I don’t have anything ready to post and have noticed the conversation has wandered far from Oil and Natural Gas in the previous thread. Please post comments on non-Petroleum topics in this thread. Petroleum (Oil and Natural Gas) topics should go in the Open Thread- Petroleum post.
It is too much work to move comments from one thread to the other so I may delete posts that are in the wrong thread.
It will help if you don’t respond to posts that are in the wrong thread, even simple stuff like “Wrong thread” will not allow me to delete the comment without messing up the conversation.
We will see how this works.
So two threads, Petroleum and non-Petroleum, when in doubt use the non-Petroleum thread. By Petroleum, I mean Oil and Natural Gas.
I’m hoping that there are still some oil guys checking this blog Dennis. There was good information here before but wading through 500 comments of environmental doom and gloom isn’t worth the trouble.
Production has dropped 9 of the last 10 weeks right?
Shallow sand- watch the WTI market close Thursday, if we close over 34.50 or so we have a good chance at a three month rally. Good resistance at 49 though. But the narrative is shifting.
Cheers
Hi HR,
I agree things get a little out of hand at times. Oil impacts many aspects of society so it is hard to keep the conversation focused. Hopefully the two thread (petrol and n0n-petrol) solution will help to some degree. It would be great to see some of the oil guys come back. They aren’t all that interested in farming, renewables, and other topics which should all go in the non-petroleum thread.
Also Enno Peters liked the idea and his ideas are excellent in general.
On the production drop, I don’t bother with the weekly numbers which are not very good. The drop since March 2015 to Dec 2015 (monthly data) was about 400 kb/d or about 50 kb/d each month on average. It that linear rate of decline continues, we would be at 8660 kb/d by Dec 2016. It will depend on oil prices, which are unknown form now to Dec 2016.
Dennis Thanks for the split.
Hi Dclonghorn,
That should be in the non-petrol thread đ
Just kidding, Forbin just posted the same in the non-petrol because he didn’t want to break the Petroleum only rule. Would have been fine in either thread in my view, which is a potential problem with the split, where’s the line?
I will leave that to the reader to decide and will try to not delete comments.
If it looks like it shouldn’t be where it is, it is better not to respond.
In that case I have the option to delete. Once someone responds, deleting a comment messes up the whole comment thread.
Dennis, thanks very much for separating threads.
I seldom comment as I am climbing the learning curve and not expert in anything significant here. My interest is in oil, etc., so I am pleased to avoid the other stuff, and I hate to see the oil guys leave as they have things to teach us.
Dennis, I even like your graphics and scenarios, and I understand that they are what ifs, not forecasts.
Thanks for all you do for all of us.
Jim
Thanks Cracker.
A hearty second on that thank you from me, and another one for Ron for all he did previously!!!!!!!!!!!
Does anybody have any insight or interesting ideas on Saudi Arabia? I believe they are disingenuous with their ‘market share’ explanation…. I’m just using made up numbers here but my point is that they have sacrificed 90 billion in profit to get 30 billion in market share. Last time I checked business was about profits not about market share. If the IMF report I saw is correct then SA needs $106/barrel to balance the national budget (not sure how that works at $106/barrel when their 2015 budget was $229 billion but expenditures in 2015 ended up being $260 billion http://www.bloomberg.com/news/articles/2015-12-28/a-breakdown-of-the-2016-saudi-budget-and-its-implications ). For the sake of argument lets call their national budget ‘corporate overhead’. I suspect SA is at a crossroads of some kind. Drilling rigs are up quite a bit the last couple years but production is up slightly/wobbly. Maybe they know they’re peaking and this is a big psy-op/economic warfare to confuse the competition, maybe it’s a tumultuous power transition that lacks strategic continuity and the new king/clique is not a good strategist….. I could go on. The intrigue could be deep or shallow. Anybody have a good theory or read on where SA is at and going to? My guess is 30 million people soon to be on foot headed for Europe.
A couple things on my mind:
World C+C minus North America is Flat since 2005:
http://crudeoilpeak.info/world-outside-us-and-canada-doesnt-produce-more-crude-oil-than-in-2005
World conventional is flat since 2005:
http://euanmearns.com/a-new-peak-in-conventional-crude-oil-production/
Hi Survivalist,
The World C+C output has either peaked (in 2015) or will do so within 10 years, we will have to wait 10 years to find out. Oil guys such as Fernando Leanme have claimed that a rise in oil prices to $150/b (in 2015$) will make a lot more of existing oil resources profitable to produce, whether this is enough to offset depletion is an open question as is the level of oil prices that the World economy can afford.
On oil prices we can do the following back of napkin estimate. World real GDP at market exchange rates about $80T 2015$ and assume 2% real GDP growth for the next 5 years which would bring us to about $88T real GWP in 2015$ in 2020. Let’s assume the world can only spend 4% of GWP on oil without causing a recession and that C+C output remains at 80 Mb/d in 2020 (29 Gb/year).
The 4% of 88T is $3520B and we divide by 29B and get $121/b in 2020. An oil price of $150/b would be close to 5% of GWP and would likely cause a recession.
I will let the oil guys comment on whether $120/b is enough to bring on adequate oil supply to avoid a recession, a crisis will eventually occur as I expect that demand will eventually outrun supply in the short term (next 10 years) and oil prices will spike above $150/b and lead to a global recession. At that point the peak may finally be clear to all and a transition away from oil will begin in earnest.
The line between oil and non-oil is pretty fuzzy. For instance, this discussion of economics is kind’ve non-oil – I mean, would a guy out in the Gulf of Mexico, commenting on his iPad while he waits for a change of drill-bit, be interested? And, how can one say ” a rise in oil prices to $150/b (in 2015$) will make a lot more of existing oil resources profitable to produce” without mentioning that it would also make a lot of substitutes far cheaper than oil? And, then, of course, examination of that idea takes us farther afield…
Hi NickG,
I agree lines are never clear. Let’s say I posted a link on Earth worm anatomy. Now one could say earthworms use energy and oil is also energy so clearly this article on earthworms is connected directly to Petroleum. Right?
Heh.
Well, as I think about it, I think the lines are a little clearer than that. I’d say there’s oil production and information that’s internal to oil companies, including their accounting, that oily guys would be privy to, and then…there’s everything else.
Micro-economics, macroeconomics, forecasts, world politics, oil substitutes: that’s all “non-petroleum”.
Things are fuzzy in large part because oil guys are happy to talk about non-oil stuff…they just don’t want people to disagree with them!
Well said, Nick, and I’m inclined to agree.
When you specialize the hell out of reality, you ‘lose’ it. Then you have a bunch of specialists running around with less of a clue as to how reality fits together. Like we have now. It’s structural myopia, glorified obsessive compulsive disorder, and with their inherent dangers, maybe even including subtle forms of neurological atrophy.
Hey Dennis, to be sarcastic, why stop at ‘petroleum and non-petroleum’? How about slicing and dicing the subject-matter into progressively-smaller elements until there’s nothing left?
As a qualification, though, perhaps POB’s threads won’t all be delineated along those two lines and so with some opportunity for idea and discussion cross-pollination, yes?
maybe itâs a tumultuous power transition that lacks strategic continuity and the new king/clique is not a good strategist
This hypothesis along with “hurt Russia” hypothesis (which simultaneously hurt their main regional rival Iran) are the most plausible IMHO. Please note that KSA is a vassal of the USA. So by extension it looks like “team Obama” is not a good strategist either.
In terms of a C&C peak pushed out for 10 years my question would be âWhereâs the oil?â even at $120 per barrel.
Apologies that the following is too long, with no charts for many (or any) to read all the way but some parts may be of interest.
The last few years have shown declining oil discoveries since 2010. What has been found is more often than not deep water and relatively small. Such fields generally have short plateaus and steep decline rates (not much better of those seen in LTO for fields less than about 150 million barrels). The larger basins found offshore have been in the 5 to 10 mmboe range rather than around 50 found in the earlier days.
I donât have access to IHS or Rystad databases but picking amongst recent press releases Iâd say 2013 was about eight billion, 2014 nine or so and 2015 four or five. This year maybe only three discoveries with a significant amount of oil â Kuwait might be significant. More gas than oil is being found
http://www.oilandgasinternational.com/directories/exploration_discoveries.aspx
There has been a noticeable reduction in development times for projects in GoM and North Sea in recent years from around 7 years down to as low as 3. That to me indicates a dearth of good, large projects to choose from.
Of some of the main producers:
Saudi; 50% increase in rig count since 2012 to keep production just about steady, announced âthe most fields discoveredâ in 2012 or 2013 but a combination of oil and gas and they didnât give quantities, have spoken of developing tight gas and solar to allow increased oil exports.
Russia; some conflicting announcements but it looks like a decline next year, largest recent find was by Repsol at about 240 mmboe. Sanctions have had an impact and may continue to do so, especially offshore.
http://uk.reuters.com/article/uk-russia-oil-rosneft-idUKKCN0WV1I3
Canada; very little drilling activity, four fields coming on over the next 2 to 3 years will add up to 400,000 bpd, but then nothing planned and at least 4 year lead times for tar sands projects. Tar sands projects have long plateaus but it appears some of the earliest mining operations are starting to see thinner seams so decline will become more evident.
Brazil; cut backs in developments and may start to decline next year, they have mostly deep water production with high decline rates and rely on continuous stream of new projects to maintain production â the oil price, âcarwashâ scandal, debt/bankruptcy problems and (maybe) just running out of suitable projects have stopped this, expect 6 to 10% decline through 2017.
http://oilprice.com/Energy/Crude-Oil/Future-Of-Brazils-Oil-Industry-In-Serious-Doubt.html
Mexico; EOR developments seem to have run out of steam and not much interest in their opening up the industry to outsiders, expect at least 4% per year decline.
http://www.bloomberg.com/news/articles/2015-05-21/mexico-lowers-2015-growth-forecast-after-oil-production-decline
USA; discussed a lot here, some expansion in GoM through 2017, unknown response to LTO drillers depending on price and credit availability, liquids from gas have been another significant and rapid boost to production recently which EIA indicate are still rising (mostly for NGLs), but surely must run out of steam sometime soon. Possibly some shut in stripper wells wonât be worth restarting.
http://www.theenergycollective.com/u-s-production-of-hydrocarbon-gas-liquids-expected-to-increase-through-2017/
China; reliant on EOR recently to maintain plateau (including a lot of steam flood from the EIA report) but predicting 5% decline next year, no great success on offshore discoveries.
http://www.bloomberg.com/news/articles/2016-03-24/-no-hope-oil-fields-spur-1st-petrochina-output-cut-in-17-years
https://www.eia.gov/beta/international/analysis.cfm?iso=CHN
North Sea; saw a spate of projects recently, mostly heavy oil, with a few more to come over the next two years and then Johan Sverdrup and Johan Castberg but these only delay decline for 2 or 3 years, recent discoveries especially in UK sector have been very poor.
http://fractionalflow.com/2016/03/29/norwegian-crude-oil-reserves-and-extraction-per-2015/
http://www.rystadenergy.com/AboutUs/NewsCenter/PressReleases/northsea-ep-decline-coming-to-an-end
http://www.OilVoice.com/n/United-Kingdom-increases-oil-production-in-2015-but-new-field-development-declines/39dbcb23d382.aspx
http://www.rystadenergy.com/AboutUs/NewsCenter/PressReleases/breakeven-ncs-new-fields
Offshore Africa; Nigeria and Angola have a number of projects this year and next ( a bit more oil than gas), but after that Iâm not clear, political unrest might be particularly important here as well. That said recent exploration success has been relatively good in Africa overall (e.g. Kenya, Ghana).
http://www.offshore-technology.com/projects/region/africa/
Venezuela; not sure if their numbers can be trusted but they seem to be in decline, I know little of their particular technical issues but assume that in order to increase extra heavy oil production they would need new upgraders and possibly a source of natural gas, like Canada, and possibly dedicated refineries to handle the heavy metal content (and assuming they can find willing creditors and EPC partners).
Iran and, possibly, Iraq and Kuwait look like the only likely areas that can show some increase, but Iran is developing South Pars gas field more than oil and Iraq/Kurdistan might have run out of impetus. Burgan field in Kuwait looks in better shape than other aging super giants and Kuwait has an active exploration and development program. And of course maybe US LTO takes off again, $80 appears a threshold but that is for WTI, ND oil has a $10 discount, the lighter LTO oil everywhere may be lower still and overall away from the sweet spots above $100 might be nearer the mark.
The seven largest oil majors have shown declining reserves of 1 and then 2 billion barrel equivalent over the last two years â this may be purely price related, but Iâm not so sure especially with BP, Shell and Chevron looking to sell assets, also I donât have the figures but Iâd guess that they have lost more in oil reserves as some of their big finds have been for gas.
http://www.forbes.com/sites/rrapier/2015/12/28/prepare-for-a-dramatic-decline-in-oil-reserves/#4e0ce4ed75cc
http://www.mrt.com/business/oil/top_stories/article_173026e6-743c-11e5-9883-bb5c1f414082.html
http://www.houstonchronicle.com/business/energy/article/Oil-companies-face-difficulties-replacing-reserves-6562231.php
To ramp up of production is going to be dependent on a work force which was aging and retiring in 2014 and now has been decimated by layoffs and recruitment cut backs. Increasing prominence of environmental issues may hinder both future recruitment efforts and the pace at which projects can be developed. Significant new oil, including reserve growth, has to come from deep water â those rigs are complicated and very expensive to run, a lot are currently being stacked.
Ramp up also needs the main stakeholders to regain their acceptance of financial risk, which is currently as low as I can remember, and significantly higher sustained prices. The other side to the equation for prices is demand. The world economy doesnât look great to me, weâre due a recession based on approximate 8 year cycles, TPTB have chucked everything but the kitchen sink at it and industrial output is definitely in decline or growing only slowly (I donât know how energy use is split for service versus manufacturing but Iâd guess itâs of smaller relative importance in the service sector). A relatively small oil price increase might be enough to kick a recession off properly.
Hi George,
Hubbert Linearization of C+C less oil sands suggests about 2500 Gb for a URR, in the past this method has tended to underestimate the URR, we have produced about half of this so far. There is also about 600 Gb of URR in the oil sands of Canada and Venezuela. The USGS estimates TRR of C+C less oil sands at about 3100 Gb, I use the average of the HL estimate and USGS estimate with a URR of 2800 for C+C less oil sands and oil sands URR of 600 Gb. Total C+C URR is 3400 Gb in my medium scenario. If extraction rates continue to grow at the rate of the past 6 years and then level off we get the scenario below.
Model based on Webhubbletelescope’s Oil Shock Model.
See http://peakoilbarrel.com/oil-shock-models-with-different-ultimately-recoverable-resources-of-crude-plus-condensate-3100-gb-to-3700-gb/
Part of my argument is, though, that the current discovery success (or lack of it) and the recent behaviour of the main oil producing nations and companies isnât consistent with that high a level for URR.
Hi George,
There will be reserve growth and discoveries in the future. As of 2010 based on Jean Laherrere’s estimates 1950 Gb of C+C had been discovered and was part of 2P reserves and cumulative output. Reserve growth is a reality, US reserves grew by 63% between 1980 and 2005. Jean Laherrere estimates about 250 Gb of discoveries plus reserve growth after 2010. Based on Hubbert Linearization, my estimate is at least 550 Gb of reserve growth plus discoveries and based on the past tendency of HL to underestimate URR, I believe 850 Gb of discoveries plus reserve growth is more realistic. In 2010 2P reserves were about 850 Gb, if they grew by 63% in 25 years, that would be about 530 Gb of reserve growth ( I expect it will be more like 40 years to get this much reserve growth) so we would need 330 Gb of discoveries after 2010 to get to 850 Gb (not including oil sands here), that would be an average of about 8 Gb of discoveries per year. Potentially reserve growth could be higher for the World than in the US where the fields are very mature, in that case less discovery would be needed.
I guess we will just disagree on this, so far decline has not been very steep for the World less (Canada + US +Russia+OPEC).
I think a case can be made, over a 10 year period, for Brazil, Canada, USA, Iraq, IrĂĄn and miscellaneous (possibly Venezuela if the Maduro regime falls) new sources to sustain an undulating plateau. I wouldn’t expect this to exceed 80 mmbopd crude plus condensate.
However, it’s more important to point out that, if the world economy keeps growing, somethng else has to feed the gap, and efficiency isn’t enough. Whether it’s now or in 10-20 years it’s definitely coming. We will need gobs of energy, and thus far I don’t see a source other than a hodgepodge which has to include nuclear.
Hi Fernando,
I agree that nuclear should be part of the mix, but for security reasons it would be better if it were minimized and if new designs were developed that don’t require cooling after shut down (pebble bed maybe I am not up to date on the subject). I think a widely dispersed HVDC connected wind and solar power system is feasible with a little natural gas backup at first, but eventually using mostly batteries and fuel cells and demand management to smooth out peaks and valleys.
See work by Jacobson and DeLucchi, the second piece has more details.
http://news.stanford.edu/news/2015/november/plan-energy-storage-112315.html
https://web.stanford.edu/group/efmh/jacobson/Articles/I/JDEnPolicyPt1.pdf
Growth in the poorer parts of the world will surely put pressure on oil supplies, and it’s anybody’s guess as to how much growth will come to pass, especially in the developing world.
But I can easily envision the efficiency of use of oil rising at one percent or faster, on an annual basis,for a decade or two, in the developed world. It’s easily possible to get that big a gain just by increasing the fuel efficiency of all the new machinery a to z that burns oil, if new machinery displaces the old stuff fast enough.
I think maybe this will happen, because although cars and light trucks are not JUNKED for fifteen years or so on average, they are mostly driven less and less as they get older. This applies to trucks too. Heavy trucks that are driven upwards of a hundred thousand miles a year by team drivers on long haul routes are generally retired to local routes within five years, and then after that, they are sold to small time operators who use them intermittently, sometimes only a day a week.
I know of plenty of ten wheelers and eighteen wheelers that are ready to go at the turn of the key, none of which get as much as ten thousand miles on the odometer in a year. Some get well under five thousand, but having them sit, tagged and insured, and available, is cheaper than hiring a truck, or trying to hire one and not finding one available on short notice. A local farm supply offloads bagged fertilizer and lime directly to customers from their eighteen wheeler for instance. It serves as on site storage when not being used to pick up from the wholesaler.
Then there is substitution. If the super strong tanks needed to store large quantities of gas in a small volume get cheap enough, we will see large numbers of trucks equipped to run dual fuel, gas OR diesel. It won’t take a whole lot of truck stops equipped to sell gas to truckers to make this a viable option, if gas is cheap, compared to diesel.
It’s impossible to guess imo how much mass transit will be built.
It has its attractions, but it also has its enemies. A business owner whose business will not be on the routes has a hell of an incentive to prevent it being built at all.
In Richmond where I used to live, it was actually a detriment to many property owners to own a house too close to a bus line. The more prosperous class of people seldom rode the buses under any circumstances, and preferred not to mix with the working class people who used the buses on a regular basis.
I owned such a house, located less than a hundred yards from a bus stop, and it appreciated much more slowly than identical cookie cutter houses a quarter of a mile or half a mile off the bus route.
Of course that will change if driving gets to be expensive enough, and if buses ever actually GO PLACES other than down town on and out again on a hub and spoke system.
I could WALK to some places three or four miles away, and back again, quicker than I could get there by bus, and back again. Of course I always had a car, and never took a bus unless headed downtown where parking sometimes meant walking quite a way, plus paying for it as well. Even as a sometimes grad student, my time was worth more than the cost of driving an old car.
Batteries will eventually displace ice engines in cars, but the hands on guys in this forum will be dead or retired before electric vehicles put them out of work.
Hi George,
One of the main producers is the US and the US is also the most intensively developed oil producing nations along with being the most mature large producer (more than 100 Gb cumulative C+C output).
To look at decline rates I took a period of relatively steady decline from 1990 to 2003 and considered the natural log of the trailing 12 month average output (to eliminate seasonality) to consider annual decline rate over this period. The slope of the linear trendline will represent the average annual decline rate.
We find that for the US this was 2.23%/year over the period in question.
For the World as a whole the average basin is much less developed than the US and we would expect that on average World decline rates would be considerably lower than for the US.
“World decline rates would be considerably lower than for the US.â – why? The US fields are mostly onshore, they are big fields, they have almost no access limits, stable socioeconomic regime, pretty good geology in most places, oil that is almost as good as it gets in terms of quality (API, metals, sulphur) and easy access to itâs main market – everywhere else is worse in at least one, and often most, of those criteria.
Hi George,
The US pushed output very hard to 61% of URR and still decline was only 2.5% (from 1985 to 2005) for all US C+C.
If the World does the same the decline may be similar, but all the reasons you give for why the US can produce a lot of oil are the reasons that decline is steeper in the US. The difficulties in the rest of the World lead to lower extraction rates and lower extraction rates result in slower decline rates. The World is only at 38% of URR (1280/3400) or if we use a more conservative 3000 Gb URR 43 % (1280/3000), if we use Jean Laherrere’s very conservative 2700 Gb URR it would be 47%.
The extraction rates in the US are much higher than the World average.
Hi George,
US extraction rate from proved producing reserves was about 13.7% in 2015, for the World my estimate (based on a shock model) is an average World extraction rate of about 8.4%, from 2014 year end proved producing reserves of about 334 Gb.
I personally believe Saudi Arabia’s oil production strategy since 2014 has 3 pillars:
1. Maintaining market share: This is Saudi Arabia’s primary asset – the ability to exert power over other countries via its oil supply. Saudi Arabia has the power to cripple rivals by flooding the market, and can also cripple OECD countries by limiting supply. Without the PERCEPTION that this is true Saudi Arabia’s only genuine political leverage evaporates.
2. Group Think: The behavior of the new Saudi King Salman, the revolt within the Royal Family as a result of his policies, and the breaking of tradition to name his “ambitious” 31 year old son as the heir apparent all suggest a breakdown of technocratic, informed policy. Say what you will about Saudi Arabia, but its political structure was technocratic until January 2015. Since then I believe there is a significant influence of Group Think, and there’s consensus that the young son if currently deciding policy, and often chooses against the advice of experienced council. This 31 year old who doesn’t listen to expert advice, who has caused a revolt within the House of Saud, may very well believe that Saudi oil fields can produce any quantity of oil, for however long he demands without consequence or depletion issues. It’s important to note that the previous King and Council decided on the current “market share” strategy, and deep animosity toward Iran as it re-enters the market may influence SA’s strategy to their own detriment.
3. There were several long-term projects such as Manifa and Khurais that were coming online regardless of a glut. These mega-projects were guaranteed to put a floor under production numbers. In concert with the sustained high rig counts to win the “maintain market share” strategy SA’s production reached record levels.
It is important to note that it took a truly herculean effort, record rig counts, and re-developing several mathbolled fields to raise production from 9.5 mbpd in 2008 to 10.25 mbpd in 2015. They threw in the kitchen sink and got 750,000 bpd of extra production.
That is telling in and of itself.
SA has followed an explicit strategy of maintaining market share i.e. producing every barrel they possibly can. SA took on a multi-year effort to push their production as high as possible. We now know SA’s maximum possible production, and the incredible effort required to maintain it. I personally do not believe SA will ever be capable of producing 11 mbpd.
It is not at all unknown for an aggressive minded political leader to bite off more than he can chew, and choke on it, due to being unwilling to listen to expert advice.
Hitler almost for sure could have won a substantial empire and Germany could probably have kept control of it for a quite a long time, if he had been ten percent as talented in military terms as he was in political terms ( not to mention being a world class evil character of course) IF he had LISTENED to his very capable senior military guys.
Brian is probably right. This young SA guy, King Salman , may be in the process of making the same mistake, namely failing to listen to his technical guys.
Even if Salman realizes he is not going to be able to increase production much if any, or even maintain it at current levels mid to long term, he may still be full of testosterone, and willing to bet his kingship, and potentially his entire country, on his current policies.
