government seeks to plug its budget deficit without hurting the prospects for the country’s biggest crude producers.
“The government is considering the variant where the export duty is reduced more slowly,” Natalya Timakova, a spokeswoman for Prime Minister Dmitry Medvedev, told reporters on Monday at his residence outside Moscow. Medvedev decided that Russia won’t make changes to an oil-extraction tax, she said.
Alex, I did not ignore anything. I simply do not have time to read every comment on every post. When the numbers of comments get into the hundreds I cannot read every one and comment when necessary.
If you want to get my attention then address the post to me: “Ron”. I get every post in the email but in groups, not individual. I search on my name in order to fin all addressed to me particularly.
The link I posted was updated yesterday: (updated 12:24 03.10.2015) You link is from 6 days ago. Are these guys just slow to get the news?
http://portal.ransquawk.com/headlines/whitting-petroleum-wll-forecasts-q3-production-of-14-7-15-1-mmboe-02-10-2015
That’s 14.7-15.1 mboe for the quarter.
Okay, how does this compare to the first or second quarter? Or the third quarter of last year?
Q2 20015 170,245 BOEPD.
Drop is in line w WLL forecasts from Q2 as they plan on 2015 exit rate of 153,000 BOEPD and 2016 average of 146,000 BOEPD.
Intend on being cash flow neutral, so no long term debt reduction other than through divestments, which would be at the bottom of the market.
http://www.engadget.com/2015/10/04/daimler-self-driving-truck-test/
MB has gotten far enough along to test their stuff on a busy highway- with a driver in the truck just in case.
It won’t be long before some of this stuff will be on all new trucks.Forward looking collision warning radar alone will prevent a hell of a lot of accidents.
Emergy Society has a new web site. https://zzn.mymailsrvr.com/a/webmail.php?wsid=dedd99fc4d7f5b4cfd96c8a0119bc88d081f1029 (Emergy!)
Robert,
Your link doesn’t work… Might it, instead, be this one?
Anyway, thanks for the heads up. Looks like emergy is the big one to watch.
Oho… Kind of cute how they put it… ^u^
OMG, that’s so cute! ^u^
Ron & Group,
Maybe some of you that are working in the field can add to this. I had a phone conversation with a fella who has been looking for oil in Texas, Louisiana and Oklahoma for the past 30+ years. Says… he knows just about everyone looking for conventional plays in his neck of the woods.
Told me something very interesting. He said, that he and other guys in his industry aren’t drilling for oil, but rather some were drilling “Water Injection Wells.” Says, companies have to continue drilling these deep wells to get rid of the toxic water that comes from extracting oil, especially shale oil.
Says this could become a big issue going forward as the EPA may start cracking down on this further. He also says as shale wells get older and lose production it becomes even less commercially viable to keep the well pumping when they have to inject higher volumes of water back into the ground that are coming via the shale oil industry.
Would love to see if anyone else here can comment on this.
steve
Depends on the well.
Bakken wells seem to produce less water as they age.
Mississippian production in KS and OK seems to have a high water cut, making same uneconomic.
EFS and Permian more of a mixed bag.
Earthquake issues arise fron these wells, not from the frac itself.
shallow,
Yes, I do realize bakken wells produce less water as they age, but doesn’t the water-oil mix increase? It might be less in volume, but more in percentage terms compared to the oil?
Anyhow… thanks for the input.
steve
Steve. I’m not entirely sure on water cut in Bakken, seems it does vary well to well.
Just as with any other oilfield, some wells are better than others.
As I have pointed out here many times before, OPEX per BOE usually is lowest immediately after the well is completed, especially if it is flowing.
I thought ROCKMAN’S post on peak oil.com, which Jeffrey referred to here recently was very telling. Something like 30% of the EFS wells completed in July, 2014 are presently shut in. That is a terrible percentage.
Peruse the monthly ND well production report. Lots of shut in wells in ND too. Many are not Bakken, but quite a few are, which is not good considering the play is not ten years old.
LTO economic issues are coming home to roost. Just hard to say how much longer banks and investors keep propping it up.
I’d say a company such as Whiting is not looking good right now. SEC PDP PV10 will be less than long term debt at year end, production is falling, still cash flow negative and still must drill and complete wells to keep production from falling of a cliff.
However, no personal liability for debt and hype can keep extend and pretend going for a long time, maybe long enough to kill a lot of other high cost production.
shallow,
I couldn’t agree more about your assessment of the current state of affairs in the U.S. Shale Oil Industry. Actually, I have found out a lot of data by reading many of your comments here in the blog. I have been a bit low-key in commenting lately, but I still enjoy reading many of Ron’s posts and comments.
As you may be aware, I have my own blog, https://srsroccoreport.com/. It’s a precious metal website that includes energy into the mix. Energy is excluded by most precious metal analysts… which I find completely frustrating to say the least.
While some label me a Gold or Silver Bug, I look at the precious metals as stores of economic energy… whether that be oil, gas, coal or human-animal labor. I agree that the “Extend & Pretend” model has been going on longer than most realized. However, when it finally cracks, I would stand very far away from anything tied to debt… STOCKS, BONDS, REAL ESTATE and etc.
So, it will be interesting to see how things play out this fall if we finally get the Stock Market Crash from hell.
steve
Another interesting article linked on Peakoil.com, which links to a Fortune article:
http://www.dailyimpact.net/2015/09/30/fortune-frackers-face-mass-extinction/
http://fortune.com/2015/09/26/frackers-could-soon-face-mass-extinction/
Hi Shallow Sands,
They started drilling in the Bakken in 1953. Very few wells that started producing in 2007 have stopped producing, only 3% in the Bakken/Three Forks. For wells starting production in 2008 about 5% of wells have stopped producing, for 2009 wells 3% have stopped producing.
I define “stopped producing” as 12 months or longer of zero output counting back from the most recent month reported. I used the data through Feb 2015 so these numbers may have changed somewhat over the past 8 months.
I question whether Rockman used a reliable method for reporting on the Eagle Ford. In many cases the RRC will report output as zero when the company has not yet reported output for a lease (or the data is pending review for accounting reasons), Drilling info gets its data from the RRC and the data is not very complete. The 30% of wells that Rockman claims have stopped producing in the Eagle Ford may just be an artifact of this incomplete data.
The 30% of wells that Rockman claims have stopped producing in the Eagle Ford may just be an artifact of this incomplete data.
I really don’t think so. Rockman wrote:
So to summarize: of the 129 EFS wells that began producing in July 2014: 40 wells (31%) suffered a 100% decline rate per year. Actually it’s higher since not all produced for the entire 12 months but I’ll let that slide: there were 4 wells that stopped producing after a month or so and only recovered less than 6,000 bo each. And the 89 wells still producing in July 2015: they have suffered a decline rate of 73%.
I don’t think Rockman would make such a silly mistake as you suggest. It appears to me that he is tracking each well and the 40 that dropped out did so at different times and simply never returned to production.
Hi Ron,
I don’t have access to the Drilling info database so perhaps you are correct. I am very skeptical of Rockman’s claims. I think he assumes that because output is reported as zero, that the output is in fact zero.
I followed some Eagle Ford wells for a while and the “missing output” is often just delayed reporting which shows up later. For a better test Rockman would have to look at wells that started producing in July 2013 and see how many of those wells were still producing in July 2014, that would avoid most of the delayed reporting artifacts.
If he did so he would probably find that 5% or fewer wells had stopped producing (where this is defined as zero production for 12 consecutive months or more).
Steve and FWIIW,
In December 2014 I presented an analysis based on work by Enno and I that showed actual developments for water cut for LTO wells in Bakken (lots of charts).
General trend is that water cut (and GOR) increases as the LTO wells ages.
http://fractionalflow.com/2014/12/11/will-the-bakken-red-queen-outrun-growth-in-water-cut/
Rune. Thanks! I thought maybe you had addressed this.
I think an interesting exercise related to the high decline and increasing water cut would be to assume a company, such as Oasis, we’re to cease all drilling, completion and refrac work.
Is there any way OAS, who I think is 100% ND and MT, could come close to retiring debt at the present strip.
I would note OAS is attempting to sell all of its non-Bakken/TF acreage and production.
A confidentiality agreement is required to view the data. The public
data indicates 625
BOEPD from 95 wells. I looked at MT site, several wells are shut in. Looks the same for ND.
I read the article Jeffrey linked comparing LTO wells to water soluble houses. I can’t really tell what is better for these companies. Keep drilling at a loss or stop and try to pay down debt. What a deal.
Might be amusing if we weren’t in a pickle with much of our production also.
A rough metaphor for the shale players is the book and movie “Thinner,” by Stephen King. A gypsy places a curse on the lead character, who weighs about 300 pounds. No matter how much he eats, he loses weight, and only by consuming vast quantities of food per day is he able to minimize the weight loss.
shallow,
I posted the chart below some weeks ago.
The chart shows Oasis credit and debts stacked (columns) along their retirement profile (time axis) and the growing lines (using October-15 as baseline) shows estimates on Oasis cumulative net cash flow with oil prices at respectively $50/b and $70/b [WTI] and no wells added post October-15 (this causes a steep decline in LTO production).
The chart assumes that the credit facility is fully utilized by October 2015.
With average oil price of $50/b Oasis may clear the first hurdle, the second one (due Feb 2019 becomes challenging).
With average oil price of $70/b Oasis may find it difficult to meet debt retirements as from 2022.
How oil prices develop is a big if, but I expect these to be low for some time. The other thing is possible rollovers of debts.
To me the best strategy in a low oil price environment would be to stop drilling (LTO) wells that has the prospects of becoming unprofitable [due to the high front end loaded production]…..and pray for a higher oil price.
Hi Rune,
Thanks.
Could you clarify the following:
How oil prices develop is a big if, but I expect these to be low for some time.
How long so you expect oil prices to be low, and how do you define low oil price?
I agree that any such guess would be highly speculative, but yours would undoubtedly be better than most other guesses.
Rune,
Great chart, and yes… I remember your article on the increased water cut as a shale oil well ages. Maybe, a good solution would be to construct reverse osmosis water plants to deal with all this toxic water and build a pipeline to California to assist the farmers.
The reverse osmosis water plants could then separate all the toxic chemicals and they could be used to frack new wells for the next 1,000 years. This seems like a WIN-WIN for everyone involved.
Lastly, I wonder what happens to the price of oil when the Chinese SPR is full? Probably be very bullish indeed.
steve
Rune, thank you. I now remember your post re OAS.
As I recall, OAS is one of the many attempting to become cash flow neutral. Their Q3 numbers should be very interesting.
Below I jotted some notes about 1986,1999 and 2008 OPEC cuts. I assume you believe there is no OPEC cut on the horizon?
Shallow,
To me cash flow neutral now translates into a decline in production.
YTD 2015 (as of July) OAS brought in on average about 7 wells/month while production remained flat at around 60 kb/d (OAS operated wells), now OAS has 3 rigs running, all ND. Their present cash flow allows for adding 4-5 wells/month.
If the oil price remains at present level and OAS remains cash flow neutral for some time, they may renegotiate the terms of their credit facilities (2018) and succeed in rolling over debt (2019).
Beyond that we will just have to wait and see.
On OPEC see your thread on this.
Rune,
Thanks! I thought high water cut for LTO wells is due to fracking water and it should decline over time. But your numbers and charts tell a completely different story.
If you look at the front of the chart, you can see that at least in recent years, water cut does in fact decline for the first few months, most probably due to recovery of fracking water. It then begins rising, increasing above the initial value, but does not usually increase much while the well remains produced by pressure depletion.
I’m not quite sure why we’re referring to a ~1-1.5 water/oil ratio as “high” when in 2004, the country as a whole was running around 11 and the lower 48 around 14. Yes, that does include old waterfloods, and 71% was being recycled into injection.
If you keep injecting contaminated water into the same place, eventually it’s going to find it’s way to the surface. If the contamination was low to start with, it may not be anything to worry about by then, but it’s still going to work its way out eventually. I’m just not quite sure why we’re singling out LTO with much lower water/oil ratios. In the event of regulation, if they were to recycle the produced water into frack fluid, the volumes aren’t much different.
EPA’s regulations require that all onshore “produced water” be reinjected, very few exceptions. Of course, as well age, the water cut increases and reinjection becomes a significant cost factor.
Says this could become a big issue going forward as the EPA may start cracking down on this further.
Given the corporate and political opposition to the EPA, I can envision waste water wells being regulated at the state level.
Oklahoma Acts to Limit Earthquake Risk at Oil and Gas Wells – The New York Times
Noted last post, I suspect we have underestimated OPEX for shale out years. Lower oil output means the onsite tanks fill slower to be off loaded by less frequent truck visits.
But the trucks for production water still have to make the trip to drain the faster filling water tanks.
Hi Watcher,
I increase the OPEX over the life of the well to account for this.
SRSRocco,
A water injection well is a different animal to me than a “water disposal well”. An injection well is used in field operations to maintain reservoir pressure by injecting water or reinjecting gas into the reservoir and would be drilled by the operator not a third party service provider. Water would probably have to be treated chemically before injecting into a reservoir.
A salt water disposal well is used to dispose of produced water that is a by product of field operations. Often these are drilled and operated by 3rd party service contractors but many times an operator will drill and operate its own disposal wells.
In Texas,the general rule is that produced salt water from one surface tract can not be disposed of on a another surface tract without the consent of the surface owner. Consent is generally given in return for a per barrel fee. It is my experienc, that operators take advantage of surface owners in this regard especially when the surface owner is absentee. Other times the surface owners operate these wells as a business and accept produced water from many different operators.
Some surface owners also sell fresh water to operators as a business too.
Large unitized fields generally have their own disposal wells for produced water and the operators run them as part of the unit operations.
Many salt water disposal operators try to convert old abandoned wells into disposal wells. There has to be a formation with enough porosity and permabilty to take the water either on a vacuum (which is the ideal situation) or on a pump which takes a lot of electricity to operate.
John S, good comment.
How much electricity it takes to dispose of produced water makes a big difference in well economics right now.
In my experience, it takes more pressure, and thus more electricity, to inject water in the producing zone, as opposed to disposing of water in the most suitable non-producing zone.
Electric expenses are only second to labor in most water floods IMO, and many times can even be higher than labor. However, chemicals also are a major expense.
