In recent years Americans have been hearing that the United States is poised to regain
its role as the world’s premier oil and natural gas producer, thanks to the widespread use
of horizontal drilling and hydraulic fracturing (“fracking”). This “shale revolution,”
we’re told, will fundamentally change the U.S. energy picture for decades to come—leading
to energy independence, a rebirth of U.S. manufacturing, and a surplus supply of both oil
and natural gas that can be exported to allies around the world. This promise of oil and
natural gas abundance is influencing climate policy, foreign policy, and investments in
alternative energy sources.
The term "shale bubble" is about the idea that the United States is poised to regain "energy
independence" becoming again net exporter instead of major importer of oil and natural gas.
The primary driver of the propaganda campaign was the U.S. Department of Energy’s Energy
Information Administration (EIA). The key technologies that were enabler of shell boom were:
Oil and gas outfit Fieldwood Energy is now in the market with a $2.63 billion
covenant-lite first- and second-lien acquisition loan.
...As lending to lower-rated companies has increased generally, more of them
are also opting for covenant-lite financings.
That trend is evident particularly in the B3 ratings category. Around 18 percent of covenant-lite
loans are for B3 rated companies so far this year, versus 8 percent in 2012 and 3.7 percent in
2011
...Loan portfolio managers said that new institutional clients are also seeking to invest.
More than $57 billion of CLOs have been issued this year, topping 2012 volume.
This refinancing bulge in 2016 became more compressed in time and more imminent.
Most of the defaults, debt restructurings, and bankruptcies so far this year and last year
were triggered when over-indebted cash-flow negative companies could not make interest
payments on their debts.
During the crazy days of the peak of the credit bubble two years ago, they would have been
able to borrow even more money at 8% or 9% and go on as if nothing happened. But those days
are gone. Now the riskiest companies face interest costs of 20% or higher – if they’re able to
get new money at all. Hence, the wave of debt restructurings and bankruptcies.
But that’s small fry. Now comes the wave of companies whose debts mature. They will have to
borrow new money not only to fund their interest payments, cash-flow-negative operations, and
capital expenditures, but also to pay off maturing debt.
That “refinancing cliff” is going to be the biggest, steepest ever, after the greatest credit
bubble in US history when companies took on record amounts of debt, and it comes at the worst
possible time, warned Moody’s in its annual report.
In its report a year ago, Moody’s had already warned that the refinancing cliff for junk-rated
US companies over the next five years – at the time, from 2015 through 2019 – would hit $791
billion. Of that, $349 billion would mature in 2019, the largest amount ever to mature in a
single year.
...Among the other macroeconomic factors, Moody’s lists the slowdown in China and
volatility in oil prices. And there’s another factor that will “make it more difficult for
lower-rated companies to refinance”: worried regulators have been cracking down on banks’
exposure to leveraged loans, which are so risky that even the Fed has been fingering them
publicly.
Banks sell these leveraged loans to loan mutual funds or repackage them into collateralized
loan obligations (CLOs) which they then sell in tranches to institutional investors. When
leveraged loans mature, companies have to come up with the money, but Moody’s warns that
“rising defaults and the impact of the Dodd-Frank Act’s risk retention rule will make it more
difficult for existing CLOs to supply corporate financing.”
The widespread use of horizontal drilling and hydraulic fracturing, the technologies
that while expensive (and unable compete with conventiona oil production price wise) , continue
to evolve and improve.
Spike of oil prices in 2011-2014
This fake promise of oil and natural gas abundance affected both domestic government priorities
and foreign policy. Domestically it slowed down rising of private car fleet efficiency d as well as
investments in alternative energy sources. The implications of this are profound. If the “shale
revolution” is nothing more than a temporary respite from the inevitable decline in US oil and gas
production (not a revolution but a retirement party), then why are there is such a rush to rewrite our
domestic and foreign policy as if we’re going to be “Saudi America” for the rest of the century?
In 2015 U.S. shale oil production has peaked, productivity gains have flatlined and the cheap
money has all but disappeared. Has the U.S. shale game finally blown over? (Alberta
Oil Magazine, Jan 7, 2016):
To summarize the damage: output has peaked, the cheap money and easy private equity are gone,
the gains in per-rig productivity have slowed and the 20 to 30 per cent break that E&P companies
were getting from contractors for labor costs won’t go on much longer. By all metrics, the shale
party is nearly over. The question now is whether the 2015 production peak will forever be the
high-water mark for this uniquely North American industry.
There are three major sources of "subprime" oil: tight oil, shale oil and tar sands.
The term oil shale generally refers to any sedimentary rock that contains solid
bituminous materials (called kerogen) that are released as petroleum-like liquids
when the rock is heated in the chemical process of pyrolysis. Oil shale was formed millions of years
ago by deposition of silt and organic debris on lake beds and sea bottoms. Over long periods of time,
heat and pressure transformed the materials into oil shale in a process similar to the process that
forms oil; however, the heat and pressure were not as great. Oil shale generally contains enough
oil that it will burn without any additional processing, and it is known as "the rock that burns".
Oil shale can be mined and processed to generate oil similar to oil pumped from conventional oil
wells; however, extracting oil from oil shale is more complex than conventional oil recovery and
currently is more expensive. The oil substances in oil shale are solid and cannot be pumped directly
out of the ground. The oil shale must first be mined and then heated to a high temperature (a process
called retorting); the resultant liquid must then be separated and collected. An
alternative but currently experimental process referred to as in situ retorting
involves heating the oil shale while it is still underground, and then pumping the resulting liquid
to the surface.
What bother many observers is the amount of unprofitable (supported by junk bonds) shale oil that
come to the market in the relatively short period of time.
“There is this huge myth propagated by the MSM as well as several of the well-known names in the
alternative analyst community about the wonders of SHALE ENERGY. I can’t tell you how many readers
send me articles from some of these analysts stating how the United States will become energy independent
while pumping some of these shale energy stocks. Nothing has changed in America….. there’s always
another sucker born every minute.
It is extremely frustrating to see the continued GARBAGE called analysis on the SHALE ENERGY INDUSTRY.
I have written several articles listing the energy analysts that I believe truly understand what
is taking place in U.S. energy industry. They are, Art Berman, Bill Powers, David Hughes, Jeffrey
Brown and Rune Likvern.”
While this conversion of junk bonds into oil has features of classic bubble (excessive greed) but
it was also different in some major aspects.
We know that bankers like bubbles because they always make money on swings, either going up or down.
We can accept that that is how things work on this planet under neoliberalism but that does not turn
them less crazy.
At the beginning this was about shale gas, only later it became about shale and tight oil production.
But shale oil production did has major elements of a bubble. And greed was present in large qualities.
Special financial instruments like ETN were created to exploit this greed. MSM staged a compaign of
how the wonders of technology, specifically horizontal drilling and hydraulic fracturing, have unleashed
a new era for energy supplies. Without mentioning that for each dollar shale industry recovered 1.5
dollar of junk bonds was created.
If we think about it in bubble terms that the key selling point of this bubble was that it will lead
to America’s energy independence, a manufacturing renaissance, and will lower gas bills for everyone.
The estimates (based on past reservoir dynamics) were grossly over represented. The factor that is present is bubbles is that they create excess production that at some point far outpace
the demand.
North American crude oil producers are not cash flow positive, and they haven’t been since the beginning
of the shale boom. Capital expenses of shale companies has consistently exceeded cash flow even at $100
per barrel oil price. So essentially this was a risky gamble that oil will go higher, and this gamble failed.
At least for now.
Most experts and analysts agree that, at current oil prices, the shale oil sector will need to
dramatically reduce per-barrel costs in order to make the vast majority of North American plays
viable. “The minimum price I’ve seen [to make production worthwhile] is $50 a barrel in the
very best possible scenarios and with the very best technology,” says Farouq Ali, a chemical and
petroleum engineer at the University of Calgary. “But most of the time they need $65 oil. So the
5.5 million shale barrels we see right now will all decline, but they will decline over time
because there are still thousands of wells. Even if oil prices go to $60 they will still decline
because that’s just not enough profit to operate.”
Of course, those returns aren’t just diminishing on the production side, but in the
pocketbooks of investors, too. Wunderlich Securities senior vice-president Jason Wangler
describes the rise of U.S. shales as a “perfect storm” of cheap money, seemingly limitless
production potential and rapidly advancing technologies. “Now the money is hard to come by,”
Wangler says over the phone from the firm’s Houston office. “With oil at $90 or $100 it was
pretty hard not to be economic.” But that old high-price environment, he says, caused significant
overinvestment in shale assets, including in risky bets on barely marginal plays like the
Tuscaloosa Marine Shale formation that spans parts of Louisiana and Mississippi. “But if you look
at the last year or so, you’ve seen a lot of folks really focus on the Permian and on the
Niobrara,” Wangler says. “Meanwhile you’ve seen the Bakken really fall off very, very hard, as
well as the Eagle Ford and the mid-continent area.”
The decreasing viability of the Bakken region is especially significant. Houston-based shale
expert and petroleum geologist Arthur Berman estimates that with West Texas oil trading at $46, a
mere one per cent of the massive Bakken shale play is profitable. At those prices, just four per
cent of the horizontal wells that have been drilled in the Bakken since 2000 would recover their
costs for drilling, completion and operations, according to Berman. Add to that the competition
from Western Canadian crude oil, which continues to travel down through the U.S. Midwest via rail
and pipeline, and one can assume that a lot of Bakken production will remain economically
underwater without a significant price correction or some breakthrough in cost savings. “In the
Bakken, you’ve got a long way to transport to get that oil to market,” Wangler says. “Obviously
you’re fighting with all that Canadian crude coming down, which makes the price more difficult.
It’s also expensive to [transport oil out of] North Dakota, whether you’re going to the Gulf
Coast or you’re going east or west.”
Due to the dramatic drop of oil prices shale bubble start deflation. Several bankruptcies occurred
in 2015. More expected in 2016 if the price not recover.
Some critics to argue the business model of shale production is fundamentally unsustainable. Before
the oil rice collapse, which started at mid 2014, immediately after signing Iran deal (strange coincidence)
it was expected that producers would have positive returns for the first time in 2015”
“Only 1% of the Bakken Play area is commercial at current oil prices based on my analysis
that follows.
Only 4% of horizontal wells drilled since 2000 meet the EUR (estimated ultimate recovery)
threshold needed to break even at current oil prices, drilling and completion, and operating costs.
The leading producing companies evaluated in this study are losing $11 to $38 on each barrel
of oil that they produce, the very definition of waste. …”
While oil shale is found in many places worldwide, by far the largest deposits in the world are
found in the United States in the Green River Formation, which covers portions of
Colorado, Utah, and Wyoming. Estimates of the oil resource in place within the Green River Formation
range from 1.2 to 1.8 trillion barrels. Not all resources in place are recoverable; however, even
a moderate estimate of 800 billion barrels of recoverable oil from oil shale in
the Green River Formation is three times greater than the proven oil reserves of Saudi Arabia. Present
U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used
to meet a quarter of that demand, the estimated 800 billion barrels of recoverable oil from the Green
River Formation would last for more than 400 years1.
More than 70% of the total oil shale acreage in the Green River Formation, including
the richest and thickest oil shale deposits, is under federally owned and managed lands.
Thus, the federal government directly controls access to the most commercially attractive portions
of the oil shale resource base.
See the Maps page for
additional maps of oil shale resources in the Green River Formation.
The Oil Shale Industry
While oil shale has been used as fuel and as a source of oil in small quantities for many years,
few countries currently produce oil from oil shale on a significant commercial level. Many countries
do not have significant oil shale resources, but in those countries that do have significant oil
shale resources, the oil shale industry has not developed because historically, the cost of oil derived
from oil shale has been significantly higher than conventional pumped oil. The lack of commercial
viability of oil shale-derived oil has in turn inhibited the development of better technologies that
might reduce its cost.
Relatively high prices for conventional oil in the 1970s and 1980s stimulated interest and some
development of better oil shale technology, but oil prices eventually fell, and major research and
development activities largely ceased. More recently, prices for crude oil have again risen to levels
that may make oil shale-based oil production commercially viable, and both governments and industry
are interested in pursuing the development of oil shale as an alternative to conventional
oil.
Oil Shale Mining and Processing
Oil shale can be mined using one of two methods: underground mining using the
room-and-pillar method or surface mining. After mining, the oil shale is transported
to a facility for retorting, a heating process that separates the oil fractions of oil shale from
the mineral fraction.. The vessel in which retorting takes place is known as a retort.
After retorting, the oil must be upgraded by further processing before it can be sent to a refinery,
and the spent shale must be disposed of. Spent shale may be disposed of in surface impoundments,
or as fill in graded areas; it may also be disposed of in previously mined areas. Eventually, the
mined land is reclaimed. Both mining and processing of oil shale involve a variety of environmental
impacts, such as global warming and greenhouse gas emissions, disturbance of mined land,
disposal of spent shale, use of water resources, and impacts on air and water quality. The development
of a commercial oil shale industry in the United States would also have significant social
and economic impacts on local communities. Other impediments to development of the oil shale
industry in the United States include the relatively high cost of producing oil from oil shale (currently
greater than $60 per barrel), and the lack of regulations to lease oil shale.
Surface Retorting
While current technologies are adequate for oil shale mining, the technology for surface retorting
has not been successfully applied at a commercially viable level in the United States, although technical
viability has been demonstrated. Further development and testing of surface retorting technology
is needed before the method is likely to succeed on a commercial scale.
In Situ Retorting
Shell Oil is currently developing an in situ conversion process (ICP). The process
involves heating underground oil shale, using electric heaters placed in deep vertical holes drilled
through a section of oil shale. The volume of oil shale is heated over a period of two to three years,
until it reaches 650–700 °F, at which point oil is released from the shale. The released product
is gathered in collection wells positioned within the heated zone.
Shell's current plan involves use of ground-freezing technology to establish an underground barrier
called a "freeze wall" around the perimeter of the extraction zone. The freeze wall
is created by pumping refrigerated fluid through a series of wells drilled around the extraction zone.
The freeze wall prevents groundwater from entering the extraction zone, and keeps hydrocarbons and
other products generated by the in-situ retorting from leaving the project perimeter.
Shell's process is currently unproven at a commercial scale, but is regarded by the U.S. Department
of Energy as a very promising technology. Confirmation of the technical feasibility of the concept,
however, hinges on the resolution of two major technical issues: controlling groundwater during production
and preventing subsurface environmental problems, including groundwater impacts.1
Both mining and processing of oil shale involve a variety of environmental impacts,
such as global warming and greenhouse gas emissions, disturbance of mined land; impacts on wildlife
and air and water quality. The development of a commercial oil shale industry in the U.S. would also
have significant social and economic impacts on local communities. Of special concern
in the relatively arid western United States is the large amount of water required for oil shale processing;
currently, oil shale extraction and processing require several barrels of water for
each barrel of oil produced, though some of the water can be recycled.
1RAND Corporation Oil Shale Development in the United
States Prospects and Policy Issues. J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and
G. Cecchine, MG-414-NETL, 2005.
For More Information
Additional information on oil shale is available through the Web. Visit the
Links page to access sites
with more information.
Major oil producers agreed Friday to a nominal increase in crude production of about 1
million barrels per day, a bid to put a damper on high oil prices. But in practice, major oil
exporters will likely only be able to add about half that total to global markets, because many
countries are already producing at capacity or face severe threats of supply disruption.
Oil markets weren't calmed by the agreement announced Friday by the Organization of the
Petroleum Exporting Countries after a contentious week of meetings. Crude prices in New York
rose more than 3 percent to almost $68 a barrel and rose about 2 percent in London to more than
$74 a barrel.
OPEC didn't agree to increase production as such. Rather the group, with the addition of
nonmember Russia, agreed to respect its existing program of restricting supplies. But since the
group had gone well overboard and trimmed output by almost 2 million barrels a day, due in
large part to a steep falloff in Venezuelan oil production, respecting the original target will
translate into more oil for the global market -- on paper, at least.
In practice, only Saudi Arabia and Russia have the capacity to add significant amounts of
crude in the next few months. That means Friday's agreement will end up adding about 600,000
barrels of oil a day to the global market.
The contentious meeting took place under the shadow of vituperation from U.S. President
Donald Trump, who worried that high oil and gasoline prices would be politically painful ahead
of midterm elections later this year. Even after the group's decision had been announced, Trump
was still tweeting hopefully about OPEC increasing production.
"... "Conclusion. No matter what clever US energy independence calculations are out there, the fact remains that the US is physically dependent on around 8 mb/d of crude oil imports, 4.3 mb/d out of which come from countries where oil production has already peaked and/or where there are socio-economic or geopolitical problems. As of April 2018 US net crude imports were about 6 mb/d, far from oil independence." ..."
"... I note also that about 45% of USA imports come from Canada, as well depicted in in your Fig 1. Thus we are 'captives' of Canada (to use the terminology of trump), but don't seem to have much appreciation or respect for their position. ..."
US total (oil + products) inventories made a new low (from the high February 2017)
US ending stocks July 6th
Crude oil down -12.6 million barrels
Oil products down -0.7
Overall total, down -13.3 (shown on chart)
Natural Gas: Propane & NGPLs up +6.1 (not included in chart)
Chart: https://pbs.twimg.com/media/Dh1-upjXUBEOjvn.jpg
"Conclusion.
No matter what clever US energy independence calculations are out there, the fact remains
that the US is physically dependent on around 8 mb/d of crude oil imports, 4.3 mb/d out of
which come from countries where oil production has already peaked and/or where there are
socio-economic or geopolitical problems. As of April 2018 US net crude imports were about 6
mb/d, far from oil independence."
I note also that about 45% of USA imports come from Canada, as well depicted in in your
Fig 1. Thus we are 'captives' of Canada (to use the terminology of trump), but don't seem to
have much appreciation or respect for their position.
The completed around 95 according to my data. The is lag in the data on confidential wells
that will show up next month in the final data. Also if the Bakken was to get and hold 1.4
million barrels a day the would need to complete around 1500 wells per year.
I managed to erase my own comment on this. And my comment was simple, the only true
measurement of market balance for oil going forward is global inventory level. Everything
else is perhaps manipulation or guesses.
I agree, with all the intentional and unintentional confusion it stays confused. I stay
confused trying to figure out what is confused. Inventory levels will be the only clear
measure of what is happening. US inventories should not be dropping fast, as we are about the
only country with increased production, but we dropped over 30 million last month. That's
really not small potatoes, as commercial stocks are just a little over 400 million. Though, I
think the US will be one of the last that would hit the danger zone.
Good point. My intention was not to give more confusion. These are forecasts from eia and, I
always like to remind this, they forecasted Brent averaging 105$ for 2015 in the STEO of
October 2014. They never forecast big surplus or deficit.
I messed with the numbers of the STEO from 2018 to guess when the are reliable. Inventory
levels are accurate for the US from the monthly report, which is 3 months old (april for July
STEO). Other inventory levels are less accurate, but stock changes are reliable from 4-5
month data.
Global inventories increased in April (0.74 Mb/d) and May (1.14 Mb/d). This would be quite
a change, as April would be a record inventory build since January 2017, and it would be
followed by another record. This have to be confirmed later.
So, now I know what I will look for in these STEO.
How does this fit with production and consumption?
I thought we have still increasing consumption of about 1.5 mb/year, and production in
April/May didn't jumped thad much – Opec flat and Permian already near it's pipeline
bottleneck.
As much as I know, many storages are unknown, especially Opec / China. There are these
satellite measurements, but there are additional deep storages.
Gathering all comsumption / raffinery input / production data would give an additional
picture. Still not easy.
With 1mb/day surplus we should go soon into the next oil price crash to 30-40.