It is well known, a trusim or cliche, that one of the best ways a leader in trouble can maintain and consolidate his power is to go to war, and SA is (obviously in the opinion of many observers ) fighting an economic war with rival oil producing countries.
I have long believed that SA is a powder keg awaiting a spark. One serious mistake on the part of the leadership could set it off. One random event could set it off. The House of Saud has made many a bargain with the devil in the guise of the super conservative priesthood which enables it ( SO FAR! ) to maintain control of the country without resorting to the business end of rifles.
Radical change is coming to SA, because it information moves too freely in the modern world to keep the people in the dark much longer. Too many privileged young folks are traveling, and doing to suit themselves, and too many poor people are growing more radical by the day. Too many outsiders are working in the country.
If it weren’t for oil, and to a much lesser extent, some other mineral wealth, the rest of the world would barely notice even the existence of that mostly desolate patch of sand.
This is purely anecdotal. For the past three years, we have rented our unused bedrooms to several Saudi students, here to study in the US. They first go to a language school, and then on to a university. In just this brief time, they speak of the Saudi government no longer footing the bill for this. This means that the student’s families must send money. For some, this is clearly not a problem, but for many it is.
OFM,
The young guy is Mohammed bin Salman, second in line to the throne last I looked, Defense Minister, in charge of an overlook body for Saudi Aramco, and other things. He may, as you say, not be listening to his technical advisors–may in fact be a loose cannon–and he is widely considered to be the power behind the throne.
He isn’t the king, though. That’s Salman himself, and he is often said not always to know where he is or what he has just said. Scary situation there, you bet.
Senior moment on my part there, but better old and absent minded than dead, lol.
I am not putting as much time in reading the news thoroughly lately as formerly.
There was an interesting documentary on Saudi Arabia last night on Frontline.
Lots of Saudis living in poverty, women begging in the street to feed their families, while very nice cars drive by. Shiite minorities in the eastern (oil-producing) region protesting and being repressed by the government.
There was hidden-camera footage inside a shopping mall — much like a mall in the US, with a Cinnabon, Victoria’s Secret, high-end makeup counter, etc, but very few people. But what the mall also had was religious police beating people who buy the stuff, and it showed them beating what appeared to be a plump middle-aged housewife, covered head-to-toe in a black burqa, who was buying makeup. So the government is simultaneously allowing the mall to sell this stuff and paying religious police to beat those who buy it.
It very much looked like a powder keg that could blow at any time.
Techsan,
Frontline documentaries are a personal favorite of mine. Always stellar, genuine investigative news journalism. Even on subjects I think I am fairly knowledgeable about I always come away having learned a lot.
It is 2nd only to Ken Burns’ documentaries, but it’s hard to compare since his documentaries are history documentaries and Frontline is investigative news.
For anyone looking for a link: http://www.pbs.org/wgbh/frontline/film/saudi-arabia-uncovered/
KSA’s aim as alleged by the mainstream media in the West is to harm high-cost competitors. The second possible explanation has to do with the geopolitical rivalry of the GCC (and its NATO masters) against Russia/Iran/Iraq/Venezuela.
I think that BOTH explanations are valid. I also think that KSA are essentially right in their pursuit of BOTH aims. Let me explain:
a) KSA is a mortal enemy of Iran/Syria and wants them destroyed. Same applies to Iraq as well and to their most powerful ally, Russia. What better way to put pressure on your hated enemies when they happen to be: Russia, Iran, Iraq, Kazakhstan & Venezuela? Obviously, a low oil price would be the best available weapon against those countries.
b) The reason why (in the short-term at least) the low oil price is a potent weapon against NATO-GCC’s geopolitical foes is because those countries are not only heavily reliant on oil exports for much of their economic well-being (GCC are also heavily reliant on oil exports) but are also much less capital poor than the NATO-GCC complex and have greater difficulty in fiscally covering for lost revenue. Additionally, many NATO members (vast majority of Europe) are oil & gas importers and have benefited from the extremely low oil prices.
c) In the longer-term, I think all on this blog understand that the oil price cannot remain remotely at the current levels. This is in my opinion the second leg of the KSA strategy. Have high-cost producers around the world suffer the consequences for their reckless investments in high-cost extraction methods of oil & gas. US shale, Canadian tar sands as well as ultra-deep-water in several regions are all disastrously loss-making with current oil prices. The full-effect of the oil price collapse on these types of investments will only be seriously felt 3 years down the road and onward. Without the current oil price collapse, marginal oil production would almost surely have kept on growing putting pressure on OPEC in general and KSA in particular to keep cutting more and more of their own production so as to accommodate more and more marginal production from North America and beyond.
So, there it goes. There are clear short-term and long-term goals in KSA’s oil strategy. As any serious war, there are always considerable costs to be incurred, but any alternative would be much worse for KSA and its core interests. Their strategy is both understandable and perfectly rationale.
Except that Iran and Russia aren’t about to knuckle to the Saudis. They both will simply weather the crisis, take note, and then the wheel will turn.
I believe both Stavros and Fernando have scored bullseyes.
I was over there 4 times in the last 2 years for work. The big runup in rig count was to maintain capacity. Remember that nitrogen injection has been ongoing there for some time, and there are many stranded globs in the reservoirs due to overpumping and coning during waterflood ops – hence all the geosteering in the horizontal wells and the ramping of rig count. The fact that ARAMCO is even employing horizontal drilling should have set off alarm bells years ago.
My first trip to KSA was long ago – the empty pipelines running across the sands far outnumber the full ones and it has been that way for well over a decade. My opinion is that Ghawars’ end is in sight, along with Safaniya, Manifa and others. This is simply based on what ARAMCO drilling ops are, not anything else. To frame it in layman’s terms – it greatly resembles what the East Texas field looked like as it declined, with every new technology they can wrap their arms around being brought into play. Cost is not an issue for them when deciding on tools or tech – recovery is. It wasn’t that way in 1995 or even 2000.
This isn’t going to happen like lightning, but even with the increased rig counts and wells put down, total production is not increasing appreciably. There was a reason that the KSA rig count hardly moved for many years – it didn’t need to. Today is not like yesteryear. My guts tell me that in the next few years, things will change more rapidly.
I am still working in the collapsing oil patch, but am not going back to KSA ever – conditions are growing worse for Anglos on the ground within the Kingdom, within Qatar and even in Egypt. I simply don’t want to get caught up in a revolt or in some other mess like I did in Colombia – it isn’t worth the risk. You guys can debate the numbers and such all day long – just like at TOD. I work in this business, and what I see in terms of well types, ops and tech deployed speaks volumes to me about what is happening downhole.
Peak Oil is like watching a train wreck in slo-mo, and it would behoove many to just accept that it was never going to be a bell curve or it wouldn’t require ‘normalizing’. The industry innovates rapidly because of huge money thrown at it, which throws a lot of otherwise great prognostications under the bus in a short time. FWIW, what I see in MENA indicates a lot of struggling to make the numbers. The fact that most MENA operators have tested a shale oil well or two is also an eye-peeler…
Oilman
Thanks for posting that information.
Hi Oilman,
Yes thanks. Note that the US declined about 2.2% from 1990 to 2003, so there will be decline but the US was at 83% of the URR estimated by HL in 2007, for the World as a whole we are at about 50% of a conservative HL estimate. So it is unlikely that World C+C will decline by more than 2%/year. Some places may decline at higher rates, others will decline at lower rates, overall for the world as a whole it will be 1% to 2% in my opinion. A physical model of oil depletion backs this up.
Oilman,
Your statement to me says it all.
There was a reason that the KSA rig count hardly moved for many years â it didnât need to.
For the slow ones, the inference being that with the current rising rig count, they need more oil now!
@Oilman2
Yes, the Saudi oilfields are getting more marginal with time, maybe significantly so. But the relevant question is: What are the actual production costs across the Saudi oil sector? And if they are X, how able/unable is the Saudi economy to maintain/slightly increase production? To illustrate my point more practically, let’s assume that full-cycle production costs in the Saudi oil sector have increased from $5/bbl to $12/bbl. It is still plausible that this poses no great threat to KSA’s ability to at least maintain production around the 10m/bbl/day. If not, why is that so?
There are enough of you doing analysis that my input in that regard is redundant. If you want to understand the costs for all this drilling, you need to realize that directional drilling is twice as expensive as vertical; geosteering is 3X vertical costs and anything added to that is even more expensive. If you look at the technology deployed, large chunks of it didn’t exist 2 decades ago.
There is little reason to geosteer in the largest oilfield in the world, unless you are trying to hit a small target…
I know you guys are looking at big data aggregations WRT depletion, but the other side of the coin is what happens when it finally sets in – like in Mexico. When you simply cannot gin up the same revenue you have grown used to. Mexico has other options thanks to major offshoring of US manufacturing and agriculture there, but I would posit that this is an anomaly for most oil exporting countries.
I would also caution that depletion is not nearly as predictable as most profess, until you get to the stripper well stage. At some point, especially under low oil price scenarios, you just leave it and walk away. Under high price scenarios, you leave it because other, bigger prospects look more promising. At every stage of these decisions, there are massive assumptions and SWAGs made.
In the US, we have tiers of companies of different sizes and overheads, giving us the unique ability to make money on stripper wells and small prospects. But even Apache walked away from gleaning the US Gulf of Mexico – they were too big and prospects becoming fewer and more risky. National OilCo’s do not have this capability, and so they leave a lot more behind when they step over and around reserves that do not make economic sense.
That is why any ultimate numbers and estimates are bogus in nationalized scenarios – it all depends on the base overhead and liabilities of the extracting entity. This is why Mexico and KSA are floating proposals out for external investment; their internal costs are too high to eke out profit under depletion scenarios.
The US is not like other countries in many respects, and this is a prime example.
Just some non-numeric thoughts for you crunchers out there..
All good points. My guess is US production would be a fraction of what it is if we had a National Oil company.
It would seem that the KSA could lease those reserves that they are not interested in to smaller private oil companies that might be able to produce them at lower cost.
The Mexico situation was pretty exceptional, they were pushing that field (Canterell, I think) very hard, does it seem to you that KSA is pushing their fields to that degree?
So far Simmons has been wrong on KSA. Fernando Leanme thinks my 3400 Gb oil shock model is pretty reasonable, though he might choose a bit lower oil sands URR (maybe 450 Gb rather than 600 Gb) due to problems in Venezuela.
Time will tell.
Pushing Cantarell hard? You mean like with lots of horizontal drilling and waterfloods and geosteering? Hmmm…
When I went to KSA the first time, there were gangs of 12 and 16 inch flowlines with heat waves pouring off of them, all flowing oil. 10-12 years later, there were more empty flowlines than full ones. Now, there are a few flowing. It isn’t rocket science to extrapolate this. You guys have a problem, in that trying to find the truth when it is in KSA mightiest interest not to share it presents you with a black hole. I can’t help you in that regard. I can’t give you numbers and a date, but always remember that it is just fine to tell lies to infidels.
As for bringing in smaller oil companies – the amount of baksheesh leveraged by KSA is the largest in the world. You have to have a KSA partner to do business in the kingdom, and they take a sizable cut just for repping anyone. Even then, if you guess at the wrong one, you get a token amount of business, so you have to let the contract expire and then pay higher percentage for a really connected guy to get decent business. Then they can force you to renegotiate this same contract for even more.
Until that changes, the incentive isn’t all that sexy for the little guys – not at all, especially for service companies. The “baksheesh factor” can’t be ignored, nor the importance of the right political connections, and it always costs more.
Hi Oilman2,
Are they using nitrogen injection in Saudi Arabia, I thought it was mostly water flood?
By pushing the field hard, I am talking about production divided by total original 2P reserves,
for Cantarell maximum output was about 2,2 Mb/d and original reserves were about 18 Gb.
By comparison, for Ghawar the original 2P reserves were about 100 Gb, over 5 times larger than Cantarell and maximum production was about 5.7 Mb/d in 1981 and reportedly as high as 5 Mb/d through 2003.
So in relative terms Ghawar has been produced at moderate levels relative to Cantarell, about half the rate in max production divided by original 2P reserves(0.057 vs. 0.112).
Oilman2
Thanks for the post. I and others here have inferred much of what you posted from the limited info we have. It nice to hear it from someone with personal knowledge.
Thanks everybody for replying to my question with such great information. I also appreciate the link on the Frontline show about Saudi Arabia that was added. That was a great investigative report. Saudi Arabia seems to be heading for a major crisis.
I found this article interesting also:
ISIS Turns Saudis Against the Kingdom, and Families Against Their Own
http://www.nytimes.com/2016/04/01/world/middleeast/isis-saudi-arabia-wahhabism.html?action=click&contentCollection=Economy®ion=Footer&module=WhatsNext&version=WhatsNext&contentID=WhatsNext&moduleDetail=undefined&pgtype=Multimedia&_r=0
This also feeds into the ‘straws in the wind’ –
http://www.bloomberg.com/news/articles/2016-04-01/saudi-arabia-plans-2-trillion-megafund-to-dwarf-all-its-rivals
“Deputy Crown Prince Mohammed bin Salman laid out his vision for the Public Investment Fund, which will eventually control more than $2 trillion and help wean the kingdom off oil. As part of that strategy, the prince said Saudi will sell shares in Aramcoâs parent company and transform the oil giant into an industrial conglomerate. The initial public offering could happen as soon as next year, with the country currently planning to sell less than 5 percent.”
How do the Saudis take the Aramco parent company public without having to disclose true reserve numbers? Or does taking the parent company and not Aramco itself allow them to keep those numbers a state secret?
I am reading The Oracle of Oil by Mason Inman. It is well researched and well written. I rank it with the all time best books on energy. I say energy because King Hubbert also developed expertise on nuclear power and solar energy. Hubbert discovered how fracking worked about six decades ago. He first contemplated resource limits as a college student during the 1920’s. He became involved with Technocracy during the depression years. He first did oil field work while going to college. After joining the Columbia Geology Department, he attempted to bridge the gap between geology and physics. Later he worked for the US Government and Shell. Hubbert was awarded the Vetlesen Prize, the closest equivalent of a Nobel Prize for petroleum scientists.
US Weekly C+C Petroleum Supply , lower 48, has dropped 200,000 bpd in the last 8 weeks and 683,000 bpd since peaking last June.
Hi Ron,
If we look at WTI prices it looks like about a 2 month delay for production to react to prices, if that is correct the decline will continue until April and then output may stabilize. It looks like the US producers slow things down when oil goes below $40/b, but that output stabilizes between $40 and $50/b, at $60/b output seems to increase (at least in 2015 it did). Chart below is the nominal spot price of WTI from the EIA.
Hi Ron,
Looking a little further I assumed an 8 week lag between production changes and oil price changes so I correlated oil price with C+C output 8 weeks ago (because it takes about 8 weeks for production to respond to the oil price), the data is for the US only and I used the EIA as my source.
Based on the correlation I would expect output to plateau or start to rise soon and possibly reach about 9100 kb/d by the end of May. The correlation suggests about a 116 kb/d in C+C output for every $10/b rise in price. Prices have risen from $29/b at the end of Jan to $39/b at the end of March, so I expect output will level off and the rise by the end of May.
Dennis, there is a far greater than an 8 week lag between price and production. Just looking at the last 8 weeks tells us virtually nothing. And $40 a barrel is not remotely close enough to the LTO profit level to get production rising. No, I definitely do not expect any kind of production plateau this summer, and certainly not a production increase.
I think the latest production decline in the last two months is simply production finally starting to show the effects of the price decline, and the oil field investment decline, that has been going on for the last year and a half. You can expect it to continue… for the next year or two years.
And this decline in production will be worldwide, not just in the USA.
Bernstein puts the drop of non-OPEC (other than US) at over four times what IEA is projecting at 50k. They project a 220k drop. I am no longer debating what drop the EIA is projecting for the US, as it is big enough, now, to be realistic. I agree that US production will not react much to prices at $40 to $50.
Hi Ron,
The analysis was looking at the US only. I agree the general fall in oil prices will lead to decline in the rest of the World, but as supply becomes short, oil prices will rise which will both reduce demand and increase supply after a 12 to 24 month delay, in the mean time there are sanctioned projects that will continue to come online and mitigate the decline to some degree, many projects have been planned and will proceed a soon as oil prices get back over $80/b, LTO can ramp up pretty quickly in the mean time. We will have to see, there will be decline, but it will slow down with rising prices and then turn around with a slight rise in output approaching ( but perhaps not surpassing) 2015 levels, that will depend on the rate of increase in oil prices and how the World economy is affected by the rise in oil prices.
The longer this lasts the harder it will be to ramp up. They can do it but the lag time is getting longer. Rigs and and all that HHP for the pumping crews are getting canabalized as they get stacked and companies are not putting out money to replace parts. And alot of the companies that make it through this are not going to be in position to tap those money markets to ramp up drilling. Nevermind all the manpower that has left and is leaving. I think we are going to feel these affects for a while.
Hi Reno,
Yes those problems are real, but a lot of the infrastructure is in place and stronger companies (maybe the oil majors) will buy up the better assets from bankrupt companies and will have the cash they need to get things moving, old hands can be brought in as consultants to train the new recruits, the oil industry has seen this all before, it won’t happen overnight, but it can happen a lot faster than a deepwater or oil sands project.
Ron,
According to my research, the time lag between oil price (green line in below chart) and rig count response (red line) stands around 6 month. This has been confirmed in 2008/9 and the current downturn 2014/2015.
However, the time lag between production (blue line in below chart) and rig count decline/rise stands around 18 months. So, when we have a high in rig count rise, we get a rise in production 18 months later.
As we have not yet seen the through in rig counts and oil prices have by far not recovered year over year, any recovery in oil production will take at least two years.
@RonPatterson
You are absolutely correct that the lag-time between price and production is much, much longer than 2 months. It’s actually somewhere between 2-5 years! So, the full effects of the recent oil price collapse won’t begin to be really felt until late 2017 and onward.
@DennisCoyne
It’s not a good idea to compare the oil production profile of the US to that of much poorer countries (I am saying this in reference to your comment about US oil production decline between 1990 and 2003) The US is rich and advanced enough to be able to produce oil at more or less break-even prices, and in the short-term, even at massive loss. For countries like Iraq/Iran/Russia and even the GCC, oil production only makes sense if they can make a lot of money out of it so that the rest of their economies may be supported by the massive oil profits. For these major oil producers, oil is almost everything in their economies or at least the core and most profitable sector. On the other hand, these other major producers are in possession of vastly more productive oil fields which makes the oil predicament even more impossible to discern.
Hi Stavros,
The oil will be produced if it is profitable to do so, this is true everywhere.
There will not be much of a difference in the decline of World output when compared to the US, except perhaps that it might be less steep because the US pushed output to 61% of its URR before decline began in earnest in 1985, even in that case the decline was only 2.53% from 1985 to 2004. In my World medium scenario output starts to decline in 2025 when cumulative output of 1570 Gb is only at 46% of the C+C URR, that is the reason annual decline rates are more moderate. Currently World cumulative C+C output at the end of 2015 is about 1280 Gb or 37.6% of my medium World C+C URR estimate of 3400 Gb.
The point I am trying to make is that oil production in countries that are much less wealthy and technologically advanced in comparison to the US and Canada (which basically all of them) is subject to several other factors beyond deposit availability beneath their soil. Tax regimes, relations with the Western powers, financial and trade sanctions, the state of their economies at any given moment, political stability (or lack thereof) etc etc etc. My conclusion, is that under the right circumstances, some of these countries, can significantly raise their oil production. I claim that these countries are Russia, Iran, Iraq, Kazakhstan and Venezuela. In my analysis of global geopolitics, these countries have been targeted by the NATO-GCC-Israel-Japan alliance. In fact, no analysis is required for that, it’s simply obvious. Their production potential is far higher than is generally acknowledged.
Hi Stavros,
Sorry, I misunderstood your initial comment.
So do you think my medium scenario for the World C+C (URR=3400 Gb) is an underestimate?
I took a second look at this output vs oil price and a 4 week lag between output and price (with output change lagging behind price changes by 4 weeks) looks to be a better match from Feb 6, 2015 to Feb 26, 2016. That indicates a possible increase of 140 kb/d by the end of april, at minimum I expect the decline will slow down or stop by then based on oil prices the week of March 26 of $39/b.
That indicates a possible increase of 140 kb/d by the end of april, at minimum I expect the decline will slow down or stop by then based on oil prices the week of March 26 of $39/b.
Based on $39 oil? I think that is totally disconnected from reality.
Hi Ron,
We will see, the oil output fell below 9200 kb/d (if the weekly estimates are accurate) at around $35/b. The problem with the analysis based on charts produced by AlexS is that the weekly numbers are not very accurate. Looking at the monthly numbers, you are correct the correlation above is not valid due to bad weekly data.
Using monthly data for output and prices there appears to be about a 5 month lag between price changes and output changes. The correlation suggests output will decline about 200 kb/d between December and July based on February’s monthly price of $30/b and July’s price of $50/b. The $50/b price suggests about 9350 kb/d of output so based on the regression we might see 9150 kb/d in July 2016, this would be the minimum and rising oil prices will eventually increase output.
Looking at the monthly numbers, you are correct the correlation above is not valid due to bad weekly data.
No Dennis, the correlation is not bad because of bad weekly data, the correlation is bad because:
1. Small changes in price, $10 or less, have little or no effect on oil production.
2. There is a delay of from 10 to 20 months between the price of oil changing and production either rising or falling. And it could be far longer, 3 years or more in some cases. It all depends on the projects that are affected by the price change. But nothing happens in just three to six months.
But what shocked me was your expectation that $39 oil would be high enough to cause oil production to plateau and even perhaps rise. 39 dollar oil? Are you kidding me?
Hi Ron,
I thought for the US LTO and stripper fields there might be some effect of prices on output, yes $10/b doesn’t move production much, what about $20/b or $30/b? At some point the oil price has an effect with some lag time. In the case above I am talking about a $20/b price move from $30/b to $50/b, over a 5 month lag time. The analysis suggests that for US output production might be affected by a change in price, there was a change in output in response to prices rising from $30/b to $60/b and the response is more dramatic at lower prices (because in percentage terms it is a doubling of the oil price),in fact the relationship may be logarithmic so perhaps I should have looked at the natural log of oil price vs output.
I do not think it will take the LTO plays 20 months to react to a doubling in the oil price, but I may be incorrect.
Time always tells.
I would be interested to know what you think would happen to LTO output if in the next 6 months the oil price doubled to $80/b. Do you think that we would need to wait for a year and a half (18 months) after oil prices reached $80/b to see any slowdown in the decline (or even an increase) in LTO output in the US?
Hi Ron,
The monthly data gives a better estimate and it is oil prices rising from 30 to 50 per barrel that will affect output. If oil prices remain at $39/b until Dec 2016 output might stabilize at 8.8 Mb/d, but I doubt oil prices will remain at $40/b for the rest of the year, I expect $50/b at minimum by Dec 2016.
Dennis,
U.S. C+C production includes Gulf of Mexico and Alaska, where output definitely does not react to monthly or weekly fluctuations in oil prices and is driven by new project start-ups (GoM), seasonal factors (GoM and Alaska) and declining production from the mature fields (Alaska and GoM).
As regards Lower 48 states oil production, it has been in constant decline since reaching a peak in March 2015, despite a temporary rebound in oil prices in 2Q15 to about $60/bbl.
Lower 48 states oil production vs. WTI oil price
AlexS,
Good point, the lower 48 would be a better gage. Note that we don’t have very good data for lower 48 output after Dec 2016. The last two months of the MER tends to follow the weekly data and that data is not very good.
One would think there should be some correlation of output with prices, though it will not be perfect and there will be a lag. The relationship between oil price and output seems to be pretty weak. By playing with the vertical scales on a chart we can create the appearance of a correlation, but if you do the regression there is not much correlation between lower 48 output and oil price.