Having a salt water disposal well that can take a lot of water on a vacuum or at low pressure can be an asset. I have recently seen some commercial disposal wells for sale, with monthly net income as high as $30K.
A good water supply well is also very useful in water flood operations. However, very important that the water can easily commingle with water in the producing zone. Otherwise, tremendous chemical expense and/or down hole problems may result. Also, tends to clog lines.
I would say most US water floods are not doing well economically at present. In the last thread had a discussion about an MLP, Mid-Con, and their expenses.
Many MLP are heavy into water floods. Also, think OXY and Chevron are big water flood players in the Permian, in addition to CO2 floods. I think many CO2 floods originally were water floods.
MBP indicated secondary and tertiary production is still profitable in the Permian. Would be interested to see OPEX, taxes and G&A for some of the larger water and CO2 floods.
Kinder Morgan has two of the largest CO2 floods in SACROC and Yates. Might see if they break out those costs. I think they have an advantage in that they own a lot of CO2 transmission lines.
Shallow,
Do you have any idea how a COPAS Agreement for a horizontal LTO or Shale Gas well differs from a conventional well COPAS agreement?
I would like to see the accounting provisions for allocating overhead for a drilling/DUC well vis-a-vis a producing well/non-producing well. I imagine that allocating overhead costs between HQ/Division/field office is enlightening too.
David Arrington/ Arrington Oil and Gas has set up a new company to do a Wolfcamp A,B,C & D town lot lease play within Midland, Texas. At a town hall meeting, his representatives said they may drill 30 wells in a 1,280 acre unit from one drill site.
I would love to see the joint operating agreement and accounting provisions.
John S. I do not know the answer to your question, but would like to see that too.
If you are able to log in to energy net may be able to find some of this stuff. I did see there is a large non-operated WI for sale in Karnes Co. EFS, with Marathon Oil as operator. 16 wells on around 900 acres with more planned. I think at least one well is in Austin Chalk.
Some of the bigger fields for this are Wasson (Denver Unit), Slaughter, Levelland, Seminole, Goldsmith, Howard-Glasscock (SACROC), and yates (the last two you already mentioned). You could probably find the operators for the fields and look it up from there.
All CO2 fields (at least here) start out as waterfloods. The rule of thumb is that a good waterflood makes a good CO2 flood (thought streaky perm or a lack of understanding of the sequence stratigraphy can kill this). CO2 floods are very expensive to initiate, so it doesn’t make sense to start one in this price env’t, but you generally want to test a fields viability for waterflood before you invest (minimally $50 MM for full field) for a CO2 flood.
MBP. I looked at Kinder Morgan. They do break out CO2 production segment. It looks to me that OPEX/LOE was about $26 per bbl at the end of the Q3, 2014 and about $23 per bbl at the end of Q2, 2015. Does that seem reasonable?
I am not sure I have that correct, as 1/5 of sales were NGLs, CO2 sales were also included, and I did not allocate operating expense to CO2 production, so I could have overstated the costs.
MBP & Shallow,
This a kind of “For What it’s Worth” comment.
I worked for a small tertiary CO2 producer for a short time. I really enjoyed it. The people were really talented. The engineering hurdles are immense, especially for the old, worn out water flood. I might have worked with you MBP.
In my opinion, there is a lot romance in the CO2 floods. I hope I get the opportunity to work on another one some day.
That’s probably in the ballpark, it wouldn’t surprise me if it was in the $21-25/bbl range. I don’t really know much about how they operate though. They do control the supply of CO2 thought which helps them over other CO2 flood operators who have to purchase their CO2.
John, I don’t work for a company that just has CO2 floods, but if you were in that segment of the industry we quite possibly crossed paths.
MBP, thanks. I suspect many CO2 floods are still okay on an operating basis, but tough to justify new projects given the upfront costs.
As always, to get the full picture, we need to know how much CAPEX is being spent, and a breakdown of what part is to maintain and how much is to increase production. Also need to know G & A allocated to the project.
I have been seeing more Permian Basin leases for sale recently. In 2012-14 that was pretty rare.
Also, seeing a lot of “LTO” acreage coming up for sale in the Permian, as I assume there is now better information as to where the “sweet spots” are and are not. There have been some really uneconomic wells, one year cumulative under 50K BOE probably does not cut it.
There are plenty of bad wells, but also a lot of good wells. I know of a well in the Delaware Basin that was drilled in February that had produced 150 MBO and 211 MMCF by the end of July. The goal is to drill more like that one.
MBP. That is a good well.
RE: Russian oil production statistics from various sources
Ron,
I personally never questioned the reliability of Russian oil statistics. But as you have repeatedly raised this issue, I did a brief assessment of the data from various sources.
The Russian Energy Ministry provides very detailed data on oil + condensate production by each Russian producer on a daily basis. As in Soviet times, these numbers are reported directly by the companies to the Ministry. They can be easily verified as all oil produced is transported by pipelines owned by the state –owned Transneft. Small quantities are processed for internal use by the companies at mini-refineries, but their throughput is also reported to the ministry.
The Ministry reports production in tons without converting it in barrels per day. However other sources (including Russian and foreign oil companies operating in Russia) use conversion ratios at 7.33 and 7.3 for Russian oil production. In the table below I calculate both numbers.
NGL production is reported separately and is not included in C+C numbers.
IEA oil production statistics include C+C+NGLs, however in their recent monthly Oil Market Reports the IEA is also mentioning C+C production for Russia. These numbers are very close to the data provided by the Russian Energy Ministry. In the past, the IEA did not disclose separate numbers for the Russian C+C, and it was first mentioned in the May OMR (p.25):
“Despite sanctions and lower oil prices, Russian producers managed to maintain crude oil output near record levels through April, hovering around 10.7 mb/d since the start of the year. Including gas liquids, Russian output exceeded 11 mb/d in both March and April.”
Note, that the IEA works closely with Russia and gets data directly from the Russian Energy Ministry.
The EIA has detailed oil and other liquids production data for many countries and releases it excel format:
(International Energy Statistics, Petroleum Production http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=50&pid=53&aid=1). This is very useful when you don’t have other sources of data. However in many cases the EIA does not get information directly from national sources and uses third party data. Besides these numbers are relatively rarely updated and in some cases look incorrect. For example, their newest international oil production data are for April 2015.
The EIA also publishes “Total liquids supply” data for the key producers in the STEO, where the numbers are updated monthly. (STEO excel file, Table 3b. Non-OPEC Petroleum and Other Liquids Supply).
Note that the updated numbers for Russia in the September STEO are 143 kb/d higher for April and 132 higher for March, compared with the EIA International Energy Statistics. Given that the EIA constantly estimates Russian refinery processing gains at 26 kb/d, we can easily calculate C+C+NGL production estimates up to August by subtracting 26 kb/d from the STEO Total liquids numbers.
As a result, as can be seen from the table below, EIA’s C+C+NGL production estimates for Russia are only marginally below the IEA’s numbers (the average discrepancy for Jan.-Aug. 2015 is ~40 kb/d).
You can also note that the EIA’s estimate for Russia’s NGLs output in the first 4 months of 2015 is around 755kb/d, while the IEA’s number is only ~350 kb/d. I think that the EIA classifies all or part of Russian condensate production as NGLs, while in the IEA and the Russian Energy Ministry’s statistics it is included in the C+C output.
Finally, JODI data is based on national statistics. As it says on its website: “The data are submitted by the national authority of the participating country. These data are considered authoritative and are not subject to alteration by any of the JODI partner organisations.” (https://www.jodidata.org/about-jodi/faqs.aspx). Nevertheless, in some cases JODI
data differs significantly from national statistics. JODI does not explain its methodology, and its officials do not respond to emails to comment on why its data differs from figures provided by national agencies.
JODI provides data on both Russian oil and NGL production. NGL data is much higher than IEA’s numbers, but slightly lower than the EIA.
JODI data is released with significant delay to the IEA and especially to national statistics. I also noticed that, unlike the IEA, they generally do not update the numbers released earlier. That can partly explain, why JODI numbers for Russia are lower than data from other sources. On average, JODI’s C+C+NGL numbers for January-July 2015 are
203 kb/d lower than IEA and 164 lower than EIA.
In general, all serious experts on Russian oil industry use the official numbers provided by the Energy Ministry.
Russian oil production statistics from various sources
I think Russian production would be easier to measure given it is much lower decline, there aren’t as many companies nor as many governmental agencies measuring it.
It appears to me US data is the most variable and likely inaccurate.
Hi AlexS,
Great post thanks.
Hi AlexS,
Do you know what the average API of Russian output is? Has it been getting heavier?
I know the benchmark has been the Urals blend at about 32 degrees API (7.2 barrels/ metric ton), has output gotten heavier so that maybe 29 degrees API may be more appropriate for 2015 Russian output? I wonder if part of the discrepancy is that Russian output is 7 barrels per metric ton, but the EIA( and JODI) are mistakenly using 7.33 barrels per metric ton?
Edit:
I looked at Jodi numbers vs Russia’s numbers. If the average Russian barrel is about 6.95 barrels per metric ton then the numbers match up and it is the IEA that is overestimating Russian output.
If 6.95 barrels per metric ton is correct, that would be an average API gravity of about 25 degrees for Russian C+C output.
I could not find this data on the web however.
Russia only gives their production in metric tons. Conversion to barrels per day is done by the different agencies who report their production.
Hi Ron,
I think AlexS has solved the discrepancy between the EIA/JODI data and the IEA/Russia data. It is mostly a matter of how pentanes plus should be classified.
The EIA puts some of these(field or wellhead pentanes plus) in the C+C category and the pentanes plus produced during natural gas processing (to produce dry gas to ship to customers) is included in the NGL category. Canada and Russia group all pentanes plus together in the condensate category (which makes perfect sense from a chemistry perspective), this accounts for about a 400 kb/d difference between EIA estimates for Russian C+C and the Russian Energy ministry estimates. The rest of difference might be due to the EIA assuming a different estimate for the density of Russian C+C (possibly they use the density of the Urals blend which would have a reciprocal of 7.25 barrels per metric ton) than the IEA (which uses about 7.31 barrels per metric ton).
Dennis,
In fact, the lighter is the barrel, the more barrels are in 1 ton.
43961 ktons reported by the Energy Ministry for September
is 10741 kb/d with 7.33 conversion ratio
10697 kb/d with 7.3
10551 kb/d with 7.2
10404 kb/d with 7.1
10258 kb/d with 7.0
10111 kb/d with 6.9
As I said earlier, the most widely used ratio is 7.33 (the numbers in Reuters and Bloomberg articles, as well as all Russian statistics by Energy Intelligence, etc.) and 7.3 (apparently used by the IEA)
I also prefer 7.3, as I think the average Russian barrel is heavier than 7.33.
That said, the Russian oil output is getting lighter due to the growing share of new fields in eastern Siberia, Far East (Sakhalin) and some other regions. Thus, according to Platts, the Urals blend API is 31.55 API,
ESPO (East Siberia) is 34.8, Sokol and Vityaz (Far East) are 39.7 and 34.4 API degrees, respectively.
(Source: http://www.platts.com/im.platts.content/insightanalysis/industrysolutionpapers/espoupdate0510.pdf )
So in theory, as the share of lighter crudes rises, the conversion ration should also increase. But I doubt that the IEA, EIA or JODI are changing their conversion ratios.
The EIA and JODI do not specify which conversion ratios they are using for Russia. If they are using 7.2 or 7.1, that could partly explain the discrepancy between their numbers and Energy Ministry and the IEA numbers.
However the key difference is the volume of condensate and NGL output. It seems that JODI and the EIA account most of condensate production as NGLs. Therefore, their NGL volumes for Russia are much higher than the IEA, and their C+C volume estimates are lower than the numbers provided by the IEA.
The IEA normally reports only combined C+C+NGL volumes, but this year they also include C+C production numbers for Russia (in the OMR main text). By subtracting C+C from C+C+NGL we get the IEA’s estimate for Russian NGL production at 340-350 kb/d in the past several months. This compares with the EIA’s 755 kb/d average monthly estimates (January-April) and JODI’s 710 kb/d estimate (January-July).
I think that the IEA’s numbers are more accurate, as in 2010 they published a study on global NGL production, where they carefully analyzed NGL and condensate production for the key producing countries using national statistics, as well as information provided by individual companies.
(“Natural Gas Liquids Supply Outlook 2008-2015.” IEA, April 2010. http://www.iea.org/publications/freepublications/publication/ngl2010_free.pdf )
Here are their numbers for Russia’s output levels in 2008:
Condensate: 356 kb/d
“Other NGLs”: 180 kb/d
Total NGL and condensate: 536 kb/d
From the IEA report: “The Russian Ministry of Oil and Energy does not report NGLs per se, but they do report LPG and condensate production per company. In this study we have applied the reports of LPG and condensate production per company as a starting point to arrive at a proxy for Russian NGL production. Based on the reported figures at August 2009 the LPG production of Russian gas processing plants was 230 kb/d, while the condensate production was 361 kb/d, a total of 591 kb/d.”
In this report, the IEA projected a sharp increase in Russia’s “Condensate and other NGLs” production from 536 kb/d
In 2008 to 817 kb/d in 2015. Indeed, as we know now, both condensate and NGL output has increased even faster in the past few years due to: 1) increasing production of wet gas, 2) better utilization of previously flared associated gas, and 3) development of several new gas condensate fields. Thus, in the first quarter of 2015, gas condensate output jumped 18% year on year to 7.86 million tons (~640 kb/d) due to the launch of new production facilities in West Siberia, primarily by Novatek and Gazprom Neft. As per the IEA numbers, NGL output also almost doubled from 180 kb/d in 2008 to 340-350 kb/d in 2015.
Apparently, JODI did not researched as deep as the IEA into the Russian NGL and condensate output, so they account most of condensate as NGLs.
As regards the EIA, their list of sources for International Energy Statistics [http://www.eia.gov/cfapps/ipdbproject/docs/sources.cfm] does not include the Russian Energy Ministry. This is rather strange, as they get data from the national agencies of such countries, as Cuba, Mongolia and others. Apparently their numbers for Russia are based on statistics from JODI, the IEA and the “Russian Energy Monthly, Eastern Bloc Research” (never heard of it).
That said, I do not suspect JODI and the EIA of being biased against Russia. These are just different statistical methodologies.