Even if we haven't hit peak yet, the fact that production is likely to be going up by a
snail's pace the next 3 years is a problem. If consumption just goes up 0.75% a year we need
600K extra a year. That seems like a big challenge to a layman like myself.
Well what will happen is that the price of oil will hit $150-$200 a barrel to ration demand.
Which will cause much pain and ruction and gnashing of teeth among the voters, but Europe
has had those oil equivalent prices owing to taxation for quite some time and they manage
high living standards. $200/bbl probably destroys 10 million a day in superfluous 'Becky
driving by herself to the mall in a 3 ton SUV for no reason' kind of demand and incentivizes
quite a bit of production.
The transition period will be moody for sure, but at $200/bbl, the amount of economic EOR
targets in the US is somewhere in excess of 70 BBO from old conventional fields from the
industry reports I have seen – its just not economic to do since there isn't enough CO2
available to flood them, so you need to use more expensive techniques which require very high
prices (ethane flooding might be useful????). Worldwide its hundreds of billions. High prices
that encourage us to use the resource wisely and not waste the goddamn stuff liberally would
be a godsend, if we could quit wasting gigatons of plastic bullshit and 40% of our food
– i.e. if everything made from oil was more expensive as well.
It would be painful economically, but Mad Max isn't coming our way. After 5 years of pain,
we might actually finally get our shit together and research some goddamn alternatives.
I believe sugar cane ethanol is very competitive at $120 per barrel. This allows converting
grass cattle grazing ground to cane. I believe soy and palm will also become very attractive
crops. And I suspect countries like Haiti and Nicaragua will continue having riots.
Yes, I believe you are right. The future energy picture is complex, but authors writing books
about this say sugar cane ethanol could have EROEI (energy return on energy invested) of up
to 4. Even based on mechanised agriculture. And the big advantage of this crop is that it is
not very nitrogen intensive, the biggest fertilizer, currently energy intensive when it comes
to natural gas usage. Even when it comes to preindustrial crop rotation, the nitrogen
intensive main food crops were often rotated with legume crops which were not nitrogen
intesive in the hope to rebuild nitrogen content in the earth. So very long term, sugar cane
ethanol is a superb type of renewable energy. (that is what I read, no expert).
Brazil has the biggest potential out there when it comes to size, and it is not
inconceivable that they can cover much of domestic fuel demand with this outside aviation and
possibly shipping (no need for diesel and gasoline ;-)). It would be in competition with food
crops and concerns about deforestation, but still; a big potential there. Brazil is well off
in a more renewable future btw, having loads of hydro power, wind power, in addition to
biomass power (sugar cane the most promising).
"[Exxon's] approach is a gamble in a new era of energy breakthroughs such
as fracking and electric vehicles. Many of Exxon's competi-tors are
transforming their businesses to move away from oil exploration, and
have begun to spend carefully and diversify into renewable
energy ."
"'Most investors like Exxon, but they like other companies better,'
said Mark Stoeckle, chief executive of Adams Funds, which owns about $100
million in Exxon shares. 'The market is not willing to reward Exxon for
spending today in hopes that it will bring good returns
tomorrow.'
"Exxon has been pledging to produce more oil and gas for years, but its
output of about four million barrels a day is no higher today than it was
after its merger with Mobil Corp. in 1999. Even if Exxon succeeds in
doubling last year's earnings of $15 billion (excluding
impairments and tax reform impacts) by 2025, as Mr. Woods vowed in his
eight-year spending plan, it would still be making far less than in 2008, when it
set what was then a record for annual profits by an American
corporation, at $45 billion .
"Exxon's fracking prospects in the Permian basin in West Texas and New
Mexico, developed by its XTO unit, remain among its most profitable
opportunities, the company says. Still, its U.S. drilling
business has lost money in 11 of the last 15 quarters."
Hi Steve, this is exactly what we have been talking about for the last 8 years. To make
matters worse there seems to be a completely irrational belief that Shale will save the day.
Outside of the fact that shale is not processable without heavier crude, and it is at best
energy neutral, and probably negative, it is also long term unaffordable. There are 1.7
million Shale wells in the US. Over the next 5 years 1.4 million of those wells will have to
be replaced to just keep production even. That will be $6.2 trillion even if done on the
cheap. $6.2 trillion is equal to the total cost of all the finished product that will be
consumed by the US for the next 12.8 years (@ $75/barrel). Expending 12.8 years of sales
revenue to produce 5 years of oil is just not going to happen!
There seems to be a black out on this terrible situation. Some of that may be just plain
ignorance, but I suspect that the main reason is that it is politically unspeakable. For that
reason nothing is being spoken. As I have been saying for some time no one should expect big
oil, big government, or big anything to come riding to the rescue. The individual is now
completely on their own. Chose your options with discretion.
Agreed. The U.S. Shale Oil Ponzi Scheme will likely begin to disintegrate within the next
1-3 years. Already, the Permian oil productivity per well has peaked.
Then when the next Shale Oil ENRON event takes place... watch as the dominos fall.
@SRSrocco, U.S. Tight Oil depends on cheap credit. Regardless of oil prices.
Once cheap credit dries up and the previous debts are unable to be paid by drilling new
wells, the entire scheme falls apart.
Oil prices do not drive U.S. Tight Oil as much as cheap credit from easy loans.
Eventually, U S. Tight Oil using new credit cards to pay debts on old credit cards will
catch up with a vengence. Rising interest rates will be the catalyst. Rising oil prices only
prolong the increasing debt.
Didn't the EIA publish something not long ago stating their concerns that we could see oil
shortages by 2020? And around the same time, I recall that the Saudi Oil Minister came out
and stated that without more investment, we would likely see oil shortages by 2020. And then
at the recent OPEC meeting, I believe it was the Oil Minister from UAE who stated that we
need to find a new North Seas equivalent oil field EVERY YEAR to meet projected demand, which
of course is not going to happen. It has been a long slow grind since 2008 to get to this
point, but from here on out I anticipate that things will start unraveling at an ever faster
pace. Big changes on the way. But one thing that will NEVER happen is that the POTUS or some
other world leader comes out and says we are running short on energy. Instead it will be
Trade Wars, the damned Russians or some other lame propaganda -- anything but the truth.
The mitigation section of the study was most telling. It simply stated that local
sustainable economies would replace the modern era. These economies included local food
production and energy production. As this process unfolds, I simply do not see how a high
rise is going to remain habitable.
Zero hedge put a news story a while ago where (I think 2016) the US oil industry lost more
in that it earned in the previous 7 years (mining in general), so more investment wouldn't
have been coming in the US anyway - the price wasn't high enough to justify it.
Worldwide we are going to see some almightly crunch, whether it will arrive after 2020
will be seen. Ironically it might save Trump anyway if the world is seen to be beset by a oil
supply crunch since its hard to blame that on him.
The U.S. needs to get off its dead ass and start developing better batteries, solar power,
and other alternative energy sources. This was talked about in 1973, during the Oil Embargo
days, and its just astonishing the U.S. has done little since to ween itself off of oil. And
now we now have a tariff against Chinese made solar panels. DUH!!! How dumb can you get?
Look at the energy density of those power sources. You'll never run an industrial
civilization off of them. Electric cars may be great for zipping a couple of people around
town from day to day, but you're never going to run the large mining and shipping equipment
needed for our society. If you want to do that, you're going to have to develop viable
breeder reactors and the technology to manufacture liquid fuels with that energy - and this
is doable.
Right. There is nothing.....NOTHING....that can replace oil and gas as it is used and
utilized by the modern industrial society. Nothing......
What needs to happen right now is a steady rise in prices that will condition our
population to start learning to do with less cheap, easy energy. We have got to curb usage to
give society a chance to begin to learn another way.
The major obstacle to doing this responsible, rational action? The egregious, criminal
banking system that has gotten the world awash in debt to feed their greed. Any cut back in
the use of energy will destroy the economy and their gravy train.
Those suckers from Sanford and Bernstein again try to push thier view that shale oil has
great potential instead of potential to bury even more money in the sand. production of shale oil includes production of a
parallel stream of junk bonds.
"... statements from the U.S. government about "zero tolerance" towards Iran could mean that those losses will end up being much higher. Just by shifting the supply outages from 0.5 to 1 mb/d would translate into an oil price increase of about $8 to $9 per barrel, according to Bank of America Merrill Lynch. ..."
"... "We estimate that every million b/d shift in [supply and demand] balances would push the oil price by $17/bbl on average. So based on those assumptions, we estimate zero Iran exports could push oil up by $50/bbl if Saudi caps out. We expect in this game of chicken, someone will blink before that happens." ..."
"Investors who had egged on management teams to reign in capex and return cash will lament
the underinvestment in the industry," the analysts
wrote . "Any shortfall in supply will result in a super-spike in prices, potentially much
larger than the $150 a barrel spike witnessed in 2008."
... ... ...
Of course, for many, this is a problem for another day. The oil market is
arguably facing a supply crisis right now. Until recently, the oil market assumed a loss of
about 0.5 mb/d from Iran because of U.S. sanctions. But statements from the U.S. government
about "zero tolerance" towards Iran could mean that those losses will end up being much higher.
Just by shifting the supply outages from 0.5 to 1 mb/d would translate into an oil price
increase of about $8 to $9 per barrel, according to Bank of America Merrill Lynch.
"We estimate that every million b/d shift in [supply and demand] balances would push the
oil price by $17/bbl on average. So based on those assumptions, we estimate zero Iran exports
could push oil up by $50/bbl if Saudi caps out. We expect in this game of chicken, someone will
blink before that happens."
In other words, if Saudi Arabia is unable to plug the deficit, the U.S. would likely have to
back down on its "zero tolerance" policy towards Iran. The oil market is too tight, and the
supply gap would be too large. Cutting Iran exports by that much, in an increasingly tight oil
market, would send prices skyrocketing, something that the Trump administration probably won't
be able to stomach. If Trump proceeded, a price spike of that magnitude would lead to a
meltdown in demand.
As the world continues to burn energy like there is no tomorrow, global oil and gas discoveries
fell to another low in 2017. And to make matters worse, world oil investment has dropped 45% from
its peak in 2014. If the world oil industry doesn't increase its capital expenditures
significantly, we are going to hit the Energy Cliff much sooner than later.
According to Rystad Energy, total global conventional oil and gas discoveries fell to a low of
6.7 billion barrels of oil equivalent (Boe). To arrive at a Boe, Rystad Energy converts natural
gas to a barrel of oil equivalent. In 2012, the world discovered 30 billion Boe of oil and gas
versus the 6.7 billion Boe last year:
"We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, senior analyst
at Rystad Energy. "The discovered volumes averaged at ~550 MMboe per month.
The most
worrisome is the fact that the reserve replacement ratio in the current year reached only 11%
(for oil and gas combined) - compared to over 50% in 2012."
According to Rystad's
analysis, 2006 was the last year when reserve replacement ratio reached 100%.
The critical information in the quote above is that the world only replaced 11% of its oil and
gas consumption last year compared to 50% in 2012. However, the article goes on to say that the
last time global oil and gas discoveries were 100% of consumption was back in 2006. So, even at
high $100+ oil prices in 2013 and 2014, oil and gas discoveries were only 25% of global
consumption.
As I mentioned at the beginning of the article, global oil capital investment has fallen right
at the very time we need it the most. In the EIA's International Energy Outlook 2017, world oil
capital investment fell 45% to $316 billion in 2016 versus $578 billion in 2014:
In just ten years (2007-2016), the world oil industry spent $4.1 trillion to maintain and grow
production. However, as shown in the first chart, global conventional oil and gas discoveries fell
to a new low of 6.7 billion Boe in 2017. So, even though more money is being spent, the world
isn't finding much more new oil.
I believe we are going to start running into serious trouble, first in the U.S. Shale Energy
Industry, and then globally, within the next 1-3 years. The major global oil companies have been
forced to cut capital expenditures to remain profitable and to provide free cash flow.
Unfortunately, this will impact oil production in the coming years.
Thus, the world will be facing the Energy Cliff much sooner than later.
Yeah tHis article is ridiculous, resident ZH self-purported Mensa members
like Tmos' have proven beyond any doubt that 'abiotic oil' replenishes the
world's supply of easily accessed hydrocarbons every fifteen minutes or so,
regardless of increasing consumption rates; indeed regardless of any
veritable facts whatsoever.
Worked by whole life in the oil business. Depletion is real. Abiotic oil
replenishment is Magic unicorns dancing on rainbows. Oil won't run out
ever, but the energy required to extract the oil will make remaining oil
reserves uneconomic at some point.
Strange that the oil industry does not agree with you. And it's strange
that reserves all over the world are not stable but decreasing. Your
Mensa idol is full of shit.
A field is creamed by massive infill drilling with horizontal wells that skim the very top
of the reservoir. The decline rate is the[n] drastically reduced while the depletion rate is
drastically increased. Things will go just great until the water hits those horizontal wells
at the top of the reservoir. Then production will drop like a rock.
I assume this is the money quote. These methods comprise the "game changer" that scuttled
peak oil predictions circa 2005.
By demurring a prediction as to when the stone might–will!–drop, you're
acknowledging the deplorable state of the data. This should give us pause. We might call this
the New Peak Oil Reticence.
Let's grant that what you say is true (I'm certainly not qualified to refute it). If you
know it (that is, that the rock will drop), then "they" know it, and by "they" I mean those
who are in the business of developing these "creaming" methods. They must know it.
No one producing country is looking at the global problem. They are only concerned with their
own country and the problems at home. Most are old men who realize that they will be long
dead if there is ever a catastrophe. And most, like the contributors to this blog, believe
that there will never be a catastrophe. They believe that renewables, or fusion energy, or
God, human ingenuity, or something else will save us from any type of collapse.
But the point is, the oil barons of each individual country, are not even remotely
concerned with the collapse of civilization as we know it. They believe God, or Allah, or
human ingenuity, will simply not allow that to happen.
"And most, like the contributors to this blog, believe that there will never be a
catastrophe. They believe that renewables, or fusion energy, or God, human ingenuity, or
something else will save us from any type of collapse."
But doesn't that require, like, planning? Plenty of planning?
I think Dr. Minqi Li put together an exceptionally well researched paper. The only one I have
a faintest glimmer of knowledge in is oil. 2021. Give or take a couple of years is a good
estimate of when peak oil occurs, based on current findings and technology. Improvements in
either would probably only affect the tail of the decline rate. Which, based on the immense
overstatement of EIA, and the creaming you mentioned, the tail should have much more of a
decline than depicted. I am tending towards 2022 to 2023 as the final peak, due to the little
over a year hiatus on the Permian final push due to pipeline and other constraints. We all
know 2042 is a bad projection for the US, it will get there as soon as it can. It will get
there as soon as it can, because the oil price will be high enough to beg, borrow, or steal
to get there. For that reason, all other sources will be staining to get there at the same
time. We are in the final stage, I do think.
Yes, I agree with you on Dr. Minqi Li's paper. I am not sure, however, that the Permian will
show enough yearly increase to hold off the peak until 2023.
The implied increase in the Permian would be staggering. US onshore outside of fracking is in
terminal decline. US GOM is peak/decline. Eagle Ford is peak/decline. Bakken is close to
peak. Eagle Ford and Bakken have very high existing production decline rates, meaning they
will fall like a brick if drilling moves to the Permian.
There isn't anything new beyond the Permian. People have looked. No more plays.
And after covering all of that and its own existing production decline (not as extreme as
the other plays but large in absolute number), the Permian is supposed to add millions of
barrels per day?
I don't think that adds up no matter what the price of oil is.
"... I believe due to OPEC massively inflating their URR, and the inaccuracy of the Hubbert method due to the creaming of all giant fields, the expected peak dates here are highly inaccurate. ..."
In the table below I have converted the data Dr. Minqi Li presented in metric tons per year
to million barrels per day. Again, this is C+C plus natural gas liquids.
2017
At Peak
Year Peak
BPD Increase
us
11.47
15.08
2042
3.61
Saudi
11.29
12.17
2030
0.88
Russia
11.13
12.01
2033
0.88
Canada
4.74
7.85
2049
3.11
Iran
4.70
5.40
2039
0.70
Iraq
4.44
6.51
2042
2.07
China
3.S6
4.32
2015
UAE
3.53
4.38
2037
0.84
Kuwait
2.93
3.35
2040
0.42
Brazil
2.87
3.03
2025
0.16
Rest of W
27.13
33.22
2004
Total World
88.10
90.95
2021
2.85
The source for this chart is the same as the table above. I believe due to OPEC
massively inflating their URR, and the inaccuracy of the Hubbert method due to the creaming of
all giant fields, the expected peak dates here are highly inaccurate.
Well, all except three. The rest of the world did peak in 2004, China did peak in 2015, and
the world will peak by 2021 or before. Congratulations to Dr. Minqi Li, the most accurate
future peak there is the one that he calculated. Guym x Ignored says:
07/04/2018 at 8:10
am
I think Dr. Minqi Li put together an exceptionally well researched paper. The only one I have
a faintest glimmer of knowledge in is oil. 2021. Give or take a couple of years is a good
estimate of when peak oil occurs, based on current findings and technology. Improvements in
either would probably only affect the tail of the decline rate. Which, based on the immense
overstatement of EIA, and the creaming you mentioned, the tail should have much more of a
decline than depicted. I am tending towards 2022 to 2023 as the final peak, due to the little
over a year hiatus on the Permian final push due to pipeline and other constraints. We all
know 2042 is a bad projection for the US, it will get there as soon as it can. It will get
there as soon as it can, because the oil price will be high enough to beg, borrow, or steal
to get there. For that reason, all other sources will be staining to get there at the same
time. We are in the final stage, I do think.
Ron, many thanks for your very informative post about world oil (as always) and your
comments on my post.
However, like much of the peak oil community, having missed some of the previous peak
oil predictions, now I may err on the conservative side. Many have criticized the EIA
projections and OPEC reserves. But again, even with those projections/reserves, the world
oil production is still projected to peak in 2021. This suggests that world oil production
may indeed peak in the near future. As I promised, I will follow up with part 2 on
this.
Regarding China, China's oil consumption growth has re-accelerated as its oil production
is in decline. This development may have some major impact on global economy/geopolitics in
the coming years. On top of that, China is (or will soon become) the world's largest
natural gas importer.
World cumulative oil production up to 2017 was 192 billion metric tons. The world's
remaining recoverable oil resources are estimated to be 276 billion metric tons and ultimately
recoverable oil resources are estimated to be 468 billion metric tons. By comparison, the BP
Statistical Review of World Energy reports that the world oil reserves at the end of 2017 were
239 billion metric tons.
World oil production is projected to peak at 4,529 million metric tons in 2021.
2017 Production and Peak Production are in million metric tons; Cumulative Production, RRR
(remaining recoverable resources or reserves), and URR (ultimately recoverable resources) are
in billion metric tons. For Peak Production and Peak Year, regular characters indicate
historical peak production and year and italicized blue characters indicate theoretical peak
production and year projected by statistical models. Cumulative production up to 2007 is from
BGR (2009, Table A 3-2), extended to 2017 using annual production data from BP (2018).
Fun to look at this analysis, and plug in a one million shortage from North America.
Obviously, there would not be a one million drop in Iran, as it would be sold somewhere.
We might be seeing similar articles about gas over the next couple of years. Driving a bit
less is maybe a good thing, pensioners and children freezing to death and industry shut down
with rolling blackouts is maybe less negotiable.
Suppose there is too little oil and the price doesn't change. Producing countries will be
sure their own countries have a sufficient amount so regardless of price, that oil isn't
leaving the country. It stays right there for consumption. External price is meaningless to
that country, as it should be.