Dennis,
“last two months of the MER tends to follow the weekly data and that data is not very good.”
I think this has changed. This month, MER did not include the numbers for February, contrary to what they were doing previously.
Tomorrow the EIA will release Petroleum Supply Monthly for January with detailed production data for all states. I expect total US output to be the same as in the MER.
Hi AlexS,
I believe you are correct, I looked at the MER after making that comment and it looks like you are correct (as usual).
Or I agree with you at least.
Hi AlexS,
If we consider the natural log of the oil price 5 months in the past (a lag of 5 months between price change and output change) vs lower48 onshore output from March 2015 to Dec 2015, we get an r squared of 48% (not very good really), this weak relationship suggests onshore USL48 C+C output will fall about 130 kb/d from Dec to July 2016. If oil prices continue to rise to about $50/b by Dec 2016, then US L48 onshore C+C output may increase slightly from the low of July 2016 from 6950 kb/d to 7100 kb/d. Note that prices after Feb 2016 are a scenario created by me, future oil prices are of course unknown, but the “model” is based on oil prices alone so to make a projection we need a price input. Clearly oil output is determined by many things besides the oil price, so the prediction will prove incorrect, also the relationship between output and oil price is based on only 9 data points and this relationship tends to change over time. Chart below should be interpreted with care (or perhaps ignored).
Dennis,
I think this kind of discussion is informative and worthwhile, but I can’t believe the correlation is that simple. AlexS has touched on a couple of issues, and I think there are many variables in the oil patch and the financial world that come to bear with different lag times.
This analysis is too simple to be useful, I’m afraid.
Jim
Hi Cracker,
I believe AlexS mostly pointed to lower 48 onshore as being a better thing to look at, which I did, that takes the long lead time off shore projects off the table as well as Arctic development in Alaska.
What are the other issues I missed?
I agree this analysis is not very good by the way, just a quick look at how oil prices might influence US lower 48 onshore oil production, which was a major player in the oil glut that started in early 2014.
Dennis,
I’m an amateur in here compared to yourself and many others here in this very knowledgeable and analytical forum. Still I would just like to throw out an idea of how production may be predicted.
For each major shale oil play, such as EF, Bakken, Permian (or area, such as Alaska):
1. Find the number of drill rigs correlated with oil price.
2. Find the number of drilled wells correlated with drill rigs
3. Estimate number of added wells
4. Find trends for production / well in order to find out if any shale plays are running out of sweet spots (and other?) – and then find total shale play decline, based on oil price-> drill rigs-> added wells
5. Estimate the share of shale oil of the total:
(shale oil + conv. oil) prod. / total oil prod.
6. Use this info to predict total oil production.
I would love to do it myself but as some of you guys are much faster than me to run the analyses, I just throw out the idea for discussion. One challenge with shale oil, though, is that the world has mostly seen the increase in production and has so far not so much experience with the decline.
Cheers!
Hi Tom,
Nice idea, I will let you do it though. Or anyone else can tackle the problem, it quickly becomes very complicated because the lag times are poorly known. Also vertical wells tend to be less productive so we would want to look at vertical rig counts and horizontal rig counts and directional rig counts. Check out shaleprofile.com to get an idea of differences between plays, changes over time, and differences in well quality between companies.
The analysis is complex.
Hi Dennis,
I think AlexS pointed out the tip of the iceberg. which is that not all projects are the same. While we may be able to observe correlations (I like Heinrich’s better, by the way), they are “averages” for the whole industry. However, past performance is not necessarily indicative that the future will be the same.
Here are some variables that can change the timing and alter the observed correlations. Please remember I’m not in the oil patch and this list is surely incomplete.
Financial sector – investor appetite for risk, interest rates, availability of capital, levels of existing debt, perceptions of the near future.
Oil patch – type of project (deepwater, onshore, LTO, oil sands); labor, rig, and contractor availability and costs; restarts and DUCs; price differentials between crude, condensate, and gas; and availability of infrastructure.
Oil price over the short term is only one factor.
One thing I think I know is that oil prices have to move up from the $30s and stay up long enough to be convincing if we are to see substantial increases in production, with a lag time, of course.
Jim
Hi Cracker,
This was something I cooked up in a few minutes. In the real World everything affects everything, that analysis would take an infinite amount of time, so you will have to wait a while đ
The simplistic analysis that I did that considers only oil price and US C+C output suggests output will fall until July and if prices continue to rise by about 5% per month from April to Dec, we might see a slight increase in output starting in August, but it won’t be very much. Probably flat output from August to Dec is more realistic under the price scenario I created (prices reach $50/b by Dec 2016). See chart right axis for price scenario.
Yes he said all projects are not he same, in particular off shore deepwater has a very long lead time and I agree that is a factor, so the second analysis includes only US lower 48 onshore production which has a relatively short lag time.
Hi Ron,
It’s been a while since I’ve seen oil production data on Alaska here. There used to be a time these data were ‘hot’, because the declining production was about to hit a ‘limit’ under which the Trans Alaska Pipeline was thought no longer being operable.
What happened to Alaska oil production in the mean time? Did it rise? Or has someone changed the functionalities of the pipeline? Or was there no problem after all?
Best regards, Bruno
Have a look at the EIA data for Alaska here. Production in 2015 was 483,000 b/day, down from 497,000 in 2014 and 864,000 in 2005.
According to Wiki the minimum flow estimations are between 100,000 – 400,000 b/day (depending if they install heaters).
The decline in Alaskan production has slowed down. Production is highest in the winter when no maintenance is usually scheduled. This summer the decline plus maintenance downtime will cause US production to drop about 100,000 barrels per day just from Alaskan production alone. The decline in US production in 2016 will likely be far greater than most prognosticators expected.
The last data point in the charts below is January 2016.
Hi Dave P,
Hi Ron,
Thanks! That’s really quickly! And interesting:
“The decline in Alaskan production has slowed down.” According to the numbers it declined 50% during a 13 year period (1988 – 2001) and it declined again 50% during the next 13 year period (2001-2014). So the decline rate is still the same and awefull. In absolute numbers the decline did indeed slow down, that’s understood.
I understand sooner or later (this year?) the summer dip will fall beneath that 400k barrels/day. Than heaters will be needed? Or are these heaters only necessary in winter time? In the latter case Alaskan oil production can go on for another couple of years before the EROI-drop caused by installing heaters. Is that right?
Couldnât they switch to using direct tanker exports from the southern Alaskan coast ports once a lower limit is reached? There are tanker restrictions on the BC coast though.
“Couldnât they switch to using direct tanker exports from the southern Alaskan coast ports once a lower limit is reached?”
huh? Did you mean NORTHERN ports? (not aware of any big enough – the SS Manhattan loaded only a single token barrel of crude on its visit).
The Trans-Alaskan Pipeline runs from the North coast of Alaska (Prudhoe Bay) South to Valdez on the South Coast of Alaska. There the oil is loaded onto tanker ships.
map at:
https://en.wikipedia.org/wiki/Trans-Alaska_Pipeline_System
The issue these guys above are talking about is that since pipeline flow has reduced (due to oil field depletion) from 2 million bpd to less than 500 kbpd, there is increased risk of freeze-up due to water separating from the oil and more wax buildup since the oil is in the pipeline longer at lower flow rates so it cools more. (the oil right out of the ground is pretty hot – 65-85 C / 150 – 185 F, so it used to keep the water & wax well dissolved).
http://www.explorefairbanks.com/go/energy/trans-alaska-pipeline/27
About their heating – they just recirculate through existing pumps:
http://www.alyeska-pipe.com/TAPS/PipelineOperations/LowFlowOperations
Low CAPEX, but rising OPEX, can you say “Lower EROEI?”
If you’re interesting in the gory details, see the Low Flow Impact Study link at alyeska-pipe.com
Real troubles begin about 350 kbpd…
“Uh Oh!”, the 2 refineries at North Pole Alaska return a stream of heavy stuff after taking out diesel/gasoline/jet fuel, but the larger Flint Hills (aka Koch Bros) refinery just closed, so that heat input is no longer coming back into the pipeline.
Squabble over the payments for the good stuff they take from the pipe:
http://www.adn.com/article/20140320/petro-star-says-alaska-refiners-face-crippling-economic-challenges
Yes I meant northern, and sounds like theyâd have to do some work to make them suitable, but with reduced ice cover it might be possible now at least in summer, and would be considered rather than leaving significant oil in the ground. But there are numerous restrictions to tankers around the Canadian coast which could be similar up there.
Yes, a bit of work ;^), like dredging about 10 miles to get to 30 foot + water. Prudhoe bay itself is 7 or 8 foot deep, but the mouth shoals to about 4 feet. A private causeway to the NorthWest, (what I think is a seawater intake/processing plant for water flood) has much better access to deep water. Looks like that is the one barges use in the summertime, but that’s only about 8′ there. Still need to go about 6 miles to 40 foot water depths, which is still kinda shallow for big tankers (the biggest go to 80 feet!).
http://www.charts.noaa.gov/OnLineViewer/16061.shtml
Tide ain’t helping much up there either, daily variation maxes out at less than a foot.
Plus they’d need a bunch of storage or shut down for 6-9 months a year, plus the tanker fleet and a spill control fleet, and get political buy in.
I think they’ll make the pipe work for a long time.
A CORRECTION: They have installed one actual heater (in addition to some pump station recirculation), and methanol injection stations to be used in case of an emergency shutdown of the pipe:
http://juneauempire.com/state/2016-02-03/slow-flow-not-low-flow-oil-pipelines-issue
And found this: BP says with heaters the pipeline can go to 70 kbpd (though this is costly).
http://www.legis.state.ak.us/basis/get_documents.asp?session=27&docid=7685
Thanks – either way the 350 to 400 kbpd isnât going to be a real limit. Even if they have to build storage and batch the flow I think they would find a way.
I coauthored a paper on Arctic port construction many years ago. I think a port can be built using a directionally drilled pipeline to get under the near shore ice environment, and a gravity based platform with a huge loading arm. The tankers have to be specially built, with thick hulls, extra horsepower, thrusters, and transfer to other tankers in open water (it’s wasteful to have an Arctic tanker carry oil all the way to Japan).
I can’t discuss everything we did, but I think it’s well known there are also many studies looking at LNG tankers coming out of Prudhoe. I developed the basic concept for a model that was eventually built to estimate navigation feasibility.
Anyhow, such a project takes 7 to 10 years to first oil because the permit process is very slow.
Verwimp,
âThe decline in Alaskan production has slowed down.â
Decline in oil production has posed problems for the pipeline. There is always talk about minimum operating levels but this is something of a red herring because contingency plans include batch shipping if (when) flow falls below 200,000 barrels per day. In other words, ultimately the Trans Alaska Pipeline may shift to intermittent flow.
The decline in Alaskan production has indeed slowed down in the past few years
Y-o-Y change in Alaskan oil production (%)
Yes, Ron, I agree with that assessment, completely. Except for a few companies who have hedges. Most aren’t hedged, and most won’t move on $50 oil. DUCs are within their capex plan, and most DUCs won’t produce the “standard” for how the drilling productivity is measured now. It is going downhill until prices go past $60.
According to the EIA’s Monthly Energy Review (MER) issued yesterday, US C+C production in January was 9221 kb/d, 41 kb/d lower than in December.
The new estimate for January is still 26 kb/d higher than in the EIA’s Short-Term Energy Outlook released on March 8 (9196 kb/d).
U.S. C+C production: weekly data vs. STEO March 2016 vs. MER March 2016
I would like to hear opinions about Continental Resources. I have been perplexed as to why it trades at such a market cap and enterprise value. I have never been able to get my mind around this, despite looking at their financials ever since Mr. Hamm announced they were cashing in all of their oil hedges in 2014.
Enno Peters data has consistently disclosed that CLR does not have superior wells in the North Dakota Bakken, which is CLR’s largest operating area. It appears that CLR has suspended well completions in the North Dakota Bakken indefinitely. They are still running four rigs there, and plan on ending the year with 195 DUC wells. So they are spending over $2 million per well drilled and cased, with no plans on any revenue from any of the wells until maybe the second quarter of 2017 at the earliest. We all seem to take all of these DUC well for granted. Never, in the entire history of the US oil industry, have so many wells been drilled and cased, and just left to sit for months, and likely one or more years, with $0 revenue being produced. This phenomenon is truly astonishing to me. Especially as the companies doing this generally already have much more long term debt than PDP PV10.
The only other significant area of operations for CLR is in OK. There, the wells appear to be deeper, and more expensive than in the Bakken, with regard to drilling and completion costs. The wells also appear to produce much more gas and natural gas liquids as a percentage of BOE. These areas are commonly known by the names SCOOP, STACK, and Springer. The Woodford shale also appears to be a target, and I will admit I do not know much about the various plays, other than reading details from company press releases and presentations.
The only real non-company detail I have seen regarding this area was CLR’s 11 well Poteet high density drilling unit. CLR had made presentations touting its success, but there recently has been no mention of this Unit in those presentations.
I reviewed lease operating statements concerning a small working interest for sale on the internet auction in the Poteet Unit. This unit is burdened with a 3/16 RI per the LOS I reviewed.
I am now going from memory, but what I recall about the Poteet Unit were well costs over $10 million each, such that it appeared drilling, completing and equipping the Unit cost in the $130-$140 million range. What I also recall were wells with high BOE IP, but that were mostly gas and 60 API condensate, that had declined in less than one year to about 10-50 bopd of liquids and 300-500 mcfpd of gas, per well. Again, this is from memory, so anyone who has data and can point out inaccuracies, please do so.
I find it interesting that, although the companies and touting pundits tout IP rates, now that this play has some age on it, we have no data as to well cumulatives, GOR, LOE, decline rates, etc. from them.
In other words, numerous people are touting CLR because of OK, admitting that the Bakken is a large losing proposition for 2016, as it was in 2015. Yet, even the pundits admit they really know nothing about the OK production, other than short term IP rates released on the company’s best wells.
As of 12/31/15, CLR had more than $7.1 billion in long term debt and about $11 million in cash. To put that in perspective, that would be 1,000 to 1 ratio to a small producer with about 200 BOE per day having $11,000 in the bank and $7.1 million of debt. I fee comfortable telling all that would be a very bad situation for any small producer.
I have absolutely no personal vendetta against CLR, their management, employees, board, etc. I very much hope they are able to be successful, that means our little stripper wells will be successful too.
I just do not get the market sentiment about CLR. As I have looked at this situation since the fall of 2014, and still have no idea what the attraction is, I would really like to hear from anyone who can explain this to me, and, in particular, give as much data about the OK LTO areas as possible.
Thanks for keeping this place going Dennis! I too appreciate the split thread format.
All good questions that the analysts should be asking shallow.
Reno. Let me give you an example. I received a Seeking Alpha email over lunch hour where an investment firm removed its buy rating on Pioneer and replaced it with Continental.
The reason given is that the STACK is better than the Permian.
CLR and PXD produce roughly the same BOE. PXD has far less long term debt. PXD has among the strongest hedges for any company of its size.
I am far from a cheerleader for PXD, and was very critical of their CEO’s “drill through it no matter the price statements”. However, in hindsight, it appears he was just saying what Wall Street wanted to hear prior to a share issuance, as I am pretty sure PXD has pulled all rigs from all basins but the Permian, including the EFS, and are down to around 12 rigs on their core Sprayberry acreage.
The STACK is really being hyped, and it may be the best LTO play in the lower 48, but the data is not available and the companies do not seem to release much detail, just a lot of IP info about their best wells, which is what they also did for EFS and Bakken.
I am not a day trader, so maybe CLR is good for day traders? Maybe the high valuation is because Mr. Hamm owns a majority of the stock.
I actually admire Mr. Hamm from the standpoint he started with nothing, and built a very successful company. The problem, which all had to a large extent, was he forgot about managing debt as the shale boom raged.
Anyway, I really have not seen a good analysis of CLR, and since they are interesting to me, I would like to see someone who has the valid reasons why CLR’s assets are valued at almost $100K per flowing BOE, 40% of which is gas, and which have a tremendous decline rate.
I also would like to see someone with more knowledge than me, explain the statement of future cash flows in the SEC 10K, wherein future production costs were slashed a full 60% from 2014’s 10K, despite proved reserves only falling 9%.
There are so many interesting things about this company, but no one seem to want to dig in and explain.
Shallow, I think I know why CLR does so well. I once worked for a certain oil and drilling company. It was said that the CEO could sell ice cubes to Eskimo’s. It was also whispered that he might not be the most technically proficient at oil production, drilling, finance or any of the companies other functions. But, he had all the brokers and other wall street types believing everything he told them.
The companies trajectory was evident in 79. The drilling side put together a 3 rig limited partnership which projected wonderful returns to the limited partners. I don’t remember exactly what they were but they were big. I do remember the projected return to the general partner. It was calculated to be infinite, a huge return with a negative capital contribution. This stinky deal was sold by the CEO to the big brokers and they pedaled it to to the small fry. No problem to sell.
There were good salaries and if you were fortunate stock options. I left there in 79, it was toast by 83.
IMHO Mr. Hamm would make an excellent living if all he had was ice to sell to Eskimos.
This guy is a huge cheerleader for CLR:
http://seekingalpha.com/article/3961993-continental-resources-buy
“Continental Resources (NYSE:CLR) has been one of the best performing shale oil players on the stock market this year. The stock has delivered impressive gains of over 30% so far in 2016 as it has taken aggressive steps to counter the challenges posed by a weak oil pricing environment. On the other hand, a recovery in crude oil prices in the past few weeks has also aided Continental’s rise. In this article, we will take a look at the reasons why Continental Resources will continue to gain momentum going forward.”
Shallow,
Do you realize a lot of companies get paid to promote stocks? Of course it’s much worse in the penny-dollar stocks… but a lot of recommendations are made because of compensation and not because of good fundamentals.
Steve
Hi shallow sand,
At some point people realize that the emperor has no clothing.
Quick question on Eagle Ford.
Assume
transport cost= $5/b
royalty and taxes=27% of wellhead revenue
OPEX+ water disposal=$6/b
downhole maintenance+repair=$10,000/month
cumulative output=148 kb over 36 months
well cost=$6.5 million
refinery gate oil price=$77/b
With the assumptions above the net revenue per barrel is $44.13/b and the cost of the well is covered in 36 months (with no discounting).
Mike has often said he wants his wells to “pay out” in 36 months at minimum (he prefers 24 months, I would prefer 12 months đ ). At $77/b at the refinery gate and 148 kb cumulative in 36 months, does the well meet those requirements under the assumptions I have given?
How might you revise the assumptions to make them more realistic? What am I missing, if it does not require a book length answer đ ?
Dennis:
148K gross oil over first 36 months.
Assume 20% royalty and 7% severance taxes?
So net oil is 118,400 barrels.
118,400 x $77 price realized = $9,116,800.00
$9,116,800.00 x (100% – 7%) = $8,478,624.00
Assume $11 LOE, water disposal, transport cost = $1,302,400.00
Assume $10K per month of “maintenance CAPEX” = $360,000.00
Subtract those two figures from our net oil = $6,816,224.00
You payout in 36 months, assuming no interest expense. Also, need to allocate lease acquisition cost, seismic, permitting etc., to our well. On the plus side, we need to also figure in the gas/natural gas liquid revenues. Also, need to see how income taxes figure in. Also, not sure if LOE is correct, does it include county ad valorem taxes?
So in 36 months, we still need to pay our interest expense, our up front land and development costs. Maybe some income tax, maybe we need to add ad valorem taxes.
Oh, also, where is our G & A allocation? Or is that included up there somewhere? That seems to be running about $2-4 per BOE (note not BO, and likewise, all other expenses are always set forth as BOE, so we need to know our GOR to adjust for that maybe?)
Finally, should we factor in time value of money, or if we add actual interest expense does that solve the problem? I agree interest rates are super low, maybe we should us PV8 or PV7? Rune and I have discussed this some.
I assume this is a pretty darn good EFS well? I guess just need to look at shaleprofile.com don’t we?
Dennis. I suppose your example is close to what will be the “average” EFS well in 2016.
One thing to remember, the EFS has different “windows” and many areas produce all, or mostly gas.
SĂĄnchez Energy is a prime example. Only 37% of 2015 production was oil. Their Catarina area is mostly gas and natural gas liquids, yet it is their primary field, and well costs are much lower.
SĂĄnchez plans on completing 55 net wells, 36 in Catarina. This compares to 116 well completions in 2015, companywide. Cost for all wells will be $180-220 million, only 3 net DUC wells from 15, rest are new drills. Plan on spending another $20-30 million on facilities.
Just some EFS company info that might interest some.
I suggest looking at SĂĄnchez Energy’s 2015 10K. Very detailed.
One area they reported was royalty burdens. Those range from 20.9% to 30.5%. I think royalty burdens are more onerous in EFS than Bakken, I think 25% is very common, and 30+% is not unheard of.
Despite a high percentage of gas, SĂĄnchez production expenses (which appear to include gathering and transport) were $8.16 per BOE. Production and ad valorem taxes were$1.40 per BOE on realized per BOE of $24.80. DD &A was $17.96 per BOE, interest expense was $6.60 per BOE, G & A $2.89 per BOE, and impairments were $71.15 per BOE.
SĂĄnchez has $435 million of cash, $1.75 billion of long term debt, PV10 of $593.5 billion, PDP PV10 of $465.5 billion.
They have two large acreage areas where they have no present plans for new wells, very few currently producing wells, and almost no PV10, being EFS Marquis area, and in the Tuscaloosa Marine Shale.
To achieve the above stated PV10, future production cost estimates were slashed from $2.635 billion as of 12/31/14 to $1.745 billion as of 12/31/15.
Another interesting thing I noted that SĂĄnchez reported, that few others do, is that they have a NOL carry forward of $765.9 million. More interesting is they adopted some type of plan to keep a hostile acquirer from obtaining benefits of this NOL. Clueless, if you are out there, would love to hear your comments on this.
SĂĄnchez has an interest in 621 gross, 504.6 net wells.
Despite being in EFS, their oil sold for an average price of $42.98 per barrel, well below WTI.
Their production really increased, from 43,893 boepd in Q4 14 to 58,115 boepd in Q4 15. They completed more wells in 2015 than in any prior year, and do not appear to have DUC’s.
And that also gives an explanation to Dennis’ supposition that rigs will fly at $50 oil (or maybe pigs will fly). Using the same numbers at $50, you get a negative return on a well that produces 148k over 36 months. Who can afford to wait 36 months in this environment, anyway?
Hi Guy,
They have been completing wells at $40/b or less, I agree nobody is making money at these prices, but if you have already spent $2 million to drill and case a well, that horse has left the barn. Now the question is do you spend another $3.5 million to frack and complete the well so you can generate some cash flow to keep the lights on. All the G&A, land acquisition and development costs and so forth have been allocated to other producing wells, income tax is not an issue because last I checked you don’t pay taxes when you are losing money.
When we do the calculation using all the same assumptions as before and look only at the fracking and completion cost of $3.5 million, that cost is paid in 36 months at $50/b.
Perhaps that is why some wells continue to be completed at $50/b, the $40/b completions may be the best well locations that have higher than average EUR.
Shallow,
SN’s production increase is all gas and NGL. Their 2015 oil production was down compared to 2014 despite completing more than 100 new wells in 2015.
Guy and Dan, great points.
EFS is tougher to get a handle on, because it is much more variable than the Bakken in terms of GOR and well depth.
I would note SM Energy still has two rigs going in Divide Co., ND. Apparently the wells there aren’t as costly as in the core of McKenzie Co. Other than that, seems like Bakken activity right now is centered in one area, where things are similar.
I don’t know a whole lot about EFS, but do know that some areas, like Catarina, are almost all gas and liquids, little to no oil. Pioneer seems to have the gassy acreage, thus zero rigs running.
Hi shallow sand,
I have focused on oil wells and ignore the gas and condensate wells. In the most recent 12 months about 80% of the C+C output is from oil wells and 20% is condensate from gas wells.