If you measure 100 cc of oil in a graduated cylinder, since the density, specific gravity, is less than water, 100 cc of oil will weigh less than 100cc of water. 1 cc of agua weighs 1 gram, 1 cc of oil will weigh less than one gram, you will need more oil, a greater volume, to obtain a weight of one gram for the oil.
A metric ton of oil will occupy a volume greater than one cubic meter, more barrels.
Russian crude oil and NGL production (kb/d)
Source: JODI
Jan 2012 Refineries came on line (?) Mother Russia keeps the good stuff for value added high density i.e.. Diesel/jet fuel? Russian polymers in the 90’s were terrible and next to useless for packaging. Many markets now well supplied with SABIC Polymers. https://www.sabic.com/americas/en/productsandservices/plastics/
In January 2012 JODI changed its methodology and started treating Russian condensate production as NGL
Thanks for all the info AlexS. What about kilowatt hours or Btu’s? It would be nice to know C and C production with those units as well.
Hi AlexS,
Thanks for all the information. One problem with EIA data (and possibly JODI data as well) is that the US EIA treats pentanes plus in two different ways. If it occurs in the field as a condensate at the wellhead it is included in the C+C output, but if it is produced in a Natural Gas Plant where the pentanes plus and other NGLs are removed from the natural gas stream, then they are included in the NGL category. Canada groups all pentanes plus together (as they are the same chemically), perhaps Russia does the same, which would probably account for about a 350 to 400 kb/d difference in the level of NGL output in the EIA data (NGL is 350 kb/d too high and C+C is 350 kb/d too low).
Dennis,
I think you are right. The EIA’s definition of NGLs includes
pentanes plus (http://www.eia.gov/todayinenergy/detail.cfm?id=5930). The IEA, similarly to the Russian statistics, apparently treats pentanes as condensate.
JODI changed its statistics for Russia from January 2012.
No conspiracy theories, just different methodologies.
Hi AlexS,
Thanks very much for your excellent work. I think you have found the reason for the difference between the Russian Energy ministry’s Russian output estimates and those of the EIA and JODI.
This is more about methodology and has little to do with politics.
Thanks Dennis,
The idea about pentanes+ was yours.
Guys, am I missing something? The definition of condensate is pentanes plus. And plus means from five carbon atoms, pentane, plus six seven and even sometimes eight (octane) carbon atoms.
From the EIA
Lease condensate: Light liquid hydrocarbons recovered from lease separators or field facilities at associated and non-associated natural gas wells. Mostly pentanes and heavier hydrocarbons. Normally enters the crude oil stream after production.
All of a sudden this is some kind of revelation? It was something I assumed everyone already knew.
Ron,
from the EIA (your link):
Natural gas plant liquids (NGPL): Those hydrocarbons in natural gas that are separated as liquids at natural gas processing plants, fractionating and cycling plants. Products obtained include ethane, liquefied petroleum gases (propane and butanes), and pentanes plus. Component products may be fractionated or mixed. Lease condensate is excluded.
—————-
The trick is that pentane and pentanes plus obtained at natural gas processing plants are included in NGPLs.
Russian statistics treat them as condensate
Also from EIA
{http://www.eia.gov/todayinenergy/detail.cfm?id=5930}
An important thing we are (were) missing is that the EIA statistics are for “LEASE condensate” rather than “condensate” and “NGPL” rather than “NGL”
Hi Ron,
If you look at the EIA statistics for NGL output from natural gas plants you will see that there was about 400 kb/d of pentanes plus included in the NGL output.
See http://www.eia.gov/dnav/pet/pet_pnp_gp_dc_nus_mbblpd_a.htm
pentanes plus in 2014 was about 13% of US NGL output (400/3000)
In Russia or Canada these 400 kb/d of pentanes plus would be included in C+C output data. This accounts for much of the data discrepancy, the rest is just a difference in the assumption about barrels per metric ton. If the IEA uses 7.33 barrels per metric ton and the EIA uses 7.25 barrels per metric ton the EIA would get a 117 kb/d lower output estimate than the IEA, add in the 400 kb/d difference in accounting for pentanes plus and we have explained 517 kb/d of the 600 kb/d discrepancy you were concerned about. We are down to an 83 kb/d difference.
I would take the average of the two estimates(JODI and IEA) so that Russian C+C output (with all pentanes plus included in C+C data) would be 10,560 kb/d +/- 130 kb/d in August 2015, September was slightly higher (about 10.6 Mb/d).
There is no need to accuse anyone of lying, these are simple methodological differences. In my opinion the Canadian and Russian method of including all pentanes plus in the same category (condensate) is better than the EIA’s method of putting some pentanes plus in the condensate category and other NGPL pentanes plus in a different category (NGPL).
This difference in methodologies between countries may be the reason that many agencies focus on C+C+NGL (because the pentanes plus problem goes away).
Schinzy,
Unlike the EIA, the Russian Energy ministry does not report hydrocarbon production measured in BTUs
AlexS. Does Russia have fields producing from 2,000 feet or less?
If so, any information about them would be of interest to me.
Thanks!
shallow sand
Most of oil fields in West Siberia and Volga-Urals basins are located at depths ranging from 2000 to 3000 meters (6500-9800 feet).
There are some shallower fields at 1200-1500 meters (3900-4900 feet).
I haven’t heard about conventional fields producing from 2,000 feet or less, but Tatarstan (Volga region) has significant resources of extra-heavy oil (bitumen) at ~400 meters depth
.
There are several small shallow fields at places like Sakhalin and North Caucasus, but nothing significant. Kazakhstan, on the other hand, has fields like Karazhanbas: 1,000 feet deep, steam injection.
http://en.wikipedia.org/wiki/Karazhanbas_oil_field
Thank you for the info!
This is pretty good write-up on how difficult job is to down scale the costs in low price environment. It is way more complicated than just reducing hourly rates.
http://oilprice.com/Energy/Energy-General/Should-Oil-Field-Services-Companies-Stand-Their-Ground-More.html
So Russian production is still increasing, thanks to the technology brought in by Western oil companies. The problem I see is that, at current prices, there’s not a lot of drilling that can be conducted. Oil companies that want to drill (as opposed to bringing expertise to established wells) would be betting on a substantial rise in prices before production starts. I can’t see many oil companies doing that at the moment – Saudi Arabia hasn’t succeeded in giving the US tight oil industry a knockout blow, so prices will stay down for a while yet and, if they do increase in the near future, US tight oil will recover.
What this adds up to is, in my view, a sustained decline in capex in the oil industry, followed by production declines across a wide front in a few years. It’s only when depletion has eroded current production levels that US tight oil production can increase without sparking another price collapse. By then, however, sweet spots in the Bakken and Eagle Ford might be getting harder to find.
We have a surplus of oil at the moment. This surplus won’t last, unless strong action is taken on climate change. And I don’t expect any US President to do that.
With regards to Keystone and ‘Dirty oil’ from Canada.
Jacobs engineering figures emissions from oil-sand crude are 12 percent higher than from regular crude. EU as per Stanford University academic Adam Brandt comes up with 22 percent.
Old news link for source of my statement.
http://www.reuters.com/article/2012/05/10/us-oil-sands-idUSBRE8490OL20120510
I read a short article recently that I cannot find again which says there has been a general trend for a long time now for vertically integrated oil companies to shed retailing operations ( company owned service stations ) and then regional wholesaling operations ( storage and trucking etc ) right on up to the refinery level.
Just looking around as a layman I see no reason to doubt this is true.The percentage of stores and stations that sell major brand name gasoline around here has dropped WAY off over the last few years. I would like to hear it yea or nay from somebody who knows for sure on the national and international level.
No, Russian production is genuinely at an all-time high. It’s not like the Russians count Lukoil’s production in Iraq as “Russian” LOL!
Consider also that Russia is under sanctions specifically designed by the West to harm its oil output.
Peak-oilers are over-eager to claim that country “X” or “Y” has peaked in terms of oil production. This is often not the case.
The only countries that have peaked in oil production, are the capital rich ones of the West. The reason for that is very clear. Those countries started exploiting their oil reserves earlier, and even more importantly have had the capital and technology to extract even the most marginal of deposits. Even in those cases, ultra-cheap financing can lead to temporary booms (US shale, Canadian sands) even if production takes place at a considerable financial loss.
Countries like Iraq, Iran, Russia or Kazakhstan still have lots of untapped reserves.
This also partly explains the current World Crisis that could even escalate into WWIII.
There’s an interesting article in OilPrice on Russia:
http://oilprice.com/Energy/Energy-General/Is-Russia-Plotting-To-Bring-Down-OPEC.html
The author uncritically accepts the myth of the “Great American Shale Revolution,” which, as you say, is a play in which “production takes place at a considerable financial loss.”
Nevertheless, the take-away is the importance that oil and gas play in geopolitics.
Countries like Iraq, Iran, Russia or Kazakhstan still have lots of untapped reserves.
Which oil reservoirs are untapped in these countries?
More on US shale…one European perspective
http://gefira.org/en/2015/10/02/us-shale-oil-industry-will-simply-vanish/
”Nowadays, the main oil price factors are the economic condition of China and expectations of demand growth in emerging markets. The oil price seems to be closely correlated in recent months to China’s Purchasing Managers’ Index (PMI), which declined in August to 47,3, the lowest level in last six years. Also increased uncertainty of developing Asian countries affected the price”
Gotta wonder bout such an Ad in an article titled “us-shale-oil-industry-will-simply-vanish”
Most Likely it’s the Investor that will vanish – the oil industry will be “right sized” when forced focus on fundamentals. Sad.. but the Ad title … OIL BOOM is spot on.
Seems like that add pops up a lot. With WTI averaging about $46 for Q3 and right there yet today, seems like OIL BUST is now the more appropriate term.
Oil production and related liquids is generating about $5 billion per day less worldwide than it did in the 2012-2014 time frame. Big transfer of funds from one group to another.
KSA realizing around $180 billion less on an annual basis. Wonder how long before they feel backed into a corner enough to do something. Looks like Russia may outlast them, as KSA is pegged to dollar and Russia isn’t.
Maybe Jeffrey can send KSA royals some good bean dish recipes and some free ice cream cone coupons from DQ. LOL!!
shallow sand,
Saudi Arabia, with its huge foreign reserves, could withstand for 3 or 4 years at $50 oil. By that time, prices will improve.
AlexS. KSA could go longer than that as I assume many banks would be willing to loan them money with reserves as collateral. They also could issue many more billions of unsecured bonds.
However, OPEC did not go years without cutting in 1986, 1999 and 2009.
Each time the cut worked. The price went up significantly. 1986 was not as successful as the other two cuts.
I may be wrong, but for US producers, it is likely the only hope.
shallow sand,
In 1986, OPEC actually started increasing production after unsuccessfully trying to stabilize prices by cutting output over the previous 5 years. Their market share dropped from 45.4% in 1979 to 27.6% in 1985, but was constantly increasing from 1986 and has reached 41.9% in 1998. Over the whole period prices remained low (with only a short spike during the Gulf war in 1990). But, for OPEC countries, this was partially offset by the increased production volumes from 15.9 mb/d in 1985 to 30.7mb/d in 1998 (almost twice).
AlexS.
I am just looking at history regarding a cut. The past may not be repeated, I agree.
1985-1986. WTI dropped 62.4% from 11/85 to 7/86, from around $31 to $11.50. In November, 1986, OPEC set a target price of $18. 1/87 WTI averaged $18.65. By 7/87 the average was up to $21.34. I do agree the price collapsed again in 1988, but recovered. The price typically was 60-70% of the $31 high in 1985 until the 1998 collapse.
1998-1999. The price dropped approximately 55% from late 1997 to 12/98, when the monthly average was $11.35. I remember that very well. Glum Christmas Party. We were at $8 and change. 3/23 OPEC announced 2.2 million barrel cut. 7/99 average $20.10. 12/99 average $26.10.
2008-2009. Price dropped 71%. June, 2008 average $133.78. February average $39.09. OPEC announced stages of cuts, 500K 9/08, 1.5 million 10/08, 2.2 million 12/08. By 6/09, monthly average 69.64. By 12/09, $77.99
2014-15. Price dropped almost 64% from June, 2014 to August, 2015. June averaged $105.79. August, 2015 averaged $42.87.
Maybe OPEC will not cut in December, 2015. Going by history they will soon. They have not let things go more than 18 months from the peak in the past. 12/4 meeting will be at 18 months from June peak.
Go read news stories from 1986, 1999 and 2008-2009. KSA was concerned about the price each time and stated such. Things are not peachy, contrary to both KSA and Russia official mantras.
Again, I could be wrong, just looking at history. Otoh, maybe lower for longer is needed to stifle the ridiculous North American CAPEX. When reading stories from late 2008, COP had announced a CAPEX budget cut of 18% to $2.8 billion for 2009. By 2014 the CAPEX budget had ballooned to over $17 billion. COP, of course, is a big player in tar sands and all major US LTO plays, so would be a good proxy for “out of control spending.”.
AlexS
We could live with 60-70% of the 6/14 high for quite awhile, which would be $63-74 WTI.
Apparently at this time the crude market does not believe this is enough to stifle North American (sans Mexico) production.
What do you think about this price range from maybe 7/16-12/20? Where do you see LTO in that scenario?
Hi Shallow Sands,
That price range sounds about right for 2016, but I think we may see it creep up by 2017 (maybe at a 5 to 10% annual rate of increase) because those prices will not be enough to encourage much investment so demand will outstrip supply and drive oil prices up. I think it likely we will see $100/b by 2018 (possibly higher), if the peak has arrived by 2018 (and output is either on a plateau or slowly declining) then oil prices may head to about $150/b within 3 to 5 years, though a recession would put a damper on the oil price rise eventually (within 1 or 2 years of reaching $150/b is my WAG.)
Others predict a permanent recession (or very slow growth) due to high debt levels.
If that hypothesis is correct, the future economic outlook is indeed very grim, even in this scenario supply would decrease faster than demand (due to low prices and lack of investment) and oil prices would eventually rise (probably not until 2020), but at a slower rate of increase maybe reaching $100/b in 2025.
I don’t find the excess debt story very compelling, but many do.
Shallow sand,
Parallels with 1985-86, 1998-99, 2001-02 and 2008-09 may lead to erroneous conclusions.