There are countries that produce about what they consume. Mexico is one. Argentina. Their
oil isn't going anywhere. A higher price elsewhere tries to get it exported? Clearly the govt
will stop anything like that. Just as the US did with its export ban in the 70s. Price
doesn't matter if bans are in place.
Oh, and another annoying thing in that article. Something like . . . if supply shrinks,
only "demand destruction" can avoid some sort of catastrophe. This is absurd. Demand is not
destroyed. The desire for oil will grow with population. The population demands oil. It is
consumption that is destroyed by lack of supply. Can't consume what doesn't exist.
Besides which, if some level of "grim" is approached, then some decision is going to be
made to liberate that Orinoco heavy from the horrible popularly elected government that
controls it. As I noted before, there is a large ethnic Russian population in Venezuela. The
1917 revolution sent many people there, fleeing confiscation. Liberation may not go
smoothly.
Mexico doesn't use what it produces, it doesn't have the refining capacity – it exports
crude and imports products.
Invading Venezuela wouldn't necessarily stop the decline in production – their
equipment and wells are falling apart, to get back to where they were a couple of years ago
would require a five year occupation, probably with forced labour (or really high wages), and
the investment money all coming from the invading country, with no net returns for longer
than that.
Demand is usually defined with some relation to price, not assuming a commodity is free.
"... tier plays that have been a bust. With the seismic and visualisation technology improvements the E&Ps should know better where and where not to drill. They seem to be more selective with falling wildcat numbers (and that is not much of a function of price that I can see as it has been happening since 2010) and yet the commercial discovery rates are staying fairly low. I can only interpret that as indicating that there just isn't that much left. With Rystad indicating 6 to 8% decline rates in mature fields, and rising, and few new prospects how can there not be a peak? ..."
"... Saudi ministers spout out any thing that comes to mind to support flip-flop policies and their feud with Iran seems to be bubbling in the background of a lot that's going on; every year Iran and/or Iraq say they have a new plan and target for higher production, which is 100% guaranteed not to be met even remotely. ..."
I think if the world economy starts to drop, which is overdue and looking increasingly likely
every time Trump opens his mouth, and keeps the oil price down then it's likely we'll be in a
slow but accelerating decline. That might be a good thing – the further the peak is
pushed out the steeper the decline when it comes.
What has surprised my most recently has been the fall in discoveries for oil and, maybe
more so, gas, and with that the number of new fron tier plays that have been a bust. With
the seismic and visualisation technology improvements the E&Ps should know better where
and where not to drill. They seem to be more selective with falling wildcat numbers (and that
is not much of a function of price that I can see as it has been happening since 2010) and
yet the commercial discovery rates are staying fairly low. I can only interpret that as
indicating that there just isn't that much left. With Rystad indicating 6 to 8% decline rates
in mature fields, and rising, and few new prospects how can there not be a peak?
The oil drop might have been more expected than the gas, and was predicted by some when
peak oil was first mentioned, I think gas less so, but perhaps the price has had a bigger
effect there. Whatever the cause many countries have been banking on ever rising supplies,
either by pipeline or LNG, that might not be forthcoming.
Having said that simple economic arguments rarely seem to work as predicted, oil supplies
would have peaked well before now without, mostly non-proftable, LTO; Venezuela production
should be rising not a basket case; Saudi ministers spout out any thing that comes to
mind to support flip-flop policies and their feud with Iran seems to be bubbling in the
background of a lot that's going on; every year Iran and/or Iraq say they have a new plan and
target for higher production, which is 100% guaranteed not to be met even remotely.
At the moment the traders don't seem certain which way to turn – falling/rising
supplies, short/long term demand rise/fall – you can see why they tend to fixate on US
crude stocks, everything else is too complicated. The next few Wednesday/Thursday trading
patterns will be interesting.
(ps if anything highlights the state of the oil industry at the moment it's that Fram, a
two well, eight year life-cycle, gas condensate tie-back with about 10 mmboe reserves, has
been the main headline news on at least four of the trade magazines this week.)
A little short by over 2 million a day. Perry has to know the Permian is on a hiatus for
at least a year. That's probably over a million. Iran push is for another million. Yeah,
that's a little short. Idiocy reigns. Russia just called for tariffs against the US. Any
assistance from Russia ain't gonna happen.
The slow motion train wreck in progress. No one knows why the driver of the Lower for
Longer Train has picked up speed down the curving stretch .
Ok, I'll forgo the train wreck series. Yeah, it's serious. So was the ridiculous pricing
we've had for the past four years, and no one but the people who relied on oil income
complained. There was not enough for capex to get new oil. The trainweck happened already.
U.S. oil production is booming at record levels, and U.S. oil exports have also reached
new highs -- 3 million barrels a day in the last week, according to government data.
Those exports are more than most OPEC countries can produce each day and only lag two OPEC
countries, Saudi Arabia and Iraq, in terms of exports.
And if you read far enough down in that article they do mention imports, as if they hardly
matter.
As U.S. production has grown, U.S. imports have decreased. The U.S. imported a
relatively high 8.4 million barrels per day last week.
Okay, the US exported 3 million barrels per day and imported 8.4 million barrels per day.
Yet the headline says the US exported more oil than most OPEC countries. Is this Orwellian
Newspeak?
We all agree that 2+ 2 = 5, but what we don't know is which one belongs to the thought
police. I agree the Permian will produce 1.3 million this year, just take the rat cage off my
head.
"the US exported 3 million barrels per day and imported 8.4 million barrels per day. Yet the
headline says the US exported more oil than most OPEC countries. Is this Orwellian Newspeak?"
At the just concluded OPEC meeting, Iran, Iraq and Venezuela were against any increase in
extraction, while the Saudis wanted an increase. What resulted is
detailed in this article . Moneygraph:
"... OPEC does not need to change its output deal since the group had already cut supply
by much more than it had agreed. What Zanganeh offered was for OPEC and Russia to pump back
up to decrease the current cuts to the initial 1.176 million barrels per day (bpd).
"Output in May 2018 was actually down by 1.9 million, somehow 62 percent or 724,000 bpd
more than what was agreed upon in 2016."
The upshot is an increase will occur but no increase will occur--understand? The
extraction amount agreed to in 2016 remains the amount OPEC will extract. There will be
no increase in that amount this year.
"... Houston, 11 June (Argus) Plains All American Pipeline, a prime mover of crude around and away from the Permian, reiterated last week that there is not enough trucking capacity to address skyrocketing production, and potential rail slots are limited. With most material pipeline capacity additions a year or more away, Plains said the logical solution is slowing output ..."
"... That's really kind of funny. The takeaway professionals have to tell them, "come on guys, put a brake on it. It can't be moved." Note, the article stated that the pipeline company said production is already slowing. Wonder if EIA will finally read the memo? Also, it may result in more little fish, being eaten by the bigger fish. ..."
"... The next 3 or 4 months for EF and Bakken might be interesting – they've both been steady or slightly declining with no pick up in drilling or, I think, permitting even as the price has risen, and the initial well production and ultimate recovery look to be declining on recent wells. If Permian is closed off I wonder if the operators will bother to move back to these. ..."
"... Yeah, I think they will. You just won't see growth just overnight from these areas, and the ones who had good areas in these, never left. EOG, Conoco and others are still doing their thing. Growth will mainly show up the first and second quarter of 2019. Maybe some the last quarter of 2018. My guess. It just won't ramp up like the Permian, EIA predicts a bunch, but they are smoking some strong stuff. They believe in teleportation of oil to the coast, and further teleportation to VLCCs off the coast. ..."
"... Wild guess on the 22nd. OPEC releases non-opec from the agreement. Increasing OPEC, at this point, will involve disintegration of OPEC, which it really is, anyway. But, a modest increase may hold them together for a little while. Although, for the Sauds part, I don't know why they would, except to keep up the illusion. ..."
That's really kind of funny. The takeaway professionals have to tell them, "come on guys,
put a brake on it. It can't be moved." Note, the article stated that the pipeline company
said production is already slowing. Wonder if EIA will finally read the memo? Also, it may
result in more little fish, being eaten by the bigger fish.
Energy News, you constantly amaze me with your finds of information. Everything is
extremely pertinent.
The next 3 or 4 months for EF and Bakken might be interesting – they've both been
steady or slightly declining with no pick up in drilling or, I think, permitting even as the
price has risen, and the initial well production and ultimate recovery look to be declining
on recent wells. If Permian is closed off I wonder if the operators will bother to move back
to these.
State of North Dakota came out with a new presentation a few weeks ago showing revised
predictions for Bakken oil output. They now have production likely reaching 1,900,000 BOPD
within the next decade while the best forecast offers better than 2,200,000 BOPD.
Yeah, I think they will. You just won't see growth just overnight from these areas, and
the ones who had good areas in these, never left. EOG, Conoco and others are still doing
their thing. Growth will mainly show up the first and second quarter of 2019. Maybe some the
last quarter of 2018. My guess. It just won't ramp up like the Permian, EIA predicts a bunch,
but they are smoking some strong stuff. They believe in teleportation of oil to the coast,
and further teleportation to VLCCs off the coast.
That not everyone believes the EIA is evident in the huge, many billions of dollars,
losses in stock value of the "Permian pure play" companies recently. EIAs and IEAs fairy
tales are coming unraveled. About the only section of the investment community that still
believes them, is that percentage of adults that still believe chocolate milk comes from
brown cows. What they are still unsure of, is how much excess capacity OPEC now has.
Wild guess on the 22nd. OPEC releases non-opec from the agreement. Increasing OPEC, at
this point, will involve disintegration of OPEC, which it really is, anyway. But, a modest
increase may hold them together for a little while. Although, for the Sauds part, I don't
know why they would, except to keep up the illusion.
There is a narrative that oil demand will soon begin dropping due to widespread use of EV.
1 million EV just replaces 14,000 BOPD of demand. Conservatively assuming those one
million EV require $40K per unit of CAPEX, just to replace 14,000 BOPD of demand took $40
billion of CAPEX.
Likewise, to replace 1.4 million BOPD of demand via EV would take $4 trillion of
CAPEX.
Worldwide demand has been growing somewhere between 1.2-2.0 million BOPD annually,
depending on who one believes.
See where I am going with this? How do the EV disruption proponents explain away the
massive CAPEX required just to cause oil demand to flatten, let alone render it near
obsolete?
The average US car gets 25 mpg and travels 12,500 miles per year for 500 gallons of gasoline
per year.
Refineries in the US produce 20 gallons of gasoline per barrel of oil.
That gives 69,000 BOPD per day reduction per million EV cars in the US and 110,000 BOPD oil
equivalent energy due to the multiple energies put into gasoline and distillate
production.
At current rates of EV sales growth the US will reach 50 million EV cars by 2031. That should
put he US to being mostly independent of external oil for gasoline by mid 2030's and
It's tough to predict a complete transition in the US since cars as a service could greatly
reduce the numbers of cars needed, especially in dense population areas. That would mean a
much earlier transition.
If US ICE cars trend upward in mpg during that time, the demand for oil could be quite low
by the early 2030's.
All depends on continuation of trends, for which the auto manufacturers seem to be on board.
Just have to get the public charging infrastructure out ahead of the trend.
Here is an interesting article, from a couple of years ago, showing the trend and sales at
that time.
Cars get replaced all the time and the cost of new EVs will fall over time to the same
price as ICEV, so it's simply a matter of replacing the ICEV currently sold with EVs over
time, in addition cars can get better gas mileage (50 MPG in a Prius vs 35 MPG in a Toyota
Corolla or 25 MPG in a Camry.) There's also plug in hybrids like the Honda Clarity (47 miles
batttery range) or Prius Prime(25 mile range on battery) these have an ICE for when the
battery is used up.
If oil prices rise in the short term to over $100/b (probably around 2022 to 2030), there
will be demand for other types of transport besides a pure ICEV.
EVs and plugin hybrids will become cheaper as manufacturing is scaled up due to economies
of scale.
Surprising stuff. Huge oil consumption growth rates in Eastern Europe. 8+% growth %s in
Poland, Czech Republic and Slovakia. Something weird going on because Romania and Slovenia
didn't show the same thing.
Western Africa grew consumption of oil 13% last year. I'll add a !!!!. East Africa about 6%.
Both are over 600K bpd, so that growth rate is not on tiny burn.
Poland's official oil consumption growth is caused by better fighting with illegal, and
unregistered fuel imports since mid 2016. When taxes are 50% of fuel price, there is big
incentive for illegal activities. Real oil consumption probably didn't increase much.
Poland, Czech and Slovakia are going through a huge economic boom now (I live in Slovakia and
party in Czech Republic). It's visible everywhere, there wasn't this much spending and
employment ever in the last 28 years
Oil demand is mostly determined by GDP growth, oil price has a minor influence on short term
demand. World GDP grew by about 5% from 2016 to 2017 according to the IMF, so oil demand
increased by 1.8% possibly less than one would expect. Real GDP (at market exchange rates)
grew by about 3% in 2017.
The idea behind peak demand is simply that oil supply may at some point become relatively
abundant relative to demand in the future (date unknown). When and if that occurs, OPEC may
become worried that their oil resources will never be used and will begin to fight for market
share by increasing production and driving down the price of oil to try to spur demand. That
is the theory, I think we are probably 20 to 40 years from reaching that point for
conventional oil.
Oil still contributes quite a bit to carbon emissions and while I agree coal use needs to
be reduced (as carbon emissions per unit of exergy is higher for coal than oil), I would
think it may be possible to work on reducing both coal and oil use at the same time. Using
electric rail combined with electric trucks, cars and busses could reduce quite a bit of
carbon emissions from land transport, ships and air transport may be more difficult.
It's better to sell half of your ressources for 90$ / barrel than all at 30$ / barrel.
The gulf states will always have cheap production costs at their side, they will earn more
at each price of oil. Why not make big money, especially when at lower production speed the
production costs are much lower (less expensive infrastructure).
And in the first case you can sell chemical feedstock for a few 100 years ongoing for a
good coin. Theocracies and Kingdoms plan sometimes for a long time. When you bail out
everything at sale prices, you end with nothing ( and even no profit).
You assume half the resource can be sold at $90/b, at some point in the future oil supply
may be greater than demand at a price of $90/b, so at $90/b no oil is sold and revenue is
zero.
In a situation of over supply there will be competition for customers and the supply will
fall to the point where supply and demand are matched. Under those conditions OPEC may decide
to drive higher cost producers out of business and take market share, oil price will fall to
the cost of the most expensive (marginal) barrel that satisfies World demand.
I don't think we are close to reaching this point, but perhaps by 2035 or 2040 alternative
transport may have ramped to the point where World demand for oil falls below World Supply of
oil at $90/b and the oil price will gradually drop to a level where supply and demand
match.
Older wells are declining at about 8% per year. A 25 BOPD well with a 10 BOPD economic limit
should have 70,000 barrels of oil left to produce in about 12 years.
Is it safe to assume that newer wells will behave the same as older wells?
Some petroleum engineers that have commented at shaleprofile.com (Enno Peters wonderful
resource) that the high level of extraction from newer wells will likely lead to a thinner
tail.
illustrates this, notice how the 2014 and 2015 wells fall below the 2010 well profile
after 24 months, the same is likely to occur for 2016 and later wells. Also note that the
2010 well profile is representative (close to the mean) for 2009 to 2012 average well
profiles.
Dennis, i would say the decline rate (8%) is very safe to use for all LTO wells, i would
definitely apply it after the 6th year of well life, because by then what counts is rock
quality and fluid type. This is only good for a bulk projection.
By the way I tweaked my price model when I was preparing my CO2 pathway. I took into
account the Venezuela crash, the difficulties the Canadians have moving their crude, etc. The
price projection is $88 per barrel Brent for evaluating projects which start spending in
2019. I also prepared a different look for very long term projects which start spending in
2023: $110 per barrel.
Don't forget these aren't prices predicted for those particular years. They are prices one
can use to evaluate long term projects such as exploring in the Kara Sea, offshore West
Africa deep water, the African rifts, Venezuela heavy oil developments, etc. These prices are
plugged in and escalated with inflation for the 20-30 year project period. Real prices should
oscillate back and forth around these values.
Norwegian crude oil & condensate production (without NGLs) at 1,321
kb/day in May, down -223 m/m, down -297 from 2017 average or -18%. The main reasons that
production in May was below forecast is maintenance work and technical problems on some
fields. http://www.npd.no/en/news/Production-figures/2018/May-2018/ Almost down to the Sept 2012 low at 1,310 kb/day
This is what happens when there are no sizeable new fields coming online for 1/2 year and as
G.Kaplan has mentioned not enough allocation for supply disruptions are included in the
forecast.
A brutal decline, even if this month is an anomaly as NPD say.
Looking at the field numbers (only through April) it looks like Troll Oil is in decline a bit
earlier and a bit steeper than expected. It's the biggest oil producer still bu has dropped
fairly consistently and slightly accelerating from 161 kbpd in October to 121 in April. It's
all horizontal wells and requires continuous drilling to maintain production, it's close to
exhaustion with only 10% remaining at the end of 2017 (about R/P of 3 years) and had been
holding a good plateau around 150 for a few years. The gas is due to be developed starting in
2021 so the oil rim would need to be depleted by then, but maybe dropping a bit sooner than
expected – is a reservoir not behaving as modelled a "technical problem"?
I don't know about the price as it depends on the demand side and the global economy looks to
me increasingly rocky, but the supply side analysis looks pretty good, except as you say a
bit conservative. One thing missing was consideration of increasing decline rates on mature
fields, especially offshore, partly a result of accelerating production in the high price
years and partly because of an increasing ratio for deep and ultra deep water. Additionally I
think the lack of increase in non-US drilling rigs as the price has risen is relevant and
partly represents a shortage of in-fill prospects and short cycle appraisals.
If they are relying on GoM to add the 300 kbpb (or more into 2020) that EIA are predicting
then I think they are going to be short by 400 to 500 kbpd for a 2020 exit rate.
(I don't follow the chart showing new OPEC developments, the numbers can't be number of
projects, probably kbpd added, or maybe mmbbls reserves, and I'm betting they've mixed in gas
with the oil.)
As in all these investment type analyses they don't look too far ahead and there's a kind
of tacit assumption that everything will be sorted out with more investment later on, but
five years of low discoveries and accelerated development of the good ones means there's
actually not that much new to invest in, and if there is then ExxonMobil will be looking to
buy it.
Yeah, demand is always a big question. Hard to measure, even in the rear view mirror.
However, their constant increase of 1.2 million barrels in the US over a three year period,
should offset any question of demand. While 1.2 in 2020 is something I can't predict, 1.2
million for 2018 and 2019 is impossible without increased pipelines long before the second
half of 2019. So, I think it is way conservative.
They say "We believe we are 6-9 months ahead of consensus with our oil forecast. Why is no
one else seeing what we see?." Obviously they haven't been reading POB for the last two
years.
POB made it possible to piece together in my own way, otherwise I would be like most. Staying
confused with constant conflicting info. Predicting price is virtually impossible, as is
demand to a large extent. But, when supply is ready to fall off a cliff, then being exact is
not required.
A simple way to think about C+C demand is to assume over the long run that supply and
demand will be roughly equal (though of course there will be short term imbalances which
changes in the oil price over the short term will try to correct). From 1982 to 2017 C+C
output grew at an average annual rate of about 800 kb/d. It is probably safe to assume that
oil demand will continue to grow at roughly that pace in the absence of a severe global
recession and those are pretty rare. I define a "severe global recession" as one where real
World GDP (constant prices) based on market exchange rates decreases over an annual cycle for
one or more years. Since 1900 there have been two cases where this occurred, the Great
Depression and the Global Financial Crisis (GFC) in 2008/2009. These have been on roughly a
60 to 70 year cycle (a previous crisis occurred in 1870, but this might have only been a US
crisis and possibly not a global one.)