When these companies are losing money, which I am confident was the case in 2015, and will likely be the case in 2016 also, income tax is zero, I think. Perhaps 30% would be a better number for royalties and taxes in Texas, 27% was a guess on my part.
Dennis.
I am reviewing EP Energy’s 2015 10K.
They list working interest and net revenue interest in each area they operate. They are a fairly large EFS player, and also operate in the Permian – Wolfcamp Shale, Altamont in UT and the Haynesville Shale.
EFS gross working interest 83%. Net revenue interest 62%.
Permian gross working interest 97%. Net revenue interest 72%.
Altamont gross working interest 73%. Net revenue interest 62%.
Haynesville gross working interest 76%. Net revenue interest 61%.
Also, in 2015 EP Energy acquired 12,000 acres in EFS for $111 million. The acreage was minimally developed, 660 BOEPD, 483 bbl per day being oil.
Looks like maybe you should figure $6-10K per acre into the EFS break even calculations.
Hi Shallow Sand,
Thanks I will use 8K/ acre. Do we know the average spacing in the sweet spots of the EFS?
How does 80 acres per well sound? That is 8 wells per square mile and would be $640k per well, if spacing is 64 acres per well the price drops to $512/well. Any estimates for development cost per well? Would $100k do it? This is cost of well pad, roads and other stuff I don’t know about (storage tanks maybe), not the capital cost of the well.
I did some quick research an it looks like 40 acre spacing is optimal, so that would be 320k for land costs and maybe 500k when development costs are included.
Hi Shallow sand,
The 36 month payout rule that Mike uses, would be a company that operates by using cash flow, so interest expense would be zero, the associated gas of the average oil well in the EFS I am not sure about, but the gas and NGL might offset some of the LOE. I was assuming all taxes and royalties would be covered by the 27% of wellhead revenue, does that seem too low, maybe 30% would be more realistic? Note that 148 kb is the average cumulative output over the first 36 months of the average 2013 to 2015 Eagle Ford Shale(EFS) oil well.
When the 36 month payout rule is used, I thought the discount rate was left out of the calculation. Also note that the land and development costs is spread over many wells, what would your estimate be for these costs per well, I have no clue.
Dennis, some good points.
See my SĂĄnchez Energy post re their royalty burden and production and ad valorem taxes per bbl.
Some acreage went for over $50K per acre. So if we are on 100 acre spacing, that would be $5 million per well? I agree, that is extreme. So use $10K per acre, 60 acre spacing, still $600K per well. Not insignificant. I do not know what seismic shoots were costing, you have the bill to the land man, and the attorney. So much of the shale plays have severed minerals, so landowner had to be paid. Plus, look at the division of interests on some of these shale units, usually over 100 separate mineral owners, all have to be contacted to sign. And the land men had to run the records in the remote county court houses to figure all of this out, very costly, leasing.
Just because Mike doesn’t borrow doesn’t mean shale doesn’t. Wouldn’t the fact that shale borrows means they need a quicker payout than Mike, who pays cash?
The gas in EFS is much more relevant than Bakken.
Dennis, would really help you to read some 10K. On EFS, I highly recommend SĂĄnchez for starters, as they are solely EFS (TMS insignificant) and have acreage in different EFS windows, yet they break out a lot of detail on each.
They are no small player, 58K BOEPD in EFS.
Sanchez bought 106,000 acres from Shell for 639 million. They picked up 43,000 acres from Hess for 265 million. Paid about 6,000 an acre.
Hi Shallow Sand,
I think the rule of thumb is that the payout in 36 months means the well is acceptable for Mike who is conservative, the shale players are not very conservative financially so 36 months would be outstanding as far as they were concerned. If the well cost was $6.5 million simple interest would be $325,000 at 5% and would be covered by the well in our example above, land and development costs might be covered by associated gas, I don’t have numbers on that.
Let’s assume no associated gas (unlikely to be the case) and using Reno’s land numbers from below say land and development costs are $350k/well, then we would need $83/b for the well to pay out in 36 months for the average well.
Dennis, sounds good. And right now the app on my phone says WTI is $38.51.
So if we need $83 to payout in 36 months, the current price is $38 and the NYMEX strip for 36 months is well below $50 WTI, why are there any wells being drilled and completed in the EFS?
For example, Sanchez, who has $1.75 billion of long term debt with PDP PV10 of just $450 million, plans on spending over $200 million of CAPEX in the EFS in 2016. They do have hedges, but they really do not help much.
See why this stuff frustrates the heck out of people like Mike and me? It is like throwing cash in a burn barrel.
Hi Shallow sand,
I gave an example above for why someone might complete a DUC at $50/b for an average well.
So find your better DUCs that might produce in the 75th percentile and maybe completing the well makes sense at $38/b, I really don’t know desperate times call for desperate measures I guess. Every oil company is secretly hoping they can outlast the other company so that output goes down and prices go up, this is a game of last man standing as far as I can tell.
Dennis. Pretty much all are in dire straits, I agree.
Looks like ND rig count is ready to drop below 30, at 30 today with one to stack.
I like that you see a quick rebound in oil prices, but I think you have been saying that for awhile.
Commodity markets can remain rational longer than many can stay solvent, unfortunately.
The same game is going on in the grains, there is supposedly a glut there too, but, like oil, a world wide price trades heavily on US government inventory estimates, with little data on stocks in huge chunks of the world.
Unfortunately, sentiment is so much more important than it should be in the commodity markets.
Hi Shallow sand,
I am getting a little more conservative in my price predictions seeing maybe $50/b by Dec 2016 and maybe $80/b by Dec 2017, but the faster output falls the quicker the turnaround in oil prices will be.
I hope for the sake of the oil guys and the environment, that oil prices get to $85/b sooner rather than later, but you are correct that I am wrong on oil prices more than I am right.
The reason I have been wrong is that I have expected a steep decline in LTO output that has not occurred, when it finally happens then within 6 to 12 months we will see oil prices rise, perhaps very quickly.
Nobody knows what oil prices will be unless a huge range is chosen ($10 to $200/b for the next 5 years would probably be right, but far from useful).
The internal accounting standards that I use to drill wells, for instance ROI and time to payout, were actually taught to me nearly a half century ago by numerous oilmen before me. I think there is a reason that those standards have been passed down over generations. They work. They essentially enable an operator to be, for lack of a better term, “self sufficient.” By that I mean reserve inventory that is being liquidated can be replaced with net cash flow, and not borrowed funds. Well costs, oil prices and risk affect those accounting standards and when and if to pull the trigger, sure. The same standards SHOULD apply to the shale oil industry but of course they haven’t and profitability has taken a back seat to reserve growth, which now of course, has proven to be a dumb mistake also. Along with a half dozen other dumb mistakes.
I won’t speculate on DUC wells and when and why they would become profitable to complete; I think perhaps it might be a mistake to assume there will be enough money to borrow to complete those wells. I see a lot of DUC wells being completed in the EF; in fact that is all I see being done in the EF. Myself and others believe the rig count in the EF is grossly over exaggerated. EF production is going to nose dive now to the rest of the year.
S. Texas is a very mature producing province and mineral owners very savvy; 25% royalty burdens are the norm and many of those leases are burdened with additional ORRI’s. Severance taxes are 4.6% of gross revenue and ad valorem taxes generally another 2.4% of net revenue to the WI.
Sanchez put all of its eggs in the Catarina basket several years ago and they are under one of the most onerous drilling commitment provisions I have ever seen. They drill it, or they lose it. That stuff is in the liquids rich gas interface window, and close to Mexico; they appear to have a plan of some kind. Others still drilling anything unconventional right now, anywhere, have no plan whatsoever. They are doing stupid things with borrowed money they will never be able to pay back at anything less than 100 dollar oil prices, sustained. The “breakeven” metric is now even more irrelevant because for a shale oil company to survive they must generate sufficient cash flow to replace very high decline rate wells… AND pay back massive amounts of accumulated debt. That ain’t gonna happen and all of them, with few exceptions, are now in Hospice care.
Hi Mike,
Thanks.
Not sure how to translate 2.4% of net revenue of working interest for the ad valorem tax.
Lets take the example where Mike owns the well with a 25% royalty and gets $40/b at the wellhead for any oil he sells, lets assume the well produced 1000 barrels yesterday and OPEX+ water disposal+ G+A+ land and development costs + the stuff I don’t know about is $15/b.
How much money does Mike take home in this example (I am unsure about how the ad valorem tax works)?
Before taxes it looks like $25/b times 750 barrels so $18,750 of revenue, the severance tax would be $1380, is the ad valorem only on the $15,000 of net revenue? That would be $360 at 2.4% of $15,000 net revenue. So I think the take home (before income taxes) would be $17,010.
Probably that is wrong, I am not good at accounting.
Nope, I got it wrong.
The net revenue would be $25/b times 750 barrels or 18750 and at 2.4% that would be $450 for the ad valorum tax, so taxes would be 1380+450=$1830 and before income tax the take home would be $16920. If the marginal income is taxed at 35%, then the take home pay would be $10,998 if I did it correctly this time. đ
Hi Mike,
On that nosedive in the Eagle Ford, does Enno Peters estimate of about 60 completions per month in the Eagle Ford in 2016 sound right? The past 3 months (Nov to Jan) the completion rate has been about 145 wells per month and for all of 2015 it was about 185 wells completed per month. So a rate of 60 per month in 2016 would be about 1/3 of the 2015 completion rate. I expect something like 90 wells per month, but my guesses are usually not very good.
From your comment above I am thinking that you might choose something like 40 completions per month, maybe lower.
The main and probably only reason they are drilling in non-sweet spots in the Eagle Ford, now, is to hold the lease. I think, even the DUCs that are being completed now fall into that category. Or, in some cases, like Dennis says, the completion cost as current year capex would be covered. The only reason a company would drill with a three year payout, is if they had adequate lending or capital resources. Otherwise, they well should mainly pay for itself the first year, or they lose the capex for next year in cash flow loss.
Hi Guy,
Most of the revenue is in the first year, about 63% of the oil flows in the first year. For the well to pay out in the first year would take an oil price of $117/b, but after a few years of wells you have cash flow not just from this years wells but the cash flow from previous years as well, this is why the 36 month rule probably works, to get the operation started you would need to borrow some money, but if you do it right you pay off those loans after 5 years or so and then work from cash flow and never need to borrow money, if you do it right and don’t have oil prices in the toilet for a couple of years.
Maybe Hamm has better contacts on Wall Street? That’s all it takes, remember that there are different rules and laws for the regular citizens and for those that fund campaigns. It is what it is.
Why are the shale guys given massive lines of credit based on the” assets” that are still in the ground and essentially worthless in today’s market?
Why did the federal reserve step in during the redetermination period last year and tell the bankers to encourage the sale of assets rather than call the loans?
Why are some people forced to mark to market while others skate?
Why aren’t guys like me and you given say a 20 million line of credit? I wouldn’t sell my soul to those assholes anyway, so no need to answer that.
“Analysts” are projecting a 30% haircut on the shale guys lines of credit in April, why only 30%? How about 100%?
If you and I were running a pretend business, would they loan us a lot of money and then look the other way when it all heads south on us? They would if Wall Street has figured out how to make big bucks and on it.
One thing some argue is that CLR has so much acreage that they got so cheap.
My response to that is go look at how much they have expiring. They are not completing any wells in Bakken, meaning all of their acreage in ND and MT is very uneconomic at Q1 prices.
So we are left with the mostly gassy OK acreage, with wells that are more costly than, but far less productive than the Marcellus. Again, we really need better info, but CLR companywide went from 70% oil 30% gas in 2014 to projected 60%/40% in 2016.
Their BOE is poised to drop 10% in 2016, but oil will drop much more steeply.
I just don’t see how under $2 gas works, although they do have some gas hedged, unlike oil.
So if an OK well produces 70% gas and ngls, hypothetically, with wellhead oil of $35 and gas of $1.75, per BOE is just $17.85. Over the life of the well, ignoring all other expenses, you are looking at just under $20 million of gross revenue using their EUR of 1.1 million BOE. That is over 30 plus years, I assume.
I don’t get SCOOP and STACK attractiveness. Devon did pay big $$ for acreage there recently, another head scratcher, especially given their enormous Barnett shale exposure, which right now is likely negative on an operating basis. DVN used to be cream of the crop independent, but have to wonder?
OK C + C production per day per EIA has fallen from a peak of 473K in 3/15 to 400K in 12/15, very steep, and even steeper when you consider there is a stripper production C + C base of 130-150K per day (although it likely declined at least 10% as well during the same timeframe).
I do agree, part of the collapse is due to Mississippian activity falling off the table. See SD and CHK, for example.
I just don’t see the hyped OK plays adding much crude, based on available data. Would be neat if all states had ND data.
Some of you might find this interesting.
North Dakota Drilling and Production Statistics Click on the year desired after “Monthly statistical update”. The last data point here is February 2016.
Dennis,
Thanks for returning to Ron’s idea of two separate threads.
Back to the discussion on drilling/completion activity in Texas.
There was indeed an uptick in state-wide oil well completions in January, but February saw renewed decline.
I couldn’t find separate data on Eagle Ford. There are only statistics for Texas districts.
Texas new oil well completions
Source: http://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/
Texas
Hi Alex,
Most of the activity in districts 1 and 2 is from the Eagle Ford, in February there were 244 oil completions in those two districts alone. In Jan 2016 the number was 288, which seems too high so perhaps half the activity in these two districts is Eagle Ford activity. The RRC data is just not up to date enough for us to figure this out. It will remain a mystery.
If we look back at the March 2015 report we get about 257 oil completions in districts 1, 2, and 3. In Enno Peters data he has 279 new wells producing in Feb 2015 (at least in the same ball park), there could be a delay between completion and production. In December 2015 there were about 300 new drill completions in districts 1, 2, and 3, again this seems too high to be all Eagle Ford.
I still think Dean’s estimates are best, along with the great data provided by Enno Peters.
Dennis,
1) Unlike TRRC production data, well completion data is not revised. So these are final numbers.
2) A lot of counties in districts 1 and 2 are not included in the Eagle Ford area
Hi AlexS,
It may be true that there are some counties that are not part of the Eagle Ford in those districts, but I don’t think there is significant activity drilling for oil.
But as we don’t have the specific Eagle Ford numbers the question cannot be answered. Also, just because numbers don’t get revised does not mean they are correct, but you didn’t say they were correct of course.
In any case we don’t really know what is going on in Texas based on RRC reports, EIA data is a little better, but not much.
Looking at Enno Peter’s data for 2014 (3028 oil wells in EF) and the annual 2014 completion report, it looks like districts 1 and 2 are a good proxy for the EF as there were about 3200 new drill oil completions for those 2 districts in 2014.
If that is correct and the 2014 data from Enno and the annual completion report is relatively “complete”, then roughly 94% of the drilling activity in districts 1 and 2 is EF drilling.
Hi AlexS,
Looking back at annual data there was a huge increase and now a huge decrease (64% annual decline in 2015) in annual oil completions (new drilling). By mid year in 2016 things might stabilize, hard to guess really as the wells completed are mostly horizontal now and may have higher output than the vertical completions they have replaced.
Shallow,
You are not wrong about CLR. Not enough attention has been paid yet to the STACK and SCOOP plays. The clock and the calendar are no friends of CLR. Just be patient. Heck….I’m reading the 10ks now and paying attention to PV10 and debt because of you. I don’t look at the auctions because I have no interest in operations but what you glean from there and share with us is really sweet.
I might add that one thing you probably won’t get from the LOE statements is deferred maintenance. You know as well as anyone that once a big company decides to divest that it won’t spend a nickel it doesn’t have too.
On another matter, take a look at this video interview of Tom Ward on Bloomberg. There is something very different about Tom Ward now vis-a-vis three to five years ago. It appears to me that Tom Ward has an awful lot on his mind.
http://www.bloomberg.com/news/articles/2016-03-29/aubrey-mcclendon-partner-tom-ward-regrets-leaving-chesapeake
JohnS. Thanks for the link.
I am not a buyer of working interests on the auctions, just ORI or, more preferably, RI. However, you get access to all, except some of the larger deals require a CA.
I just look at the LOS on these shale leases because that is where the BS stops. The 10K tell a lot, but not all. Once you get down to the LOS, you really learn a lot.
Unfortunately, the EFS and the OK plays rarely have non-operated working for sale. I take that back, there are a lot of OK Mississippian non-operated for sale, and most of those look really bad. CHK seem to operate a ton of that stuff, and I have seen numerous of those where there is not even 10K gross BO in the first 12 months, but a lot of gas being sold for about a buck.
The Bakken has had many small non-operated because during the boom, a lot of fractional mineral owners decided to go that route rather than settle for RI. Now, of course, they are all trying to bail.
Owning non-operated WI is a dangerous game, you can make a lot of money, but you have no control. Really need to know what you are doing. Shale non-operated has to be scary, as not only has the price collapsed, but the well that was cranking 500 or more BOPD to start is likely below 100 BOPD a couple years later, and still on a steady decline. Then the $100K workover hits, or better yet, the $3 million refrack, where you hope like heck the thing pays out quick, but cannot at $25 well head.
Death of a Shale Gas Salesman
Aubrey McClendon was fracking’s greatest advocate — until he drove his car into a concrete wall.
http://thetyee.ca/Opinion/2016/03/28/Death-Shale-Gas-Salesman/
Fracking is a wonderful tool. Drilling horizontal is a wonderful tool. Operators do theses things because they do not have good rock to drill. There is no technology that replaces good rock with good p and p.
Reno, I think the fact that there have been less than 50 vertical oil rigs running for quite some time says something about the conventional prospects left in the US lower 48, especially at an average price for Q1 of around $34 WTI, over $8 less than Q4 of around $42 WTI.
Per EIA, onshore conventional lower 48 oil will be under 2 million BOPD in 2016. Non LTO will be under 4 million for the US in 2016, which includes GOM and Alaska.
48% of 2015 lower 48 oil came from LTO wells that were completed in 2014 or 2015.
Need price to at least double from here to stem the decline in US production, IMO, and/or will need more stupid money to drill wells that cannot payout.
There are a lack of quality prospects but the shale companies have sucked all the capital out of the markets. Public and private. Less competition for leases. Less money to drill.
30/3/2016
US shale oil peak in 2015
http://crudeoilpeak.info/us-shale-oil-peak-in-2015
wow
http://www.pbs.org/wgbh/frontline/film/saudi-arabia-uncovered/
Thanks for the link. This is the Frontline documentary that I referred to above. (It may now say it was posted by undefined; but this reference to me is greatly exaggerated.)
Oil industry bribery.
This will grow in importance, coming on top of Brazil âcarwashâ and Nigerian revelations:
http://www.theage.com.au/interactive/2016/the-bribe-factory/day-1/the-company-that-bribed-the-world.html
I never had much to do with procurement but knew of two attempts to facilitate contract placements (by a South Korean and an ME company). The main oil majors have been on top of this for many years and I donât think there is any issue there, even a hint of impropriety and you are shown the door, but the middle sized service companies and vendors seem the biggest risk.
Oilfield in SA – Khurais
http://www.hydrocarbons-technology.com/projects/khurais/
Does anyone know how much and when this oil field will affect SA Production? One source suggests production can be increased to 12.3 mbd.
that was 7 years ago, no?
Dennis,
Oops. I see it is a very old article and the oil field started producing in 2009 and did not produce as much as expected. There was some news that SA would largely increase the gas production from this field and thus I got a bit curious.
There is an expansion project in progress but itâs ben slowed down and start up date is unknown but possibly after 2017.
http://the-mea.co.uk/news/khurais-oilfield-pipeline-extension-under-way
http://www.constructionweekonline.com/article-35229-saudi-arabia-khurais-oil-project-delayed-past-2017/
George,
Thanks for info.
In 2 of the Sources, one from 2009 and one from 2014, the SA production capacities would acc. to the articles increase to 12.5 mb/d, ie. nothing has changed in 6 years. Not trustworthy… To me, it is another sign that SA is producing flat out.
Article in Bloomberg mentioning Khurais expansion project:
Saudi Arabian Oil Co. is pressing ahead with an expansion of the Khurais oil field despite lower crude prices and plans to double its production of natural gas over the next 10 years, the companyâs chief executive officer said.
Khurais oil fieldâs expansion is due to be complete in 2018, Nasser said. Aramco was seeking to add 300,000 barrels a day to the fieldâs production to reach a capacity of 1.5 million barrels a day, the companyâs former CEO Khalid Al-Falih said in October 2013.
The worldâs biggest oil exporter, known as Saudi Aramco, wonât cancel any oil, gas or refining projects, Amin Nasser told reporters during a conference in Al-Ahsa in eastern Saudi Arabia. Aramco is also studying a possible expansion of the countryâs largest oil refinery, Ras Tanura, which has a capacity of 550,000 barrels a day, he said Wednesday.
âUntil now all of our downstream and upstream projects are continuous,â Nasser said. âNo project in our programs got canceled.â
Ghawar oil field, the worldâs biggest, has been producing for 70 years and will keep pumping oil for âmany years to come,â Nasser said at the conference. Sixty percent of Saudi Arabiaâs crude oil output comes from Ghawar, Abdul Latif Al-Othman, governor of the Saudi Arabian General Investment Authority, said at the same event.
http://www.bloomberg.com/news/articles/2016-03-30/saudi-aramco-expanding-oil-and-gas-projects-even-with-low-prices
AlexS
Thanks, it was the article I saw (although not in English).
A metric ton of oil in Japan sells for ÂĽ26,670 or about 32.65 per barrel.
The Japanese are saving five dollars per barrel buying in bulk.
26,670/112 = 238 USD per metric ton.
238/7.3 = 32.62 USD per barrel.
A discount for paying with cash or something like that.
Japan buys Middle Eastern oil, which trades at a significant discount to Brent and WTI
Kuwait and Saudi Arabia planning to re-start a jointly-owned offshore oil field with potential output of 300 kb/d.
From Bloomberg:
Kuwait Says It Agrees With Saudis to Restart Joint Oil Field
http://www.bloomberg.com/news/articles/2016-03-29/kuwait-agrees-with-saudis-to-resume-oil-output-at-shared-field
⢠Plans gradual start at 300,000 barrel shared Khafji field
⢠Field being prepared for maintenance before output resumes
Kuwait agreed with Saudi Arabia to resume production at an offshore oil field shared by the two OPEC members, the official Kuwaiti news agency reported, without giving a specific time for the restart.
Production will start initially in âsmall quantities, which would be increased taking into consideration environmental concernsâ before returning to normal levels, according to KUNA. Production at Khafji halted in October 2014 because of environmental concerns.
Saudi Arabiaâs Ministry of Petroleum and Mineral Resources didnât immediately reply to a request for comment.
The plan to restart Khafji comes as Saudi Arabia and Kuwait are set to attend a meeting of OPEC members and other producers in Doha, Qatar, next month to discuss a proposed freeze in output.
âIâm skeptical until I see some confirmation from the Saudi side or some signs that work is being done at the field,â said Robin Mills, chief executive officer at Qamar Energy in Dubai. The plan to restart Khafji wonât affect the Doha meeting because production probably wonât have started in major quantities by then, Mills said.
Production in the shared area between Kuwait and Saudi Arabia reached 600,000 barrels a day in 2011, including output from Khafji and the onshore Wafra field, according to data compiled by Bloomberg Intelligence. The Khafji shutdown led to a loss of 300,000 barrels of daily output.
Two more shale companies in big trouble:
SandRidge eyes bankruptcy, restructuring in U.S. shale bust
Wed Mar 30, 2016
http://www.reuters.com/article/us-sandridge-restructuring-idUSKCN0WW1MB
SandRidge Energy confirmed on Wednesday it has hired advisers to evaluate options including a bankruptcy filing, in what could be the most high-profile reorganization yet in U.S. shale oil industry.
SandRidge’s oil and gas output fell 18 percent in the fourth quarter of 2015 compared with the same period a year ago.