Sharp oil price declines in 1998-99, 2001-02 and 2008-09 were caused by cyclical demand reduction during global recessions. It was relatively easy, for OPEC, to support prices by cutting output, as demand quickly rebounded. OPEC restored production levels in a few months and didn’t lose its market share.
By contrast, oil price decline in the 80s was due not only to a deep recession (1980-83), but also to long-term trends triggered by the oil price shocks of 1973-74 and 1979-80. These included oil substitution by natural gas in power generation and industry, oil/energy saving measures, and a sharp increase in oil production in the North Sea, Alaska, Mexico and Western Siberia. OPEC initially tried to offset falling demand and the tide of rising non-OPEC supplies by cutting its own output, but this proved inefficient. Competitors were taking its market share and prices continued to decline. Therefore, Saudi Arabia and other OPEC members changed their market strategy from defending prices to defending market share.
The current oil price slump is due to long-term trends in supply (primarily LTO, but also Canada and some OPEC members). Cutting OPEC output to maintain prices would only support LTO and other non-OPEC supplies, including costly projects such as Arctic. As we have seen in 2Q15, even at $60 WTI tight oil producers are ready to increase drilling activity, but at the current $45 LTO production is declining. Therefore, it doesn’t make sense for Saudi Arabia and its neighbors to cut output and support competitors. They will wait until rising demand and stagnating or declining non-OPEC production will finally erase excess supply. That will take much less time than in the 80-90s, as current spare capacity is only about 2.5 mb/d vs. 11-12 mb/d in 1985.
Hi AlexS,
Here is the problem if OPEC follows the path that you suggest. CAPEX cutbacks will bite hard after a lag period and supply will be unable to meet demand which may lead to a super spike in oil prices, followed by recession and lower demand. OPEC would be better served by less volatility in the oil market, oil prices that are too high may lead the World away from oil sooner than OPEC would prefer.
A small cut by OPEC to get oil prices to the 65 to 75 dollar per barrel range might keep oil prices from rising too far too fast and would be their best strategy. If prices remain at $50/b for much longer LTO output will begin to crash in 2016, it is far from clear that there is much ability for the World to make up the difference and LTO may not rebound as fast as some believe. Financing may prove to be a bottleneck as the US oil industry picks up the pieces.
Hi Dennis,
That would be optimal best solution for Opec to do what you suggest but, there is one thing that OPEC cannot control in that scenario. And that is greed. As soon as price moves to $60 as we have seen in the spring everyone start pulling their stacked rigs from the yard. Everyone moves in auto-pilot mode with single goal “Let’s get drilling” even though that even at $60 the only thing that they are drilling is cash into the ground. It is just paradox of the this world.
Dennis,
You said: “Here is the problem if OPEC follows the path that you suggest. CAPEX cutbacks will bite hard after a lag period and supply will be unable to meet demand which may lead to a super spike in oil prices, followed by recession and lower demand.”
In my view, that might happen not earlier than the beginning of next decade. There is still a surplus in the market of around 2 mb/d. It would take time before it is erased. As prices start to rise again, there will be additional supply from Iran, Iraq and Brazil. Libyan oil will also eventually return to the market.
Finally, while LTO output might indeed “begin to crash in 2016” if oil stays below $50, the shale industry will not be killed. After all, the necessary infrastructure remains in place; there is a vast fleet of drilling rigs and fracking equipment. Some companies might go bust, but their assets will be bought by bigger and stronger players. Financial markets will be cautious and access to capital for LTO producers will be more difficult, but it will not be cut. I agree that “LTO may not rebound as fast as some believe”, but I think it will take no longer than 6 to 9 months. If and when WTI reaches $65 LTO industry will show first signs of life, and at $75-80 it will resume steady growth.
Annual growth rates of 1 mb/d are in the past, but 500 kb/d are quite possible, probably not for 7-8 years, as Mark Papa says (see Ron’s link below), but at least for 4 -5 years.
Super spikes in oil prices are possible in the future. The oil industry is cyclical and is known for big fluctuations in prices. But I do not think that potential price spikes in the next decade is what is seriously worrying the Saudis at this moment. So their decision not to cut output now seems quite logical to me.
Hi AlexS,
Well if your assumptions about new oil coming to market are correct then there will be no danger of a superspike in oil prices.
I don’t think $70/b oil will cause a lot of new output to come to market. The Saudis export about 8.8 Mb/d of crude and petroleum products, an extra $20/b amounts to $176 million per day or $64 billion per year.
For all of OPEC about 27 Mb/d of crude plus products are exported, so raising oil prices by $20/b increases revenue by $520 million per day (assuming 1 Mb/d lower output) or about $190 billion per year.
The oil market may adjust very smoothly in the absence of any cartel action, but this will be historically unprecedented.
I have a little faith in markets, but you must be a true believer in free markets. I am not, markets need some regulation and in the absence of the RRC or OPEC, the oil market will be Volatile.
Shallow,
I am much on the same page as AlexS here.
It is hard to know what OPEC’s true objectives are; there is a lot of chatter in the media.
I noticed KSA recently (again) cut the price to some of their Asian customers.
A lower oil price stimulates consumption (demand) and there are some new developments that still may grow the supply side. Then there is Brazil, Iran, Iraq and Libya (to name some).
To me the big unknown is how demand, especially in emerging Asian economies develops and the slowdown in China’s imports of commodities (iron ore, coal, nat gas etc) are signs of a slowing economy. China has been pulling their neighbors, so as China slows so will others.
If one follow the commodities flows to China through the Chinese factories the end products normally ends up with consumers all over the world. Lower commodity prices may be a sign about consumer’s general financial health (a demand issue). These are indicators that may be helpful in understanding directions for global oil demand.
There are also some reports about China now filling their strategic petroleum reserve. In other words, what one needs to do is break the demand into consumption and stock build.
OECD has a huge (and growing) stock overhang which needs to be worked through.
Now I hold it 70+% probable that OPEC will not cut during their next meeting later this year.
Rune, thanks for the input.
I really appreciate plain-language, easy-to-understand systems-holistic/cross-referencing/multidisciplinary information, so thanks seconded and extended to the rest of the good folks who endeavor in this regard.
Hi Rune,
Interesting.
I would think that $50/b will not result in a lot of new oil coming from Brazil, Iraq is in chaos, Libya about the same so probably not a lot of new supplies coming from any of those 3. We might see some new output from Iran, the question for me is will this offset the declines in Canada, US, and the North Sea due to CAPEX cutbacks. You are correct that there are a lot of stocks out there, so any danger of a spike in oil prices is minimized by the excess stocks (roughly 250 million barrels based on OPEC’s Monthly report in September).
I believe that Canadian oil sands and US LTO output will fall faster than OPEC anticipates and may bring supply and demand into balance by June 2016 (assuming OPECs demand forecast is correct).
The slowdown in China may be positive for many Asian nations that compete with China exporting their products to other nations, but only if there is not a bigger fall in exports to China than the increase in exports to other nations. The fall in the value of the Yuan in August may help China’s exports.
Most economic forecasts have World growth at about 3% in 2015, these are not much better than long term weather forecasts so we will find out in time.
One thing I would say is that if AlexS and Rune agree on a forecast of the oil industry, it is likely correct.
On the other hand Jeffrey Brown and Steve Kopits seem to think the oil market will become tight sooner rather than later.
I just don’t know what the future will bring.
Dennis,
IEA, EIA and OPEC forecast that supply and demand will be balanced by 4Q 2016 ,
and they anticipate relatively modest increase in Iran supply and no increase in Libya.
That means that global crude and products inventories will continue to increase for at least the next 3 or 4 quarters, although not as fast as in the first half of 2015.
Once the balance is reached and then demand starts to exceed supply, it will take time before the excess volume of inventories is wiped out.
Well, it was just matter of time, to save what little can be saved.
“Suncor Energy Inc. (“Suncor”) today announced that it has formally commenced an unsolicited offer (the “Offer”) to Canadian Oil Sands Limited (“COS” TSX Symbol “COS”) shareholders to acquire all of the outstanding shares of COS for total consideration of approximately $4.3 billion. Under the terms of the Offer, each COS shareholder will receive consideration of 0.25 of a Suncor share per COS share. Including COS’ estimated outstanding net debt of $2.3 billion as at June 30, 2015, the total transaction value is approximately $6.6 billion.
Shallow sand,
Tremendous thanks for the info on Mid-con in the previous thread. What you say makes a lot of sense. I did not realize new waterfloods decline year over year to that extent. So I guess the key is having a good mix of older waterfloods for stable production & newer waterfloods to keep overall OPEX low. Mid-con management have owned a private company since the 80’s and still have a private GP that drops down a lot of suitable properties to the public entity. Is there a public site where you can look up production info for a company on a well by well basis?
Kellyb. No problem. Keep in mind that I was giving general information per my experience only. Waterfloods can differ quite a bit. I do not know anything about Mid-Con other than what I looked up online, and I am not making any comment about whether they are good to invest in or not. I am partial to waterfloods, so I hope they do make it. Actually, even though I kind of blame shale for the current low prices, I hope those companies make it also. I am sure they have many good people working for them. I just wish they would slow down drilling and not flood the market with oil and gas at a loss to keep wall street happy. Maybe spend the next couple of years trying to pay down debt, and save some of their good locations for when the oil is needed.
Texas RRC PDQ is a free site that has all Texas production information online. OK has online production information, but I think you have to register and pay a fee. KS and CO both have free online information. WY and CA also do. NM I think requires registration and a fee. ND has free information, more detailed than most, and further for a small annual fee (I think) has even more info. MT has a free site, I think NE has free information also. So do some other oil producing states.
Some of the states’ information is on a lease by lease basis. Others have well by well. TX is an example of lease by lease, whereas ND breaks out individual wells.
Keep in mind you will be seeing gross production, and therefore would need to know what interest the company has in each well/lease to know what the company is actually receiving in the way of income.
Just Google the state and “oil production” and you usually will be directed to the site.
This is rather old but might have some relevance especially given the above discussions about condensates.
WITH OR WITHOUT SPLITTING? CHANGING LEASE CONDENSATE EXPORT DEFINITIONS
“…Trouble is that the production of increasing volumes of condensate from US shale plays – in particular in the Eagle Ford basin in South Texas, has overwhelmed the capability of US refiners to deal with this type of light hydrocarbon that most refineries were not designed to process in large volumes. During the past two years however, several US midstream companies have been busy making plans to build a kind of simple refinery called a condensate splitter. These stand-alone units process condensate into its component fractions – mostly NGLs, naphtha and distillate or jet kerosene. Using a splitter allows a producer to transform lease condensate by a simple distillation process into hydrocarbon products that can then be exported…”
https://rbnenergy.com/with-or-without-splitting-changing-lease-condensate-export-definitions
Whaaaa? Kerosene in condensate?
There’s been RBN praise in the past, but I looked at their staff and they are all journalists. No petroleum engineers writing freelance.
According to the Energy Information Administration exports of processed condensate (classified as “kerosene and light gas oils” in a EIA Petroleum Supply Monthly report) began last year in July and averaged 16 Mb/d through November (latest data). I know nothing about this BUT in Canada, Alaska and Russia “jet fuel” contains about 30% kerosene which prevents fuel from “freezing” at low temperatures. I think they have summer and winter blends.
Hello All,
Can someone tell how we are going to get the news of how the banks have treated the shale oil loans.
1/Will there be a blanket statemnet from the banks?
2/ Early statements, with capex adjustments, before the quarterlies?
2/ We will have to wait for the quarterly reports for each company, early next month?
I was hoping for #1, but I suspect #3 will be the answer!
Thanks in advance.
Push
It may be a combination of #2 and #3.
There have already been a few E&PS who have gotten positive reviews of their redeterminations and a couple have even been given increased borrowing capacity if they so choose to use it.
I cannot recall any names this moment, but I’ll do some checking.
All these companies have been attempting to put their best face on the their finances these past several months in attempts, I imagine, to calm nervous investors.
Thanks Coffee,
I believe what you are saying, if the company has good news to announce, we will hear early, meanwhile bad news may come later, hidden in the quarterly?
I am really surprise at your statement, “a couple have even been given increased borrowing capacity if they so choose to use it”. I have no information to argue against it, it just surprises me!
Push
In the past few weeks …
Gastar (smaller outfit) said their credit facility was reviewed and okayed to continue as is.
Gulfport (bigger company) had a positive credit review with the lead bank’s recommendation to increase credit from $575 to $700 millions.
Kinda weird. What do these guys know that we don’t?
The banks really don’t have much to worry about as they are in first place should the company get liquidated. I feel sorry for the junior debt holders. These guys are getting subordinated into oblivion from increased bank borrowing and the second lien debt jumping ahead of them. For this reason, the unsecured debt market for the shalies is shut and will stay that way for a long time. They will only be able to finance drilling through bank debt and equity. Eventually, the bank lines will get tapped out. But with no junk bonds, the industry will be starved of a couple of hundred billion dollars in financing.
Willbros Group amends credit facilities
October 5, 2015
http://www.ogfj.com/articles/2015/10/willbros-group-amends-credit-facilities.html
Willbros Group Inc. has completed amendments to its 2015 term-loan and ABL credit facilities. The amendments establish less-stringent term loan financial covenants beyond the end of the first quarter of 2016 that are designed to address the impact of current market conditions.
Consistent with the company’s expected revenue levels for 2016, the ABL commitment has been reduced from $150 million to $100 million, with an accordion feature to expand up to $175 million to accommodate future revenue growth.
These amendments also enable Willbros to proceed with its asset sale initiatives, including the sale of its Professional Services segment, which will allow the company to strengthen its balance sheet through debt reduction.
The amended financial covenants are more aligned with current market conditions and the company’s performance objectives, and the amendments approve the sale of certain assets, including discrete assets that it may market in future periods. Net proceeds will be used primarily for debt reduction and secondarily for working capital.
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PDC Energy extends maturity of revolving credit facility
October 2, 2015
http://www.ogfj.com/articles/2015/10/pdc-energy-extends-maturity-of-revolving-credit-facility.html
PDC Energy Inc. has extended the maturity of its revolving credit facility by two years to May 2020. The borrowing base has been reaffirmed at $700 million of which the company has elected to keep its commitment level at $450 million.
CFO Gysle Shellum stated, “We are very pleased with the support of our bank group and its agreement, given the current market conditions, to not only reaffirm our current borrowing base, but to also extend the maturity of the revolving credit facility by two years. This liquidity and flexibility provides us the ability to continue operating with a clear focus on maintaining favorable debt metrics and executing on our strategic vision of delivering shareholder value through continued production and cash flow growth, and strong returns.”