In any case, my guess is that a Global economic crisis may result a the World tries to
adjust to declining (or stagnant) World Oil output after 2025, probably hitting around 2030
to 2035. If economists re-read Keynes General Theory and respond to the crisis with
appropriate policy recommendations, the economic crisis may be short lived. On the other hand
a World response similar to the European response to the GFC, where fiscal austerity is
considered the appropriate response to a lack of aggregate demand (this was also Herbert
Hoover's response to the 1929 Stock Crash), then a prolonged deep depression will be the
result.
The somewhat vast majority of countries say their reserves are flat in 2017 vs 2016. They
pumped billions of barrels, but no change to reserves for . . . lemme count . . . 36
countries (of which the US was one).
World as a whole reserves total declined 0.03%.
BP's flow report is "all liquids". Dunno if that is consumption, too. And if reserves . .
. reserves are in a footnote. Crude, Condensate AND NGLs. Probably excludes algae.
What? Me worry? Rystadt says US has 79 more years of oil still available. Of course, that
is the imaginary oil. They admit that commercially recoverable oil in the world only has 13
years left. Where did we pick up another 50 billion of imaginary oil in the US this year?
India's oil consumption growth was only 2.9%. Derives from their monetary debacle early in
the year. We should see signs of whether or not that corrects back to their much higher norm
before next year.
China consumption growth 4%. Higher than India. Clearly an aberration.
KSA consumption actually declined fractionally, which allows Japan to still be ahead of them
in consumption.
US consumption growth 1%. So much for EV silliness.
Oil production seems to have left its bumpy 6 year long (2010-2015) plateau of 8.4 mb/d and
is now back to 2004 levels of 7.9 mb/d, a decline of 6% over 2 years.
Base production is the sum of the minimum production levels in each country during the
period under consideration. Incremental production is the production above that base
production. In this way we clearly see that the peak was shaped by China, sitting on a
declining wedge of all other Asian countries together. Note that growing production in Thailand
and India could not stop that decline. Now let's look at the other side of the coin,
consumption:
There has been a relentless increase in consumption since the mid 80s. The growth rate after
the financial crisis in 2008 was an average of 3% pa.
Chinese annual oil consumption growth
rates have been quite variable between 2% and a whopping 16% in 2004 which contributed to high
oil prices. Fig 4 also shows there is little correlation between GDP growth and oil consumption
growth (statistical problems?). There is nothing in this graph that could tell us that the
Chinese economy has a consistent trend to become less dependent on oil. In the years since
2011, oil consumption growth was around 60% of GDP growth.
Let's compare China with the US. China's oil consumption is catching up fast with US
consumption.
On current trends, China's oil consumption would reach US consumption levels of 20 mb/d in
just 14 years.
Contrary to misinformation by the media, the US is still a net importer of oil. Even blind
Freddy can see that there will be intense competition for oil on global markets.
All governments who plan for perpetual growth in Asia (new freeways, road tunnels, airports
etc) should fill in the above graph. Hint: We can see that Asia has diversified its sources of
oil imports but is still utterly dependent on Middle East oil
"Other Middle East" is Iran
and Oman (as Syria and Yemen no longer export oil)
China is preparing for the future by building bases to secure oil supply routes:
Proven reserves have not changed much in the last years meaning that P2 and P3 reserves have
been proved up commensurate with production. The reserve to production ratio is 16.7 years
equivalent to an annual depletion rate of 6%, a little bit higher than a reasonable rate of 5%
(R/P of 20 years).
The depletion rates vary considerably and may only be approximate as oil
reserves will have been estimated by using differing methodology and accuracy. Indonesia's
depletion rate is very high. Not shown in Fig 14 is Thailand where the depletion rate is off
the charts (almost 50%) suggesting reserves are too low.
There are some rumors that KSA has increased exports starting in May (about 0.5 m b/d more
than prior months) by drawing even more from storage. If we are to believe OPEC production
numbers from May which are steady, that must be the case. OPEC has essentially flooded the
market with exports before the meeting on Friday. The nearest month Brent future changed to
contango compared to closest month some weeks ago, but it has now all changed again to
backwardation. Point being, it seems the physical market is getting tighter again and that
the export flood may have something to do with the meeting. Or it could be that reduced
exports from Iran, Venezuela and Libya are starting to impact the market.
If the market balance overall is to change from a a deficit to near balanced, production
within OPEC has to be increased with almost maximum of whatever spare capacity available in
my opinion. The assumption is that spare capacity in reality is smaller than stated by the
agencies.
"... The author is a prominent American social critic, blogger, and podcaster , and one of our all-time favorite pessimists. We carry his articles regularly on RI . His writing on Russia-gate has been highly entertaining. ..."
"... He is one of the better-known thinkers The New Yorker has dubbed 'The Dystopians' in an excellent 2009 profile , along with the brilliant Dmitry Orlov, another regular contributor to RI (archive) . These theorists believe that modern society is headed for a jarring and painful crack-up. ..."
"... You can find his popular fiction and novels on this subject, here . To get a sense of how entertaining he is, watch this 2004 TED talk about the cruel misery of American urban design - it is one of the most-viewed on TED. Here is a recent audio interview with him which gives a good overview of his work. ..."
"... If you like his work, please consider supporting him on Patreon . ..."
"... Quite the opposite of a dilettante, Kunstler has dug into the research on oil and related energy technologies, and is extremely well-informed, writing books on the subject. What he says implies a massive wealth transfer to Russia, Iran, and the Middle East, as the wells start to dry up. ..."
"Anyway, we're not going back to the Detroit of 1957. We'll be fortunate if we can turn out brooms and scythes twenty years from
now, let alone flying Teslas." 10 hours ago | 1,690
41 MORE:
Business The author is a prominent American
social critic, blogger, and podcaster , and one of our all-time favorite pessimists.
We carry his articles regularly on RI . His writing
on Russia-gate has been highly entertaining.
He is one of the better-known thinkers The New Yorker has dubbed 'The Dystopians' in
an excellent 2009 profile , along with
the brilliant Dmitry Orlov, another regular contributor to RI
(archive) . These theorists believe that modern society is headed for a jarring and painful crack-up.
If you like his work, please consider supporting him on
Patreon .
Quite the opposite of a dilettante, Kunstler has dug into the research on oil and related energy technologies, and is extremely
well-informed, writing books on the subject. What he says implies a massive wealth transfer to Russia, Iran, and the Middle East,
as the wells start to dry up.
The ill feeling among leaders of the G-7 nations -- essentially, the West plus Japan -- was mirrored early this morning in the
puking financial market futures, so odious, apparently, is the presence of America's Golden Golem of Greatness at the Quebec meet-up
of First World poobahs. It's hard to blame them. The GGG refuses to play nice in the sandbox of the old order.
Completely, totally, delusional
Like many observers here in the USA, I can't tell exactly whether Donald Trump is out of his mind or justifiably blowing up out-of-date
relationships and conventions in a world that is desperately seeking a new disposition of things. The West had a mighty good run
in the decades since the fiascos of the mid-20 th century. My guess is that we're witnessing a slow-burning panic over
the impossibility of maintaining the enviable standard of living we've all enjoyed.
All the jabber is about trade and obstacles to trade, but the real action probably emanates from the energy sector, especially
oil. The G-7 nations are nothing without it, and the supply is getting sketchy at the margins in a way that probably and rightfully
scares them. I'd suppose, for instance, that the recent run-up in oil prices from $40-a-barrel to nearly $80 has had the usual effect
of dampening economic activity worldwide. For some odd reason, the media doesn't pay attention to any of that. But it's become virtually
an axiom that oil over $75-a-barrel smashes economies while oil under $75-a-barrel crushes oil companies.
Mr. Trump probably believes that the USA is in the catbird seat with oil because of the so-called "shale oil miracle." If so,
he is no more deluded than the rest of his fellow citizens, including government officials and journalists, who have failed to notice
that the economics of shale oil don't pencil out -- or are afraid to say.
The oil companies are not making a red cent at it, despite the record-breaking production numbers that recently exceeded the previous
all-time-peak set in 1970. The public believes that we're "energy independent" now, which is simply not true because we still import
way more oil than we export: 10.7 million barrels incoming versus 7.1 million barrels a week outgoing (US EIA).
Shale oil is not a miracle so much as a spectacular stunt: how to leverage cheap debt for a short-term bump in resource extraction
at the expense of a future that will surely be starved for oil. Now that the world is having major problems with excessive debt,
it is also going to have major problems with oil.
The quarrels over trade arise from this unacknowledged predicament: there will be less of everything that the economically hyper-developed
nations want and need, including capital. So, what's shaping up is a fight over the table scraps of the banquet that is shutting
down.
That quandary is surely enough to make powerful nations very nervous. It may also prompt them to actions and outcomes that were
previously unthinkable. At the moment the excessive debt threatens to blow up the European Union, which is liable to be a much bigger
problem for the EU than anything Trump is up to. It has been an admirably stable era for Europe and Japan, and I suppose the Boomers
and X gens don't really remember a time not so long ago when Europe was a cauldron of tribal hatreds and stupendous violence, with
Japan marching all over East Asia, wrecking things.
There is also surprisingly little critical commentary on the notion that Mr. Trump is seeking to "re-industrialize" America. It's
perhaps an understandable wish to return to the magical prosperity of yesteryear. But things have changed. And if wishes were fishes,
the state of the earth's oceans is chastening to enough to give you the heebie-jeebies. Anyway, we're not going back to the Detroit
of 1957. We'll be fortunate if we can turn out brooms and scythes twenty years from now, let alone flying Teslas.
This will be the summer of discontent for the West especially. The fact that populism is still a rising force among these nations
is a clue of broad public skepticism about maintaining the current order. No wonder the massive bureaucracies vested in that order
are freaking out.
I'm not sure Mr. Trump even knows or appreciates just how he represents these dangerous dynamics.
Sand is not a problem. The real question is how much oil is consumed getting this amount od
sand to their designation. 91,000 truckloads of frac sand using, on average say 5 miles per
gallon and 100 miles each way (200 miles roundtrip) would be 3,5 million gallons of fuel per
month. That means that one day a month is essentially lost to sand transportation costs.
The U.S. Shale Oil Industry utilizes a stunning amount of equipment and consumes a massive
amount of materials to produce more than half of the country's oil production. One of the vital
materials used in the production of shale oil is frac sand. The amount of frac sand used in the
shale oil business has skyrocketed by more than 10 times since the industry took off in
2007.
According to the data by
Rockproducts.com and
IHS Markit , frac sand consumption by the U.S. shale oil and gas industry increased from 10
billion pounds a year in 2007 to over 120 billion pounds in 2017. This year, frac sand
consumption is forecasted to climb to over 135 billion pounds, with the country's largest shale
field, the Permian, accounting for 37% of the total at 50 billion pounds.
Now, 50 billion pounds of frac sand in the Permian is an enormous amount when we compare it
to the total 10 billion pounds consumed by the entire shale oil and gas industry in 2007.
(charts courtesy of the EIA - U.S. Energy Information Agency)
As we can see in the graph above, the Permian Region is the largest shale oil field in the
United States with over 3 million barrels per day (mbd) of production compared to 1.7 mbd in
the Eagle Ford, 1.2 mbd at the Bakken and nearly 600,000 barrels per day in the Niobrara.
However, only about 2 mbd of the Permian's total production is from horizontal shale oil
fracking. The remainder is from conventional oil production.
Now, to produce shale oil or gas, the shale drillers pump down the horizontal oil well a
mixture of water, frac sand, and chemicals to release the oil and gas. You can see this process
in the video below (example used for shale gas extraction):
The Permian Region, being the largest shale oil field in the United States, it consumes the
most frac sand. According to BlackMountainSand.com Infographic , the
Permian will consume 68,500 tons of frac sand a day, enough to fill 600 railcars . This equals
50 billion pounds of frac sand a year. And, that figure is forecasted to increase every
year.
Now, if we calculate the number of truckloads it takes to transport this frac sand to the
Permian shale oil wells, it's truly a staggering figure. While estimates vary, I used 45,000
pounds of frac sand per sem-tractor load. By dividing 50 billion pounds of frac sand by 45,000
pounds per truckload, we arrive at the following figures in the chart below:
Each month, over 91,000 truckloads of frac sand will be delivered to the Permian shale oil
wells. However, by the end of 2018, over 1.1 million truckloads of frac sand will be used to
produce the Permian's shale oil and gas . I don't believe investors realize just how much 1.1
million truckloads represents until we compare it to the largest retailer in the United
States.
According to Walmart, their drivers travel approximately 700 million miles per year to
deliver products from the 160 distribution centers to thousands of stores across the country.
From the information, I obtained at MWPWL International on Walmart's distribution
supply chain, the average one-way distance to its Walmart stores is about 130 miles. By
dividing the annual 700 million miles traveled by Walmart drivers by the average 130-mile trip,
the company will utilize approximately 5.5 million truckloads to deliver its products to all of
its stores in 2018.
The following chart compares the annual amount of Walmart's truckloads to frac sand
delivered in the Permian for 2018:
To provide the frac sand to produce shale oil and gas in the Permian this year, it will take
1.1 million truckloads or 20% of the truckloads to supply all the Walmart stores in the United
States. Over 140 million Americans visit Walmart (store or online) every week. However, the
Industry estimates that the Permian's frac sand consumption will jump from 50 billion pounds
this year to 119 billion pounds by 2022. Which means, the Permian will be utilizing 2.6 million
truckloads to deliver frac sand by 2022, or nearly 50% of Walmart's supply chain :
This is an insane number of truckloads just to deliver sand to produce shale oil and gas in
the Permian. Unfortunately, I don't believe the Permian will be consuming this much frac sand
by 2022. As I have stated in several articles and interviews, I see a massive deflationary
spiral taking place in the markets over the next 2-4 years. This will cause the oil price to
fall back much lower, possibly to $30 once again. Thus, drilling activity will collapse in the
shale oil and gas industry, reducing the need for frac sand.
Regardless, I wanted to show the tremendous amount of frac sand that is consumed in the
largest shale oil field in the United States. I calculated that for every gallon of oil
produced in the Permian in 2018, it would need about one pound of frac sand. But, this does not
include all the other materials, such as steel pipe, cement, water, chemicals, etc.
For example, the Permian is estimated to use 71 billion gallons of water to produce oil this
year. Thus, the fracking crews will be pumping down more than 1.5 gallons of water for each
gallon of oil they extract in 2018. So, the shale industry is consuming a larger volume of
water and sand to just produce a smaller quantity of uneconomic shale oil in the Permian .
Lastly, I have provided information in several articles and videos explaining why I believe
the U.S. Shale Oil Industry is a Ponzi Scheme. From my analysis, I see the disintegration of
the U.S. shale oil industry to start to take place within the next 1-3 years. Once the market
realizes it has been investing in a $250+ billion Shale Oil Ponzi Scheme, the impact on the
U.S. economy and financial system will be quite devastating.
Check back for new articles and updates at the SRSrocco Report .
Sand, a material so abundant, you could not give it away, but now, it has worth, thanks
frackers. His article a week or so back was claiming that all the sand had to be shipped out
of michigan, a blatant lie, or perhaps he really is just that ignorant.
A fellow in west texas bought some sparse land a few years back for about $40,000, it was
10's of acres. He was offered $13,000,000 recently, which he lept at. then he found out the
people that bought it from him, flipped it to a sand company for $200,000,000. Now he wants
to sue.
the point being that technology can make formally useless things, worth more. This is the
fundamental reason that economies grow. Knowledge adds value, making the pie larger for
everyone.
Oil may be a ponzi scheme, who knows, if a trade war crashes the global economies and
energy usage plummets by 20-50%, I would expect the deflationary environment he is talking
about. On the other hand if that does not happen, and oil goes to $100 or $200 then we will
hear a bunch of whining, but everything will keep chugging along.
and if graphene filters allow for the energy efficient filtration of salts from produced
water, and those salts are then processed for the elements such as lithium found in them, and
produced water becomes net profit stream instead of a net cost stream, then the whole
equation changes, technology adding value.
A lot of if's, that is what makes the future interesting.
you are an idiot...all sand is not the same. sand runs the gamut of smooth and round to
rough course edged. sand isnt that easy to find when you have to have a particular kind of
sand.....
Permium 1.1 million truckloads per day and + 71 billion gallons of water per year!
People in North America will be in serious need of fresh water soon, however, with
fracking spoiling water nationally and the combined effect of increased earth
tremors/potholes in vast areas, well mother nature is calling in the cards.
Combine that with GM food hidden in most products plus the millions of pharmaceutical
lovers, poisoning their own water supplies and effecting most native species and perhaps a
little radiation from Nukes and the Sun and the cell towers and a few miles of chem trails i
don't give much hope for a sustainable North American future.
I was just telling the second head growing out of my back, the other day, 'man this is the
best it has ever been', and he said ' groik splish!' and bit me on the arm. So I would say we
are of two minds on the matter.
You can make fresh water from sea water for about $2000 per acre foot using expensive
california power. I think that comes to $60 per month for a family of 4 using the fairly high
rate of water consumption by california residents.
(desalination plants already exist in Santa Barbara and San Diego, CA and there are desal
plants all over the world)
80 gallons per day * 4 people * 365 days / 330000 gallons * $2000 / 12 months = $60
An acre foot of water is about 330,000 US gallons.
Reverse osmosis in the home runs about $75 per year and cleans up most of the
problems.
Now what about the cost of distributing that? See that the thing about getting water the
old fashioned ways. Water actually cost nothing to make. The cost is building a system to
distribute the free water. It also come with gravity assist moving water from high to low.
That way you use natural property of water to flow from high places to lower ones. Now in
your system you take sea water and have to move that up from sea level. That cost is addition
to cost of converting sea water to fresh water.
Maybe we could substitute illegal aliens, or Obama-ites convicted of felonies for much of
the frac-sand?
Think of how much money that would save vs incarceration costs!
If we moved up to insane Liberal idiots who were about to explode anyway because their
Liberal world is crashing down, we'd further save the environment from all the silly electric
cars they drive. Its a win-win!
Thanks for pointing out alternatives we never thought of before!
Art presentation raises numerous points that are worth mulling over and at least considering.
According to Art: Eagle Ford production growth is unlikely and that reserves should be exhausted at current production rates
in ~7 years. While Permian production growth is likely, reserves will be exhausted in ~4 years.
Petroleum Age after WWII produced unprecedented economic growth.
Oil shocks of 1974-1986 threatened to end that party.
Demand destruction & oil production bubble resulted in 18 years of cheap energy.
Debt re-started economic growth & debt-based growth of China challenged oil supply
after 2004.
Second oil shock made unconventional oil possible. Zero-interest rates led to 2 nd oil
bubble.
Longest period of high oil prices in history.
That bubble burst in 2014 and oil prices collapsed but without demand destruction.
Now, we are near the end of long-term debt cycle but in denial that the economic basics
have fundamentally changed since the post-war era.
SLIDE 5: Low Interest Rates Created A Capital Bubble For Tight Oil & The Permian
Basin
The oil-price collapse coincided with the end of QE 3 and the beginning of U.S. interest
rate increases.
Continued low interest rates caused margin hunters to focus first on tight oil and then,
specifically on the Permian basin.
$30 oil prices brought large capital flows to a select group of producers seen as
winners.
Tight oil and Permian rig counts have more than doubled since August 2016. Rig
countsincrease with expectation of $55+ oil prices
Increased rig count and fear of ongoing over-supply is a major drag on oil prices.