Reuters reported in January that the heavily indebted oil and gas company was exploring debt restructuring options, including an orderly bankruptcy.
SandRidge, which is working with law firm Kirkland & Ellis and investment bank Houlihan Lokey on restructuring options, has drawn down its revolving credit line and has tried to trim costs with asset sales and job cuts.
In December, Capital One Securities ranked SandRidge as the most indebted of 50 U.S. shale oil producers, noting that its net debt to cash flow ratio exceeded 10, far above a ratio of 2 that analysts consider desirable.
SandRidge, which produces oil and gas from shale formations in Oklahoma and Kansas, was founded in 2006 by Tom Ward, who also co-founded natural gas company Chesapeake Energy Corp (CHK.N). Ward, a pioneer of the U.S. fracking boom, was ousted as chief executive in June 2013 by SandRidge’s board after a fight with activist shareholders.
The company’s stock rose as much as 50 percent after Ward’s ouster, but since then has crashed. Its shares now trade at around 10 cents each. In 2008, they were worth more than $60 each.
=============================
Midstates Petroleum raises bankruptcy concerns
Wed Mar 30, 2016
http://www.reuters.com/article/us-midstat-ptrlum-bankruptcy-idUSKCN0WW2KV
Oil and gas producer Midstates Petroleum Co Inc raised doubts about its ability to remain as a going concern and said it may need to seek Chapter 11 bankruptcy protection.
“We have substantial debt obligations and may not be able to maintain adequate liquidity throughout 2016,” Midstates Petroleum said.
Midstates Petroleum said on Wednesday it had engaged financial and legal advisers to analyze strategic alternatives to address its liquidity and capital structure.
“The company believes a filing under Chapter 11 of the U.S. Bankruptcy Code may provide the most expeditious manner in which to effect a capital structure solution,” the company said.
Oklahoma-based Midstates had total debt of about $1.8 billion as of Feb. 26, excluding outstanding borrowings under its credit facility.
The company had cash and cash equivalents of about $81 million as of Dec. 31.
——————————–
About 40 oil and gas producers across the globe have filed for bankruptcy since oil prices began to decline in late 2014, and up to a third of all energy companies may fail unless prices recover, consulting firm Deloitte said last month.
Two OK based companies who both focused on the Mississippian Lime.
In fact, Sandridge sold rock solid conventional assets in the Permian Basin to do so.
Shallow,
those assets in the Permian were acquired and then divested by SandRidge so Tom Ward could play on his loan covenants to borrow more money. He had to have a certain amount of oil production to raise capital.
Those assets were dogs and then Ward set up the Permian Royalty trust to screw the stockholders even more. I knew some of the field operations and regulatory people back then so I had some idea of what was going on.
The only reason that man is not in jail (in my opinion) is that he ratted out Aubrey McClendon to the feds.
Watch that video I linked to yesterday. TW very carefully parses his words when Aubrey McClendon is discussed.
JohnS. You would know much more than I about the Permian assets.
From what I recall, SD bought out Arena, the assets were mostly San Andreas and Clearfork, and Arena had success with down spacing infill locations (vertical). That happened around 2010. Then in 2012, Sandridge sold those assets to Sheridan and used the proceeds to drill a bunch of Mississippian horizontals in OK and KS.
I assumed the conventional stuff wasn’t too bad, but really don’t know, nor do I know what went to Sheridan and what went to the royalty trust. Sandridge also bought Permian assets from Forest in 2010. They sure were doing a lot of wheeling and dealing.
I googled Arena and found a 2008 seeking alpha article interviewing CEO Phil Terry.
Article says they took leases in Fuhrman Masho field from 240 bopd to over 7,000 bopd by work overs and infill drilling. He says they did this without debt. Thought that fact was pretty interesting.
Ultimately in 2010 the company was bought out for $1.6 billion by Sandridge, but unfortunately it was a mostly stock deal.
Looks like most of the wells were San Andreas wells around 4,800′.
Looks like they were hoping for 40K barrel of oil recovery, assume those wells were costing maybe $350K?
More Numbers:
http://realmoney.thestreet.com/articles/03/30/2016/sandridge-energy-says-it-may-seek-bankruptcy-protection
Hi all,
The Petroleum Supply Monthly is out.
http://www.eia.gov/petroleum/production/
US C+C is 9179 kb/d in Jan 2016, a decrease of 56 kb/d from Dec 2015 and L48 onshore is 7035 kb/d, down 28 kb/d from Dec 2015. Chart below is in kb/d, Lower 48 onshore C+C output is read from right axis.
Strange, when I access the Petroleum Supply Monthly I get:
Petroleum Supply Monthly
With Data for December 2015 | Release Date: February 29, 2016 | Next Release Date: Delayed
How come you can get it and I cannot?
Edit: I know, I know, your site is not really the Petroleum Supply Monthly site but another site called “Monthly Crude Oil and Natural Gas Production”. It is just that I am just a stickler for accuracy. Sorry about that. đ
Ron,
this page has also latest data for December:
http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_m.htm
Hi Ron,
You are correct, I think I found the link at the petroleum Supply Monthly page and should not have called it that, its data from the survey that the EIA sends out and may be the basis for the PSM, not sure. You are correct the PSM was delayed.
The estimate for the US C+C production was revised up 23 kb/d for November;
down 27 kb/d for December.
The estimate for January is 42 kb/d lower than in the Monthly Energy Review and 17 kb/d lower than in the latest Short-Term Energy Outlook.
Dennis. The link confirms my recent posts about the collapse of US lower 48 onshore conventional production. Look at the yoy percentage change for the non-shale states. Generally 15-20% in one year.
Wow, the dependence on LTO by US going forward is staggering. No wonder the cheerleading.
shallow sand,
Texas oil production is up 25 kb/d (after a 69 kb/d decline in December).
But North Dakota is down 32 kb/d, following a 31 kb/d drop in December.
LTO production is declining and the downward trend will continue in the next several months.
But the decline is slower than we would expect looking at shale companies’ financials
AlexS. I do realize the non shale states contribute a small fraction of US oil production, but I think looking at their decline shows just how reliant US will be on shale in the future.
GOM, Alaska and lower 48 will likely never contribute more than 4 million barrels of oil per day again. Given the current and future lack of investment in these areas, below 3.5 million by 2020 would not surprise me.
This would mean the US would need to ramp LTO back up over 6.2 million bopd by 2020 to pass the US C+C 2015 peak.
Given many of the best locations have been tapped already in the LTO fields, and given the oil price may not rally much until US storage drops to pre 2014 levels, and given US LTO could drop below 4 million bopd within one year, I think US peak #2 has likely passed.
There may be vast LTO deposits in Russia and other world locations, but I doubt these will be opened up significantly until they can be without the issuance of mountains of debt. This would take oil well north of $100?
One of the factors explaining relative resilience of LTO production: even bankrupt companies continue producing.
From Reuters:
As U.S. shale drillers suffer, even the bankrupt keep pumping oil
http://www.reuters.com/article/us-usa-energy-bankruptcies-idUSKCN0WY3JU
More than 50 North American oil and gas producers have entered bankruptcy since early 2015, according to a Reuters review of regulatory filings and other data. While those firms account for only about 1 percent of U.S. output, based on the analysis, that count is expected to rise. Consultant Deloitte says a third of shale producers face bankruptcy risks this year.
But a Reuters analysis has found that bankruptcies are so far having little effect on U.S. oil production, and a tendency among distressed drillers to keep their oil wells gushing belies the notion that deepening financial distress will prompt a sudden output decline or oil price rebound.
Texas-based Magnum Hunter Resources, the second-largest producer among publicly-traded companies that have filed for bankruptcy, is a case in point.
It filed for creditor protection last December, but even as the debt-laden driller scrambled to avoid that outcome, its oil and gas production rose by nearly a third between mid-2014 and late 2015, filings show.
Once in Chapter 11, its CEO Gary Evans said the bankruptcy, which injected new funds to ensure it would stay operational, could help to “position Magnum Hunter as a market leader.”
⌠all of the nearly 3,000 wells in which Magnum Hunter owns stakes have continued operations during its bankruptcy.
Production figures can be hard to track post-bankruptcy, but restructuring specialists say that many bankrupt drillers keep pumping oil at full tilt. Their creditors see that as the best way to recover some of what they are owed. And as many bankrupt firms seek to sell assets, operating wells are valued more than idled ones.
“Oil companies in bankruptcy do not seem to automatically curtail production,” said restructuring expert Jason Cohen, a partner at the Bracewell firm in Houston. “Lenders are willing to let them continue to produce as long as economically viable.”
For most companies in bankruptcy or considering it, maximizing near-term production does make economic sense. Day-to-day well operating costs in most U.S. shale fields remain well below $40 a barrel. Bankrupt firms are also eligible for new financing that can allow them to keep pumping for some time.
At least 20 publicly traded companies have filed for creditor protection since the start of 2015. They held at least 95,000 barrel of oil equivalent per day (boepd) in production, according to their last disclosed annual output figures. Another 30 or so privately held companies also have gone bust, in what already is the biggest wave of North American bankruptcies since the subprime mortgage crisis.
They account for just over 1 percent of U.S. output, but the figure is set to grow with banks expected to slash credit lines to energy firms in their biannual review of borrowing limits in April.
In what could become the most high-profile reorganization in the sector, Oklahoma City-based SandRidge Energy Inc confirmed on Wednesday that it has hired advisers to review its options, including a bankruptcy filing.
About a million barrels of U.S. oil production, over a tenth of the total, is under the control of firms considered “financially challenged” estimates Rob Thummel, a portfolio manager at Tortoise Capital Advisors Llc.
Yet even if many more firms go bust, production is not expected to fall much.
Many bankrupt firms can sustain their output thanks to so-called debtor-in-possession (DIP) financing for operating and other expenses made available by existing creditors, banks, or private equity firms.
Magnum Hunter, for example, received $200 million in DIP funding, and so far is being run by the same management as before its bankruptcy.
Many distressed producers have also drawn down their credit facilities or skipped bond payments prior to filing to conserve cash.
Among the companies reviewed by Reuters, Swift Energy Co, Samson Resources Corp and American Eagle Energy Corp Co all chose to skip interest payments ahead of bankruptcy filings, citing ongoing talks with lenders to restructure their debt.
With operating expenses for existing U.S. shale wells between $17 and $23 per barrel, most companies can keep pumping unless oil falls below $20 per barrel,
What bankrupt and financially stretched producers are unable to do is drill new wells and since output from shale wells can fall as much as 70 percent during their first year, a sustained lull in drilling would gradually erode U.S. production.
Ultimately, the number of bankruptcies may matter less than the lack of funding. The lending reviews now underway are likely to leave more companies without sufficient credit to finance new drilling, analysts say.
“We could see a 150,000-200,000 bpd fall in oil production if financially challenged producers were to slow spending,” said Thummel.
Hi AlexS,
The bankrupt companies are unlikely to complete new wells and without new completions output will drop pretty rapidly. The analyst’s estimate of about a 20% drop in output of the financially challenged companies seems optimistic.
If we assume the conventional output of 2 Mb/d drops by 20% (400 kb/d) and the estimate of the LTO output drop of 200 kb/d is too low and bump that up to 300 kb/d, we get a drop of about 700 kb/d for US L48 onshore in 2016, which seems about right.
I admit that this is an extreme analogy, but so many seem to not understand bankruptcy that I cannot resist.
Assume that the owners of Secretariat filed for bankruptcy a week before the Kentucky Derby. He still runs and goes on to win the triple crown. The point being, your debt might vastly exceed your assets, but your assets do not become worthless just because you filed for bankruptcy.
Hi Clueless,
If the bankrupt companies cannot finance completion of new wells, output will fall at an annual rate of more than 25%. That is the reality of the LTO plays. Not really any way to sugar coat it.
Dennis,
I can agree with you only partially.
Yes, although bankrupt companies are not shutting down producing wells, in most cases they would not drill new wells.
But the restructuring process usually involves sales of assets and changes in ownership of the distressed company. New owners of the sold assets and/or of the bankrupt company will inject capital and restart drilling.
So these barrels will not be lost; they will be extracted, only with some delay.
Hi AlexS,
I agree 100%, I was simply implying that until those assets change hands, new wells will not be completed. I do not know how quickly the bankruptcy process proceeds, I imagine a year delay at least, but I am not in the business so that’s a guess.
For those taking an interest,
I recently posted an update on Norwegian crude oil extraction (production) based on NPD data as of end 2015.
http://fractionalflow.com/2016/03/29/norwegian-crude-oil-reserves-and-extraction-per-2015/
Thanks Rune. Always interesting to read your updates on Norwegian oil and gas production. But it looks like you have missed phase two of the Johan Sverdrup production. Lundin petroleum has said that production will increase to 550-650 kboepd after 2022. By the way from where do you get all the data?
FreddyW, thanks.
For the forecasts in the charts I use (primarily) sanctioned developments/fields.
You are right about a second phase of the Johan Sverdrup is now in the planning phase, which could bring total capacity in the range of 550-650 kb/d by 2022.
As of now this has not been sanctioned.
This (first) development phase of Johan Sverdrup will have a capacity of about 360 kbo/d.
As fields/developments are sanctioned they are included in my forecasts.
Ok I see. Assuming it will be sanctioned, then I can see on your production graph that production will be able to reach around 1,5 Mb/d in 2022 which is close to the 1,6 it is now. But the depletion rate for Johan Sverdrup will in that case be around 10% per year on the original reserves. So the decline rate will be high. It will in that case look even worse in your graph by 2030.
FreddyW,
Yes, that is a possibility. What I am not sure of is how sustained low oil prices [state of companiesâ balance sheets etc] may change both schedules and extraction profiles.
If you take a look at figure 06 [in my post linked to] there is a table that lists Johan Sverdrup [this phase] reserves at around 1.8 Gb.
As the next phase is sanctioned I expect these reserves to come up with around 1 Gb [this is from various sources] to total reserves of somewhere around 3 Gb.
Unless they find some bad surprises during the current phase 1 drilling there is no way that phase 2 will not go ahead. The economics of this field are just too good.
What is meant by;
â The economics of this field are just too good.â
They had a break even of 40 usd or so and then managed to lower the development costs by quite a bit. I can try to find the numbers again. Field is in shallow water close to infrastructure and is really easy to drill
I bet that sanction will come in due course around 2018. Aren’t they proceeding with the engineering?
It looks like demand will catch up with production from this summer and onwards and the oil price has already started to recover. So I don´t think it will have any effect. They plan to submit the PDO for phase 2 in Q4 2017. It´s quite soon and they have not changed their minds yet.
The reserves are said to be in the range of 1,65 Gb to 3 Gb with 2P reserves at 2,3 Gb. I would assume that the first two numbers are 1P and 3P reserves. So yes it sounds reasonable that with reserve growth it could reach 3 Gb.
Hi FreddyW,
I think some of the data is found at the link below:
http://www.npd.no/en/
Thanks Dennis. Lots of interesting information there. Only one minor gas discovery so far in 2016 I see. The rest are dry wells.
Rune,
Thanks for the analysis and forecast of Norwegian crude oil production.
Figure 01 shows that combined output of the currently producing fields will drop from 1.57mb/d in 2015 to around 250 kb/d in 2030. That implies an average annual decline rate of 11.5%.
Decline for the fields that were producing in 2001 during the period to 2013 was about 9% per year.
Is this projected acceleration due to the rising share of the small deepwater fields with higher decline rates? What are combined decline rates for the old mature fields?
What are your oil price assumptions? Do you think that potential sharp increase in oil prices after 2020 may slow production decline, like in 2014-15?
AlexS, thanks.
For several of the mature fields that still contributes meaningfully, the developments of discoveries within their business areas (like Gullfaks, Oseberg) and infill drilling [made commercial/profitable from a higher oil price] makes it now difficult to pull out/estimate their [call it âunderlyingâ] decline rates [from data in the public domain] post these developments.
The reserves added from these developments and infill drilling are reported within the business areas [reserve growth].
For all fields started before 2002;
From 2012 to 2013 the decline slowed to 2 %/a.
From 2013 to 2014 extraction grew about 3%/a.
From 2014 to 2015 extraction grew about 2%/a.
Several of the decisions that led to this reversal was made while the oil price was high and thus funding available.
Looking at the total production from fields started as of 2004 and 2012 these had a year over year decline of more than 15% from 2014 to 2015.
(Grane [reserves 900+Mb] started in 2003 and saw a slowdown in its decline in 2015.)
This illustrates how many smaller fields with short plateaus and steep declines influences the total decline rate and until Johan Sverdrup starts to flow, these smaller fieldsâ portion of total extraction will grow.
As alluded to in the text I have not made any oil price assumptions for the forecast [which is based on sanctioned developments].
Presently, several fields are planned plugged and abandoned (P&A) as the lasting, low oil price has shortened their economic life.
Plans now call for Jette, Varg, Volve to be P&A later this year.
More will follow according to various sources.
The low oil price recently caused the Vette development to be scrapped.
All things equal this makes for a steeper decline in total extraction than what is now reflected in my forecast.
I am [and have for some years been] firmly in the camp that think it will take a loooooong time before we again see a sustained $100+/b [$2016], even as the present supply overhang from whatever reasons comes to an end.
Hi Rune,
In your comment above can you tell us how long “looooong” is in years? Perhaps you mean >100 years. Also does “sustained $100+/b [2016$] imply about 36 months or more with the 12 month centered average Brent real oil price above $100/b in 2016$?
Only trying to understand your meaning as your analysis is excellent in general.
Loooong is less than 100 years, but several years. Several years with oil prices, say below $70/b, will affect the supply side.
In this context a sustained oil price [$100+/b] lasts more than 5 years.
Sorry, I think it is difficult to be more precise as everything increasingly now seems to become fluid.
Rune,
I appreciate your answer, that clarifies your statement a lot. I agree predictions in this environment are difficult, yours would be much better than mine, in my opinion.
Your prediction looks sensible to me. A few years with oil prices below $70/b will reduce supply, let’s say until 2018, then maybe by 2019 oil prices rise to $100/b or more, if they remained under $125/b for 5 years (and more than $100/b) the World might be able to muddle along at slow growth of 1% to 2%, but that scenario does seem far fetched.
More likely is a spike in oil prices by 2022 or sooner to over $150/b (2016$) and then a severe recession within a year or two which will bring oil prices below $100/b.
This may not be what you have in mind, but it roughly matches a few years under $100/b and less than 5 years at more than $100/b and seems moderately plausible, at least to me.
Dennis,
My public views on the oil price can be found in the post linked below.
http://fractionalflow.com/2016/03/15/the-oil-price-some-mar-16-observations-and-thoughts/
In closed/private settings/groups I am more concrete.
Thanks Rune,
I am less pessimistic. In China government debt has been relatively steady at about 40% of GDP since 1998 (FRED data). For outstanding public debt it has increased from 2.5 % in 1995 to 15% in 2013, very low by OECD standards. For private debt the level increased from 2.5% in 1995 to 28% in 2013, again very low by OECD standards.
For the US household debt it decreased from 97.5% of GDP in 2010 to 80% in 2015. Public debt rose from 60% in 2000 to 100% in 2015. So in the US we have about 180% of GDP in public and private debt in 2015. For China the total debt is about 43% of GDP in 2013.
China’s debt is less than one fourth of the US level of debt on at debt to GDP basis.
For this reason I don to think that debt will be a big problem for China, the problem may simply be mismanagement of the Chinese economy by the Communist party, a very real possibility.
Debt will not be a problem for the US in the near term (next 5 years) in my view. Since 2010 the total debt situation in the US has remained relatively constant.
Dennis,
âIn China government debt has been relatively steady at about 40% of GDP since 1998 (FRED data).â
Please provide links, because BIS data shows that Chinese public debt grew from about 22% of GDP in 1995 to 42 % by Q2 2015.
Are data from BIS (Bank for International Settlements) and studies from McKinsey no good?
If so, provide proof for this.
âFor private debt the level increased from 2.5% in 1995 to 28% in 2013, again very low by OECD standards.â
For China and according to BIS data [China is member of BIS] private debt to GDP stood at 205 % by Q3 2015.
âChinaâs debt is less than one fourth of the US level of debt on at debt to GDP basis.â
Dennis, can you please provide links to sources that documents this?
Because your claim grossly deviates from what BIS data show.
Hint, try to understand what BIS is.
â Since 2010 the total debt situation in the US has remained relatively constant.â
This is interesting as it is at odds with what BIS (and FRED) data show.
Please document it.
Hi Rune,
The data is from FRED
https://research.stlouisfed.org/fred2/
The debt service structure for private non-financial companies is similar for China as it is for many OECD nations.
See
http://stats.bis.org/statx/srs/table/g1
I will post chart down thread where it will be readable.
Hi Dennis,
To assume that Debt will not be a problem in the USA over the next 5 years is risky, in my view. If there is a recession than government revenues will be lower and public debt will mushroom. Its really just a question of how deep a recession we encounter. Chances of a recession in this timeframe I would rank as high.
Hi Hickory,
The question is, what level of debt will be a problem, and during a recession, perhaps more debt is better than less debt. Typically there is deleveraging of private debt during a recession, increased public debt is and attempt to offset the fall in private debt. If the government chooses to worry too much about public debt (like European Union during GFC), it simply reduces the chance of economic recovery.
Debt can be too high, and it can be too low (1930-1933 in the US).
Hi Rune,
For the US total credit to GDP has been between 247% and 250% of GDP from 2010 to 2015, according to the data from bis below:
http://www.bis.org/statistics/totcredit/tables_f.pdf
For all advanced economies the Debt to GDP increased from 262% in 2010 to 274% in the first 3 quarters of 2015. China’s debt to GDP increased from 188% to 248% in the 3 Q of 2015. The 3Q 2015 level was less than most advanced economies such as Norway at 264% in 3Q 2015 and similar to levels in the US.
As long as debt grows at the same rate as the economy from here forward China and the US will be fine, the US has more or less been doing that since 2010, China will need to slow down its debt growth, maybe by raising interest rates.
Steve Kopits has argued that China’s lack of growth was due to it not devaluing its currency as most other Asian nations have done. The Chinese should let their currency float.
Dennis, now you provide an answer that is very different from your first.
http://peakoilbarrel.com/open-thread-petroleum-oil-natural-gas/#comment-564823
In Q3-08 total US private debt was at 170% of GDP, in Q3-15 it was down to 149%. (Much helped by student loans and sub prime auto.)
This may suggest that private sector has reached debt saturation (lack of collateral).
In recent years US total private and public debt has been around 250 % of GDP.
When was it last at these levels? And how did that work out?
GDP does poorly as collateral for debts.
âAs long as debt grows at the same rate as the economy from here forward China and the US will be fine,..
Well, there are now few signs of a slowdown of debt growth in China.
There are scores of experts with detailed knowledge of the Chinese economy who does not share your views. And these experts documents their standpoints, they do not assume or believe or think.
Devaluing may create growth in volume and as measured in local currencies, not sure how that will work out measured as market value. Devaluing will also affect the carry trade and Chinese imports.
Lack of growth is more likely a symptom of slowing global demand [ref also the Baltic Dry Index] as consumers are close to/or maxed out on their balance sheets.
Hi Rune,
No the basic argument remained the same, the FRED data doesn’t gather the total credit number together as nicely as the BIS, but I said the US situation has been stable since 2010, which is confirmed by BIS data. I also said Chinese debt had grown, but was not at high levels relative to advanced economies, also confirmed by BIS data.
As to what will happen in the future in China there are many different expert opinions on this. The US total debt situation has been stable roughly 250% of GDP since 2010. The average for advanced economies is about 274% total credit to GDP in 2015.
One possible explanation for higher debt to GDP is slow GDP growth due to contractionary fiscal policy by the EU in response to the GFC.
In the face of a major recession this was exactly the wrong policy response. The US government responded with some fiscal stimulus (though not as large as it should have been, the Obama administration was too timid) in response to the GFC.