PDC Energy’s operations are focused on the horizontal Niobrara and Codell plays in the Wattenberg field in Colorado and on the condensate and wet gas portion of the Utica shale play in southeastern Ohio.
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Chesapeake amends revolving credit facility
October 1, 2015
http://www.ogfj.com/articles/2015/10/chesapeake-amends-revolving-credit-facility.html
Chesapeake Energy Corp. has amended its five-year, $4 billion revolving credit facility agreement maturing in 2019 with its bank syndicate group.
Key attributes include:
• Facility moves to a $4 billion senior secured revolving credit facility from a senior unsecured revolving credit facility
• The initial borrowing base is confirmed at $4 billion, consistent with current availability
• Previous total leverage ratio financial covenant of 4.0x trailing 12-month earnings before interest, depreciation and amortization (EBITDA) is suspended
• Two new financial covenants include a senior secured leverage ratio of 3.5x through 2017 and 3.0x thereafter, and an interest coverage ratio of 1.1x through the first quarter of 2017, increasing incrementally to 1.25x by the end of 2017.
Chesapeake’s credit facility may become unsecured when specific conditions set forth in the credit agreement are met. During an unsecured period, the total leverage ratio would be reinstated and the senior secured leverage ratio and interest coverage ratio would no longer apply. While Chesapeake’s obligations under the facility are secured, the amendment gives Chesapeake the ability to incur up to $2 billion of junior lien indebtedness. As of Sept. 30, Chesapeake has $12 million in outstanding letters of credit under the facility with the remainder of the $4 billion available.
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New Source Energy Partners updates on pending borrowing base deficiency
September 29, 2015
http://www.ogfj.com/articles/2015/09/new-source-energy-partners-updates-on-pending-borrowing-base-deficiency.html
New Source Energy Partners LP, due to a pending borrowing base deficiency under its revolving credit facility, will be prevented from paying the quarterly cash distribution on its 11% Series A cumulative convertible preferred units.
“While it was the Partnership’s intention to pay this distribution, there are covenants in our credit agreement with our reserve based lending group that prevent our ability to make the payment while in a deficiency,” said Kristian Kos, chairman and CEO. “We are not in a deficiency at this time. However, based on initial communication from our reserve based lending group, we expect to be in a borrowing base deficiency after our biannual redetermination takes place in early October, which will prevent us from making a distribution on Oct. 15. We will be working with our lenders to finalize the new borrowing base over the next several days, as well as exploring alternatives to remedy the deficiency to allow the Partnership to resume making distributions on the preferred units as soon as possible.”
New Source Energy Partners is an independent energy partnership engaged in the production of its onshore oil and natural gas properties that extends across conventional resource reservoirs in east-central Oklahoma and in oilfield services that specialize in increasing efficiencies and safety in drilling and completion processes.
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Bill Barrett reaffirms borrowing base
September 29, 2015
http://www.ogfj.com/articles/2015/09/bill-barrett-reaffirms-borrowing-base-sells-certain-uinta-properties.html
Bill Barrett Corp.’s (NYSE: BBG) semi-annual borrowing base review has been completed with the bank group reaffirming the $375 million borrowing base related to its revolving credit facility maturing in April 2020. The credit facility has $375 million of commitments and there are currently no borrowings under the credit facility.
As part of the redetermination process, the company and its lender group agreed to amend the maintenance covenants in the revolving credit facility by replacing the leverage covenant limiting the maximum total debt to trailing 12-month EBITDAX ratio of 4.0x with a covenant limiting the maximum senior secured debt to trailing 12-month EBITDAX ratio of 2.5x through March 31, 2018, after which the leverage covenant reverts to a maximum total debt to trailing 12-month EBITDAX of 4.0x, as of June 30, 2018. In addition, an interest coverage ratio requirement was included, pursuant to which the ratio of EBITDAX to interest expense may not be less than 2.5 to 1.0 for each quarter through March 31, 2018.
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Approach Resources confirms reaffirmation of lender commitments in credit facility at $450M
September 28, 2015
http://www.ogfj.com/articles/2015/09/approach-resources-confirms-reaffirmation-of-lender-commitments-in-credit-facility-at-450m.html
Approach Resources Inc. has completed the scheduled semiannual borrowing base redetermination of its revolving credit facility, and as a result, the bank group has set the lender commitment amount and borrowing base at $450 million.
Under the terms of the credit agreement, the bank group redetermines the borrowing base semiannually, using the banks’ estimates of reserves and future oil and gas prices. The next borrowing base redetermination is scheduled to occur by April 1, 2016. As of Sept. 24, Approach had $276 million outstanding under its revolving credit facility, resulting in liquidity of $177 million.
Approach Resources is an independent energy company focused on the exploration, development, production, and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas.
Enterprise increases capacity of bank credit facilities to $5.5B
September 17, 2015
http://www.ogfj.com/articles/2015/09/enterprise-increases-capacity-of-bank-credit-facilities-to-5-5b.html
Enterprise Products Partners LP’s operating subsidiary, Enterprise Products Operating LLC, has increased its bank credit facilities by $500 million to provide the company with up to $5.5 billion of aggregate borrowing capacity.
The facilities consist of an amended $4 billion multi-year revolving credit agreement that matures in September 2020 and a new $1.5 billion 364-day revolving credit agreement, both of which are unconditionally guaranteed by Enterprise on an unsecured and unsubordinated basis. As of today, aggregate available borrowing capacity under the increased bank credit facilities is $4.7 billion.
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Gastar borrowing base maintained at $200M
September 1, 2015
http://www.ogfj.com/articles/2015/09/gastar-borrowing-base-maintained-at-200m.html
Gastar Exploration Inc. has completed its second scheduled borrowing base redetermination of its revolving credit facility for 2015 and, as a result, the borrowing base has been reaffirmed by the lending participants at $200 million.
Currently, Gastar has drawn $65 million under its revolving credit facility, resulting in $135 million of unused borrowing capacity. The next scheduled borrowing base redetermination is to occur by May 1, 2016.
Gastar’s principal business activities include an emphasis on unconventional reserves, such as shale resource plays. In Oklahoma, Gastar is developing oil-bearing reservoirs of the Hunton Limestone horizontal play and expects to test other prospective formations on the same acreage, including the Meramec shale play (middle Mississippi Lime) and the Woodford shale play, which Gastar refers to as the STACK play. In West Virginia, Gastar is developing liquids-rich natural gas in the Marcellus shale play, and has drilled and completed two dry-gas Utica/Point Pleasant wells on its acreage.
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RSP Permian completes bolt-on Midland Basin acquisitions and increases borrowing base
August 26, 2015
http://www.ogfj.com/articles/2015/08/rsp-permian-completes-bolt-on-midland-basin-acquisitions-and-increases-borrowing-base.html
RSP Permian Inc. closed an amendment with the lenders under its revolving credit facility that, among other things, increases the borrowing base 20% to $600 million. The company currently has no amounts drawn under its revolving credit facility and the next scheduled borrowing base redetermination is May 1, 2016.
Exterran Holdings secures financing to enable spin-off of businesses
October 6, 2015
http://www.ogfj.com/articles/2015/10/exterran-holdings-secures-financing-to-enable-spin-off-of-international-services-and-global-fabrication-businesses.html
Exterran Holdings Inc. (NYSE: EXH) has provided an update to the planned financing in connection with its previously announced separation.
In November 2014, Exterran Holdings said that it intends to separate its international contract operations, international aftermarket services, and global fabrication businesses into a stand-alone, publicly traded company named Exterran Corp. Upon completion of the spin-off, Exterran Holdings, which will continue to own and operate its contract operations and aftermarket services businesses in the US, will be renamed Archrock Inc.
As previously announced, Exterran Corp. entered into a $750 million revolving credit facility on July 10 that would become available upon the completion of the separation and the satisfaction of certain other conditions. On Oct. 5, Exterran Corp. amended and restated the credit agreement to provide for a new $925 million credit facility, consisting of a $680 million revolving credit facility and a $245 million term loan facility. The revolving credit facility will have an interest rate subject to a leverage grid with an expected initial interest rate of LIBOR plus 2.75%. The term loan will carry an interest rate of LIBOR plus 5.75%, with a 1.00% LIBOR floor.
Availability under the new credit facility is conditioned upon the completion of the separation and the satisfaction of certain other customary conditions. The revolving credit facility will mature five years after the effective date of the separation transaction, and the term loan facility will mature two years after the effective date of the separation transaction.
The new credit facility includes, among other covenants, financial covenants requiring Exterran Corp. to maintain (after the separation) an interest coverage ratio of not less than 2.25:1.00 and a total leverage ratio of not greater than 3.75:1.00. Should Exterran Corp. refinance the term loan facility with the proceeds of certain qualified unsecured debt or equity issuances, the financial covenants in the revolving credit facility will be modified to require that Exterran Corp. maintain a total leverage ratio of not greater than 4.50:1.00 and a senior secured leverage ratio of not greater than 2.75:1.00, while the interest coverage ratio will not change. Such capitalized terms are defined in the amended and restated credit agreement.
In connection with the spin-off, Exterran Holdings anticipates that Exterran Corp. initially will borrow under its new credit facility and transfer an amount of proceeds to Exterran Holdings which, when taken together with the proceeds from borrowings under the Archrock credit facility as described below, will enable Exterran Holdings to repay all of its existing indebtedness.
As of June 30, on a pro forma basis after giving effect to the spin-off, Exterran Corp. would have borrowed and transferred to Exterran Holdings approximately $539 million. Subsequent to June 30, and prior to the completion of the spin-off, Exterran Holdings expects to incur additional borrowings under its existing credit facility of between $40 million and $50 million to finance expenses related to the completion of the spin-off, which will increase the amount that Exterran Corp. borrows under its new credit facility and transfers to Exterran Holdings.
Also, Exterran Holdings entered into a $300 million credit facility on July 10 that would become available upon the completion of the separation and the satisfaction of certain other conditions. On Oct. 5, Exterran Holdings executed a first amendment to the credit agreement that, among other things, increases the aggregate commitments under the revolving credit facility from $300 million to $350 million. The revolving credit facility includes, among other covenants, financial covenants requiring Archrock Inc. to maintain (after the separation) an interest coverage ratio of not less than 2.25:1.00 and a total leverage ratio of not greater than 4.25:1.00 (except that the maximum total leverage ratio during a specified acquisition period will be increased to 4.75:1.00), as those capitalized terms are defined in the credit agreement. The revolving credit facility will have an interest rate subject to a leverage grid with an expected initial interest rate of LIBOR plus 1.75%.
Alex
… and the band played on …
Big time thanks for your time and effort.
Thanks. So only New Source Energy Partners gets their revolver called in, and they’re small. Also a lot of these aren’t E&Ps.
Most of the banks seem to have first lien and not a huge loan, and will end up getting their money back eventually, but it still seems odd to me that they’re lining up to spend money and time in court.
Folks interested in fuel cell cars will enjoy reading this article..
Personally I tend to think Tesla is the ticket, given that the grid goes everywhere already- but betting against Toyota is betting against some extremely talented and dedicated and well financed scientists and engineers. A WHOLE BUNCH OF THEM , actually.
http://www.caranddriver.com/toyota/mirai
Delivery of these cars to California customers is just around the corner.
How dare you besmirch this fine oil and gas thread with talk of fuel cells?
I beg you pardon.
Here is a link to cheer up oil guys. Somebody thinks it’s time to mosey up to the bottom feeding trough and swallow up a competitor. I guess SUNCOR thinks there will be a market for whatever the company can produce. LOL
http://www.nytimes.com/2015/10/06/business/dealbook/suncor-announces-hostile-takeover-bid-for-canadian-oil-sands.html?_r=0
You got it wrong Mac. What Suncor offer means is only one thing and that is that Cnd. Oil Sands (COS) with beloved Buffet as one of the shareholders, was actually swimming naked when the tide pulled. Sometimes even Buffet should listen to his own advice.
And what Suncor thinks now that will happen with availability for future oil market for that product we will have to wait and see. Buffet thought the same just couple years ago and got it wrong big time.
Hi Ves,
You may be right, I have no crystal ball, but depletion marches on. No new supergiant fields have been discovered going on thirty or forty years now and new giants are scarce.
BUFFET may have targets in mind that he thinks will pay better. He is obviously pretty smart but as you say, not infallible. He has missed the boat before a couple of times by his own admission.
I believe in peak oil being NOW or very soon, and I believe in JB’s export land, and in the return of hundred dollar and up oil.
The fuel cell dialog fits in an oil and gas thread because selling hydrogen technology is like selling snake oil.
I do not know who is responsible – Toyota or Car and Driver. But, let us hope that they are better at high tech engineering than at proof reading. Specifications in the article: Wheelbase 109.4 inches. Length 92.5 inches.
https://rbnenergy.com/one-thing-leads-to-another-sweet-spot-bakken-oil-means-more-gas#comment-1821
One Thing Leads To Another—Sweet-Spot Bakken Oil Means More Gas
Crude oil producers in the Bakken region responded to the oil price collapse with drilling cutbacks and a laser-like focus on sweet-spot areas with high initial production rates. It turns out those oil sweet spots also produce a lot of associated natural gas.
It appears RBN has noticed the increasing GOR in the Bakken, and have come to conclusion that it is all those great super sweet spot wells, that are the reason. I have left my doubting Thomas question. It will not be posted until they come up with a reply. It will interesting to see their reply.
It looks like RBN, didn’t like my question, as they are yet to post my question or reply as yet.
Maybe, I phrased it wrong and made it too negative for them?
Or they did some research and didn’t like the answer?
It will be interesting to watch, and see if they get around to answering. Maybe, later after the high traffic flow has finished, so not too many people get to read it. Time will tell.
http://www.businesswire.com/news/home/20151002005545/en/Automotive-Industry-France-PSA-Prototype-Car-Travels#.VhNb_OsaX5Z
There are SOME people out there who believe in the future of oil.
http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/suncor-makes-hostile-43-billion-bid-for-canadian-oil-sands/article26648394/
We have to be honest and admit that we are all beneficiaries of this windfall in access to easy and cheap energy. Yet there are huge hidden and unaccounted for costs. Here’s what those, people, that supposedly assume that oil sands, tar sands, shale, etc… are just another benign source of energy should try to understand. Nature and the environment have been massively subsidizing our lifestyles but the question is, for how much longer can that go on?
https://www.ted.com/talks/garth_lenz_images_of_beauty_and_devastation
Hi Fred,
Ya coming thru wall tuh wall an treetop tall good buddy.