OPEC production cuts have balanced oil markets since early 2017 & some are now
questioning the lower-for-longer paradigm that dominated the last 3 years.
SLIDE 6: The False Premise that Tight Oil Plays Are the New Swing Producer
No factual support for widespread belief that there is a price war between OPEC &
U.S. tight oil.
OPEC/Saudi Arabia reacted pragmatically to price collapse & recovery.
Prime directive not to repeat mistake of 1982-1986 production cuts.
"Just-in-time production" is another baseless theory.
Shale output reacts to price just like all plays -- slowly & in long-period
cycles.
Idea that U.S. shale is the new swing producer of the world also has no basis.
Being a swing producer means that there is sufficient spare capacity to turn on and off
based on market signals. Shale plays have no spare capacity (they are just-in-time).
Even if DUCs provide some spare capacity, there is no decision-making process that
governs 1000s of independent producers.
SLIDE 7: Shale Cost Reductions 90% Industry Bust, 10% Innovation and Efficiency
Lower costs of shale production widely attributed to technology and efficiency.
Price deflation accounts for 90% of lower costs because of a depression in the oil
industry; 10% is because of technology & efficiency.
That is over for now and prices increased 8% in 2017.
Shale growth has more to do with outside capital supply than break-even prices.
Investors need to believe that significantly higher prices are coming.
"Buy low, sell high" not a sophisticated concept but was responsible for capital flow
into tight oil after price bottom in early 2016.
Smart money has always believed in limits to oil supply.
That will drive the next inflow of capital as markets understand the limits of tight oil
supply.
SLIDE 8: Two of the Largest Tight Oil Plays are in Texas: Eagle Ford & Permian
The Eagle Ford Shale play is expected to recover to 1.3 mmb/d by 2022 & then decline to 1.2 mmb/d by 2050.
The Permian basin plays are anticipated to grow from 2.2 mmb/d in 2018 to more than 3.5 mmb/d by 2044 & then
decline to 3.4 mmb/d by 2050.
Geologist Arthur Berman, who has been skeptical about the shale boom,
warned on Thursday that the Permian's best years are gone and that the most productive U.S.
shale play has just seven years of proven oil reserves left.
"The best years are behind us," Bloomberg quoted Berman as saying at the Texas Energy
Council's annual gathering in Dallas.
The Eagle Ford is not looking good, either, according to Berman, who is now working as an
industry consultant, and whose pessimistic outlook is based on analyses of data about reserves
and production from more than a dozen prominent U.S. shale companies.
"The growth is done," he said at the gathering.
Those who think that the U.S. shale production could add significant crude oil supply to the
global market are in for a disappointment, according to Berman.
"The reserves are respectable but they ain't great and ain't going to save the world,"
Bloomberg quoted Berman as saying.
Yet, Berman has not sold the EOG Resources stock that he has inherited from his father
"because they're a pretty good company."
The short-term drilling productivity outlook by the EIA estimates that the Permian's oil
production hit 3.110 million bpd in April, and will rise by 73,000 bpd to 3.183
million bpd in May.
Earlier this week, the EIA raised its forecast for total U.S. production
this year and next. In the latest Short-Term Energy Outlook (STEO), the EIA said that it
expects U.S. crude oil production to average 10.7 million bpd in 2018, up from 9.4 million bpd
in 2017, and to average 11.9 million bpd in 2019, which is 400,000 bpd higher than forecast in
the April STEO. In the current outlook, the EIA forecasts U.S. crude oil production will end
2019 at more than 12 million bpd.
Yet, production is starting to outpace takeaway capacity in the Permian, creating
bottlenecks that could slow down the growth pace.
Drillers may soon start to test the Permian region's geological limits, Wood Mackenzie has
warned. And if E&P companies can't overcome the geological constraints with tech
breakthroughs, WoodMac has warned that Permian production could
peak in 2021 , putting more than 1.5 million bpd of future production in question, and
potentially significantly influencing oil prices.
The takeaway bottlenecks have hit WTI crude oil priced in Midland, Texas, which declined
sharply compared with Brent in April, the EIA said in the May STEO.
" As production grows beyond the capacity of existing pipeline infrastructure, producers
must use more expensive forms of transportation, including rail and trucks. As a result, WTI
Midland price spreads widened to the largest discount to Brent since 2014. The WTI Midland
differential to Brent settled at -$17.69/b on May 3, which represents a widening of $9.76/b
since April 2," the EIA said.
"... By Gary North, Oilprice.com's South-East Asia & Pacific correspondent. He writes about energy matters, geopolitics and international financial markets. Originally published at OilPrice ..."
"... A more conservative rate of growth may simply be desired by some, but it also may be an inevitability. Kevin Holt, chief investment officer of Invesco's U.S. value equities has said that the situation many companies find themselves in is in part a consequence of the link between their leaders' pay and production growth, rather than returns on investment. ..."
"... Ultimately the market is subject to myriad pressures, such as the heterogeneous quality of oil, fluctuations in labor costs and oil prices, as well as changes in the pace of technological development. These pressures shape the nature of the market, and also make it difficult to predict the longevity of tight oil reserves, and the ability of companies to exploit them. Another significant factor is regulation. How long will Trump's EPA remain the castrated shadow of its former self, and how long until it begins to bare its own teeth? ..."
"... The US might produce 11 million bpd of oil and condensates, but it still consumes nearly 20 million bpd. So, while the US might become a large exporter, it will be a large net importer. I don't see how shale or fantasy oil fields offshore Florida or in the ANWR will add 21 million bdp of production which would allow the US to be a net 12 million exporter. And by 2023? This must have been a typo. ..."
"... "The US might produce 11 million bpd of oil and condensates, but it still consumes nearly 20 million bpd." Exactly. The US is going to be a net exporter .and a net importer . of the same thing. And people accept this. We are leaving the Orwellian Age behind, and entering the Age of Insanity. ..."
"... Has anybody worked out how many years it will be until those particular shale formations have been sucked dry? The article mentioned that some formations had already been run dry. This somehow smacks to me of trying to keep the age of cheap oil going a little bit longer. ..."
"... Yes, most of the increase in oil comes from oil shale. Unlike a conventional oil well, shale extraction means a constant process of fracking (driving a hydraulic fluid into the geology to release light oil and gas trapped in the rock pores), so its much harder to assess the long term viability of a reserve than with a conventional well, which is usually an oil filled underground void with a measurable capacity. The typical production life of a single 'frack' is around 9 months or so, although a single well can be fracked multiple times if the geology is right. ..."
"... Ditto Genscape.com regarding overall supply-demand factors. Not a subscriber nor do I regularly follow sector developments, but big inventory drawdowns at Cushing, OK terminal over the past four months are puzzling in the face of rising EIA oil production data. ..."
"... Slow us expansion and the next recession, which might rival the last one because private sector debt, will push price sub 40. But majors have cut back exploration for some time, OPEC and Russia maybe in decline, and conversion to electrical cars minimal I'm guessing new price record in five years. ..."
"... The weird thing about shale is it unites the power of the financial lobby who finance the drilling with the power of the oil barons who control the market – that gives it 'umph' in the capitalist world. ..."
Yves here. The US seems overeager to be exceptional.
By Gary North, Oilprice.com's South-East Asia & Pacific correspondent. He writes
about energy matters, geopolitics and international financial markets. Originally published at
OilPrice
U.S. shale has effectively upended the oil industry, with
predictions that total U.S. oil production will surpass Saudi Arabia's output this year, in
turn rivalling Russia's to become the preeminent global producer. From its position of being
dependent on, and subordinate to OPEC, the U.S. has seemingly become the big bad wolf. Through
a catalogue of tactical errors and misplaced belief in its own muscle, the mighty brick edifice
of OPEC has begun to look more like a bundle of sticks.
The International Energy Agency (IEA) forecasts that the U.S. will become a net energy exporter by
the late 2020s, but how accurate is that forecast, and to what extent is it mere hyperbole? In
October last year there were already caveats
about the nature of U.S. shale, with some warning that aggressive expansion was leading to
rapid initial growth that would ultimately peak too soon. Mark Papa, former head of EOG
Resources (NYSE: EOG)
raised the question of flatlining output in the face of the doubling of the oil rig count,
"(h)ow can a rig count be double and yet production be stagnant?"
Figures have also been influenced by the
rapid pace of technological development, a pace which has itself plateaued. Robert Clarke,
WoodMac research director for Lower 48 upstream,
said that "(i)f future wells are not offset by continued technology evolution, the Permian
may peak in 2021". IEA forecasts then, may be based on rapid growth and technological
development that simply isn't sustainable. Related:
Shell Outsmarts Competition In The Gulf Of Mexico
Is U.S. shale just a sheep in wolf's clothing, its bite ultimately as benign as grandma's?
The IEA is
still forecasting that the U.S. will be the number one oil exporter by 2023 at 12.1 million
bpd, but at the CERAWeek Conference in Houston on Tuesday, Papa is set to turn that thinking on
its head when he warns the industry that shale will hit roadblocks that prevent such forecasts
from being realized. He
says the best drilling locations in North Dakota and South Texas are already tapped out.
"The oil market is in a state of misdirection now," Papa told the WSJ. "Someone needs to speak
out."
How much of this is indeed misdirection on his part? Papa is CEO at Centennial Resource
Development (NASDAQ: CDEV), which holds the rights to 77,000 acres in the oil-rich Delaware
sub-basin of the Permian. A slowdown in expansion and its potential consequence of increased
oil prices is advantageous to Centennial's shareholders, so who are we to believe guilty of
misdirection?
A more conservative rate of growth may simply be desired by some, but it also may be an
inevitability. Kevin Holt, chief investment officer of Invesco's U.S. value equities has said
that the situation many companies find themselves in is in part a consequence of the link
between their leaders' pay and production growth, rather than returns on investment. This
has fostered a drilling frenzy that has resulted in an explosion of production – an
unregulated drilling frenzy that may be at odds with the long term survival of those companies.
Investors have subsequently demanded a more conservative approach to drilling, which appears to
be having a stabilizing effect.
Ultimately the market is subject to myriad pressures, such as the heterogeneous quality
of oil, fluctuations in labor costs and oil prices, as well as changes in the pace of
technological development. These pressures shape the nature of the market, and also make it
difficult to predict the longevity of tight oil reserves, and the ability of companies to
exploit them. Another significant factor is regulation. How long will Trump's EPA remain the
castrated shadow of its former self, and how long until it begins to bare its own
teeth?
Is Papa's anticipated warning about to shake up the industry? Or is it merely the
continuation of the chorus of restraint that many in the industry have been voicing in this
period of massive growth and upheaval? Ultimately the industry will decide whether it will be
eating out of Papa's hand, or persist in biting the hand that feeds it.
The US might produce 11 million bpd of oil and condensates, but it still consumes nearly
20 million bpd. So, while the US might become a large exporter, it will be a large net
importer. I don't see how shale or fantasy oil fields offshore Florida or in the ANWR will
add 21 million bdp of production which would allow the US to be a net 12 million exporter.
And by 2023? This must have been a typo.
In any case, without a major transition away from internal combustion engines and heating
oil, the US will not be a net export any time soon.
As for shale, while the technology is improving, the rig counts show the true story. US
production is not expanding in line with rigs, nowhere near it. Shale is not Ghawar and never
will be.
"The US might produce 11 million bpd of oil and condensates, but it still consumes nearly
20 million bpd." Exactly. The US is going to be a net exporter .and a net importer . of the same thing. And people accept this. We are leaving the Orwellian Age behind, and entering the Age of
Insanity.
I'm probably going to get smacked down on this but all the oil that the US is pushing out
comes from those shale formations, don't they? But they are not like oil wells which you can
keep pumping for decades but are more about sucking all the loose stuff that you can out of
geological formations. And they deplete – rapidly!
Has anybody worked out how many years it will be until those particular shale formations have
been sucked dry? The article mentioned that some formations had already been run dry. This
somehow smacks to me of trying to keep the age of cheap oil going a little bit longer.
Yes, most of the increase in oil comes from oil shale. Unlike a conventional oil well,
shale extraction means a constant process of fracking (driving a hydraulic fluid into the
geology to release light oil and gas trapped in the rock pores), so its much harder to assess
the long term viability of a reserve than with a conventional well, which is usually an oil
filled underground void with a measurable capacity. The typical production life of a single
'frack' is around 9 months or so, although a single well can be fracked multiple times if the
geology is right.
If you google the geologist Arthur Berman, you'll find many of his articles on the topic.
He's long been something of a fly in the ointment for the trade, as he has argued that
extrapolations based on early explorations are likely to be too optimistic, as the industry
is aiming for 'sweet spots', which will provide very good flows, but not a good indication of
longer term potential. He has also pointed out (which is not denied in the industry), that
unless new technologies are developed, the 'drop off' from peak production will be a much
sharper decline than from a conventional oil field, as there will come a point where repeated
fracking is not economically viable.
So nobody ultimately really knows – if you believe the industry, better and cheaper
techniques will allow fracking to extend outwards from known sweet spots to extend over the
truly vast expanse of oil and gas shales that run from Texas up to Pennsylvania and New York
state. The pessimists (who tend to include most oil geologists) say that the extractable oil
is already getting worked, and the point of unviability will come very quickly, and there
will be a very rapid drop-off. Only time will tell.
Another point worth making is that oil is not as fungible a product as is often assumed.
Shale oil is known as 'tight oil – its very light, but there are only very limited
numbers of refineries that can deal with it. This is why it goes hand in hand with the use of
heavier grades to mix in, so it can be refined in existing facilities which are designed
usually for Gulf of Mexico or Alaskan crudes. This oil is mostly Venezuelan heavy crude or
Canadian oil sands product. So there is a sort of dance going on between these products to
ensure tight oils viability. Its notable that so far as I've seen, nobody seems willing to
invest in tight oil refineries, which to me suggests the industry is not optimistic about its
long term potential.
Another point worth making is that oil is not as fungible a product as is often
assumed
Very true. Refineries have to be "tuned" for a specif type of oil. Most refineries can
only process oil from a single origin, and change of origin requires expensive, slow changes,
made reluctantly.
Why reluctant to change? Construction in refineries is dangerous.
Yup. Fracking means scraping the dregs out of spent fields.
Permian Basin(which I've seen touted as the "new saudi arabia", lately) peaked in like 72 or
73.
all over that part of texas are rusty pumpjacks, idle until the oil price gets rather
high(Bush Darkness, they started running again)
These are marginal wells, at best, without extraordinary measures(like fracking what they
used to call bottle-brushing*).
Oil is finite which means that at some point it will no longer be worth it to get it out of
the ground(EROEI).
Ergo, these big plays that will "make us energy independent" are flashes in the pan.
(* my dad used to fish with a guy who did bottle brushing for saudi aramco, circa late
80's, apparently a rare skill at the time. he said back then that they were gonna run out,
because you don't do that to healthy(sic) fields. )
https://peakprosperity.com has
been behind shale oil production issues for the last decade and has published blogs /
podcasts, interviewed experts, etc
Some articles are behind a paywall, but it is a very good source
Ditto Genscape.com regarding overall supply-demand factors. Not a subscriber nor do I
regularly follow sector developments, but big inventory drawdowns at Cushing, OK terminal
over the past four months are puzzling in the face of rising EIA oil production data.
Exports?
Read that OPEC representatives are meeting with US in Houston this week.
Slow us expansion and the next recession, which might rival the last one because private
sector debt, will push price sub 40.
But majors have cut back exploration for some time, OPEC and Russia maybe in decline, and
conversion to electrical cars minimal I'm guessing new price record in five years.
The weird thing about shale is it unites the power of the financial lobby who finance the
drilling with the power of the oil barons who control the market – that gives it 'umph'
in the capitalist world.
My particular fear for America is that the entire country except the east and west coasts
are approved for fracking. An important part of national food production comes from states
like Kansas which use aquifer water entirely. If the farmers pump oil-flavored water on their
fields it will have an effect on the harvests. In profiting one way, the country sustains a
loss in another.
What Is The Right Price For Oil In A Balanced Market?
By
Dan Steffens
-
Feb 21, 2018, 6:00 PM CST
The price of oil is well off the low for this cycle because the OPEC + Russia plan to rebalance supply &
demand has worked. Now the question is
"What is the Right Price for oil in a balanced market?"
(Click to enlarge)
The price of
West Texas Intermediate (WTI)
crude oil, like the stock market, was
overdue for a bit of a pullback or "correction". After peaking at over $66/bbl on January 26, 2018 the
front month NYMEX contract for WTI followed the stock market correction down to just above $59/bbl on
February 13. By the close on February 16 it had rebounded back to $61.55/bbl. The fact that a key
resistance level at $57.65 was not tested during the selloff is encouraging.
WTI has been moving in a strong upward channel since last summer. Right now there is strong support at
$57.65 and strong resistance at $66.70. A close above $67.00 should set up a test of $75.00 sometime in
the 3rd quarter. At least that's what the "tea leaves" are telling me.
In my opinion, there are several "myths" or "false paradigms" that are holding down the price of oil.
Myth #1: U.S. Tight Oil production can meet the world's future demand for oil.
U.S. oil production is on the rise. There is no doubt that vast improvements in horizontal drilling
technology and completion methods have made harvesting oil from shale and other tight zones possible.
U.S. oil production now exceeds 10,000,000 barrels per day; a level no one in the industry believed was
possible at the turn of the century. However, U.S. tight oil production is still only 5% of the global
oil supply. It is highly unlikely that U.S. oil production will be able to ever meet U.S. demand
(currently over 17,000,000 barrels per day), much less supply the rest of the world.
Myth #2: All Shale Leasehold is the same.
The Permian Basin covers 19 million acres, however only a small percentage of the leasehold is
considered "Tier One" for shale oil recovery. Upstream companies are rapidly drilling up their best
acreage, a process called "High Grading". Once they have drilled out the Tier One locations, it will be
extremely difficult to maintain the pace of production growth that we have seen recently.
Adding to the problem is the fact that horizontal wells are completed with massive frac jobs, which
enable the wells to have very strong initial production rates. Initial production ("IP") rates are
unsustainable. After the initial surge, production declines rapidly in all horizontal wells. In most
areas, production declines by more than 50% from the IP rate within a year. After three years, most
horizontal shale wells are producing less than 10% of their "IP Rate".
Related: The U.S. Oil Industry Sets Its Sights On Asia
From a well-level economic standpoint this is great since the wells payout quickly. However, we now
have 100s of thousands of high decline rate horizontal wells online and another 20,000 new shale wells
will be completed this year. Soon after the Tier One areas are developed, it will be mathematically
impossible to drill enough Tier Two wells to maintain production growth. Most people that I talk to think
the Bakken Shale and the Eagle Ford Shale have already seen their peak production.
Myth #3: All oil is the same.
This is really more of a common misunderstanding than a
myth. The oil being extracted from shale and other tight formations has very high API gravity (over 40
degrees). To a point this was good news, but now we are producing so much "Light Oil" that our refineries
cannot handle all of it. This is one reason that the U.S. is now exporting more oil and why Brent oil
trades at about a $4.00/bbl premium to WTI. Per the most recent U.S. Energy Information Administration's
("EIA") weekly report, over the last six weeks ending February 9, 2018 the U.S.:
• Produced 9,926,800 barrels of crude oil per day
• Imported 7,976,500 barrels of crude oil per day (mostly heavy oil)
• Exported 1,341,500 barrels of crude oil per day (all light oil)
• Exported 4,885,000 barrels of refined products per day
I am expecting the problem of too much light oil production to get more press coverage this summer
because (a) it takes more crude oil to produce summer blend gasolines & diesel and (b) there is a limit
to how much light oil we can export.