That is part of the reason that the US real GDP has been growing faster than the EU from 2010 to 2015.
See http://www.nytimes.com/2015/01/23/opinion/paul-krugman-much-too-responsible.html?_r=0
Hi Rune,
Chart below has 14 of the top 19 countries with highest debt service ratios for private nonfinancial sector. The average of the top 19 is 19.6 for Q3 2015, China is 20. (Malaysia, Hong Kong, UK, Spain and Portugal were left off the chart to make it more readable).
China’s debt service increased from 10 to 20 over the 1999 to 2015 period, but the level is manageable in my opinion.
Thank you DCoyne. I have never understood the fixation of some to the stock of debt relative to the flow of income (Debt to Income Ratio) to the exclusion of the flow of debt servicing to the flow of income (Debt Service to Income Ratio). Stocks and flows, levels and rates, etc.
The graph is hard to read so the BIS chart from 2010-2015 is attached.
http://www.bis.org/statistics/dsr/tables_g.pdf
It is quite clear that the U.S. debt service to income ratio has declined since 1999 subsequent to the 2007 peak.
Thank you, Rune
A detailed bottom-up, field-by-field analysis is really valuable
New coal plants rise in 2015 despite falling consumption
Old coal plants are increasingly lying dormant, yet new ones keep getting built, according to a new report.
The analysis by CoalSwarm, which includes researchers from Greenpeace and the Sierra Club, looks at the state of global coal over the last year.
Their findings highlight a disconnect between the recent reductions in demand for coal, and the hundreds of gigawatts of new capacity that developers want to build in the future.
http://www.carbonbrief.org/new-coal-plants-rise-in-2015-despite-falling-consumption
Boom and Bust 2016
TRACKING THE GLOBAL COAL PLANT PIPELINE
https://sierraclub.org/sites/www.sierraclub.org/files/uploads-wysiwig/Final%20Boom%20and%20Bust%20report_0.pdf
“Old coal plants are increasingly lying dormant, yet new ones keep getting built, according to a new report.”
It only proves that the managers of utilities are not very bright and did not understand the writing on the wall. We had the same situation in Germany a few years ago. Many new coal power plants will be stranded assets.
North Dakota rig count finally breaks the big 3 0… It just hit 29 with one still listed to stack.
And to think, this happened while oil was at the amazing high of $39 per barrel. Or somewhere near there anyway. đ
Hi Ron,
WTI averaged $30/b for the month of February. Do you believe oil prices will remain under $40/b for the remainder of 2016? I do not. Output will fall by 700 kb/d in the US to 8450 kb/d by the end of the year and oil prices will rise, to $50/b or more in my opinion.
Dennis, I have no idea where oil prices will remain for the remainder of 2016. But there is one thing I do know, that is if oil prices remain in the region of $39 a barrel then production will definitely continue to fall and fall rather dramatically. And that is not just in the USA but around the world.
A prolonged price of $39 dollars a barrel would be devastating for the oil industry.
Yes, I do believe oil prices will rise. But they will have to rise to a lot higher than $39 a barrel, or even $50 a barrel. $50 a barrel will not be high enough to cause world production to start to increase again.
Any increase in production caused by an increase in price to above $50 a barrel would have to come from the US and Canada. That is because oil at above $100 a barrel did not cause oil in the rest of the world, outside the US and Canada to increase in the last five years. Well, that is outside of OPEC. OPEC, or Persian Gulf OPEC, is another matter. That is because politics come into play here and not just geology.
Hi Ron,
I agree, $39/b will not cause the decline in output to stop, but my guess is that the decline would be faster at $30/b than at $40/b and faster at $40/b than it would be at $50/b. In fact at $50/b the decline might stop eventually, but I agree with Guy who suggested $60/b will be needed to get drilling to increase and probably more like $80/b for 6 months before any noticeable increase in US and Canadian output. That might not occur until 2018, it will depend on the World economy and demand for oil. I would be surprised if we had not reached $100/b by then unless there is a severe global recession between 2016 an 2018.
PETROLEUM 7,697 90,072 90,072 | 9,943 122,126 122,126 | (22.59)% (26.25)% (26.25)%
Week 12, BNSF Weekly Carload report.
7,697 carloads of petroleum in 2016.
2015 week 12 was 9,943. 2200 plus drop in petroleum carloads hauled.
Coal cars down about 18,000.
http://www.bnsf.com/about-bnsf/financial-information/weekly-carload-reports/
How can anybody like Ted Cruz be a presidential candidate? Even a Republican? How can this possibly be? Abraham Lincoln is spinning in his grave. Uff da looey.
You cannot make this stuff up.
Cruz is creepy.
“Time could run out for companies that have been hanging on by a thread.”
http://www.zerohedge.com/news/2016-03-31/impatient-banks-real-red-flag-oil-patch
Oilpro
From BloombergView
Thanks for the link AWS. I found the full story at:
Saudi Arabia Plans $2 Trillion Megafund for Post-Oil Era: Deputy Crown Prince
Saudi Arabia is getting ready for the twilight of the oil age by creating the worldâs largest sovereign wealth fund for the kingdomâs most prized assets.
Over a five-hour conversation, Deputy Crown Prince Mohammed bin Salman laid out his vision for the Public Investment Fund, which will eventually control more than $2 trillion and help wean the kingdom off oil. As part of that strategy, the prince said Saudi will sell shares in Aramcoâs parent company and transform the oil giant into an industrial conglomerate. The initial public offering could happen as soon as next year, with the country currently planning to sell less than 5 percent.
âIPOing Aramco and transferring its shares to PIF will technically make investments the source of Saudi government revenue, not oil,â the prince said in an interview at the royal compound in Riyadh that ended at 4 a.m. on Thursday. âWhat is left now is to diversify investments. So within 20 years, we will be an economy or state that doesnât depend mainly on oil.â
Almost eight decades since the first Saudi oil was discovered, King Salmanâs 30-year-old son is aiming to transform the worldâs biggest crude exporter into an economy fit for the next era. As his strategy takes shape, the speed of change may shock a conservative society accustomed to decades of government handouts.
Buying Buffett and Gates
The sale of Aramco, or Saudi Arabian Oil Co., is planned for 2018 or even a year earlier, according to the prince. The fund will then play a major role in the economy, investing at home and abroad. It would be big enough to buy Apple Inc., Google parent Alphabet Inc., Microsoft Corp. and Berkshire Hathaway Inc. — the worldâs four largest publicly traded companies.
I would bet that Deputy Crown Prince Mohammed bin Salman is a believer in peak oil.
I bet they think the political risk of being invested in a nation loaded with would be terrorists is too high. They plan to park a chunk of cash offshore and wait for the shoe to drop. I wouldn’t invest in Aramco given this reality.
I figured you’d already be all over the Saudi mega fund story!
It was the Oilpro story that I thought some here might find of interest.
aws,
I certainly found the Oilpro story of interest; thanks for publishing it.
I haven’t been able to open the Oilpro site since Wednesday.
aws.
It was. Thanks very much.
Jim
Ron,
From your experience in Saudi Arabia wouldn’t you say that the Saudi’s have left it at a little too late for transition?
There can never be a transition from oil in Saudi Arabia. When the oil starts to seriously decline there will be turmoil in Saudi.
Right now there is an aura of fear among the general population and even the expats in Saudi. The police throw people in jail for the slightest provocation. No one dares to protest or even speak against the regime. They could be jailed or even publically whipped. But if things get really bad and enough people lose their fear of the police, then all hell could break loose.
Then there are the mullahs. They have authority over the populace which the authorities allow in order to keep the peace, and to keep the people in their place. I have seen them hit people with a cane for window shopping during prayer time. All stores must close during prayer time.
Saudi Arabia is basically a police state with the mullahs acting as if they are part of the police. But there is a deep resentment among the people with little money and no power. It is a powder keg that could blow if things get really bad. And when oil production starts to slide things could get bad very fast.
Max 5% of Aramco to be sold to the public, and the “public” will likely be defined as Public Investment Fund.
Window dressing. Nothing is changing.
Baker Hughes has oil rigs down 10 this week.
The Baker Hughes Rig Count is out.
Pain in the Permian
West Texas is the beating heart of US oil. Can it survive the price bust?
Justin Jacobs, Midland, Texas, 30 March 2016, Petroleum Economist
I’ve updated the interactive presentation on the Permian basin, here. It now contains data from the Permian in New Mexico as well, as well as various other improvements.
Very good work.
Thanks Fernando.
Great work as usual Enno.
Thanks.
Shallow – computer disaster for 12 days – crypto blocker [the ransom scheme]. Maybe someone here got to me – just kidding.
With respect to your question on the Sanchez 750+ million $ net operating loss. There are strict rules for using NOL’s when there is a change in ownership. Flashback to the 1960’s – a company could end up bankrupt with zero assets, still have unpaid debt, but also a huge NOL carry-forward. The trustee could sell the company for some amount – say 10-15 cents on the $ for the NOL. [If the tax rate is 30%, the NOL would be worth 30 cents on the dollar, discounted for the time it took for subsequent profits to offset it.] The acquirer could use it against subsequent profits that the “acquirer” generated with a consolidated tax return.
Now, if there is a change of ownership, the NOL carry forward is prorated down for the amount of the new ownership. And, I believe, if the change is too high, all NOL carryover is lost. So, best case, the NOL has a marginal value, except to probably a hedge fund [guessing that most oil and gas companies are NOT looking for more tax deductions, and probably have NOL’s of their own]. Not knowing the facts, Sanchez may have taken additional steps with their ownership to guarantee that none of the NOL could be used – unless perhaps someone worked with them in a friendly manner. Caveat – I have not been a tax specialist for over 25 years.
Clueless, interesting.
Also interesting are the stories I read about the MLP’s. They are going BK, wiping out the unit holders, except the unit holders will get a final K-1 with a lot of taxable income resulting from debt forgiveness.
And the bust continues, yielding all kinds of interesting financial issues.
Does anybody have estimates of the minimum sustained price that is needed to go ahead with a new deep water oil play?
It depends. Location, geology, anticipated reservoir quality, regulations and taxes, water depth, weather, size, distance to market, things like that impact economics. Where did you have in mind?
Lets start with GOM and North Sea. Just a rough average would do.
Yes, just those two places would be fine to get an idea about what is necessary for ANY new deep water oil production.
The conversation recently has been almost all about land based production.
Any significant amount of new deep water oil will make a difference in the timing of the overall peak and decline rate.
Now the rest of this comment is a little off topic maybe, but anybody who has not seen them, and lusts in his heart for a great looking car should take a look at pictures of the Tesla Three. It’s as classy looking imo as cars that cost three times as much. Too pricey for me though. I will continue driving my Escort which will be old enough to vote next year, and put my money into assets that don’t depreciate.
For the deepwater GOM I would estimate around $60, assuming there is an some associated reduction is the cost of doing business. I can’t think of any projects that have been cancelled because of cost. BP’s Hopkins was cancelled/deferred presumably because of poor appraisal drilling results. Chevron backed out of Buckskin, but partner Repsol is going to try and make it work.
New projects continue to come on line – this year Anadarko’s Heidelberg has already started production, and Shell’s Stones and Exxon’s Julia projects should come on line later in the year.
Deepwater GOM production is up to about ~1.4 mmbopd (total GOM is about 1.6 mmbopd).
In my opinion, peak GOM production will probably never exceed 2 mmbopd on an annualized basis, regardless of oil price.
Thanks SLA GEO,
The projects you mention are all already underway, and the money already spent is spent and cannot be recovered.
Do you mean to say that an oil company might be willing to pay the costs of exploration, leasing,drilling, etc, starting from SCRATCH expecting to get only sixty bucks, long term, for whatever oil their new deep water field produces ?
The Gulf of Mexico is apparently one of the most economical places to do deep water. Would you put your own money in a new start from scratch deep water field there for sixty bucks long term ?
Thanks Geo,
Just to be clear, the projects you mention are all already underway, with big sunk investments.
Are you saying that there are still places left where independent oil companies are willing to invest in FROM SCRATCH new deep water oil, expecting to get only sixty bucks for it, long term?
OFM,
Yes, I was referring to existing projects that are, as far as I can tell, planning to go forward.
Now, are there places left in the deepwater GOM where an independent operator could drill a discovery, and then, make the decision to develop the discovery if they thought oil prices were going to remain at $60 for the project life?
So the first issue is – are there places left where independents are drilling exploratory wells in the deepwater GOM? The answer is yes, but the number remaining, in my opinion, is getting smaller and the prospects are getting smaller and/or riskier.
A very common project-type developed by an independent would include 2-4 wells designed to recover ~20-40 MMBOE via a subsea tie-back to an existing platform. I think if the operator thought the reserves were there, and, if he thought he could take advantage of lower project costs (drilling costs, subsea costs, etc) he would proceed with the project even at $60 oil.
Companies that have a niche in this area include LLOG, Noble and Deep Gulf Energy.
Thanks SouthLaGeo.
If we see $80/b and oil men think prices are likely to remain above $80/b for 5 years or more, does your 2 Mb/d maximum output estimate for GOM change? Is this your estimate regardless of oil price? The maximum realistic oil price is probably $125/b in 2016$ in my opinion (probably not reached until 2019 at the earliest.)
Dennis,
Regardless of oil price, I don’t see GOM exceeding 2 mmbopd. Shelf production is probably around 200 kbopd now. Let’s say, in a very high oil price setting, it can get up to 300 kbopd (this is, in my opinion, very unlikely). Can deep water get up to 1.7 mmbopd? The biggest projects that came on last year, Jack/St. Malo and Lucius, are currently contributing about 140 kbopd total. They are sustaining production levels fairly well, and with new wells could get up to 200 kbopd.
I just don’t think new projects, even in a high price environment, will be able to contribute enough new production to offset existing field declines and get total deepwater production much over, say, 1.5 mmbopd. Unlike some other deepwater basins, a field that consistently produces 100 kbopd in the deepwater GOM is an anomaly, and, especially as more Wilcox fields come on line, with their 50-70 kbopd rates. The 3 projects I mentioned earlier, Heidelberg, Stones, and Julia, will contribute, at best, 150 kbopd new production (in my opinion, I’ll know better say a year from now).
Hi SoLaGeo,
I am confident that your estimates are better by far than any WAG I would make, I just wanted to clarify.
At times Fernando has suggested high oil prices might bring on a lot of output, but he may have been thinking of other places than GOM, maybe Brazil, West Africa, or the North Sea or even the Arctic.
Or maybe he was thinking $300/b (2016$), but that would be a pretty far fetched oil price in my opinion, the World economy would crash at anything over $160/b.
Interesting statement from lucas energy: ” seek to expand the Company’s asset base into more conventional plays and improve our returns to our shareholders.”
Shale oil companies moving back into conventional oil?
Well productivity
I have a feeling that the increased well productivity of shale oil wells may give false expectations of increased overall production in a shale play. It is easy to understand that pad drilling gives a higher efficiency for a rig, and it is straightforward that drilling longer gives a higher production for each well. However, drilling several wells from one hub/pad and drilling longer wells also mean that play will run out of the sweet spots faster, and the production of added wells in the shale play will not grow as fast as expected.
In other words: I don’t think the productivity per area unit will become a lot larger due to advanced drilling techniques, but they may become more cost efficient.
Agree?
BTW, does anyone know how thick the shale layers are? Something like 10m – 50m?? Is it worthwhile to frack at several depths in the same layer of shale?
Thanks to all the clever and helpful people contributing to this interesting blog.
Hi Tom,
In the established plays such as Bakken and Eagle Ford I agree, well productivity will not increase by much unless well costs go up as well as far as EUR per dollar spent on the well, I think we are at the maximum. In newer LTO plays (parts of the Permian and Niobrara perhaps) there may be a little room for improvement because each play is a little different and it takes some time to find the optimum set up.
Hi Dennis,
Thanks for the reply. I’m not sure if I expressed myself very well. My point is that it seems quite obvious that well productivity increases if the well is made longer (horizontally). I understand this is the case, from about 200-300m in the beginning of the shale era and now 2-3 km, with more “fracking explosions” per well. But it still does not mean that more oil is produced per area. Ie. the production potential for the shale play will probably not increase (significantly) due to longer wells. A more useful parameter than well productivity might be “Production/area”. It is also why I’m curious about the formation thicknesses, as larger thicknesses may enable drilling at different depths in the same area. My suspiscion that well productivity may not be the most meaningful parameter is general for all shale plays.
Cheers!
Hi Tom,
No the “well productivity” is not a perfect parameter, but we are talking about 10,000 wells and as Rune Likvern showed many years ago with his impressive “Red Queen” analysis the well profile of the average well remains relatively stable over periods of a year or two. If we track the well profile of the average well over time we can estimate output with a “model” of well completions per month times the well profile of the average well.
Typically (in the Bakken and Eagle Ford at least) the optimum well setup stabilizes to a “standard well” of length x with y frack stages that gives the most oil per dollar spent (on drilling and completion as well as land and development costs, LOE, G+A, etc.).
The USGS takes a volume approach, looking at area and thickness and output per unit volume of the basin to estimate about 11 Gb of C+C output in the ND Bakken/Three Forks. David Hughes does much the same in “Drilling Deeper” and estimates about 8 to 9 Gb for the Eagle Ford URR. The EIA is forecasting 10 Gb from the Permian basin from 2012 to 2040, but I have not found a detailed analysis on the Permian, Hughes does not give an estimate, but states that the EIA estimate is optimistic. From 2009 to 2014 proved plus probable (2P) reserves increased by about 4 Gb in the Permian Basin, I would expect at 5 Gb of LTO output from the Permian and maybe another 2 Gb from other US plays for a rough US LTO total of 27 to 28 Gb from 2005 to 2050.
Dennis, thanks!
Is 2P reserves and technically recoverable reserves the same? (I would not be surprised if that has been discussed many times before, but please enlighten me.)
It seems difficult to estimate technical recoverable reserves from shale oil as the experience with shale oil is quite limited.
Hi Tom,
No technically recoverable resources (TRR) are usually larger than 2P reserves, proved reserves more than a 90% probability of being produced, probable reserves have between and 89% and 50 % probability of being produced. The 2 P reserves are proved plus probable reserves and have a greater than 50% chance of being produced. They represent the mean or “best” estimate of reserves.
Often the TRR will be close to the 2P reserves plus cumulative output to date, especially towards the end of a fields life. Often there is reserve growth as the field is produced (this is a revision of estimates to a higher number). Typically TRR is a little larger than 2P reserves plus cumulative output.
Hi Oil Thread Guys,
I was just curious to know how oil price volatility– which increasingly seems to be the case– affects oil production and investment in the short to long term. It would seem that it would affect it negatively, yes?
Also, any informed opinion on KSA’s recent (and potential) sociopolitical effects (including on neighbors) on oil production over the short to long term would be cool too. (I guess I’ll also look over the thread too to see if there’s been anything about this already.)
Thanks, and happy oil-related chatting… And– hey– feel free to drop in on us Non-Petroleum Threaders once and awhile, will ya?
Lubed regards,
~ Cae (from the ‘Dry Side’)
One thing you can count on: An ample supply of oil for the day to day bidness of the world, it all can just go on like it does everyday.
That is today in today’s world.
You are almost giving it away at 37 dollars per barrel. If it would be free, there might not be so much demand, just give it to whoever wants it, let them pay for the shipping. Might be easier to charge a price for oil, including the shipping. You’ll end up with more.
Who wants to ship oil for free? Anybody want to drill wells for free, besides Colonel Drake? Edwin Drake forgot to patent his unique drilling technique and never made a dime from his own technology. Didn’t know how important it was.
âColonelâ Edwin Drake used a steam engine and cable-tool drilling rig to drill his famous well. He pioneered new drilling technologies, including a method of driving an iron pipe down to protect the integrity of the well bore. âDrake faced difficulties from the beginning, the known methods of drilling for oil at the time only ended in failure,â explains historian Urja DavĂŠ.
âHe spent five months trying to recover oil, and people had lost their trust in him and some began calling him âCrazy Drake.â Even his primary driller, William âUncle Billyâ Smith, also began to feel dejected. In order to overcome the hurdles before him, he invented a âdrive pipeâ or âconductor,â an invention he unfortunately did not patent.â
http://aoghs.org/petroleum-pioneers/american-oil-history/
“In a few days, Drake extracted as many barrels of oil as a whaling ship could gather on a four-year voyage.”
http://pabook2.libraries.psu.edu/palitmap/DrakeOilWell.html
Now you know. Oil saved the whales. More of a blessing than a curse, one would think, oil is. Better to hunt for oil than to hunt whales. Rock oil beats whale oil, hands down. As time goes on, things do change. Can’t really be an oil change denier, har.
20 million tons of coal and ten million tons of crude oil plus those pesky condensates will be needed to carry on with the normal garden variety activities, parlance for business as usual. Along with the business, a lot of fuzzin’ and fightin’ too.
Ten billion kilograms of oil for 7.4 billion people, that is one point two, almost, kilograms of oil per person each day.
There is demand for crude oil. Been that way for 150 years of modern era, 1600 years of oil as a resource. Not about to go away anytime soon. Can’t be denied.
If there were no gas for your car, no oil for lubrication, it would be a bad day in a bad way.
Count your blessings and oil is one of them.
Also, sorry to be an advocate for the extra-somatic energy, the finite resource, oil, in a usable form. I apologize for being an unabashed supporter of oil consumption.
Makes for a good day.
“I think most people act in their self-interest.” — Aubrey McClendon
http://www.resilience.org/stories/2016-03-29/death-of-a-shale-gas-salesman
A fundamental truth, not necessarily measured in a substance created from nothingness on a whim, aka money.
Money is the form the tool takes when it is time to marshal material and human resources to do a job.
It is more or less true that money can be created at will, but it is also true that it cannot be created in unlimited amounts or at too fast a rate without destroying the usefulness of it.
Thanks for this link, Duncan. Another informative read which fills in a little more of my knowledge of the shale industry’s history.
Florida – The Sunshine Wasted State – imports 99+% of it’s Energy.
http://www.zerohedge.com/news/2016-04-01/gas-pipeline-uses-160-eminent-domain-suits-get-property-3-states
The electricity industry has evolved to the point it is now practical for there to be real competition in actually GENERATING electricity, and there OUGHT to be free competition in so doing. We are now to the point that only DISTRIBUTION via the power lines need be a monopoly.
Generally the only way a monopoly can be maintained these days in a stable and more or less free country is via government intervention in favor of the monopolist.The people of Florida will eventually figure it out, once a personal pv system gets to be fully competitive on a dollars and sense basis with purchased electricity.
Ten more years. The old Florida fogeys who instinctively distrust environmentalists and their ilk will be mostly dead by then, or at least in nursing homes, and pv will be cheap enough to be economical even if it is not grid connected at all.
I have a friend in Hawaii that already has a separate, non grid tied system that he uses to run portable air conditioners, etc, quite economically. Of course juice is super expensive in Hawaii, but the trend is clear. PV is going to bite a hell of a chunk out of the ass of the market for gas in places with really good wind and sun resources.
1/2 My usual end of the month comparison b/t the latest EIA Texas data and my corrected RRC data: #crude+#condensate
… and here is #naturalgas
Dean – have you seen this:
http://patzek-lifeitself.blogspot.co.uk/2016/03/is-us-shale-oil-gas-production-peaking_16.html ?
Tad Patzek used to be at Texas A&M (I think, or maybe another one in Houston), but now in Saudi. Before that a reservoir engineer with Shell. He has won prizes for his academic work and authored a couple of books. He has fitted H/L logistics to all the shale oil and gas plays (as Verwimp has done for Bakken). The fits are really quite good, more remarkable for a couple of the gas plays that are in long term decline (Barnett and Haynesville). He estimates URRs that are quite low and doesnât think there will be a big increase if prices bounce up.
Univ. Texas. President ASPO. Now in Saudi Arabia. This should be interesting. http://gaia.pge.utexas.edu
Why did Patzek leave U of Texas?