You can at least SEE the mess the tar sands make. Take Manhattan Island now- that once upon a time bit of paradise is so covered up with civilization you can now only see concrete and asphalt.
I am as big an advocate of low birth rates, small electrified cars, a simplified lower energy life style as anybody BUT BUT BUT BUT-
How we gonna git frum where we are to “that thar Renewables Promised Land” ‘thought plenty o no2 ?
I am afraid half the regular commenters have decided I am a hopeless redneck simply because I am a REALIST.
The transition, if it happens, is not going to happen overnight.
Now I PRESUME you are using your own name, and in that case it is quite obvious that given your business interests, you must refrain from actually saying what you may REALLY think- for instance you never seem to say you see an ecological and economic hard crash as INEVITABLE. Given your level of understanding of the issues, I can only conclude you are either a hopeless optimist, or else just prefer not to be labelled as a hard core doomer.
Ron for instance is retired and like a retired general can afford to say what he really thinks.
IF my personal credibility or reputation mattered to me, I would not endorse closing the borders of this country in a forum such as this one, which is obviously dominated by leftish leaning or liberal members. Rubbing people’s noses in their cognitive dissonance based errors is NOT a good way to make friends of them.
We all , for all intents and purposes, believe in the utter necessity of lowering the population, but I am the ONLY one willing to actually point out that getting our birth rate below replacement can be accomplished immediately by stopping large scale immigration. It’s all back to that old lack of thinking critically, versus thinking what we want to think.
Doofus conservatives want to have their material cake and eat it too, without facing up to the indisputable fact that the brick wall of resource depletion is directly ahead and we are headed directly for it pedal to the metal.
Doofus environmentalists preferentially choose to ignore the hard science of population demographics so as to indulge their political and ( commendable) human impulse to help out others.
But like Ron, I am retired and can afford to say what I really think, and pretty soon I will be dead, and anyway, nobody in this forum lives near enough to drop by for a drink and conversation.
NOW tell me this. Do you, or does anybody else, have a good answer to my argument that a successful transition to renewables is NECESSARILY dependent on the continuation of BAU for at least two or three decades?
Many a general has won a crucial battle all thru history by throwing in his last ready reserves. Crucial battles won often mean the war is won. THAT oil might just be the DIFFERENCE between winning and losing.
Anybody who believes in auto insurance and home owners insurance and health insurance sure as hell ought to believe in ENERGY INSURANCE as well, to the extent it can be had, until the need for it passes.
It is entirely possible that the Keystone could be one of a handful of hot button issues in a future election – assuming it is NOT ever built- that could put a very hard core right wing government in power in this country. Elections in this country are often won and lost on just three or four percent of the voters switching sides. Fifty one forty nine is a squeaker but fifty-five forty five is called a land slide.
Just imagine the political ads, if a day comes when that oil is going east and west to Europe and Asia, and it has been sold under long term contracts, and the tankers are just not arriving here full to the gunwales anymore.
PS I don’t know what Ron thinks about closed borders but my guess is that he is NOT for closed borders.
OFM,
Full disclaimer, as to whether or not I’m a hard core doomer or a cockeyed optimist, it really depends on how I feel when I wake up in the morning… Some days I’m more optimistic than others. At the end of the day I am a realist! Though I try really hard not to let reality get me down. I have made little secret of the fact that I absolutely do not believe we are headed for a planet with 9 to 10 billion humans living on it and I have the utmost disdain for those who spout such nonsense!
I wish I believed in the notion that any one country physically closing its borders would somehow solve the global population crisis. It won’t and I don’t think it will stop desperate people from trying to get through regardless. As you know I’m of Hungarian descent with family in Hungary and Germany so I have been watching what happens there very carefully. Closing borders is like putting a little band aid on a slashed open artery, It won’t correct the underlying systemic problems. I’m also sitting in Sao Paulo as I write this and this is a city that is vying really hard for the number one spot in the competition for the most unsustainable and unlivable cities in the world. So over all it is very hard for me to ignore our dilemmas.
I also think it is a toss up as to whether or not another two or three decades of BAU will give us the chance to transition to a radically different economic paradigm without actually destroying us in the process. It’s a case of dammed if we do and dammed if we don’t.
Humans are not exempt from the laws of nature, what we know about population dynamics tells us that when the population of any species goes into overshoot and there aren’t enough resources to go around the population usually crashes and there is dieoff.
But tomorrow is another day and I expect the sun to come up, I’ll have my cup of coffee and some breakfast I’ll thank my lucky stars that I have yet another day to see if I can find a way to make a difference, what else can any of us do?
Cheers!
Closing borders one or many will certainly not solve any world problems.
Closed borders would buy a little more time for a country such as the USA to work on the transition, given a lower population.
The time of tshtf is upon us, and while we are morally obligated to do what we can to help each other, the laws of nature apparently dictate that in the end it is every man for himself and his own family and community and country.
Saving the world from general collapse is out of the question.
Saving the USA from outright collapse is not YET out of the question imo.
A hell of a lot can happen for better or worse on in twenty or thirty years.
Damned if we do and damned if we don’t summarizes our situation very well indeed.
If I had Bill Gates money, I would spend however much it took to invent a birth control drug for men and for women that would work for the rest of their life- one dose- and PAY people to take it.
Most of the near worthless ( in terms of having good habits and being good fathers ) men in THIS country would take the pill for a thousand bucks anytime they run short of beer and cigarette money. I expect millions of poor women would GLADLY take it once they have one kid or maybe two. Paying them with a shopping gift card worth a thousand bucks would create such a buzz they would be lined up for blocks to sign up.After a while you could cut back to five hundred and then a hundred.
How many women and men might be willing to take such a pill in various other societies I have no idea- but it would be a large number I am sure.
U.S. shale oil needs $80 to grow
U.S. oil production growth will stop this month and begin to decline early next year due to low oil prices, the former head of oil firm EOG Resources, Mark Papa, said on Tuesday.
Papa, now a partner at U.S. energy investment firm Riverstone Holdings LLC, told an industry conference in London that the U.S. shale oil industry needed oil prices of at least $80 a barrel to resume production growth.
“We are about to see a pretty dramatic decline in U.S. production growth,” said Papa, who was a key figure helping to spur the U.S. shale oil boom when he was at EOG Resources.
U.S. oil production has been growing by around 1 million barrels per day (bpd) year-on-year since mid 2012, thanks to the introduction of new drilling techniques that have released oil and gas from shale formations.
But output in North America has started to slow in recent months as prices have fallen sharply.
Papa said U.S. oil production would stall this month and begin to decline from early next year. He said the main reason for the decline would be the lack of bank financing for new shale developments.
If U.S. light crude oil prices went back up to $75 a barrel, Papa said U.S. oil production would resume growth at around 500,000 bpd – or around half the record growth rates observed in the past few years.
Of course, at an overall decline rate of 10%/year from existing production, operators need to put on line close to 1.0 million bpd of new C+C production per year, just to offset declines from existing wells. At a probably more realistic decline rate of about 15%/year from existing production, they would need to put on line about 1.5 million bpd of new C+C production per year, just to offset declines from existing wells (at current production levels).
And PAPA estimates about a third of that much new production. His little piece is pretty obvious pumping propaganda considering depletion rates.
Now back to autonomous vehicles for a minute.Having made a career out of not having a conventional career, I have stuck my nose into almost every sort of work that you can get into and out of easily, including trucking. Sometime back I hired a good friend who has a tandem dump – a ten wheeler- and a heavy duty trailer- an eight wheeler to haul some equipment for me for a day. Both of us are semi retired in that we work when we want to and have plenty of free time so we set the throttle on that truck so it would not exceed fifty mph and ran her all day. This resulted in an hour and a half of extra road time- but the fuel economy jumped by forty percent compared to running her either pedal to the metal or a little over the speed limit. ( Such trucks will not generally go the speed limit up long grades etc.)
The potential for autonomous trucks to save oil is simply ENORMOUS. They can be left loaded and make a hell of a lot of runs in the wee hours etc at low speeds.
People with newer cars that have instantaneous fuel economy displays will tell you that a minivan that gets thirty two at sixty five will get forty five at thirty five.
The implications are self explanatory. Cubicle man can work on his way to work at a snails pace and it won’t matter except it saves forty percent,maybe more, of the fuel needed to commute at freeway speeds.
Just for fun, I did the math. First, an assumption, pedal to the metal or speed limit would be 70 mph. You did 50 mph. So, to spend 1 1/2 hours longer, the trip was 262.5 miles, which took you 5.25 hours at 50, and would have taken 3.75 at 70 mph. Another assumption: at 70 mph, you would have gotten 8 mpg. So, you did 40% better. So you got 11.2 mpg. At 70 mph, fuel use would be 32.81 gal. At 50 mph, you used 23.44 gal. A savings of 9.37 gal, which at $3 gal, would be a savings of $28.11. Two people on the trip, saved $9.37 per hour each. What was the cost/value of two truck drivers? More than $9.37 per hour each? If it were a business, with a back haul, you could make 2 trips at 70 mph in one day and have total driving time of 7.5 hours, and revenue for two loads. At 50 mph, it would be 10.5 hours driving time. Which could affect over the road driving time limits/overtime etc., plus the extra 3 hours of salary for 2 people.
When I was a child, I learned “penny wise, pound foolish.”
Hi Clueless, as usual you are not. ( clueless that is )
At any typical USA cost for diesel fuel, it is virtually always more profitable to run a truck as hard as you can because the increase in productivity brings in substantially more money than you can save via better fuel economy. When they think they can get away with it, most truckers do not hesitate to drive over the speed limit.
BUT if fuel is expensive enough- or rationed then it’s a whole new ball game.
Some truckers have jobs where they run hard all day- for instance my friend uses his truck to haul gravel and asphalt for a large paving company and he can get paid either by the load or by the hour. If hauling by the load, he runs flat out to make as many loads as possible.
Now take the driver out of the equation, or TWO drivers out on cross country trips, and the math starts to look altogether different. An autonomous truck could do twenty two or twenty three hours on the road cross country at fifty mph maybe 1100 miles or so, whereas a team can average close to sixty five for twenty hours ,speeding a little here and there, maybe 1700 miles.
Now take out the expense of the two drivers and add in the savings on fuel and a whole new picture emerges. California strawberries headed to New York are perishable and an autonomous truck hauling perishables would likely be programmed to run the speed limit but if it is loaded with appliances or toys or lumber or steel …. the math changes dramatically.
The savings per trip would then vastly outweigh the loss of revenue from making more trips because you could make up the lost trips by having more trucks. Drivers and fuel together are a hell of a lot more expensive than trucks.
You would just buy more trucks-but not as many more as you might think at first glance.Computers don’t insist on days off. Naked ape truckers tend to quit and do not always show up.They lose their licenses for various reasons.So a trucking company needs more drivers than it has trucks and a dispatcher will tell you that herding a couple of dozen drivers is as hard as herding cats.
If the technology works out, it will eventually force most truck drivers into another line of work. I expect it to work “road ready” within the next few years but also for it to take quite some time to be accepted by various regulatory authorities ranging from small town councils to the feds. The political battle might last for years and years.
If the tech can be installed in a heavy duty truck for say “ONLY” fifty thousand bucks, it will be a no brainer decision.It will probably cost a lot less than that once scaled up.
From my desk:
Sorry for the blur, it was a high quality pic to start with.
Which could affect over the road driving time limits/overtime etc., plus the extra 3 hours of salary for 2 people.
When I was a child, I learned “penny wise, pound foolish.”
Perhaps you missed the memo? The plan is to go 100% driverless and eliminate both of those drivers…
There is a lot of disruptive technology already in the pipeline, which means we are going to be facing monumental paradigm changes probably sooner than later.
The rich folks are going to have to provide lots of bread and circuses in order to keep all the unemployed people distracted so as to keep them from realizing how much fun it is to riot and drop big rocks on fancy cars from over pass bridges.
But driverless trucks might save enough oil and other resources to allow us a little more time to successfully adapt to ever less plentiful and ever more expensive oil as time passes.
Fred – you failed to read!! OFM related a personal story with the facts. [“Both of us are semi retired in that we work when we want to and have plenty of free time so we set the throttle on that truck so it would not exceed fifty mph and ran her all day.”] My math was done on that story.
After, my comment, OFM offered up a future scenario with no drivers.
If we returned to $80/barrel (and that could happen pretty easily if the dollar fell or other causes), that would mean we would have over 11 million bpd in four years. When would peak oil happen in that case?
At the 1965 to 1970 rate of increase in US C+C production, the US would have been producing about 73 million bpd in 2015:
http://www.eia.gov/totalenergy/data/monthly/pdf/sec3_3.pdf
Two thumbs up.
U.S. oil output on brink of ‘dramatic’ decline, executive says
http://www.reuters.com/article/2015/10/06/us-oil-outlook-usa-idUSKCN0S021Y20151006
Delegates at the Oil and Money conference in London, an annual gathering of senior industry officials, said world oil prices were now too low to support U.S. shale oil output, the biggest addition to world production over the last decade.
“We are about to see a pretty dramatic decline in U.S. production growth,” the former head of oil firm EOG Resources Mark Papa, told the conference.
The chief executive of Royal Dutch Shell Plc agreed, saying U.S. oil producers would struggle to refinance while prices remained so low, leading to lower output in future.
“Producers are now looking for new cash to survive and they will probably struggle to get it,” Ben van Beurden said.
Longer term, there was a risk that low levels of global production could bring a spike in oil prices, he said.
If prices remained low for a long time and oil production outside OPEC and the United States declined due to capital expenditure cuts, there was not likely to be any significant spare capacity left in the system, he said.
“This could cause prices to spike upwards, starting a new cycle of strong production growth in U.S. shale oil and subsequent volatility,” van Beurden said.
Adam Sieminski, administrator at the U.S. Energy Information Administration, told reporters on the sidelines of the conference the U.S. oil industry had reacted to lower prices by improving its productivity.
But this process could not continue forever.