Myth #4: We no longer need conventional exploration.
You could argue that this is the same as Myth #1. The thinking among investors is why waste capital on
exploration in remote areas or on high risk drilling like deep water prospects when shale can produce all
the oil we will ever need? The truth is that Non-OPEC / Non-U.S. oil accounts for over 45% of this
world's crude oil supply and it is now at risk of going on steady decline because so little capital has
been deployed in these "Other Areas". With demand for oil now increasing by 1.5 to 2.0 million barrels
per day year-after-year, we are going to need lots of new supply outside of the shales.
Myth #5: OPEC and Russia can flood the market with oil whenever they feel like it.
• First of all it would be incredibly stupid for the cartel members to over produce again since they
were the ones that suffered the most during the recent oil price collapse.
• Second, OPEC may actually have very little production capacity beyond what they are producing today.
In the International Energy Agency's most recent "
Oil
Market Report
" that was published on February 13, 2018 it was reported that OPEC members were 137% in
compliance with their production agreement and the Russian lead Non-OPEC group was 85% in compliance with
their agreement. In my opinion, the real reason that OPEC is holding down production is because they
can't produce much more oil than they are producing today. Regardless of the reason, this one is a fear
that should not keep investors up at night.
Related: Frac Sand Shortage Threatens Shale Boom
If you're considering investing in the Saudi Aramco IPO later this year, you may want to think about
the paragrap:above.
One of my friends with decades of oil & gas industry experience sent me this note: "I attended an
energy conference in Houston last year and the speaker from Tudor Pickering Holt & Co. (a highly
respected energy investment & banking firm) made this comment:"
"When oil was over $100/bbl, did any new production come on in OPEC or Russia? The only area that saw
a significant increase in oil production was North America. No other geologic province increased
production. That tells you that if it were there, it would have been brought on to produce during a
period of $100 + oil. It is the belief of TPH that any production outside of North America and big
offshore projects requiring years to develop do not exist".
I'm sure there are many industry experts that believe there are massive recoverable oil reserves out
there, but TPH's comment does give one pause.
Myth #6: Electric Vehicles and Renewables will soon slow oil consumption.
There is no evidence that this is going to happen anytime soon. The "Millennials", defined as persons
reaching adulthood in the early 21st century, have been brainwashed to believe we'd be better off without
hydrocarbon based fuels and feedstock. Nothing could be further from the truth, but that is a subject for
another time. Millennials believe that all educated people will be driving electric cars within a few
years. They never pause to think about where all the rechargeable battery materials will come from or the
massive changes that will be required to the power grid.
If you are over 30, you may recall that biofuels were going to cause oil demand to go down. It never
happened.
We are going to see more electric vehicles in the future, but they won't make a dent in gasoline and
diesel demand for at least another decade. Wind and solar generate electricity and therefore are more of
a threat to coal, but they still cannot compete with gas fired power plants.
Like it or not, this world runs on oil. Nothing can come close to the energy density of gasoline &
diesel and they are still relatively cheap compare to other transportation fuels.
(Click to enlarge)
Fact: In April, demand for crude oil is expect to spike by over 2.0 million barrels per day.
In 2017, demand for oil increased by 2.3 million barrels per day from the first to the second quarter.
Last year, U.S. crude oil inventories were at the top of the five year range. Today, U.S. crude oil
inventories are in the middle of the five year range. Facts eventually top Myths.
Some statistics in the IEA's Oil Market Report that should have raised a few more eyebrows:
• Global oil supply in January edged lower to 97,700,000 barrels per day. Compare this to global
demand that IEA forecasts will exceed 100,000,000 barrels per day by the 4th quarter.
• IEA's oil demand growth forecast for 2018 was raised to 1,400,000 barrels per day. In my opinion, when
the actual data is in for 2018, demand will have gone up by over 2,000,000 barrels per day. Global GDP
growth estimates just keep going up and GDP growth is the primary driver of oil demand.
• OECD commercial stocks (crude oil and refined products) fell in December by 55,600,000 barrels, the
steepest drop in over seven years. OECD stocks are now 2,851 million barrels, which is way below "glut"
level.
My prediction:
When the U.S. refinery maintenance season is over in March,
supply/demand statistics are going to turn VERY BULLISH for oil in April.
By Dan Steffens for Oilprice.com
Mamdouh G Salameh
on February 22 2018 said:
While I agree with you on myths surrounding US shale oil production, I disagree that OPEC can't produce
more given the right oil price. Iraq alone could add more than 2 million barrels a day (mbd) by 2021/22
given the ongoing development of many discovered oilfields. Iraq has a large number of huge discovered
oilfields that are waiting to be developed. A successful development programme could take Iraq's oil
production to more than 10 mbd by 2026/27.
Moreover, OPEC could easily raise their production by more than 2.5 mbd at an oil price of $100/barrel or
higher. But having suffered a real ordeal with the oil price crash in 2014, they are not going to flood
the oil market again.
I totally agree with you that there is a huge hype about the impact of a wider use of electric vehicles (EVs)
on the global oil market and the demand for oil. EVs will hardly make a dent on the global demand for
oil. There will never be a post-oil era during the 21st century and far beyond.
The oil price is heading towards $70/barrel and beyond during 2018 and could even touch $80 in 2019
buoyed by very positive oil market fundamentals and a re-balanced oil market.
In my considered opinion, a fair price for oil ranges from $100-$130. Such a price will provide good
revenues to the oil-producing nations and will enable them to invest in exploration and in expanding
oil-production capacity. It will also enhance global investment in oil and energy projects and will
enable major oil companies to balance their books and invest further in oil projects. All in all, it will
stimulate the global economy and impact positively on it.
Dr Mamdouh G Salameh
International Oil Economist
Visiting Professor of Energy Economics at ESCP Europe Business School, London
Pankaj Kumar
on February 22 2018 said:
What happens if India and China start booming? Their oil consumption and appetite increase beyond the
projected estimate. This could mean oil prices reach the highest threshold they've ever seen. This
is important with many countries (USA) now becoming more territorial and protection driven. $100-130
would be conservative numbers if this happens.
The increase in well productivity comes with a higher cost tag and whether it is 225 or 250K
BO EUR, at a gross WH price of $60 per barrel and a net back price of $30, those kinds of
estimated UR's are barely (in)sufficient to pay out $7.5M well costs. One cannot replace
reserve inventories that are declining precipitously, much less grow reserves, by breaking
even. It is, in my opinion, a mistake to assume the future of unconventional shale oil
resources in our country is strictly price dependent. It is very much money dependent.
I think one of the primary reasons there are any rigs still running in the EF is to comply
with SEC, 5 year, drill-it-or-lose-it rules for proximity related PUD reserves. If you have
borrowed money on PUD reserves and are about ready to have to impair, again, because you are
running out of time, you are up Shit Creek. Or further up Shit Creek than you already were.
Otherwise, I don't know why anyone is drilling Eagle Ford wells anymore unless they know,
guaranteed, the price of oil is going to $85 and will STAY there.
Just thinking about all these stripper horizontal wells gives me LOE nightmares.
A major expense being downhole failures, doesn't it make practical sense that these wells
will be very high cost? Over 10,000' of rods rubbing up and down against 10,000' of tubing,
and in particular in beginning of the "curve" where the down hole pump apparently must sit in
order to keep from pumping off.
We have wells that haven't been pulled in years, but those are slow pumping verticals that
are very shallow. Many drilled with a cable tool. Straight holes, little rod wear.
I just cannot imagine getting a long run without a failure on these hz wells with a 640
Lufkin pounding away 24/7/365.
I drove by 33 Eagle Ford shale oil wells today, Shallow; did a little windshield poll. Twenty
one of them were down. Or on pump-off controls. Either way, they weren't making money. Might
be they were all WOR; everybody has fled S. Texas for points West. Hauling frac sand can now
make you upper middle class in less than 6 months.
Rod lifting those kinds of wells you describe been there, done that. It sucks. Steal one
in a garage sale, or off eBay and for a while you think you hit a big lick. Then along comes
a $135K well intervention that takes 2 years to payout and you wish you'd become a landscape
engineer (lawnmower) instead.
All wells on rod lift eventually will have down hole failures. When wells fail often, or are
low oil volume, they may become uneconomic to produce.
From what I have seen from actual joint interest statements to non-operated working
interest owners, it costs between $3,000-$20,000 per month to operate a shale oil well. Much
of the expense depends upon how much water is produced with the oil. Almost all produced
water is truck hauled. Water disposal systems are being constructed, but those are very
expensive.
The $$ figure I cite does not include repairs of down hole failures such as pump failures
or tubing leaks. About the cheapest downhole repair I have seen for one of these wells was
$15,000. The highest I have seen was almost $500,000.
EUR estimates for these wells are for a 40-50 year well life. Much of that life the well
will produce under 25 BOPD. Most of the wells in TX are burdened with a 1/4 royalty.
So, just for illustrative purposes, let's say a 5 year old EFS in TX is now producing
6,000 net BO to the working interest owners. At $50 WTI it is providing gross income of
$300,000. By the time we subtract LOE, G & A, and severance taxes, there is likely less
than $100,000 left.
Then, realize many shale companies, to raise money, have sold their gathering systems,
something which kind of astonished me at first. Therefore, the working interest owners are
also paying to use those systems. Even less $$ to the bottom line.
So, as Mike says, it just becomes a gamble on how many down hole failures occur. If you
luck out and have none in the year, you might make a little at $50 oil, more than one per
year and you have likely lost $$.
There will be several hundred thousand of these wells onshore US before it is over. Each
with a plugging and abandonment cost of around $250K estimated.
But, at $100+ oil, these might work. Just a big risk.
Looses of shale companies which hedged oil production for 2018 at 2017 prices can be
tremendous.
Notable quotes:
"... Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at prices that could end up being quite a bit lower than the market price, which could limit their upside exposure should prices continue to rise. ..."
too
much hype surrounding U.S. shale from the Saudi oil minister last week, a new report finds
that shale drilling is still largely not profitable. Not only that, but costs are on the rise
and drillers are pursuing "irrational production."
Riyadh-based Al Rajhi Capital dug
into the financials of a long list of U.S. shale companies, and found that "despite rising
prices most firms under our study are still in losses with no signs of improvement." The
average return on asset for U.S. shale companies "is still a measly 0.8 percent," the financial
services company wrote in its report.
Moreover, the widely-publicized efficiency gains could be overstated, at least according to
Al Rajhi Capital. The firm said that in the third quarter of 2017, the "average operating cost
per barrel has broadly remained the same without any efficiency gains." Not only that, but the
cost of producing a barrel of oil, after factoring in the cost of spending and higher debt
levels, has actually been rising quite a bit.
Shale companies often tout their rock-bottom breakeven prices, and they often use a narrowly
defined metric that only includes the cost of drilling and production, leaving out all other
costs. But because there are a lot of other expenses, only focusing on operating costs can be a
bit misleading.
The Al Rajhi Capital report concludes that operating costs have indeed edged down over the
past several years. However, a broader measure of the "cash required per barrel," which
includes other costs such as depreciation, interest expense, tax expense, and spending on
drilling and exploration, reveals a more damning picture. Al Rajhi finds that this "cash
required per barrel" metric has been rising for several consecutive quarters, hitting an
average $64 per barrel in the third quarter of 2017. That was a period of time in which WTI
traded much lower, which essentially means that the average shale player was not profitable.
Not everyone is posting poor figures. Diamondback Energy and Continental Resources had
breakeven prices at about $52 and $37 per barrel in the third quarter, respectively, according
to the Al Rajhi report. Parsley Energy, on the other hand, saw its "cash required per barrel"
price rise to nearly $100 per barrel in the third quarter.
A long list of shale companies have promised a more cautious approach this year, with an
emphasis on profits. It remains to be seen if that will happen, especially given the recent run
up in prices. But Al Rajhi questions whether spending cuts will even result in a better
financial position. "Even when capex declines, we are unlikely to see any sustained drop in
cash flow required per barrel due to the nature of shale production and rising interest
expenses," the Al Rajhi report concluded. In other words, cutting spending only leads to lower
production, and the resulting decline in revenues will offset the benefit of lower spending.
All the while, interest payments need to be made, which could be on the rise if debt levels are
climbing.
One factor that has worked against some shale drillers is that the advantage of hedging
future production has all but disappeared. In FY15 and FY16, the companies surveyed realized
revenue gains on the order of $15 and $9 per barrel, respectively, by locking in future
production at higher prices than what ended up prevailing in the market. But, that advantage
has vanished. In the third quarter of 2017, the same companies only earned an extra $1 per
barrel on average by hedging. Part of the reason for that is rising oil prices, as well as a
flattening of the futures curve. Indeed, recently WTI and Brent have showed a strong trend
toward backwardation -- in which longer-dated prices trade lower than near-term. That makes it
much less attractive to lock in future production.
Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at
prices that could end up being quite a bit lower than the market price, which could limit their
upside exposure should prices continue to rise.
In short, the report needs to be offered as a retort against aggressive forecasts for shale
production growth. Drilling is clearly on the rise and U.S. oil production is expected to
increase for the foreseeable future. But the lack of profitability remains a significant
problem for the shale industry.
"... Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at prices that could end up being quite a bit lower than the market price, which could limit their upside exposure should prices continue to rise ..."
Riyadh-based Al Rajhi Capital dug
into the financials of a long list of U.S. shale companies, and found that "despite rising
prices most firms under our study are still in losses with no signs of improvement." The
average return on asset for U.S. shale companies "is still a measly 0.8 percent," the financial
services company wrote in its report.
Moreover, the widely-publicized efficiency gains could be overstated, at least according to
Al Rajhi Capital. The firm said that in the third quarter of 2017, the "average operating cost
per barrel has broadly remained the same without any efficiency gains." Not only that, but the
cost of producing a barrel of oil, after factoring in the cost of spending and higher debt
levels, has actually been rising quite a bit.
Shale companies often tout their rock-bottom breakeven prices, and they often use a narrowly
defined metric that only includes the cost of drilling and production, leaving out all other
costs. But because there are a lot of other expenses, only focusing on operating costs can be a
bit misleading.
The Al Rajhi Capital report concludes that operating costs have indeed edged down over the
past several years. However, a broader measure of the "cash required per barrel," which
includes other costs such as depreciation, interest expense, tax expense, and spending on
drilling and exploration, reveals a more damning picture. Al Rajhi finds that this "cash
required per barrel" metric has been rising for several consecutive quarters, hitting an
average $64 per barrel in the third quarter of 2017. That was a period of time in which WTI
traded much lower, which essentially means that the average shale player was not
profitable.
Not everyone is posting poor figures. Diamondback Energy and Continental Resources had
breakeven prices at about $52 and $37 per barrel in the third quarter, respectively, according
to the Al Rajhi report. Parsley Energy, on the other hand, saw its "cash required per barrel"
price rise to nearly $100 per barrel in the third quarter.
A long list of shale companies have promised a more cautious approach this year, with an
emphasis on profits. It remains to be seen if that will happen, especially given the recent run
up in prices.
But Al Rajhi questions whether spending cuts will even result in a better financial
position. "Even when capex declines, we are unlikely to see any sustained drop in cash flow
required per barrel due to the nature of shale production and rising interest expenses," the Al
Rajhi report concluded. In other words, cutting spending only leads to lower production, and
the resulting decline in revenues will offset the benefit of lower spending. All the while,
interest payments need to be made, which could be on the rise if debt levels are climbing.
One factor that has worked against some shale drillers is that the advantage of hedging
future production has all but disappeared. In FY15 and FY16, the companies surveyed realized
revenue gains on the order of $15 and $9 per barrel, respectively, by locking in future
production at higher prices than what ended up prevailing in the market. But, that advantage
has vanished. In the third quarter of 2017, the same companies only earned an extra $1 per
barrel on average by hedging. Related: The
Unstoppable Oil Rally
Part of the reason for that is rising oil prices, as well as a flattening of the futures
curve. Indeed, recently WTI and Brent have showed a strong trend toward backwardation -- in
which longer-dated prices trade lower than near-term. That makes it much less attractive to
lock in future production.
Al Rajhi Capital notes that more recently, shale companies ended up locking in hedges at
prices that could end up being quite a bit lower than the market price, which could limit their
upside exposure should prices continue to rise .
In short, the report needs to be offered as a retort against aggressive forecasts for shale
production growth. Drilling is clearly on the rise and U.S. oil production is expected to
increase for the foreseeable future. But the lack of profitability remains a significant
problem for the shale industry.
The last time U.S. drillers pumped 10 million barrels of crude a day, Richard Nixon was in
the White House. The first oil crisis hadn't yet scared Americans into buying Toyotas, and
fracking was an experimental technique a handful of engineers were trying, with meager
success, to popularize. It was 1970, and oil sold for $1.80 a barrel.
Almost five decades later, with oil hovering near $65 a barrel, daily U.S. crude output is
about to hit the eight-digit mark again. It's a significant milestone on the way to
fulfilling a dream that a generation ago seemed far-fetched: By the end of the year, the U.S.
may well be the world's biggest oil producer. With that, America takes a big step toward
energy independence.
The U.S. crowing from the top of a hill long occupied by Saudi Arabia or Russia would
scramble geopolitics. A new world energy order could emerge. That shuffling will be good for
America but not so much for the planet.
For now, though, the petroleum train is chugging. And you can thank the resilience of the
U.S. shale industry for it.
What didn't kill shale drillers made them stronger. The survivors have transformed
themselves into leaner, faster versions that can thrive even at lower oil prices. Shale isn't
any longer just about grit, sweat, and luck. Technology is key. Geologists use smartphones to
direct drilling, and companies are putting in longer and longer wells. At current prices,
drillers can walk and chew gum at the same time -- lifting production and profits
simultaneously.
Fracking -- blasting water and sand deep underground to free oil from shale rock -- has
improved, too. It's what many call Shale 2.0. And it's not just the risk-taking pioneers who
dominated the first phase of the revolution, such as Trump friend Harold Hamm of Continental
Resources Inc., who are benefiting from the surge. Exxon Mobil Corp., Chevron Corp., and
other major oil groups are joining the rush. U.S. shale is "seemingly on steroids," says
Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London. "The market
remains enchanted by the ability of shale producers to adapt to lower prices and to continue
to grow."
Geez Mike, your link to the oilprice.com story will surely bring Texas Tea back. Upsetting
the oil minister of KSA is the ultimate sign of victory to the shale/political types.
These shale guys are bound and determined to kill the oil price rally, and IEA and EIA
(which BTW in my opinion are both very political organizations) are really boosting it
too.
I know you feel you have a short window, but hang in there. The current price is pretty
good for "us types" and maybe it will hold between here and $55 WTI for the downside, while
we blow through 10 million and 11 million, all the while thinking, just like 1970, that USA
has unlimited supplies of oil.
I am starting to think the dollar is the key anyway. It was weak in 2011-2014, and oil was
sky high. Might be headed that way again, who knows.
Really enjoying all of the history on Oilystuff. Keep it coming!
Will be interesting to see US shale production in response to increasing frac hits,
increasing costs, mounting debt wall. These are all legitimate issues which IEA seems to
overlook when issuing rosy predictions. Three Stooges thought they could repair a hole in a
pair of pants by cutting it out .same logic as IEA.
Yeah, it's those items and more. The biggest they overlook is declines from production. The
past two years, they have concentrated in sweet spots, to keep their chins above water. In
doing so, they have miraculously brought production back up to 2015 highs, and not much more,
although the EIA is reporting imaginary oil. Underneath all that production, wells are
declining at a rapid rate. The biggest rates are what they drilled last year. Those wells
will produce less than half of what they produced last year. So, how many wells would need to
be completed to increase production over a million barrels in 2018? More than current
capacity, that's for sure.