I don’t know but what could be more rewarding to a world class peakist than teaching and doing research in Saudi Arabia. http://www.kaust.edu.sa/latest-stories/university-hosts-2016-kaust-future-fuels-workshop.html
George,
I like the question from Anonymous. It will be interesting to see Tad’s reply.
Einstein thought experiment, total Bakken production at
a. $40 WTI forever
b. $100 WTI forever
[Just give me your rough guess and why. I won’t pin you down, but I want to see how you think about this.]
Hi George,
the posts are interesting, but I have some doubts about the H/L method. Actually, some problems were already highlighted in the comments to those posts that you linked. Briefly:
– the effect of price is not considered
– Marcellus and Utica are not considered or only partially considered (and they can give -at the very least- a couple of more years of gas consumption)
– probably even more important and not considered at all, is the effect of debt. Without the trillions of debts used by the energy industry in the last 10 years, the predictions by Hubbert and the Club of Rome World3 model would have been quite precise. Instead, debts allowed to increase productions considerably.
Actually, the lack of inclusion of debt is not a problem of energy economics in particular, but of all economics in general. It may seems strange, but only in the last years economists have started to consider debt in their models seriously and also with great difficulty, due to the resistance in mainstream economics, just see the verbal spat between prof. Krugman and prof Steve Keen.
Of course, debt cannot increase to infinity, just see the problem with Japan (also known as “japanification”) . Really, it is a very interesting field of research.
Regards, Dean
Nobody claims debt can go to infinity. Japan’s problem is demographic.
Did he not consider price in his answer to one question – i.e. he added 50% to the URR that the logistic indicates given current price? Pretty rough and ready, but as good as anything else coming from someone with a lot of deep insight given how inaccurate most forecasts are, even with sophisticated models.
Pump, pump, pump:
http://www.reuters.com/article/us-russia-energy-production-idUSKCN0WZ0CV
“Russia’s oil production rose 0.3 percent to 10.91 million barrels per day in March, its highest level in nearly 30 years”
Price really a decisive parameter for them, eh?
It is in their best interests to destroy their enemies. The battlefield chosen must not be financial or military, because on those battlefields they have no advantage.
It’s genius, really. That output hits the market and KSA announces they will not allow themselves to lose marketshare.
And then everyone blames KSA.
Russian oil production in March was only marginally above January levels.
Average production for the 1st quarter was 2.2% above 1Q15.
From Reuters:
âAn increase in Russian oil production toward a record high in March will not be an obstacle to an expected agreement on a production freeze, Russian Energy Minister Alexander Novak said on Saturday, local news agencies reported.
Novak said that it was important that Russia’s average production over a prolonged period would not exceed its output level in January, as previously agreed.â
http://www.reuters.com/article/us-russia-oil-doha-idUSKCN0WZ0KD
Meanwhile, according to Bloomberg:
âSaudi Arabiaâs deputy crown prince said the kingdomâs commitment depends on regional rival Iran, which has already ruled out its participation. If any producer increases output — and Iran has made clear its intention to do so — Saudi Arabia will likewise boost sales, Mohammed bin Salman said in an interview with Bloomberg.â
http://www.bloomberg.com/news/articles/2016-04-01/oil-freeze-thaws-as-saudi-arabia-says-accord-hinges-on-iran
Russian C+C production (kb/d)
Source: Russian Energy Ministry
Hi AlexS,
Thanks. You are more knowledgeable about Russian output than me by far, what is your expectation for future Russian output, roughly a plateau for 5 years or so at 10.4 to 10.7 Mb/d?
See an interesting interview (slightly edited Google translation). Looks like the new oil reserves in Russia are very expensive, on par with the US shale and the old are mostly depleted.
============================================
Once upon the time we dreamed that the price of barrel of oil rising to 20 dollars per barrel
izvestia.ru
The President of the Union of oil and gas Industrialists of Russia Gennady Shmal told "Izvestia" about what oil price is needed for Russia and when the industry will overcome dependence on imported equipment
Q: OPEC believe that soon the price of oil should stabilize at a "normal", but not a too high level. What do you think, what level of oil prices can be considered normal for Russia today?
A: If we are talking about a fair price of oil globally, I believe this is $80 per barrel. Keep in mind that a significant part of oil – about a third – is produced offshore, where the cost can be high. And there is a deep-water shelf, for example, in Brazil, where one of the first well cost more than $300 million. Subsequent wells would of course cost less, around the half the price, but still very expensive. Therefore, the capex of this oil extraction is high enough. The breakeven price of our oil production without taxes is around $10 per barrel, nationally. But when we include taxes, we get around $30 per barrel. But this cost is not no tragedy for us. I remember a time when a barrel of oil was less than $10. Then we dreamed about the price rising to $20.
When the three-year average cost of oil was above $100 per barrel, we got too used to it. But the high price is one big drawback – it can affect demand and stimulated production. And that's what basically happened.
Therefore, now our oil companies might well be now content with the price around $50-60 per barrel.
And I think in general, globally it would be OK price for both producers and consumers. Even for the United States that would be an acceptable price. Canadians with their oil sands would need a higher price – up to $ 80. But as the Canadian oil going to the United States, anyway, loses can
be compensated with domestic shale production and they would have to come to a common denominator.
Q: You're talking about this level of prices, without taking into account the Arctic shelf projects?
A: Arctic shelf – it is quite another matter. My point of view on this issue is different from the most popular view that exists today. I believe that we need to engage the shelf in terms of prospecting, exploration. We generally do not even know that there, how much oil we have on the shelf. We have so far only preliminary estimates of reserves – C2, C3 (preliminary estimated reserves, potential reserves). And in order to have A, B, C1 (proven reserves), it is necessary to drill. I am sure that we are not ready to work on the Arctic shelf both technically and technologically, nor economically.
We do not have qualified people for that too. First of all, we need several platforms. One platform for "Prirazlomnoe" that we now have been built for more than 15 years, and we sank into it about $4 billion
And this one is not a new one, this is a second hand equipment. In order to seriously develop the shelf, we need not one, but dozens of platforms, support vessels. Also offshore operations must have the regulatory framework.
That means all the necessary technical regulations, standards. We have nothing. But the main thing – the cost effectiveness of this oil: it is necessary to consider how profitable in today's environment to produce Arctic oil. So, I think we now have enough things to do on land – in Eastern Siberia, for example, before we need to jump with two legs into arctic oil extraction.
Q: How record oil production that Russian oil companies demonstrate in the past few years, affects the structure of the Russian economy?
A: First of all, I believe that there are no records. Yes, we produced 534 million tons. But in 1987 the Russian Federation has produced 572 million tons. Compared to the 1990s there is a certain growth in recent years, but I would not talk about records. Second, the question about optimal production volumes is a very complex one. The main question to which I have no answer today: how much oil we need to extract?
Without answer on this question it is impossible to say whether we produced too little oil or too much. If we consider that in 2015 we extracted more then 246 million tons, then, I would say
we produced too much. This is not the way this business should be run. The fact is that Russia can not influence the world oil price too much because we make only 19-20% of the market. But we can and should make the country less dependent on raw oil price fluctuations. We could process all extracted oil and export mainly gasoline and diesel fuel, as well as products with high added value in the form of chemicals, petrochemicals, composite materials.
That means that we need to adopt a different approach to the structure of our industrial production.
For example, China in the last twenty years has built a series of petrochemical plants, and today they have the chemical products sector with total value of production about $1.4 trillion, or around 20% of China GDP. It should be noted that China's GDP is eight times more than ours. Our chemical sector production is around $80 billion – 1.6% of Russia's GDP. In 2014 alone BASF Chemicals (which is a single German company) produced 1.5 times more than all the chemical enterprises of Russia. Petrochemicals may be the critical link, pulling which we could hange the whole structure of industrial production in Russia.
Q: If we talk about production prospects, we promise in this sense, today's oil reserves structure?
A: Unfortunately, today we do not have a reliable statistics. According to some estimates, of
those oil reserves that are under development, about 70% are so-called hard-to-extract oil. That is, stocks, where oil production is complicated mining and geological, geographical conditions.
In these fields there might be tight reservoirs, reservoirs with low permeability, viscous oil, etc. By the way, today we have a clear definition of hard-to-extract inventory, although this depends on the benefits that can be granted to companies to work on the fields with such reserves. Therefore we need serious work on the classification and definition of reserves that will be put into the hard-to-extract category. By the way, the current production mostly (about 70%) relies on the old fields, which now have a high water content, high percentage of extraction of reserves. Of course, they will not last forever. Therefore, sooner or later, will have to enter in the development of the field with hard to recover reserves.
Q: Extraction of hard inventory requires new technologies, which in Russia does not fully have. What are the tools the government has to encourage their development?
A: The state has a lot of tools to stimulate this technological developments. That tax system can perform stimulating role along with fiscal and re-distributive functions. However, our tax system performs mostly fiscal function and only slightly – re-distribution. Simulative function is not yet here. As an illustration, take Texas, USA: if the well there gives 500 liters of oil per day, it is considered a cost-effective – this way the tax system is built. for us a well, which gives 4000 liters per day, is already viewed as unprofitable, and is moved into the idle fund. Now, of course, some work is being done in respect of incentives – MET rates introduced.
But I believe that the future of our oil industry is largely dependent on whether we are able to create the technology of oil production from the Bazhenov Formation or not. Because the geological reserves of the Bazhenov Formation in Western Siberia are more than 100 billion tons of oil. Even at a conservative estimate, if it is possible to extract around 40-60 billion tones of oil with the current technologies.
And please remember that all we have in Russia today, all C2 stocks, are just around 28 billion tons So if we find the necessary technology that can be applied to the Bazhenov Formation, the peak oil production issue for Russia can be resolved for a sufficiently long period of time. And in respect of the help from the state it could be such measures such as tax holidays, tax exemption, reduction in mineral extraction tax, etc.
But currently the Ministry of Finance is interested only in filling the budget. We need to make sure that taxes are fair. For this, they must be applied to the end result of production. In our country today we have taxes on earnings – up to 65-70% of the average withdrawal. Norway, for example, has high taxes too, but they are levied on profits.
Taxes should be applied to profits, not revenue, the latter for us looks like the absolutely wrong approach.
Q: According to various estimates, in the Russian oil and gas industry today up to 45-50% of the equipment are imported. Will Russian oil companies to move away from this dependence
in view of sanctions. And what should be role of the state in achieving this results?
A: At the request of "Lukoil" we did last year such a study. We've got that on average 53% of drilling equipment in Russia is imported. Of course, we must bear in mind that, for example, pipes, with rare exceptions, we can produce domestically. But today there are some technological segments where there is a high dependence of Russian oil from foreign suppliers. Those segements include: software control, automation and remote control.
Today, the Ministry of Energy to the Ministry of Industry set up working groups that
are engaged in import substitution. And we have already been there for some equipment that is competitive with foreign models. So, one of the factories in Perm began to produce excellent pumps, which match in quality the best foreign analogues. Some factories in Bashkortostan started the production of valves, cut-offs switches and other fittings for any type of drilling. But it is not necessary to replace all the foreign oil production equipment. And, of course, we can not do this.
We make good tanks, but we do not produced luxury cars like Mercedes. We just don't produce them.
I believe that if we had a dependence on imports in the range of 20-25%, it would be acceptable and probably close to optimal.
Today we can get rigs from China. Our experts say that they are of a sufficient level of quality. We also have a factory, which in 1990 produced drilling rigs – "Uralmash". Then, the plant produced 365 sets of drilling equipment per year. In the past year – only 25.
Therefore we need to rely on the Chinese oil extracting equipment, as they have learned to make a decent drilling equipment. And for the price, no one can match them. I believe that we need to very clearly define few areas of oil extraction equipment, which are critical for us. and then pay close attention and allocate resources to those areas. We do not need to cover everything. And I am sure that before the end of 2020 Russia could reduce this dependence on foreign equipment to 25-30%.
Thanks for posting this, likbez.
Dennis,
I expect 2016 average Russian C+C output to be slightly higher than last year.
Production in 2H will be supported by start-up of Lukoil’s Filanovsky field in the Caspian Sea
Assuming a gradual recovery in oil prices, production in the next several years can plateau close to the current levels, Output can be supported by a number of new project start-ups (mainly medium-sized fields); developmet of satelite fields and deeper layers of the producing fields; and infill drilling.
More info on the Bahzenov Formation. Certainly a huge wild card in Russia’s production potential-
http://uk.reuters.com/article/russia-shale-kemp-idUKL6N0PR1OP20140716
Thanks AlexS.
So you would expect maybe 1% decline (assume oil prices over $90/b) starting around 2021 ? I am assuming “several” means 4 years. Or do you think the plateau might last for as long as 10 years (assuming oil prices and oil demand supports that level of output.)?
Can one see Stockman on CNN, CNBC or Fox?
“Of course there is going to be much more carnage in the oil patch. After all, a decade of coordinated money printing by most of the worldâs central bank eventually generated spectacular levels of excess capacity and malinvestment in the global oil and gas patch.”
“Instead, the current massive overhang of surplus stocks and excess production capacity is owing to the drastic mispricing of capital and the temporary bubble in petroleum demand that pushed prices into an artificial and unsustainable triple digit range. Accordingly, the present oil price collapse is just getting started. It will be subtracting from CapEx and production levels in the US and around the world for years to come.”
http://davidstockmanscontracorner.com/yelling-stay-in-a-burning-theater-yellen-ignites-another-robo-trader-spasm/
Looks like Stockman mixed things up:
– Oil price collapse basically ended. Oil price recovery started.
– Shale industry collapse just started.
I’m not so sure the oil price collapse has ended.
I agree the shale industry collapse has started and it will continue to snowball.
In any market, when the top is in, it is hard to see. Also, when the bottom is in it is hard to see.
I always read financial “news” with a skeptical view. Tonight, Bloomberg says the number of oil shorts is up – probably because the proposed production “freeze” will not work. So, let’s all agree that a production freeze is not going to be agreed to. So, where is any net increase in production going to come from? Score one for Iran. But, how about the rest? Such as USA, SA, Russia, Iraq, Canada, Angola, Nigeria, Venezuela, Libya, North Sea, Brazil, Mexico, Kuwait. So, a production “freeze” agreement is pointless anyway.
Oil shorts have life so good. Iran, KSA and Russia just keep taking turns saying unhelpful things. Where does it end?
Does anybody think there is any strategy behind this. It seems insane at times.
Iran, KSA and Russia just keep taking turns saying unhelpful things. Where does it end?
We are reading Western MSM which tend to distort things that those countries representatives are saying. This is especially true for Iran.
I think you misunderestimate Putin đ
I doubt that I “misunderestimate” Putin.
Although it makes little sense, US stocks make a huge impact on the worldwide oil price.
Until US inventories meaningfully drop, the oil price will stay low, sub $50.
Not seeing a sign of that happening yet. Hopefully will soon.
Hi Shallow sands,
It is strange that anybody pays attention to US crude stocks, for the past 4 weeks average net imports of crude have been about 7.6 Mb/d, there are about 200 Mb of excess crude stocks (above normal levels), reduce imports by 1.6 Mb/d and the excess stocks are drawn down to normal levels in 125 days (about 4 months).
It would make more sense to look at the change in refinery inputs and US crude output.
I also do not understand the focus on inventory. Inventory change is a function of “Crude in less crude out”. Inventory can be manipulated by importing more and as a consequence keep pressure on price. Why does inventory keep going up? It is related to the contango in the oil futures market. In the attached table the front month contango is $1.34, today. If an investor owns storage, he can take delivery today and sell one month forward for a gain of $1.34 less about 50¢ for storage costs. As long as the front month contango stays above $1, inventory will continue to grow.
Although it makes little sense, US stocks make a huge impact on the worldwide oil price.
Very true.
At this stage of oil price cycle I do not think that the size of inventories is a material factor, affecting the oil price. It is played as such by Wall Street, but that’s just reflects the power of “paper oil” producers. They can choose something else (S&P transportation index readings, for example) and use it to depress the oil price.
What it probably reflects at this stage of the cycle is the level of pure greed.
So, a production âfreezeâ agreement is pointless anyway.
It’s not pointless. It is pretty powerful PR statement as in “Go f*ck yourself”. If it materialize, it will help US shale to survive.
Remember famous Margaret Thatcher TINA (“There Is No Alternative”) statement. This is the same statement now made by OPEC and Russia as for the oil price trajectory: there is no alternative to higher oil prices. Peak oil is real, get used to it.
Also for those shorts who were especially brazen, there can be a day of reckoning soon.
Let’s just wait for late April and see.
Article on oil in the latest weekly edition of Barron’s. Talking about Pioneer, one guy said that looking at the Permian, they are looking at $5.5 million for a well that will produce 1 million barrels. Pointed out that is economic at $20 oil.
But, there has been a lot of analysis here looking at the various shale plays. I do not recall any company having any well profile anywhere that was getting a million barrels per well. Is something new going on, or same old BS?
More like propaganda then BS. Along the lines of “Fuser law”: breakeven price of oil reported by MSM is always less then 0.8 * current_WTI_price. Fuser Law holds amazingly well with the USA MSM.
Clueless
I have not read the article, but if it is boe versus bo, sure, there are companies touting EURs well above one million boe.
Continental is now claiming EURs for some of their Oklahoma wells of two million boe.
The associated gas energy equivalent is generally 6 million cf natgas equals 1,000 barrels of oil.
As for strictly oil potential recovery of one million barrels, I have not heard of any operator yet claiming one million bo for an EUR, but, if any place could do it, it might be the Permian.
The thickness of some of those formations is well over 1,000′.
(For comparative purposes to the Utica, there are literally dozens if wells currently producing 6 billion cubic feet of natgas in a year … the energy equivalent of one million barrels of oil.)
What is the estimated decline rate of Utica gas wells?
OFM
That is definitely a work in progress.
Account must be taken of the three ‘windows’ … oil, condensate, and dry gas.
In addition, the wells are so new and had been coming online so rapidly in 2014/2015 there is little history yet.
However, the Ohio state website (location of the vast majority – 1,200+ of the wells) has an easy-to-access and analyze database.
Oilandgas.ohiodnr.gov is two clicks away from downloading the data which is compiled on a quarterly basis.
FWIW, one company, Rice Energy, has 16 dry gas Utica wells showing ZERO decline (flatline production on restricted choke) for up to 18 months for its oldest – Bigfoot.
(Bigfoot has produced something like 7/8 billion cf in that time – about 15 MMcfd.
Pretty amazing formation still in its infancy.
And what does Rice Energy’s worst well look like?
Their latest presentation can be found at http://WWW.riceenergy.com
According to their “Type Curve” they will produce 16 mmcf/d for a year on choke totaling about 6 Bcf in first year. After that they decline rapidly with a projected cumulative production of 21 bcf. These appear to be excellent wells, of course most production does not usually follow the type cure,
Hi dclonghorn,
Yes most wells don’t follow the type curve which most companies develop from their top producing wells, If they tell you 21 BCF, that would be their best well, their average well will probably be about 2.1 BCF.
coffee – you are probably right. However, the whole paragraph just referred to barrels of oil. But, I think that you are right because even the financial press is very careless with getting the facts correct.
From Pioneer’s most recent presentation:
âD&C cost per well:
$7.5 MM -$8.0 MM assuming average perforated lateral lengths of ~9,000 feet and optimized completions compared to 2014
âProduction cost per well:
$5.00 -$7.00 per well (includes LOE of $3.00 -$5.00 and taxes of $2.00)
âForecasting EURs ranging from ~0.8 MMBOE to ~1.2 MMBOE with IRRs up to 30% at current strip prices
( Reflects strip prices ranging from $36.00/BBL in 2016 to $49.00/BBL in 2020 for oil and $2.35/MCF in 2016 to $3.10/MCF in 2020 for gas)
According to the presentation, an average well produces ~80% oil, 20% gas.
dclonghorn
Richard Zeits raised some eyebrows with his latest Seeking Alpha post projecting Cabot’s Susquehanna county wells (northeast PA) with putting out 27 Bcf EUR … a seemingly preposterous number for an $8 million well.
Thing is, their #1 producer in the Marcellus, the T Flower 2, has ALREADY produced 16 1/2 Bcf in three years time.
Currently putting out a steady 7/8 MMcfd.
Hi Coffeguyzz,
They should only drill those kind of wells. đ
What matters for a company’s bottom line is the average output of all there wells. I imagine if you take a close look at the 10k you can determine how many producing wells they have and what their total output is, pretty sure it is going to be about 5 to 10% of that monster well, maybe less. Talk of the best well is a red herring.
Hi AlexS,
Thanks. Looking at Enno Peter’s site http://www.shaleprofile.com,
Pioneer’s average well in 2015 looks like it has high output for 10 months and then looks like it will revert to the average 2011 well profile from months 12 to shut in. I would estimate the EUR on these wells is about 160 kbo at most, adding in 20% natural gas would get the well to maybe 200 kboe of oil, NGL, and natural gas (in boe) for a URR. The return on these wells will be negative.
Don’t understand why they don’t recognize this and just complete their DUCs (if it will not result in cash burn, at current oil prices it will) once prices make it profitable to do so. Enno Peters has more data so perhaps he sees something that I do not.
Dennis,
I have also looked at Enno Peters’ recent post on the Permian.
According to Enno, the average productivity for Pioneer’s wells in the Permian is much lower than what the company shows in the presentation.
Enno’s numbers are for total wells, and the presentation mentions only those wells that were completed in 2015. There were obviously improvements in average productivity in the past few years, but I doubt that they were that big.
Hi AlexS,
You can look at individual years for individual companies, the site is awesome if you play with it a bit. Chart below.
Dennis,
I know Enno cautions on reading too much into the the last couple months data, as it can wriggle around a bit, but if PDX’s 2015 wells continue as shown in your graph, it may just mean that PDX were just trying a little too hard to get good production figure from the Sprayberry, and potentially are going to pay the price for this over production with long under performance of the well.
Chart below is the cumulative well profile for Pioneer wells in the Spraberry by year.
Thanks Dennis.
Enno Peters’ numbers for 629 Pioneer’s wells that started production in Spraberry formation in 2015 show ~34 kbo average cumulative production for the first 3 months.
Pioneers’s numbers for 11 wells in 4Q15 show ~60kboed
(48 kbo, assuming 80% oil)
As in all shale companies’ presentations, the numbers for individual wells is simply cherry picking
AlexS
Interesting! Well spotted!
Anyway, a likely reason for the increased productivity for the well is much due to the fact the the wells are drilled longer. I have a source (unfortunately not in English) saying that 1st generation fracking wells were 200-300m long, second generation wells up to 2-3km, with increased number of explosions. No wonder the well productivity goes up. But I wonder how meaningful this parameter is. I suspect that the parameter “Production/area” would be more meaningful and most likely not show such a large an increase, maybe even a decrease.
Hi Tom,
Remember an oil man really doesn’t care about the oil produced, it is the dollars produced that is the aim. So to the oil company oil per unit area is not something they would really consider. They are really interested in the oil produced per dollar spent, but most interested in the profits produced. Often the higher productivity wells are more expensive to complete (more frack stages, more proppant, or longer laterals), if they spend 10% more on the D+C and get 15% more output from the well (especially if the extra output happens early in the life of the well) that is money worth spending.
Usually they figure out the optimum setup after 2 or 3 years, eventually sweet spots will run out of room and well productivity will decrease, so far there is little evidence of well productivity decrease in the Bakken or Eagle Ford. In the Permian in 2015 it looks like high output in the first 13 months has hurt the well productivity for months 15 and later bringing the well to the level of the 2011 or 2012 wells after month 13. It is also possible that the last data point (month 13 for the 2015 wells)is based on too few wells to be reliable and may be statistical noise. I still think the 2015 average Permian well will have an EUR over 180 months of under 210 kb, similar to the average Eagle Ford well and at $8 million per well and current oil prices, these wells should not be drilled.