“Now we are seeing the limits at least in the near term and it is beginning to impact production,” Sieminski said. “We see (U.S. oil production declines) continuing into next summer.”
About two weeks ago, as reported in the Daily Oklahoman, Harold Hamm (Continental Resources) said that by May of 2016, US production decline would be so significant and obvious that the crises would be over [paraphrasing].
Utica showing signs of age? From an anti-fracing org, but more importantly, is the data valid?
The Curious Case of the Shrinking Utica Shale Play
September 29, 2015
http://www.fractracker.org/2015/09/shrinking-utica-shale-play/
Steve
I had read that piece when it first came out and, as it didn’t seem to make sense to me, I dismissed it.
However, a very quick re-read prompts me to suspect errors have been made in that presentation.
I will spend time later, but anyone can quickly pull up Ohio’s latest quarterly production numbers and check out the brine output that the piece says Chesapeake’s Trueshall well was over 1,800 bbl per DAY???
Unless I am mis reading (possible, in a rush), the well produced about 30,000 for the quarter … about 300 bbl/day.
In a nutshell, author seemed to set up a straw man premise wherein the oil output may not be as high as some had hoped, but the recovered dry gas from the Utica is going off the charts.
Thanks, Coffee.
As a long-term investor in 2019 natgas futures, was particularly interested in your comment on the mega-wells they are drilling in the Utica play.
The author seemed to be making the point the sweetspots are not a large as presently assumed.
“While the OGS [Ohio Geological Survey] projected natural gas and natural gas liquid potential all the way from Medina to Fairfield and Perry counties, we found a precipitous drop-off in productivity in these counties to <1,028 Mcf per day (<155,000 Mcf total from 2011 to Q1-2015) or a mere 6-11% of the Belmont-Monroe sweet spot."
That appears to be an accurate plot of total gas produced per well over the period. Note that they are not adjusting for well age, so this short-changes the newer wells. Also, I’ve seen quite good results a little farther south, which is cropped off of that map. The wells are mostly new new enough that they wouldn’t be terrific by that measure, but they should wind up about as good as the sweet spot shown.
The whole wet gas region has been quite disappointing. I commented on this earlier.
Note that the EIA Utica rig count is currently flat out wrong, leading to EIA output projections which are too low.
Early results from the Utica formation in PA appear promising, but I haven’t seen any statistics, and I haven’t seen results from enough wells to be convincing. These will appear as “Marcellus” region wells in EIA numbers.
First I would just like to clarify that while FracTracker might seem like an “anti-fracing org” we believe that the pro/con labels are typical of debates in US (i.e., you are either with us unconditionally or against us!).
There is plenty of room in the middle and at the margins for sound research and mapping with respect to hydraulic fracturing and the broader hydrocarbon industrial complex with respect to land-use/land-cover (LULC), waste generation and transport, water use and watershed resilience, Energy Return On Energy Invested (EROEI), and potential threats to ecosystem services.
That said we are very interested in modeling the spread between Utica production expectations and reality.
1. Herein we compiled a very robust data set of 1,100 Utica wells to construct this spacially explicit model using a technique called Empirical Bayesian Kriging.
2. The data we have compiled speaks to Ohio’s Utica wells experiencing 84% declines in oil and gas production on a per day basis from years 1 to 2. From that point forward oil and gas declines by 25% and 10%, respectively.
Furthermore, the newer wells are experiencing more pronounced exponential declines in productivity.
3. We aren’t “set[ting] up a straw man premise” about production but simply showing that the Ohio DNR is woefully lagging behind in updating their constituents as to the realities of the Utica from an oil, gas, and brine perspective.
Mr. Auch
Straight up, if you honestly are unaware of the difference between flow back water and produced water, you may want to get an education right quick.
I checked the brine output for the three wells mentioned in the article, and found the 1,800 barrel was for TWO days after the well came online. The NEXT 91 days, this Chesapeake Trueshall well produced 170 bbl/d.
Exact same premise for the EM and Gulfport wells. (Gulfport’s Bolton well is currently producing 15 barrels of water a day).
Anyone who remotely thinks the dry gas Utica is shrinking or diminishing in any way is simply uninformed.
I am just using the data provided by ODNR Coffeeguyz
I am fully aware of the difference but unless you can compel the industry participants to parse flowback and produced water this is the best we can do.
Your condescending tone isn’t very helpful sir/madam(?) but regardless my email is available at our website and you can email me directly and I would be happy to share our sizable data-set with you?
You really should take your concern(s) up with the major industry participants here in Ohio and ODNR.
Hi Ron,
The link is short and PAPA does not mention interest rates.
I for one wonder if tight oil is truly profitable at eighty bucks if the producers have to pay a realistic interest rate. Sooner or later they WILL HAVE TO.
New credit facilities, oil stocks see steady two day gains.
Interesting how WTI is inching closer to Brent. When oil was in the $100 range, the two prices were around 10% apart. I am talking post 2008.
Currently barely $3 separates them at $50, or 6%. So either demand in the US is out weighing international demand, or US supply is falling? Maybe a little of each.
I wonder how long before the 2 cross over, and re-establish there more traditional relationship?
$3 is pretty close to the pipeline tariff. I wouldn’t think it would fall much or reverse until they need to pump oil north again, which is not currently close to happening. On the other side, we aren’t all that far from full pipelines or, with export restrictions, a USA light oil glut, but we are trending in the opposite direction.
I wonder if Dennis might have been technically wrong, but actually fundamentally correct, about an oil price bottom in January, when Brent averaged $48. Brent averaged $47 in August, and probably about the same in September, and it’s currently trading at about $53 this morning. It seems to me that the bottom line is that monthly lows so far in his cycle have been in the high 40’s.
Incidentally, I had forgotten how rapid the run-up was in oil prices from 2007 to 2008. From June, 2007 to June, 2008, monthly WTI prices exactly doubled (hitting $134 in June, 2008), and Brent almost doubled (hitting $132 in June, 2008). Brent then fell to a monthly low of $40 in that price decline, in December, 2008.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RWTC&f=M
Hi Jeffrey,
I think I was just plain wrong on my guess at an oil price bottom in January.
I also was wrong about how fast LTO output would decline (I thought at under $50/b) the decline in LTO output would be much steeper and that the well completion and drilling rates would decrease much faster than has been the case.
If the LTO output had fallen as fast as I thought back in January, $48/b for Brent might have been the bottom. I have no clue what will happen going forward. Do you still expect oil prices might reach $65/b or higher by Jan 2016 (even with no OPEC cut)? Everything has moved much slower than I anticipated, certainly Steve Kopits forecast from Feb 2015 wasn’t correct and I have not heard any new forecasts from him, what’s your take, July 2016 oil prices reach $70/b?
Biography M. King Hubbert Available April 2016 http://www.oracleofoil.com
Yesterday the NDIC released the latest update on the status of all wells in ND (no production numbers).
What I found most interesting is that a very low number of 66 wells were spudded in ND in September. The last time so few wells were spudded in ND was early 2010. This number may still be revised (I expect up to 10% higher), but it is much lower than the 121 wells spudded in August, and the 109 wells spudded in July. It also indicates that the trend of the rising number of spuds/rig/month has reversed, as shown in the chart below (latest data is for September).
A similar temporary rise in this ‘drilling capacity factor” (wells spud/rig/month) was also visible during the 2009 downturn, as can be seen. I have no explanation for it.
So yes, drilling efficiency has increased over the last 4 years, from an average of 0.6 wells spud/rig/month, to recently almost 1.2 wells spud/rig/month, but it is still a far cry from 2, which Lynn Helms mentioned in a recent update.
I expect that this big drop in new wells spudded will show up as lower output, in a delayed response, somewhere mid/end next year, as the current fraclog is depleted slowly each month (meaning more wells are being brought online than drilled), as has been the case since December 2014.
Thank you Enno, very interesting.
The average rig count in North Dakota in September was 67.
If 66 wells were spudded, there is only 1 well spud/rig/month.
Do you think your numbers show that improvements in drilling efficiency have finally reached a limit?
What is your estimate of the current fracklog in ND and what was its peak level this year?
Thanks again
Alex,
“Do you think your numbers show that improvements in drilling efficiency have finally reached a limit?”
That appears to be the case based on the latest data. However, the last few months showed large fluctuations, so a few more months would be useful to come to a more firm conclusion.
“What is your estimate of the current fracklog in ND and what was its peak level this year?”
If I assume that 125 wells were brought online in August, and 115 in September (vs 136 in July), the below picture emerges.
I provide 2 measures for the fraclog:
1) Uncompleted well inventory: This is the well inventory counted from the start of spudding a well, and before first production. This is an accurate measure, as the data is available. It has been trending down since last November (1260), and could drop to about 940 by the end of September, based on the above assumption. It will never come close to 0, as there are always a few months between spudding a well and first production.
2) Estimated fraclog: This is the well inventory, counted from 5 months after spudding, and before first production. Historically, there used to be about 5 months (although this number has varied) in between these 2 activities, so I think this is a more reasonable estimate of the actual number of wells where completion is clearly being delayed. This number has been rising until June, as more wells spudded late last year past the 5 months waiting time, and I expect it to keep dropping since then. According to this measure the June peak was at 500 wells, and by the end of September dropped somewhat to 460. Now that the number of spudded wells has dropped significantly in September, I expect that this measure of the fraclog will start to drop more rapidly early next year, if a steady number of wells are completed.
I am quite curious of the quality of the wells in this fraclog. So far, despite high-grading, no improvement in well productivity has been seen in 2015, compared with 2014. This is somewhat surprising, but on the other hand it would make sense if operators typically have focused on their best areas in the past already. In the current price environment, I belief it is rational to expect that operators keep employing the same strategy, of bringing their best wells online first (except EOG, which is not bringing any wells online, some of which are known to be very good). If that is the case, the average well in the fraclog may be of lesser quality than the wells being brought online so far. For example, it could contain a greater ratio of Three Forks wells. This is just a theory, which may be revealed in the data in the coming year.
Thank you Enno.
I think the best definition of the fracklog is “drilled but uncompleted wells” (DUC), but this information in unavailable.
I agree that your “Estimated fraclog” better reflects the real trend than the
“well inventory counted from the start of spudding a well, and before first production”.
One question: how do you estimate the quality of the wells in this fraclog if these wells are not yet producing?
“One question: how do you estimate the quality of the wells in this fraclog if these wells are not yet producing?”
I have no information on the quality of the wells in the fraclog, nor any estimate. What I meant was that I suspect that the quality of those wells may be less than the wells being brought online during the recent period. This could be confirmed once the fraclog wells are online, and we can measure their performance.
O.K., thanks Enno
Enno. Saw you comment on the Seeking Alpha article re: CLR. Am I correct that a massive write down is coming for CLR at year end, and thus a massive loss in earnings?
Also, surprising to me how much shale stocks have rebounded with WTI just improving by about $4-$5 per bbl.
Shallow,
Correct. But it will be presented as “a one-off non-cash write-off, typically ignored by analysts”, despite being massive and having been paid up front. 🙂
Indeed the rebound is somewhat surprising. Perhaps a short squeeze?
Impairment charges at record levels for North American E&P peer group (IHS Herold)
1 September 2015
http://blog.ihs.com/impairment-charges-at-record-levels-for-north-american-ep-peer-group-ihs-herold
The elevated level of asset impairments in the first half of 2015 have exceeded the previous annual high of the past decade in 2008. Given continued low commodity prices, we predict continuing severe impairments for companies in our North American E&P peer group during the remainder of 2015, with companies with high DD&A expense and assets outside core areas of the best plays most at risk. With proved reserves used as collateral for debt financing, E&Ps taking major write-downs in 2015 could have difficulty obtaining financing from their banks if prices remain depressed.
• Our preliminary second-quarter 2015 data shows the North American E&P peer group (Large, Midsized, and Small) took a total of $31 billion in impairment charges during the quarter, surpassing the first-quarter total of $29 billion. This propels the first-half 2015 total to $60 billion, far exceeding the previous high of $49 billion in 2008, as well as the 10-year annual average of $18 billion.
It appears that some companies began taking charges in Q1, and are taking a charge each quarter, while others are waiting until the end of 2015.
What is the reason for this difference? Accounting methods?
It appears that there are just two months left for SEC reserve value calculations for year end, 2015. As I and others brought up several months ago, many companies will have PDP PV10 smaller in value than the amount of their long term debt.
I think John Keller and Blaine brought up that banks are not on the hook for most of the debt, but unsecured bonds make up the bulk of it. It is odd, however, to see banks eager to loan funds to LTO companies who could possibly default on unsecured debt and who are insolvent, on paper, at least.
Again, I do look for US conventional production to continue to absorb the hit, as many conventional producers tend to be small business owners, who actually have to be concerned about paying debt back, no matter to who it is owed.
Why do unsecured bond holders just take a bath and take no action? It would seem to me that upon default, the unsecured bond holders could obtain a judgment against the defaulting company and lien the assets. Seems this might be some leverage to get some money out of the defaulting company/first lien banks, who probably do not want to go through the foreclosure process?
Or once the interest payment is missed, do the defaulting companies immediately file BK?
I would think it would usually be in the interest of the junior creditors to to force bankruptcy as soon as possible, while it still looks as if there might be value left over after addressing more senior liabilities. Their problem is that unless they have a debt covenant, they can’t force a bankruptcy until the company actually defaults on a payment, and for the most part, the bonds don’t have one.
Remember how all the E&Ps made such a big deal about how they didn’t have any debt due soon? Payments due are generally quite small. There’s really no standard approach, but when they started realizing they were in trouble, a lot of the companies issued secured second lien bonds which cut ahead of the older bonds, and they’ve been using the cash from these (plus credit lines) to make all contracted payments.
One way to achieve this might be to stratify them by county, using McKenzie, Mountrail, Dunn and Williams as ‘core’ counties, as well as by targeted formation (as you have said).
Our analysis was that high-grading was relatively difficult, at least geologically, as the industry was already completing 84% of its wells in core counties. The percentage has increased this year, but there was little headroom for them to improve. Obviously this excludes sub-county level high-grading, but it is not unreasonable to have expected companies to generally bring their best wells on first even in the absence of price pressure. In the daily reports companies have still been completing wells in peripheral counties like Bottineau and Bowman.