Although tight oil output has increased at an annual rate of close to 1000 kb/d over the
past 12 months (Dec 2016 to Nov 2017), I doubt that rate of increase will continue, probably
about half that unless oil prices rise more than I expect (and I expect we might get to $85/b
by Jan 2019).
I'd say it's a crap shoot as to whether it goes up, or down with about the same number of
completions in 2018 as 2017. Ok, let's say we have more completions, I still can't say it
will go up 500k barrels. While people place statistics on depletion rates, I haven't seen a
well, yet, that can comprehend statistics. As a matter of fact, they defy statistics.
There are 180k producing wells in Texas. There were about 5400 completions in 2017. That's
about 3% of total producing wells.
"... Major oil producing countries, Saudi Arabia chief among them, are using technology to stave off production declines. These YouTube videos are a perfect example of the extreme lengths being employed to continue production: ..."
"... When the decline kicks in, these technologies will ensure that the cliff will be steeper. While I believe we are living at the absolute peak of world production and that decline will kick in soon, I'm not so concerned about specific predictions. It will happen soon enough and when it does the impact will be severe. ..."
"... I think of this problem in personal terms -- my son was born in 2000. He will live to see a world of diminishing oil production (as well as sea level rise, resource conflicts, and many other problems). Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place than it is today? I have lived through the peak period. I cannot envision what comes after. I can only hope that my son finds a way through it. ..."
"... "Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place than it is today?" ..."
"... Perhaps. But such sentiments were very common ten, fifteen years ago, and they were directed toward today, not 2030. So, yes, I do "doubt" it, but that's not saying much, as it's a subject I find interesting but useless to speculate about. ..."
"... I'm checking in here for the first time in about 9 years. I'm an old-time peaker, who jumped ship in 2009 when it became clear the dire predictions of Campbell, Deffeyes, et al., were failing to materialize. ..."
Ron is absolutely right about the creaming issue. Major oil producing countries, Saudi Arabia
chief among them, are using technology to stave off production declines. These YouTube videos
are a perfect example of the extreme lengths being employed to continue production:
These videos underscore how uniquely valuable oil is as an energy source and how no other
substitute will ever come close to matching its utility.
When the decline kicks in, these technologies will ensure that the cliff will be
steeper. While I believe we are living at the absolute peak of world production and that
decline will kick in soon, I'm not so concerned about specific predictions. It will happen
soon enough and when it does the impact will be severe.
I think of this problem in personal terms -- my son was born in 2000. He will live to see
a world of diminishing oil production (as well as sea level rise, resource conflicts, and
many other problems). Does anyone doubt that by the time he is 30 (2030) world oil production
will be in decline? Does anyone doubt by the time he is 50 (2050) the world will be a
drastically different place than it is today? I have lived through the peak period. I cannot
envision what comes after. I can only hope that my son finds a way through it.
"Does anyone doubt that by the time he is 30 (2030) world oil production will be in decline?
Does anyone doubt by the time he is 50 (2050) the world will be a drastically different place
than it is today?"
Perhaps. But such sentiments were very common ten, fifteen years ago, and they were directed toward
today, not 2030. So, yes, I do "doubt" it, but that's not saying much, as it's a subject I
find interesting but useless to speculate about.
I'm checking in here for the first time in about 9 years. I'm an old-time peaker, who
jumped ship in 2009 when it became clear the dire predictions of Campbell, Deffeyes, et al.,
were failing to materialize.
This doesn't mean I think oil is infinite or anything. I do think our capacity to predict
doom is much more circumscribed than our abilities to avoid it.
Interesting BOEM report attached – their prediction of GOM oil and gas production from
2018-2027.
They predict oil production will increase from 1.65-1.67 mmbopd in the 2017-2019 window to
1.74-1.77 mmbopd in the 2023-2027 time frame. They include future production from current
reserves, contingent resources and undiscovered resources. Contingent resources are mainly
field expansion projects, new fault blocks, new reservoirs, and resources from discoveries
that have not been put on production.
They have initial production from undiscovered resources occurring already in 2019 –
suggesting that a few discoveries will be made and be on line by the end of 2019. Seems
rather ambitious even for subsea tiebacks.
Given the lack of GOM exploration success in the last few years, my biggest challenge to
these predictions are their estimates of production coming from new discoveries. They show
about 1 BBO of production comes from currently undiscovered resources in this 10 year window.
SLG – hope you are well and had a good holidays. Here is my updated effort at the same
thing. I've added some new discoveries, but not as big or developed as fast BOEM show. I've
included all qualified fields as named entries except a few discovered in 2016 and 2017, and
for a lot I've had to make guesses for reserves based on the expected development size
(numbers in brackets show nameplate capacity). I might be able to improve things a bit when
BOEM reserve numbers for end of 2016 come out, but it's still not going to look much like
their estimates. It's noticeable that there's a lot of activity in short term, small tie
backs now – but these only add about 5 to 10 kbpd and immediately start to decline. So
like you I don't know where they are getting such high contingent resource production
additions from unless it is all on existing developments – I guess if a lot of fields
get to grow like Mars-Ursa has and Atlantis might this year then there'd be enough, but that
seems unlikely to me, especially at the rate they show it.
Thanks George, and same to you for the new year.
I've made a stab at comparing numerous production profiles for the 2018-2027 window –
your's from above, my midcase and downside estimates from a little over a year ago, and
BOEM's estimates – both their total estimate, and their total estimate minus any new
resources/discoveries.
I plan to expand on this in a future post – including revised EUR estimate ranges.
They are all models with something worthwhile to add to the discussion, which is not what I
would say about the EIA projections. They just add have some kind of growth rate, with no
basis in actual numbers, and make it look fancy by adding a hurricane effect – and yet
this is the number usually quoted in the MSM. I think their predictions a couple of years ago
had an exit rate for this year of 2.2 mmbpd – miles off, and when they do try to
provide bottom up justification they look ridiculously ill informed.
Maybe they have a higher oil price forecast? Or they don't bother to see if what gets put on
line is worth developing? I know this is hard, but try preparing a forecast with prices
increasing 3% per year above inflation for 30 years, and you will get a higher forecast.
There is natural gas coming out of our ears at the moment because of the shale phenomena; the
price is tanking back to the mid $2's and there is no place to put anymore gas.
Notable quotes:
"... Shale companies are on track to spend $20 billion more than they will generate in the next six months if prices hover around $40 a barrel, analysts say. ..."
"... Compensation practices play a role in the behavior of U.S. shale producers: Most of their management teams are paid based on growth or adding new oil and gas reserves -- not on profits -- according to Matt Portillo, an analyst at Tudor Pickering Holt & Co., in Houston. "Until that changes, growth may continue to prevail," he said. ..."
The shale oil industry is NOT profitable. It never has been and in general terms it will not
be in 2018 either. There has always been something fishy about its funding, particularly when
wanders like this guy can make $16M a year in compensation, while his company looses money
year over year for stock holders.
Clearly, however, it is not his fault his company can't be profitable and it is not their
fault they are "forced" to borrow all that money
As we've noted on too many occasions to count, this is aiding and abetting a situation
where these companies effectively sow the seeds of their own demise. They're running up the
down escalator. They're working their asses off to drive down the price of the very
commodity they're producing.
And hilariously, they think maybe you're the problem. Here's the
Journal again:
"The biggest problem our industry faces today is you guys," Al Walker, chief executive
of Anadarko Petroleum Corp. , told investors at a conference last month.
Wall Street has become an enabler that pushes companies to grow production at any
cost, while punishing those that try to live within their means, Mr. Walker said, adding:
"It's kind of like going to AA. You know, we need a partner. We really need the
investment community to show discipline."
Even if companies cut back on drilling now, it wouldn't be enough to stop a new wave
of oil from hitting the market in the second half of the year : U.S. shale output
typically lags behind new drilling by four to six months, analysts say.
Shale companies are on track to spend $20 billion more than they will generate in the
next six months if prices hover around $40 a barrel, analysts say.
Compensation practices play a role in the behavior of U.S. shale producers: Most of
their management teams are paid based on growth or adding new oil and gas reserves -- not
on profits -- according to Matt Portillo, an analyst at Tudor Pickering Holt & Co.,
in Houston. "Until that changes, growth may continue to prevail," he said.
Isn't that last bit about executive compensation great?
So folks like Al Walker are paid based not on profits, but on growth, and that growth is
funded by investors like you.
So if you connect the dots there, it means you are literally giving these management
teams money to fund the growth that ends up boosting their compensation, and that growth is
going to ultimately bankrupt the companies you're investing in by creating a supply
glut.
Welcome to the shale industry, goddammit. Enjoy your stay.
Every article on oil prices in the last several months says the ONLY downside is US shale.
Do the larger US shale companies pay attention to supply/demand dynamics at all? At
current prices most can show positive EPS, assuming service costs do not surge too much?
For example, auto manufacturers do not produce the maximum vehicles possible. They pay
attention to supply and demand. Almost every single manufacturer tries to forecast demand for
its product.
Even farmers try to grow what crops are in most demand and raise what livestock is most in
demand.
We have not drilled a well in over 3 years due to lack of oil demand, our production has
fallen.
"Rystad Energy is even bullish on American oil. The Norwegian firm sees U.S. crude output
hitting 11 million barrels per day by December, narrowly surpassing global leader Russia and
OPEC kingpin Saudi Arabia."
Absolute poppycock! US output will do good to get to the level that EIA is currently
reporting, about 9.75 by the end of 2018. Mike's post explains why. 11 million barrels a
day,? Man, that is some potent stuff they are smoking.
>Do the larger US shale companies pay attention to supply/demand dynamics at all?
> At current prices most can show positive EPS, assuming service costs do not surge too
much?
This might be a wrong question. The right question IMHO is: "To what extent shale
companies are just prostitutes of Wall Street and to what extent they are independent oil
production companies? "
What if the key role for such companies is to be a part of "price crasher" mechanism
(along with "naked shorts" and similar financial chicanery) ?
I believe that with the shale boom it is Wall Street that obtained mechanism using which
they can dictate oil prices.
Not Saudies or OPEC in general but Wall Street titans are now in the driving seat,
although OPEC and Russia are fighting back by limiting production.
And Wall Street is not shy to step on the throat of "conventional" oil producers and force
them to produce with no or even negative margins because of the specific of oil industry.
When you gets so much money on such lenient conditions something is fishy This dual
production mode (oil plus junk bonds and evergreen loans) looks to me just a variable of
"subprime housing boom" on a new level.
The past week of continuous record low temperatures and snowfall has oil-dependent power
plants in the northeast scrambling to secure supplies of some of the dirtiest burning oil
available in the market due to an impending supply shortage, according to a new report by
Hellenic Shipping News .
Oil fuels 30 percent of the New England power plant market, but winter storms could lead to
another foot of snow, making it difficult for tankers or trains to deliver needed commodities,
Marcia Blomberg of regional grid operator ISO New England, said.
Oil imports to the East Coast jumped by almost 60 percent last week in anticipation of
increased demand due to heating needs. JBC Energy predicts distillate use to increase by 90,000
barrels per day in January and February as well.
The cold weather, expected to become a "bomb cyclone" in the coming days, has also
shocked
natural gas markets. Extreme cold is cutting production in North Dakota's Bakken, while demand
is surging because everyone is turning up the thermostat to stay warm.
Reuters said that gas flowing through interstate pipelines from North Dakota dropped from
1.3 billion cubic feet per day in the week ending on December 25 to just 1 bcf/d as of Tuesday.
Texas (-20 percent) Oklahoma (-22 percent) and Pennsylvania (-5 percent) are also reporting
weather-related production problems, Genscape data says.
Yes, it is unreal: either at the Texas RRC they had really HUGE problems in the past months collecting data, or the EIA used only
model estimates without any form of revision.
The correcting factors of the Texas RRC have not changed much and they showed they usual variability, so that I cannot explain
why there is such a big divergence between corrected RRC data and EIA. They only problem that I can think of (on the part of the
RRC) is that the hurricane completely disrupted their work: does anyone know whether the offices and data servers of the Texas
RRC were damaged during the hurricane? Thanks for the information.
I had a very interesting discussion on Twitter: operators in Texas confirmed me that the RRC offices were not affected by the
hurricane and data reporting proceeded normally. At this point the only (legal) reason left to explain the divergence is that
the EIA has started including NGL into their numbers:
"... Rystad Energy concluded this week that 2017 was yet another record low year for discovered conventional volumes globally. Less than seven billion barrels of oil equivalent has been discovered YTD. "We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, Senior Analyst at Rystad Energy. "The discovered volumes averaged at ~550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement ratio* in the current year reached only 11% (for oil and gas combined) – compared to over 50% in 2012." According to Rystad's analysis, 2006 was the last year when reserve replacement ratio reached 100%; largely thanks to the giant onshore gas field Galkynysh in Turkmenistan. Not only did the total volume of discovered resources decrease – so did the resources per discovered field. An average offshore discovery in 2017 held ~100 million barrels of oil equivalent, compared to 150 million boe in 2012. "Low resources per discovered field can influence its commerciality. Under our current base case price scenario, we estimate that over 1 billion boe discovered during 2017 might never be developed", says Passos. ..."
"... We have recently observed strong empiric evidence for the theory that a positive tendency in initial production rates for shale wells does not always lead to similar improvements in ultimate recovery. ..."
"... But profits and stock valuations are terrible over the past five to ten years. Drillers, Explorers, Services, I'd be shocked if you could find an index combo that has come even close to matching S&P, Biotech, Semiconductors, NASDAQ. Not positive but E&P et al might not even have beaten transportation over the past decade. If you've been invested in Oil and Gas you are officially a loser. ..."
"... The cooperative program and understanding between the Kingdom and Russia, the two largest producers in the market. ..."
"... Last but not least, we need to develop a culture of saving to increase our capital buildup for the economy. This is not an easy task, and requires a total rehabilitation of our consuming behavior." ..."
"... At this posting, New England is burning oil for 17% of their electricity generation. Wholesale spot price for electricity is $230/Mwh, about 10 times regular pricing. Later this afternoon, demand is expected to increase more. ..."
ALL-TIME LOW FOR DISCOVERED RESOURCES IN 2017: AROUND 7 BILLION BARRELS OF OIL EQUIVALENT WAS DISCOVERED
Rystad Energy concluded this week that 2017 was yet another record low year for discovered conventional volumes globally.
Less than seven billion barrels of oil equivalent has been discovered YTD.
"We haven't seen anything like this since the 1940s," says Sonia Mladá Passos, Senior Analyst at Rystad Energy. "The discovered
volumes averaged at ~550 million barrels of oil equivalent per month. The most worrisome is the fact that the reserve replacement
ratio* in the current year reached only 11% (for oil and gas combined) – compared to over 50% in 2012."
According to Rystad's analysis, 2006 was the last year when reserve replacement ratio reached 100%; largely thanks to the giant
onshore gas field Galkynysh in Turkmenistan.
Not only did the total volume of discovered resources decrease – so did the resources per discovered field.
An average offshore discovery in 2017 held ~100 million barrels of oil equivalent, compared to 150 million boe in 2012.
"Low resources per discovered field can influence its commerciality. Under our current base case price scenario, we estimate that
over 1 billion boe discovered during 2017 might never be developed", says Passos.
I think every drilled high impact wildcat well identified by Rystad at the end of 2016 has now turned out dry, with a couple
postponed for lack of finance.
It would be great if they gave the gas/liquids split all rolled up. Does it look to your eyes like a roughly 50/50 gas/liquids
split in 2017, as it does to mine? (Talking about Rystad chart.)
2017 looks likes another very disappointing year for conventional discoveries. I wonder how unconventional resource adds have
been over the last few years. I suspect that is how many of our big oil friends are achieving their annual resource add goals.
The EIA reserves are going to be interesting: even before the price crash the extension numbers, which is where all the LTO growth
came from rather than discoveries, were starting to fall and reserve changes looked like they might be going negative, which I'd
guess is due to decreases in URR estimates; e.g. below for Bakken.
Yes reserves decreased in 2015, probably due (in part) to a fall in oil prices from $59/b in Dec 2014 to $37/b in Dec 2015,
the price in Dec 2016 was $52/b, using spot prices from the EIA, so perhaps reserves increased a bit in 2016, it will be interesting
to see the 2016 estimate.
I think they have to use averages for determining economic recovery not spot prices – I can't remember now if it's six month or
annual (or other – I think maybe six months to March and September when they reevaluate) – 2016 would be bout the same or a bit
lower depending on the time frame.
Initially, SEC rules required a single-day, fiscal-year-end spot price to determine a company's oil and gas reserves and
economic production capability. The SEC Final Rule changes this requirement to a 12-month average of the first-of-the-month prices.
Using this I get
2014, 101
2015, 54
2016, 42
So 2016 reserves should decrease further if prices affect reserves.
EMPIRICAL EVIDENCE FOR COLLAPSING PRODUCTION RATES IN EAGLE FORD
We have recently observed strong empiric evidence for the theory that a positive tendency in initial production rates for
shale wells does not always lead to similar improvements in ultimate recovery.
Cabot announced they are selling up in the EF and concentrating on gas (15,000 bpd), maybe more likr them to come.
I have had to work hard over the years to explain to management that oil completions have to be optimized, and that seeking the
highest peak rate wasn't likely to be the best answer. This of course happens because high level oil company managers are good
at sales and PowerPoint, but have opportunities for improvement in key areas.
This confirms the suspicion of many that the high peak rates on newer wells (often with longer laterals and more frack stages
and proppant, in short more expensive wells) don't boost cumulative output much. In the case of the Eagle Ford, wells in Karnes
county (the core of the play) only increased output by about 40 kb over the older wells with less expensive completion methods.
Looking at Bakken data, it is clear that this is the case as well, with about a 10%to 15 % increase in cumulative output over
the first 24 months and then similar output to older wells thereafter.
Many observers assume that a higher peak production from a well leads to higher cumulative output of the same proportion. That
is if the peak goes from 400 kbo/d for a well projected to have an EUR of 200 kbo to a peak of 800 kbo/d for a newer well, it
is often assumed that the new well will have cumulative output of 400 kbo. This is incorrect, in fact the newer well is more likely
to have an output of 240 kbo an increase of only 20% rather than the 100% often assumed.
However, Rystad Energy argues that there is some evidence that suggests those higher initial production (IP) rates do not
necessarily translate into larger gains in the total volume of oil and gas that is ultimately recovered. A sample of wells in
the Eagle Ford showed steadily higher IPs in recent years, but they also exhibited steeper and steeper decline rates.
It seems a bit unlikely that Canada is going to continue increasing production as shown above over the next 6 to 8 years (after
2018 ramp ups are complete). There are no major greenfiled developments currently under construction and these take at least 5
years from FEED to production, there are continuing redundancies in the oil patch as some of the large, recent developments move
from development to operations, and there is no spare pipeline (or rail) capacity such that the oil is at about $10 to $15 discount
which is likely to increase as Fort Hill's ramps up through next year (and new pipeline permitting and construction is likely
to take even longer than the actual oil sands project).
With Iran and Iraq – they may have oil in the ground, but they need huge,new surface production facilites to process it and
supply water/gas for injection – those too take about 5 years to construct, assuming they can find some outside funding.
"OPEC has already demonstrated it can produce more, before they cut back in Jan 2017"
Yes OPEC may have some capacity to increase production. But many OPEC countries are in decline and Saudi Arabia does not have
any Khurais or Manifa like fields left to develop. If I ruled Saudi Arabia then I wouldn´t produce more than 10 mb/d even if there
were shortages. Better to stay on the platau a little bit longer. Iraq is the country with the biggest possibilities for increases.