Dennis, Alex,
I do want to make one clarifying note to Pioneer Nat. Resources.
The well data I have for North Dakota, Colorado, and New Mexico, is excellent, and I don’t need to estimate anything.
For the Eagle Ford, it is pretty good, as the estimation puzzle is quite easy (few wells / lease, and not many old vertical wells).
For the Permian, the situation is worse, as there are leases that have 100s of wells on a lease (this includes leases from Pioneer), which makes the well production estimation more difficult.
My solution so far is that I only show what I feel is reasonably accurate. That means that for the Texas Permian, almost 30% of the oil production is not shown in the “well quality” graphs. I will try to improve this in the future, but the RRC interface does pose some limitations on what is possible.
This all means that, although the overall production from Pioneer is shown accurately in the Permian in Texas, the well quality graphs include only a (though still large) subset of wells. Theoretically it is possible that on the few leases that I miss, the well productivity is much higher. I don’t think that this is the case, but I can’t show it. Just please keep this in mind.
If Pioneer wants to demonstrate that its wells are better than I show, I will be happy to accept its actual well data, and I will then update the presentations.
Just querie the wells on a subscription service.
Enter parameters of horizontal and Permian to get total wells.
Then refine by entering in a parameter for active and a parameter for last month’s oil production. I suggest 3,100, or 100 bopd for 12/15.
See how many produced more than 100 per day v how many produced less than 100 per day.
Tells a big story re Permian. Wells simply do not hold up.
Bakken wells hold up best is you try the type of querie is suggest.
I think Enno is accurate. I will give him credit, he is very careful to be factual.
AlexS.
I have a data subscription and have finally broken down and paid a little $$ to satisfy myself about both the Permian hz wells, and also the OK hz wells.
I cannot legally reproduce the data, but my view is:
A. Enno’s data is trustworthy re Permian.
B. The OK hz wells are generally gas wells, with associated liquids, which rapidly deplete. Will not impact US oil production in a meaningful way. Some prolific gas wells, however.
Pioneer does have a few big Sprayberry wells, but most will never produce more than 300-400K barrels of oil, absent refracks or EOR breakthroughs. Most seem to really tail off after hitting 75-150K BO, and will produce the remainder over the next 20-40 years. At least that is what I see generally.
shallow sand,
Thanks
Now compare what is said about those excellent wells IPs, EURs and D&C costs with Pioneer’s actual 2015 results.
With annual average WTI oil price of $48.66 + hedges, the company posted net loss of $273 million.
Oil and gas revenues were $2 178 million,
Net derivative gains: $ 879 million;
Net gain on disposition of assets: $782 million.
So, without hedges and gains on asset sales, Pioneer’s net loss would be much bigger.
Now look at their cash flow statement:
Net cash provided by operating activities: $1 248 million
Cash capex: $2 393 million;
Negative free cashflow: $1 145 million.
Not surprisingly, they had to borrow almost $1bn and sell assets for $553 miilion.
And this is one of the leaders in the shale sector!
Look at Q1 16 earnings estimates. Even worse.
And they have better hedges than most.
CLR and WLL have ceased completing oil wells. They are projected to lose major $$.
BTW, it looks like CLR Red River wells will wind up being a much better investment at $30 oil than their Bakken and TFS wells are. Those Red River wells cost a fraction of the Bakken/TFS and will wind up producing similar, if not superior cumulative oil per well.
AlexS.
NASDAQ has earnings estimates on its site.
I think every US E & P that is not integrated will post a loss in Q1 2016. This is before impairments.
In fact, the Chevron estimate is an 11 cent/share loss.
$30 oil is destroying the US E & P industry.
Imagine that. Who would like to see such a thing?
What happens if it is nationalized? The shareholders might get, say, a 10% premium over market price for their shares (making them happy), paid for with printed money.
The employees get gov’t benefit packages and the executives even have a bonus plan like AMTRAK or USPS.
The enemy would have to try a new tactic.
so “finally”?
NEW ORLEANS (CN) – A federal judge has granted final approval to a $20 billion settlement related to the 2010 Deepwater Horizon disaster.
The settlement approved by U.S. District Judge Carl Barbier on Monday includes $5.5 billion in Clean Water Act penalties and almost $5 billion to the five states along the Gulf affected by the oil spill — Louisiana, Texas, Mississippi, Alabama and Florida.
The settlement also requires BP to pay $8.1 billion in natural resource damages, with funds going toward Gulf restoration projects that include restoration of coastal wetlands and wildlife. An additional $600 million will cover other costs related to state and federal reimbursement claims, and up to $1 billion will be given to local governments to settle claims for economic damage from the spill. The spill was the result of the April 20, 2010, explosion and sinking of the Deepwater Horizon oil rig 50 miles offshore from Louisiana. The blast killed 11 workers, injured numerous others and unleashed one of the worst oil spills in history.
The agreement accepted by Judge Barbier calls for the money to be paid out over a 16-year period.
http://www.courthousenews.com/2016/04/04/judge-gives-final-approval-to-20b-bp-oil-spill-settlement.htm
$35.58 4/4/2016. Looks like another price crash.
Is it fair to say that there is a consensus among oil and gas professionals (and by this I mean working guys, rather than entrepreneurs and folks who buy and sell stocks, leases, etc who have powerful incentives to tell a few whoppers before breakfast ) that we have PLENTY of gas to run the yankee economy for several decades, assuming it fetches a decent wholesale price ?
Rockman who used to post a lot at TOD says the gas is there at a high price. I expect he is right, but second third and fourth opinions are welcome.
OFM.
We do not own gas wells, outside a few royalties, and so keep that in mind.
However, I would agree there is a much more shale gas available than LTO.
For example, I have recently looked into the OK wells and found that although they are not big oil producers, many produce very large amounts of gas. Many over 3 million mcf in year one, or the 6/1 ratio of 500,000 BOE.
But the gas producers are really losing a lot of $$ too right now.
OFM/shallow
Not only is there quite a bit more shale gas than LTO available now and far off into the future, the physics of extracting a gas with one to two mile horizontals is WAY easier than lifting a liquid.
Shallow has described over time both the expense and challenges of producing oil from older vertical wells. The horizontal is even much more challenging.
With gas, you stick a steel straw down hole, bend it 90 degrees, and go fishing for the next 25 years.
(Obviously tongue in cheek, but much less work once the takeaways are installed).
As far as available natgas resource? A whole, whole lot.
If you have time to listen to it, this is a great piece about the history of Hubbert and his work on peak oil.
I haven’t yet found a transcript, and there may not be one. I personally prefer to read, rather than listen, it’s MUCH faster for me.
http://www.xepodcast.com/energytransitionshow/ET-EP13-oracleofoil.mp3
I listened. Instead of a transcript read Mason Inman’s book. I read it once quickly and am now re-reading it slowly. An obvious obsession. I have been interested in Hubbert for the better part of a half century but am learning so much more. One disappointment. Mason left out the material on the collaboration between King Hubbert and L.F. Buz Ivanhoe due to space considerations.
As you can see, 9,530 wells in April of 2015, in January of 2016 there are 10,438 wells. An additional 908 wells required to produce close to equal the volume of oil produced each day in April of 2015. A nine percent decline in less than a year. Average monthly loss is 319 barrels ten months later or so. 10,438 times 319 equals more than 3.3 million barrels per month in lost production. Looks like 30,000,000 barrels per month in December of this year. Maybe 29,000,000 barrels per month.
2015 4 33269979 1108999 9530 3491 116
2016 1 33104618 1067891 10438 3172 102
https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf
All at a loss. The faster you go, the behinder you get. har
Looks like we are in for a long period of low oil prices, according to the EIA, March 8, 2016.
“Global Petroleum and Other Liquids
Global oil inventories are forecast to increase by an annual average of 1.6 million b/d in 2016 and by an additional 0.6 million b/d in 2017. These inventory builds are larger than previously expected, delaying the rebalancing of the oil market and contributing to lower forecast oil prices. Compared with last month’s STEO, EIA has revised forecast supply growth higher for 2016 and revised forecast demand growth lower for both 2016 and 2017. Higher 2016 supply in this month’s STEO is based on indications that production is more resilient to lower prices than previously expected. Notably, revisions to historical Russian data, which raised the baseline for Russian production, carry through much of the forecast. Additionally, lower expectations for global economic growth contributed to a reduction in the oil demand forecast. ”
Production is expected to be above consumption until the second half of 2017.
https://www.eia.gov/forecasts/steo/report/global_oil.cfm
On the othet hand we have the hundreds of millions of unaccounted for barrels of oil.
The quality of the EIA statistics and forecasts is outstanding! đ
For 7 months (from August 2015 to February 2016) they kept unchanged estimates and projections for Russia’s oil production, ignoring production data from Russiaâs Energy Ministry and hence showing a declining trend.
Then the EIA suddenly noticed that Russiaâs oil production was actually increasing and, in the March 2016 issue of the Short Term Energy Outlook, has updated its estimates and projections. For unknown reasons, the changes were made for the period from November 2015 to December 2017, but the numbers for previous months were not revised.
For comparison, the IEA also tends to underestimate the resilience of Russiaâs oil output, but they are updating their estimates and projections in each monthly report (OMR).
The upward revisions in the EIA numbers for Russia were quite significant: 430-435 kb/d for January-February 2016; 324 kb/d for 2016 average and 348 kb/d for 2017 average.
Not surprisingly, these changes have altered the projected global supply/demand balance.
Russian C+C+NGL production estimates and projections: EIA STEO and IEA OMR (mb/d)
Accordingly, the EIA has sharply revised down its oil price forecasts for 2016-2017.
From the EIA STEO, March 2016:
“Brent crude oil prices are forecast to average $34/b in 2016 and $40/b in 2017, $3/b and $10/b lower than forecast in last monthâs STEO, respectively. Forecast West Texas Intermediate (WTI) crude oil prices are expected to average the same as Brent in 2016 and 2017. The lower forecast prices reflect oil production that has been more resilient than expected in a low-price environment and lower expectations for forecast oil demand growth.”
Unfortunately for the EIA, their new oil price forecast proved to be wrong already for March.
The EIA was projecting average spot WTI oil price in March 2016 at $32/bbl, while the actual price was $37.5/bbl
EIA spot WTI oil price forecasts vs. actual price
Alex,
Unfortunately for the EIA, their new oil price forecast proved to be wrong already for March.
Why unfortunately? May be this a real milestone for EIA. They reached the “total disconnect from the reality” in this price forecast.
Or may be this is just spring worsening of institutional schizophrenia đ
Saudi Arabia is fixing to bail out Egypt for the next five years. I doubt if anybody in either country who has his eyes open ever expects the money to be paid back.
I see this as a gift and a self defense measure on the part of the House of Saud. They have the cash, and can afford to burn it , ensuring regional stability as best they can.
If Egypt falls, SA will be in a substantially more dangerous position, in terms of regional politics.
http://www.channelnewsasia.com/news/world/saudi-arabia-to-sign-us-2/2667092.html
Is U.S. Shale Oil & Gas Production Peaking? Part I: Gas Production
Tad Patzek makes a wise point in a reply to Coffeeguyzz in his post above.
Aws
I think the most ‘agreeable’ point Mr. Patzek and I may hold is the inclination to embrace, promote and disseminate data that reinforces our already held positions.
If you read Mr. Patzek’s piece, and the comments I made in reply on his blog site, you would see how I questioned virtually everything he presented as being , at best, skewed.
Now, anyone following would be strongly inclined to favor a professional, published-numerous-times and highly regarded in his field such as Mr. Patzek, over some anonymous commenter.
That’s natural.
But how in the heck could Mr. Patzek virtually dismiss the Marcellus’ output, ignore the Utica, mischaracterize the current Pennsylvania reporting parameters and MOST importantly, NOT recognize that the decline in output from the other formations is a direct consequence of being displaced by the much bigger, more economic Appalachian Basin?
I claim no special insight.
I acknowledge my partiality to fossil fuel use/consumption now and for the foreseeable future.
I would suggest that those who feel/think otherwise are not so immune from cognitive bias as they would wish to be.
Hi Coffeeguyzz,
What prompted me to post was how Patzek characterized sweet spots.
From what I understood in Patzek’s post was that he felt there really wasn’t enough data to honestly assess the Marcellus. Which is why he gave it an optimistic fudge factor.
Your point on the Marcellus displacing production from the other less productive basins is fair enough. That said I don’t really see how anyone is making money in the Marcellus.
I am reminded of what Rex Tillerson said about gas producers a number of years ago, “Everyone is losing their shirts. It’s all in the red.”
Btw, you may have a pseudonym, but I don’t consider you anonymous. You are familiar enough to no longer appear anonymous. đ
Coffee, it took nuts to stir up Tad Patsek’s oatmeal on some stinking shale gas play; I’ll give you that. He is a renown reservoir engineer having taught at one of the best, if not THE best petroleum engineering schools in the entire world. He is a “distinguished” member of the Society of Petroleum Engineers. The SPE does not hand those out to anyone. I have set in on his lectures, and his talks; he is a good man and I can assure you he has only the need for truth in his heart about the future of hydrocarbons.
You, on the other hand, are anonymous and won’t say why exactly you are such a adamant cheerleader for the shale industry. You “claim no special insight” in shale matters yet you are willing to go toe to toe with a reservoir engineer who taught tens of thousands of petroleum engineers to deal with facts, the science of the rock and how to extract the hydrocarbons from that rock…profitably. Forgive me, but you appear to simply be using stuff you glean from the internet, most of which is put there by shale companies themselves.
You cannot credibly root for an industry based on MCF’s, or monster IP’s, and not dollars, sir. It has to make money. For instance, 16.5 BCF wells in 3 years are war horses, for sure; at 5 dollar gas. At 70 cent gas those cherry picked wells of yours still have not paid out and might themselves, in yet another 3-4 years, but won’t ever help pay back the sorry wells the same company drilled nearby. Tight shale gas formations in the App basin are displacing other gas production in the US by natural decline, not because they are more economic. That statement put the b in bias.
For instance, 16.5 BCF wells in 3 years are war horses, for sure; at 5 dollar gas. At 70 cent gas those cherry picked wells of yours still have not paid out and might [pay] themselves in yet another 3-4 years, but wonât ever help [to] pay back the sorry wells the same company drilled nearby
The issue of “ultimate profitability” brings us back to the “cheap, abundant money supply” theme. Or more correctly the Feb induced regime of “cheap credit for shale” that existed for the last 7 years. When anybody with a rig could get loans or sell bonds because banks were flush with the Fed money and wanted to put them to work somewhere, even if this “somewhere” was extremely risky (somewhat similar to subprime mortgages). Add to this the political pressure from Obama administration (energy independence theme) and we get a unique environment for shale producers that existed probably until the second half of 2015. This regime of abundant credit lines and junk bond issuance for now is over.
With enough money you can make pigs fly, but you better do not stand at the place where they are going to land.
This is the issue that Coffeeguyzz and Co fail to understand.
As a conventional oil and natural gas producer who is suffering financially at the moment because of overleveraged shale oversupply, Mr. Coffee might rightfully suggest that I am bias against the shale industry. Truthfully, I want the shale industry to succeed but it must do so by standing on it’s own feet, without borrowing money from outside sources it cannot pay back. It must develop it’s remaining reserves from net cash flow, in a manner that is commensurate with worldwide supply/ demand fundamentals, at a reasonable, rational pace that will ensure price stability, not price volatility. It must find a way to do that AND pay back it’s indebtedness.
America has 2.8 million BOPD of conventional oil production that is getting hammered right now largely because of an LTO industry who has had, for the most part, no finding costs the past nine years. There are thousands of shale gas wells in the App Basin that were drilled with borrowed money that have been shut in for years with no takeaway capacity. I can find no success story in that kind of stupidity.
The shale industry must find a way to make shale oil and shale gas extraction profitable or it will play NO role in the energy future of America. The first place to start, in my humble opinion, is to quit lying to the America public about it’s sustainability. I detest that BS. As I do cheerleading for an industry who is about to financially implode. Thank you likbiz, and Mr. Leopold.
Mike
Mike,
Well put!
(I shall steal it.)
All rights relinquished, kind sir. I hope you are well and awaiting the little boy to leave and the little girl to arrive. Soon enough, I am told. Good for the NW; a not so pleasant reminder for the SW that water is king, not stinking hydrocarbons.
Mike,
Thank you for your comment, which is in my view very important.
Another summary on the investing disaster in shale here, it all comes down greed, corruption and stupidity in the end:
http://www.credoeconomics.com/shale-euphoria-the-boom-and-bust-of-sub-prime-oil-and-natural-gas/
Mike. Heinrich, & Shallow
I really hope that in a year or 2, we can climb out of the bunker, pat one another on the back and say we made it through this mess. If we do…..adult beverages are on me. Anywhere in Texas that is.
JohnS. TX is ok w me.
I’d just like to get to $55 WTI, because then we can go back to normal and we could see how well LTO will do at that price.
I suspect that would not do them any good other than get some more money out of investors, especially into the Permian companies. Share issuance, but likely not much more debt issuance.
I agree Shallow.
I hope $55 works for you. I don’t think it will be enough to save the debtor class in the oil patch. $55 won’t be enough to make the PE/HF crowd whole so I think you are right. Those days are gone.
It is going to be fascinating to watch the secured and unsecured creditors carve up the carcasses in the LTO & shale gas. Where is all that off balance sheet financing going to land?
Carrion and dead carcasses everywhere. We are going to need a lot of vultures to clean up the dead and dying.
The IRS is standing at the head of the line to get its cut. A lot of liens are going to be filed and bank accounts frozen.
As I peck away here, creditors are putting in lock boxes to intercept account receivable payments. Debtors are intercepting the lock boxes to keep funds away from creditors. Local bank accounts are being closed and funds are redirected to the home office (some out of the country)
Ever tried to secure a place in line with the other creditors when the debtor files for bankruptcy outside the USA?
My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated for political and propaganda reasons is unchanged and now supported by sufficient data.
And for economic reasons too. The principal question here is “Whether deferred adjustment to higher oil prices is beneficial to the USA economy in a long run?”. They were definitely beneficial to “team Obama”, but this might well be “after us deluge” type of thinking.
The EIA posted the January production number yesterday. January, 9179 kb/d, is down by 56 kb/d from December and down by 83 kb/d from the unrevised December. Attached is a comparison of the monthly and weekly EIA data. The January monthly EIA production is about 45 kb/d lower than the average January weekly data.
Reuters article on oil output freeze deal:
Russia sees oil price of $45-$50 per barrel ‘acceptable’ as it prepares for freeze deal – sources
http://www.reuters.com/article/us-russia-opec-freeze-idUSKCN0X30M0
Russia believes an oil price at $45-$50 per barrel is acceptable to allow the global oil market to balance, as it prepares to meet leading oil producers in Doha later this month, sources familiar with Russian plans said on Wednesday.
Leading oil producers plan to meet in Doha on April 17 to cement a preliminary deal reached between Russia, Venezuela, Qatar and Saudi Arabia in February to freeze oil output at levels reached in January, to curb a surplus on the oil market.
“Now there is discussion of how long production will be frozen and ways to monitor the agreement,” one of the sources said.
“The level of $45-50 (per barrel) is acceptable from the point of view of market balance: if prices go higher shale oil production could start to recover.”
The key question concerns Iran, which saw its oil output curtailed for years by sanctions that have been lifted this year, and wants to bring its output to pre-sanctions levels before sticking to any agreement. Tehran plans to attend the Doha meeting, Russian Energy Minister Alexander Novak said this week.
The sources who discussed Moscow’s position said they believed Iran would struggle to quickly reach levels it has announced. They said Iranian growth is now coming mostly from selling oil from storage and putting easy-to-launch fields on stream.
“A freeze without Iran is being discussed. At the moment we don’t see tough conditions (from others) for Iran to join,” one of the sources said.
The sources added that 17 countries in total could take part in the Doha meeting. They said Russia was considering a number of options to deepen its cooperation with OPEC, but they don’t include joining the organization.
The Russian sources said that the deal to freeze oil output is expected to speed up rebalancing of oil supply and demand by around half a year.
Russia was pumping at a 30-year high last month of 10.91 million barrels per day (bpd), even higher than its previous record in January. The sources said the agreement in Doha is set to cover production, not exports.
They said Russia would not put new projects on hold as part of the freeze deal, and may use other methods to regulate its production, including technical ones. They did not elaborate.
“A cut in production was not discussed as it is hard to implement and may lead to a sharp jump in prices, causing a new wave of output activation at more costly fields,” one of the sources said.
Alex,
Judging from market action today something had happened.
We probably should not trust even a single word from such report from such a notorious source without comparing it with non-Western sources :-). Like in âI’m not upset that you lied to me, I’m upset that from now on I can’t believe you.â
â Friedrich Nietzsche
Or:
Looks like Iran experiences some difficulties with the increase of output.
http://www.irna.ir/en/News/82020951/ (slightly edited for clarity)
Iran more red herring than black swan for oil: Reuters
http://www.irna.ir/en/News/82016849/
Lots of graphs.
Wind and Solar Are Crushing Fossil Fuels
Record clean energy investment outpaces gas and coal 2 to 1.
Tom Randall, Bloomberg, April 6, 2016 â 5:00 AM EDT
http://www.reuters.com/article/us-oil-japan-idUSKCN0UX0QC
Japan’s Cosmo Oil Co has purchased a U.S. crude oil cargo, the first by a buyer in the country since the ending of a four-decade ban on most U.S. crude exports and potentially the first in Asia, two sources familiar with the matter said on Tuesday.
Chinese oil refiner Sinopec Corp (0386.HK) has also bought U.S. crude for export, to be loaded from a Gulf Coast port in March.
Must help the BDIY a little bit.
http://www.bloomberg.com/quote/BDIY:IND
Rose Rock today: http://crudeoilpostings.semgroupcorp.com/
http://www.marketwatch.com/investing/stock/rrms
R Walter,
Ironically, US crude exports fell from 500 kb/d to 339 kb/d since the export ban has been lifted.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCREXUS2&f=W
Total crude oil and oil product exports fell also to a one year low of 4,023 mb/d last week.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WTTEXUS2&f=W
So this is going into the wrong direction.
A West Virginia judge ruled today that coal King Don Blankenship will head behind bars for a year for his role in safety violations related to an explosion that killed 29 miners six years ago this week.
Blankenship, former CEO of Massey Energy, was convicted in December of one of three counts against him for conspiring to âwillfully violate mandatory mine health and safety standardsâ at the Upper Big Branch mine that claimed the lives of 29 men in an explosion on April 5, 2010. A federal safety inspection later found that âif basic safety measures had been in place⌠there would have been no loss of life at UBB [Upper Big Branch].â
Blankenship was sentenced today to one year in prison, plus one yearâs supervised release and a $250,000 fine -â the maximum penalty for the conspiracy charge, according to ABC Newsâ local affiliate WCHS. Prosecutors had bemoaned such a short maximum sentence for what they called âmonstrousâ wrongdoing.
http://abcnews.go.com/US/coal-king-don-blankenship-year-prison-deadly-mine/story?id=38191606
It looks like someone dumped a truck load of crude @ a strategic location in South Dakota & Transcanada had to shut down a 600K BOPD pipeline to Cushing, OK.
The oil shortage is finally about to start manifesting itself, it can not longer be hidden, the US Government is out of bullets. Obama was planning on “Fake Overflowing” the Commercial Storage Tanks in Cushing in the coming weeks in order to counteract or at least limit any positive movement in the price of oil. However, Transcanada has foiled his plans with this pipeline outage.
I wonder if Transcanada had the crude oil dumped in South Dakota or if this was someone else’s plan & Transcanada just went along with it?
There are no shortage of entities around the world & in the US who feel like what the US Government has been doing with oil prices is wrong. Cab Drivers in any 3rd world country, Mexicans trying to transit to work, Canadian Roughnecks, & countless foreign governments have had enough… They could not have dumped the oil & had the pipeline shut down at a better time…