As mentioned before, my guess is that improvements in early production levels are temporary and technological – adding more sand to the frack, fiddling the engineering/choke – to improve IP, and thus asset bases and the potential size of loans, at the expense of ultimate recovery. Companies that need to do this far outnumber the ‘genuine’ oil companies that merely try to extract oil for a lower price than they sell it for, and comprise at least two of the three top producers.
thanks for your comments gwalke, I agree with you.
Hi Enno,
So with a frac log of 450 wells and assuming 70 wells drilled per month and 140 wells completed, we run out of the frac log in less than 7 months, if the frac log is 900, this gets extended to 13 months under the same assumptions. So possibly output could be maintained until April or September if well quality doesn’t deteriorate. Great stuff, thanks!
What is your source for the “Wells Spud” data, and why do we believe that this the date is accurate? Clearly the count from ND should be correct in the sense that it matches the actual wells, and the operators will eventually have to file paperwork with the correct spudding date.
But is there a reason they need to promptly report the spudding of a well? If your source is the ND well status reports, is there a reason why they shouldn’t be a month or two stale?
I get this data from:
– https://www.dmr.nd.gov/oilgas/
– Go to the GIS Map Server
– Click on “download shape files” (top right)
– download the wells.zip at the bottom
– open the wells.dbf in Excel
I have worked with this data over a year, and I found that every update typically contains minor revisions, mostly over the last few weeks. The revisions are typically changing the spud date with 1 day forwards/backwards, and a few new spud dates in the previous period. This was typically a minor occurrence, therefore I said above it could still be revised upwards with about 10% in my experience.
Thanks. Since that’s actual spud date data and not a proxy, I agree that the older data should be quite accurate, and that the accuracy of the more recent data can be determined from the revision history, and is apparently accurate as well.
Increasing pad size should be causing an increase, but that should be longer term, and not this kind of spike.
The only thing that I can think of that would cause the spike is crewing. Maybe when they’re about to lay people off, they have more people standing around waiting to fix anything that goes wrong? Even if they had the same number of people per rig, they wouldn’t be busy with setting up the next pad. The effect is larger than I would have thought, but after all wells are drilled by people, not rigs. Maybe someone with some experience could comment if this seems reasonable?
“The effect is larger than I would have thought, but after all wells are drilled by people, not rigs. ”
That’s a good point.
Current daily report data is also very interesting. We are only five days in (of 22) to forecasting September production, but on current data new wells would only add around 25kbpd. That’s compared to around 51kbpd added by July’s new wells.
One thing I noticed is that many (300+) inactive wells have been recently put back on active again. I am not sure how big an impact that will give.
WTI just hit $49.50 this AM
Reports are coming out of KSA that King Salman
is in a hospital in critical condition.
In regard to Saudi Arabia, I usually reference “On Saudi Arabia,” which was published in 2013. Following is a link to, and excerpt from, Chapter One:
http://www.amazon.com/gp/product/0307473287?ie=UTF8&isInIframe=0&n=283155&ref_=dp_proddesc_0&s=books&showDetailProductDesc=1#product-description_feature_div
An article from April, 2015:
King Salman of Saudi Arabia Changes Line of Succession
http://www.nytimes.com/2015/04/29/world/middleeast/king-salman-of-saudi-arabia-changes-line-of-succession.html?hp&action=click&pgtype=Homepage&module=second-column-region®ion=top-news&WT.nav=top-news&_r=0
An article from June, 2015:
Surprising Saudi Rises as a Prince Among Princes
http://www.nytimes.com/2015/06/07/world/middleeast/surprising-saudi-rises-as-a-prince-among-princes.html?_r=0
Someone recently posted a story about a memo circulating among the Saudi Royal family that was highly critical of King Salman and his designated successors.
Saudi royal calls for regime change in Riyadh (September 28, 2015)
http://www.theguardian.com/world/2015/sep/28/saudi-royal-calls-regime-change-letters-leadership-king-salman
Saudi King Hospitalized for Dementia (October 6, 2015)
http://en.abna24.com/service/middle-east-west-asia/archive/2015/10/06/713917/story.html
Interesting trends in the US onshore drilling sector:
Oilfield cannibals: to save cash, U.S. drillers strip idle rigs
http://www.reuters.com/article/2015/10/07/us-oil-services-parts-idUSKCN0S109S20151007
In a bid to save cash, rig owners are cannibalizing parts such as motors and drill pipe from idled rigs to fix 800 active ones in the U.S. when stuff breaks.
In good times, they would buy new equipment … when parts fail. Now, they just pick over any of about 1,100 rigs idled by the price crash.
Cannibalization is so widespread in this downturn that services companies and others say even after oil prices recover it will take six months or more to see a significant rebound in drilling and production – a timeframe that will allay fears of a quick uptick in drilling promptly sinking prices again.
NOV [National Oilwell Varco] has said so many rigs are idled that firms could cannibalize drill pipe for up to a year before placing new orders.
“(Cannibalization) will slow the industry’s ability to ramp the rig count back up so it will delay the production response from oil prices,” said James West, oilfield services analyst with Evercore ISI.
While there are no official statistics available, cannibalization has been so pervasive in this slump that industry experts say it is possible a majority of the 1,100 rigs that are not working have been scoured for parts.
Land rig utilization is hovering around 60 percent for larger U.S. drilling contractors, according to data from Tulsa, Oklahoma-based Helmerich & Payne Inc, which has a higher utilization rate because it has a fleet of newer rigs.
There are lots of spares available because the U.S. rig fleet was near a 15-year high when prices started to tumble.
Investors, still seeing an oversupply of rigs, and are encouraging companies to scrap more rigs to halt the slide in daily rental rates, now around $20,000, depending on the rig’s speed and power.
“Companies have to continue to scrap idle rigs and do all that they can to balance supply with demand,” said Robert Thummel, a portfolio manager at Tortoise Capital Advisors.
However, the scrapping of more rigs would likely increase the number of those ripe for cannibalizing, analysts said.
To escape the downturn gripping the U.S. shale market, Premium Oilfield is expanding in the Middle East.
“Our U.S. domestic customers, the oil producers, are shutting off all capital spending on just about anything,” said Hewell, whose Houston company is backed by Houston-based private equity firm Global Energy Capital LP.
Drilling efficiency? 🙂
cost optimization
Breaking apart perfectly fine rig in order to save few bucks on a spare part is the pinnacle of delusion. It’s like killing a cow for just two steaks.
One of many reasons that it’s going to take quite a while to get anywhere close to prior drilling and completion levels, even with supportive oil prices.
Ves,
The current US active rig count is 809. The 2014 peak level was 1931. In 2011 rig count exceeded 2000. Total number of oil and gas rigs, including rigs idled for long-term, was close to 3000. The common view among experts is that when drilling activity rebounds active rig count will is unlikely to exceed 1200-1400 units.
Furthermore, there is a constant shift towards newest and most efficient rigs.
I am sure that most rigs that drilling companies are disassembling are relatively old and will never be needed.
Alex,
I am not sure that I would agree that explanation on justification for disassembling the rigs.
1) “Experts” predict that rig count will not likely exceed 1200-1400 rigs.
Well then why these experts did not foresee collapse in 2013-14 and advise drilling companies to rain spending on the new rigs? The simple truth is that their opinion is worth it as much yours or mine.
2) Second justification that they are disassembling rigs are relatively old and will never be needed is also weak. They need them now because the parts that are taking from them are for the rigs that are drilling right now. So these are not obsolete rigs. They do serve the function.
3) And the third about constant shift towards newest and most efficient rigs. Well my question is did the drillers retired the loans that they got for the current rigs? With huge decline in the rig rates the answer is clearly not. So the question is where they will find capital to buy newer and fancier rigs? They will not get it. So that is why this is delusion on their part.
Ves,
U.S. oil & gas active rig count remained within a relatively narrow range between 1700 and 2000 for almost 4 years, while US C+C production increased from 5.5 mb/d to 9.5 mb/d, and natural gas and NGL production was also increasing.
Drilling companies were actively modernizing their drilling fleet, so there were also about 1000 permanently idled old rigs.
There is no doubt that all existing rigs will not be needed even if the drilling activity rebounds.
(1) Shale production will increase at much slower rates, and the drilling frenzy of 2011-14 will not be repeated.
(2) New rigs are more efficient and
(3) The is a constant shift to pad drilling
Thanks to (2) and (3) less rigs are needed to drill the same number of wells.
(4) If the demand for rigs start ito rise, customers (the E&P companies) will require newer and more efficient rigs, so there is no need to store old rigs.
Remember the 80’s, when 3/4 of U.S. rigs were scrapped
It has been common practice almost forever to strip parts off of idle equipment in slow times to keep equipment still on the job running.
For example, a couple of EXPERIENCED guys with a boom truck can remove a twenty thousand dollar (used) diesel engine from a dozer in half a day – and put it in a dozer on the job in another day and a half.
The bad engine that comes out can be put in the maintenance shop for a rebuild at leisure and installed in the donor dozer at leisure or kept on a pallet for a ready spare.
This way the mechanics are kept busy, helping keep the crew together, the dozer on the job gets fixed pdq, and the twenty or thirty grand needed to purchase a rebuilt or used running engine in a hurry is conserved to help the company get thru bad times.
Almost nothing is actually LOST except a day or two day of labor. The cost of that labor is apt to be less than the cost of a rental dozer for a couple of days.
Now I have never been around an oil rig, but I bet a five hundred horsepower weather proof electric motor can be removed in a day and that a new one would cost at least fifteen or twenty thousand and probably more.
Getting a bad one rewound would most likely take at least a week to a month because when times are slow for contractors, they are generally pedal to the metal for the specialists who fix stuff contractors cannot fix in their own maintenance shops.
Any large company that uses a lot of big diesel engines most likely has in house diesel mechanics. But electric motors are so dependable hardly any company has enough to maintain their own electric motor shop – so they get sent out.
Having said all this, older machines are indeed frequently robbed to the point they are never put back in service.
Manufacturers expect to make more money on parts than they do on selling new equipment, over the years. If you go to a heavy truck dealer and ask for the prices of the fifteen or twenty most expensive parts of a given truck, the total will exceed the price of a complete truck by a wide margin.There would be a thousand parts still to be bought to assemble a truck.
It doesn’t cost THAT much to keep parts in a warehouse and ship them to a dealer. Parts are THE profit center- along with the service department of course.
It is totally common place for a dealer to bill labor at five or more times what a mechanic makes.
People who sell new parts like to make fun of used parts, but the fact of the matter is that as soon as you drive a car off the dealer lot, with ten miles or less on the odometer, EVERY single part of it is a USED part.
I blew the engine of my first and only car and cannibalized another one like it with a bad body for its engine, which was in fine shape. Through this and another experience with almost wrecking the engine of my first and only motorcycle, as well as a few other mishaps, I found out very early on in life what a money sink and slave one can be to that kind of thing, never mind peak oil. License? Insurance? Tickets? I guess car-ownership is a bit of a cash-cow for the other side.
The car: Plymouth Valiant 1977 (big end came loose and it all flew through the bottom)
The bike: Yamaha RD350LC 1982 (near-seized piston)
Bonus edit:
As a kid, I once attached a Lego ‘motor’ to a blender motor… I found it intriging how fast I could get the little plastic square Lego piston– a toy– to go up and down (fast enough that it appeared static and blurred), especially with the engine-block, which would break apart at a certain RPM, duct-taped and some vegetable oil added to between the piston and cylinder. Suffice to say that the little plastic Lego ‘motor’ got scrapped too, though not puréed.
In its Short-Term Energy Outlook the EIA revised higher estimates of US oil production: by 62 kb/d on average for the second half of 2015, by 49 kb/d for 1H16 and by 22 kb/d for 2H16. I think this largely reflects the revision of its historical estimate for July.
From the report:
“Based on the latest survey-based reporting of monthly crude oil production estimates, U.S. production averaged 9.4 million b/d in the first half of 2015. This level is 0.2 million b/d higher than the average production during the fourth quarter of 2014, despite a more than 60% decline in the total U.S. oil-directed rig count since October 2014. However, crude oil production started to decrease in the second quarter of 2015, beginning with Lower 48 onshore production in April. Although the Lower 48 onshore decline was offset by production gains in the Gulf of Mexico that kept total production growth positive in April, total U.S. production began declining in May.
EIA expects U.S. crude oil production declines generally to continue through August 2016, when total production is forecast to average 8.7 million b/d. Forecast production begins rising in late 2016, returning to an average of 9.0 million b/d in the fourth quarter. A total of 12 projects are scheduled to come online in the Gulf of Mexico in 2015 and 2016, pushing up production from an average of 1.4 million b/d in the fourth quarter of 2014 to more than 1.6 million b/d in the fourth quarter of 2016.
Expected crude oil production declines from May 2015 through mid-2016 are largely attributable to unattractive economic returns in some areas of both emerging and mature onshore oil production regions, as well as seasonal factors such as anticipated hurricane-related production disruptions in the Gulf of Mexico. Reductions in 2015 cash flows and capital expenditures have prompted companies to defer or redirect investment away from marginal exploration and research drilling to focus on core areas of major tight oil plays. Reduced investment has resulted in the lowest count of oil-directed rigs in about five years and in well completions that are significantly behind 2014 levels.
Oil prices, particularly in the second quarter of 2015, remained high enough to support continued development drilling in the core areas within the Bakken, Eagle Ford, Niobrara, and Permian formations, with July and August showing the first consecutive month-to-month increases in the oil-directed rig count since September and October 2014. However, WTI prices below $60/b through the forecast period are anticipated to limit onshore drilling activity and well completion totals, despite continued increases in rig and well productivity and falling drilling and completion costs. The forecast remains sensitive to actual wellhead prices and rapidly changing drilling economics that vary across regions and operators.
While projected oil production in the Gulf of Mexico rises during the forecast period, oil production in Alaska falls. Production in these areas is less sensitive to short-term price movements than onshore production in the Lower 48 states and reflects anticipated growth from new projects in the Gulf of Mexico and declines from legacy fields in Alaska.”
http://www.cnbc.com/2015/10/07/russia-saudi-oil-cooperation-is-hogwash-kilduff.html
I agree with this guy, the chances imo of the Russians and the Saudis getting together to cut back on oil production are exceedingly slim to approaching zero.
My opinion is based not on their finances but on their rivalry. The Saudis have a LOT of reasons to fear and hate the Russians and to try to bankrupt them.