But they will do so when they are able to, not because of shortages. The other countries you mentioned have mainly expensive oil
like tar sands in Canada, arctic in Russia and ultra deepwater in Brazil. Sure we can see increases there but it takes a long
time to develop.
"I don't think oil producers were struggling at $100/b, they were overproducing so prices dropped."
For the World Debt to GDP has increased from 226% in 2012 to 243% in 2Q2017, for advanced economies over the same period debt
to GDP went from 272% to 275% and for emerging economies over the same period 145% to 190%.
The story is better access to credit for emerging economies from 2012 to 2017.
A major recession is not very likely.
The IMF forecasts real GDP growth of 3.75% for the World from 2018 to 2022.
Oil prices at over $100/b were no problem for the World economy from 2011-2014, real GDP grew at 3.5% per year. No reason $100/b
oil would cause a recession.
The $160/b (2017$) will only be about 3.3% of World GDP in 2026, assuming medium UN population growth scenario and real per
capita GDP growth at 1.5%/year and 84 Mb/d C+C output in 2026.
There was another big drop in US crude stocks by the twip – down 6.5 mmbbls with gasoline and diesel up 2 mmbbls combined.
The crude level is fast approaching the middle of the 5 year average – how far does it have to undershoot before panic sets in?
US SPR drawdown this year is about 21.5 million barrels, this is usually not included when calculating the 5y average. Planned
annual sales are similar for the next couple of years (
https://www.eia.gov/todayinenergy/detail.php?id=29692
note that the figure shows fiscal year).
The story being told is that oil markets should be in balance next year or slight surplus if LTO maintains its pace. KSA low
production during end of 2017 and the problems in Venezuela should result in continued stock drawdowns or only a small build during
the spring (forties supports this too). Next summer driving season can be interesting, assuming the economy remains healthy. 2019
will be _very_ interesting since it will be revealed how much of the OPEC cuts were made voluntary.
As inventories are still way above historical averages, it is important to bear in mind that substantial infrastructure in form
of tanks and pipelines have been constructed over the last few years. This increased the necessary working inventory to keep the
system functioning. So, the critical inventory level might be much higher than in previous years.
They need a minimum amount of empty capacity to allow for blending and movement, not a minimum amount of stored volume to keep
it working. The storage is to cover for upsets and to allow people to make money from arbitrage.
It was propably close to the point where it was low enough to cause problems at that time. Why? Because from a commercial point
of view, it´s just stupid to have more storage than you need. It´s cost money to store it and it´s better to sell it and get the
money instead of just having it in storage. Also there is the SPR from where you can get oil if there is supply problems. So really
no need to have large amounts of oil in storage.
Yes that was how I interpreted your original comment. At least for US commercial crude stocks for the current week we are currently
about 95 million barrels above the 2012 and 2013 average for the same week of the year, so perhaps another few years before any
panic if stocks continue to decrease by 50 Mb per year as they did from 2016 to 2017. I chose 2012 and 2013 because oil prices
were relatively high in 2012 and 2013 ($88/b and $98/b in Dec 2012 and Dec 2013 for WTI).
On rereading your original comment, I think when it gets near the lower edge of the 5 year average, panics sets in, it may
take a few years.
"You can just say it is an industry in decline and there are better places to put one's money in." yes you can say "the industry
is in decline" but then you would be wrong, not usual for you or many on the board. In this case however, the statement is not
only wrong but delusional. Both production and demand are at record highs for oil natural gas and natural gas liquids. Of course
why let facts get in the way of your political views, to quote a old line; fat, drunk and stupid in no way to go through life,
son
"Both production and demand are at record highs for oil natural gas and natural gas liquids. "
But profits and stock valuations are terrible over the past five to ten years. Drillers, Explorers, Services, I'd be shocked
if you could find an index combo that has come even close to matching S&P, Biotech, Semiconductors, NASDAQ. Not positive but E&P
et al might not even have beaten transportation over the past decade. If you've been invested in Oil and Gas you are officially
a loser.
Now, high yield bonds might be a different story. But in the wake of all the bankruptcies for the past five years was 100%
of all bonds paid? They might have been, not sure.
Oil companies themselves have changed the way they are investing. So I take that as a sign they, too, think their best times are
behind them.
In terms of financial management, there are industries that have done better and are likely to do better than gas and oil.
It's simply not a growth industry anymore.
I think oil prices have an effect on investment, especially outside the LTO focused companies. For the LTO players they seem
to focus on output growth regardless of profits, not a great long term business model.
Regarding the gap, a third of the consumption growth over the last decade was from China. If Chinese consumption plateaus, as
it very well might, then consumption growth from here will be less and the gap smaller. But putting in an assumption to change
an established trend would just add another point of failure. This piece isn't so much a model as a creation story, trying to
figure out why past expectations weren't met and where the known unkowns might come from. A big one of these is what the Permian
might end up doing. I think that is why industry is paying up to get into the Permian. If you are not in the Permian you don't
have a future. And shareholders will pay any amount of money for you to keep your job.
The piece was prompted by Ovi's observation that Non-OPEC less the big three has been in decline since 2004 – very encouraging.
There are some systems in which a price rise does not result in an increase in production simply because the resource is clapped
out. The gold market last decade for example. The gold price rose at an average of about 17% per annum year after year but gold
production fell. That is not supposed to happen. Now some mines are digging up rock with just over one part in a million of gold
in it and that pays for turning that rock into mud.
There was a July report for China imports that extrapolated to another 6.6% consumption growth year for them. No evidence of slow
down. Ditto India.
Reminder to folks because it is a tad obscure. India's consumption growth is 8% but it's concentrated in an unusual way. LPG.
They run motors on LPG, mostly motorbikes.
Vehicle miles driven. The increase is relentless as is US population growth. In the big smash of 2008/2009 there was a flattening
of the increase but not really any sort of collapse. There was in oil price, but there was no need for it since consumption did
not decline more than 5%. A quick look at historical consumption not just miles driven shows essentially the same tiniest of down
ticks during that timeframe.
So I would say we need a new theory as to why price declines during recession. Doesn't appear to be less driving to work.
Consumption of oil would seem to decline a little bit right across the board during a recession, especially a big one. Construction
machinery runs less, people travel less, buy fewer new things. It doesn't take very much by way of falling consumption to reduce
the price of oil. The price of oil is highly inelastic, in the short term, and it's like milk.
The price of milk has to fall a long way before you can find uses for more than the usual amount.
People buy as much milk as they want for their kids, and maybe a little to cook with. NO MORE, even if the price goes down
a lot. They don't have any use for it. So .. if it's coming to market, it has to sell cheaper in order for people to FIND uses
for it. You can feed milk to the cat, and even to the pigs, if it's cheap enough. Farmers have been feeding excess milk to pigs
just about forever, lol. I did so myself when we had more than we could use otherwise when I was a kid.
So . if the price of gasoline falls, maybe you take the ski boat to the lake one extra weekend , which can easily result in
burning a couple of hundred gallons, round trip, as opposed to spending the weekend golfing at a cheap nearby course.
Or you drive the old car that's a gas hog more, because it saves putting miles on a newer car. When the price of gasoline bottomed
out, I drove my old four by four truck a lot more than I would have otherwise, because I knew I would be retiring it before long,
and wanted to get as many miles out of it as I could, saving wear and tear on the car .. which I'm planning on keeping indefinitely.
It broke down yesterday, and while it's not quite dead, I 'm thinking it's time to euthanize it, lol.
I'm also running my big yellow machines a lot more than usual, because when diesel is down close to two bucks, as opposed to
four bucks or so, this saves me a hundred bucks a day, or more, if I stay with it, and I've got some pretty big long term projects
such as a new lake, which I work on at odd times, whenever circumstances permit.
IF I were hiring out, which I don't , I would be able to offer a neighbor a hundred bucks or more off for a days work, with
diesel at two, as opposed to four bucks. That would result in neighbors with cash, and thrifty Scots habits, spending some of
their savings, doing long planned work sooner, or maybe going for a new small project.
Overall though construction falls off during a recession.
Most of the increase in total miles happens as the result of people driving new cars, and by and large, new cars and light
trucks are far more fuel efficient than old ones.
And people who are broke spend as much on gasoline as they can afford, period. They MUST spend to get to work. If a tank at
twenty bucks will get them to Grandma's house and back in their old clunker, they go. A tank a forty bucks often means calling
rather than visiting.
It is pretty much a given that Permian oil needs export market. This is from PAA conference call.
" PAA comments: If you look at the amount of 45-plus gravity. It's about 300,000 barrels a day now, growing to 1 million plus.
So, a lot of those volumes are coming, and that's really the crux of the benefit of a Cactus pipeline being able to take that
directly to the water because I think we are going to see a lot of pushback from refiners. We are already starting to see it as
far as the lightning of the general stream going up to Cushing.
The refiners don't want any lighter. So, it's an integral part of the strategy and a piece of everything we've been building."
Delaware basin produces 56% oil that is greater than API gravity 50 plus according to Woodmac.
Every week I see announcements to export US oil. Here are some.
"OPINION-
Don't be taken in by the surge in oil prices
But oil prices have continued to be volatile. They went down from $114 per barrel in June 2014 to $26 per barrel in early 2016
and moved gradually upward to touch $64 per barrel in late November 2017. On the other hand, economic forecasts expect oil prices
to continue to rise to a range of between $70 to $80 by the end of the first quarter of 2018. Futurists in the field base their
expectations on the following indicators:
1) The cooperative program and understanding between the Kingdom and Russia, the two largest producers in the market.
2) The continuation of efforts to reduce oil surplus in the market 3) The agreement among OPEC members and some non-members to
continue their programs of production reduction up to the end of 2018. 8. Last but not least, we need to develop a culture
of saving to increase our capital buildup for the economy. This is not an easy task, and requires a total rehabilitation of our
consuming behavior."
Interesting development for natgas: Iroquois zone 2 spot prices just shot up to over 32 USD per mcf. This is nearly 1000% up from
last month. As much depends now on the future weather, it shows how volatile the US gas market can be – despite massive efforts
towards more supply.
As the industry has completely shifted the supply from the South to the Northeast, hurricanes are no more a threat to supply,
yet freeze offs become now a major issue. Previously just the supply of the Rockies has been hampered by freeze offs. As this
concerned just 10% of US total production, this has never been an issue for gas supply. However, as currently 70% of supply comes
from the Northeast and the Rockies, freeze off could lead to serious supply disruptions, if the freeze continues.
Not freeze offs, simply lack of pipeline capacity in the face of unprecedented demand. When the receipt figures from the various
transfer points are published, they should show 100% capacity utilization.
At this posting, New England is burning oil for 17% of their electricity generation. Wholesale spot price for electricity
is $230/Mwh, about 10 times regular pricing. Later this afternoon, demand is expected to increase more.
The supply is there in the pipelines, Mr. Leopold, there just isn't enough of them to satisfy demand during this cold spell.
I was expecting your reply. Thanks for your opinion.
Nevertheless, there has been huge infrastructure spending over the last years. The pipelines should be already in place.
However, freeze offs are not an issue just yet. If the gas wells freeze off later in the week (temperatures are going to zero
down until Cincinnati) , the shortage of supply may be really a concern. There is just one week left and we know it.
This is one of the structural weaknesses of Shale gas:you probably do not have it when you need it the most.
The pipelines that have been completed greatly favor delivery west to southwest from the Appalachian Basin.
The Atlantic Sunrise is being built that will deliver into the NYC area via a hookup with Transco, I believe.
Deliveries to the north, that is New York State and New England have been virtually nil.
Yes, the storage aspects of all gas products is a challenge, and – as you mentioned – the coming cold days will highlight the
vulnerabilities of the situation, sadly, at great expense to many.
Are companies which produce it profitable or they survive by generating a parallel stream
of junk bonds and evergreen loans?
Most of them are also shale oil producers and might well depend on revenue from shale oil
to produce gas. Shale oil proved to unsustainable at prices below, say $65-$75 per barrel or
even higher, excluding few "sweet spots". Also a lot of liquids the shale well produce are
"subprime oil" that refiners shun.
They are not only much lighter but also they have fewer hydrocarbons necessary for
producing kerosene and diesel fuel. Mixing it with heavy oil proved to be double edged sword
and still inferior to "natural" oil. So right now the USA imports "quality" oil and sells its
own" subprime oil" at discount to refineries that are capable of dealing with such a mix.
Say, buying a barrel for $60 and selling a barrel of "subprime oil" at $30.
And without revenue from oil and liquids it can well be that natural gas production might
be uneconomical.
I wonder what percentage of the total US oil production now is subprime oil.
Modern multistage shale well now cost around $7-10 million. And that's only beginning as
its exploitation also costs money (fuel, maintenance, pumping back highly salinated and often
toxic water the well produces, etc). So neither oil nor gas from such wells can be very
cheap.
Generally such a well is highly productive only the first couple of years. After that you
need to drill more.
Also there is a damage to environment including such dangerous thing as pollution of
drinking water in the area,
So, is there a big wall of US shale oil coming from Texas that will dash my "happy times" of
$55-65 WTI?
So thankful to get up to this level after 36 months of headaches about the oil price.
Seems the only thing that could screw it up is US shale, which apparently is set to explode
in 2018.
I saw someone touting Halcon stock today on SA. Making a big deal about having little
debt. Too bad they flushed about $3 billion of debt when they went BK. I'm sure Mr Wilson
(CEO) is, "still getting his" so to speak.
My brother is griping about why he hasn't been able to draw a salary for the last three
years, heck all the shalie management has! Have to remind him we aren't in the shale fantasy
land. He knows, he's just blowing like I'm prone to do.
If I don't post anymore this year, happy New Year everyone!! Things are looking up, just
hope the shale industry doesn't torch it again!
IN my view you will be sleeping well in the next year. Shale increases mostly the supply
of condensate and light distillates, which does little to cover the worldwide shortage of
middle distillates. So, the price of 'real' oil will very likely increase over the next
future whereas the prices of light distillates (propane, butane, pentane , LPG, NGPL
composite .. ) are very likely depressed. Light distillates can substitute middle distillates
to some degree, yet the potential is limited. So, in that sense I wish you a happy and
successful New Year.
There is no question, Shale is a disaster for investors. Nevertheless, it is a blessing for
Wall Street as high oil and gas production ensures dollar stability and a growing bond
bubble. The only question is when will investors will wake up. As it is perfectly OK for
small companies to sacrifice themselves and burn the cash of investors through, big companies
are less willing to do so. Who is next? XOM, Statoil , APA ?
The ratio of commodities / S&P500 is at a record low, S&P_GSCI / S&P_500
The S&P GSCI currently comprises 24 commodities from all commodity sectors – energy
products, industrial metals, agricultural products, livestock products and precious
metals.
Bloomberg chart on Twitter: https://pbs.twimg.com/media/DSCfWj6W4AA7xyW.jpg
Discoveries of new reserves this year were the fewest on record and replaced just 11
percent of what was produced, according to a Dec. 21 report by consultant Rystad Energy.
While shale wells are creating a glut now, without more investment in bigger, conventional
supply, the world may see output deficits as soon as 2019, according to Canadian producer
Suncor Energy Inc.
Are we not now near enough to 2019 to say that there just isn't time to bring major new
conventional projects on-line before mid to late 2019? The only offshore projects that could
be approved and developed earlier than that would be single well tie backs using the
wildcat/appraisal well as a producer, probably no more than 5 to 10 kbpd and in immediate
(and likely rapid) decline, and would be dependent on there being spare processing capacity
on a nearby hub (i.e. production the new production would be mitigating decline not adding
output).
But the issue isn't lack of discoveries this year, as the headline implies, it's the lack of
recent FIDs which might be in part because of the drop off in discoveries in 2012 to 2015
(for all oil, but particularly easily developed oil), coupled with high debt loads, and
prices that aren't high enough (or at least not yet for long enough) to allow development of
what resources there are available to the IOCs. As prices rise and IOCs become more confident
and are able to pay dividends as well as fund longer term developments then the really low
discoveries in 2015 to 2017 might give them far fewer options than people expect (noteworthy
is that any discoveries in that period that have been attractive, like Liza, have been
immediately fast-tracked, so there really isn't much of a backlog of attractive projects at
all).
I was basing my comment on what the article said. Many of the companies are aware that
discoveries have been low and not many projects will be coming online soon.
Mexico may be heading for a period of accelerated decline (above 10%). Their two onshore
regions and the southern marine region are falling at 15 to 20%, and the largest producing
region (Northern Marine, which includes KMZ and Cantarell) looks like it may be starting to
accelerate. The non KMZ nd Cantarell fields had been the only ones increasing, but look to
now be in decline or at least on plateau, and by PEMEX forecast KMZ should be off plateau in
the next couple of months or so. Mexico has now stopped exporting light oil (which mostly
comes from the three smaller regions, with KMZ and Cantarell producing heavy and medium
heavy) and will presumably be looking for increasing imports of it, which is probably good
for the Texas LTO producers. Operating rigs have recently been declining fast.
Do you have any information on how the ramp up of production is going for the Western
isles project following first oil on 15th November. On a side it looks like the Weald basin myth is starting to unravel.
Not yet -first numbers for December start-up should be in March, it's a question of limiting
their losses at current prices I think. All the wells were predrilled so ramp up should be
fast but I wouldn't be surprised if they get pretty low reliability in the first 6 to 12
months given all the construction problems they had. Also interesting that Catcher started up
on time, against most expectations. Wonder if Clair Ridge will make it this year – do
you know if there are big tax benefits from depreciation for starting within a given calendar
year in the UK (or might be financial yar end is more important)?
This shows how fast the SW marine region fields are now falling (a lot of small fields were
added 2007 to 2015 and are now in steep decline).
There seems no reason this and the two land regions shouldn't continue to fall at current
rates (they may even accelerate given how the rig count has dropped), and if KMZ follows the
predicted PEMEX curve Mexico could drop around 350 kbpd this year, possibly the same in 2019
in decline (but with 60 kbpd additions due from Abkatun), but maybe approaching as low as
1000 kbpd by mid 2020, which is probably the earliest ENI will be able to get their shallow
water field on line if they fast track it.
CALGARY -- Imperial Oil says its much-delayed $16.1-billion project to build a natural
gas pipeline across the Northwest Territories from the coast of the Beaufort Sea to northern
Alberta has finally been cancelled.
Originally the plan was to increase Majnoon to over 1 mmbpd. That has now been downgraded
to 400 kbpd (from current 220). Shell and Petronas have pulled out and a "government panel"
will oversee the development. I'd bet on continued decline rather than any increase, and
potential for significant reservoir damage along the way.
Similarly for Nasirya oil field – intend is to increase from 90 kbpd to 200, using a
local oil company that also sounds like it has a lot of government input.
To me none of this ever declining brownfield development with IOCs pulling out, and
promises of more exploration "coming" is compatible with the claims for their discovered
resources (developed or not), or any chance of a quick ramp up if oil prices start to inflate
rapidly after 2018.
So far, the experiences about freeze off Shale wells are limited. Will glycol also work for
Shale wells when there is much water involved? I think nobody knows yet how big the impact of
the cold will be on Shale wells. However, it looks like shorts are getting hyper-nervous.
Oil and Gas Producers Find Frac Hits in Shale Wells a Major Challenge In North America's most active shale fields, the drilling and hydraulic fracturing of new
wells is directly placing older adjacent wells at risk of suffering a premature decline in
oil and gas production.
The underlying issue has been coined as a "frac hit." And though they have long been a
known side effect of hydraulic fracturing, frac hits have never mattered or occurred as much
as they have recently, according to several shale experts who say the main culprit is infill
drilling.
"It is a very common occurrence -- almost to the point where it is a routinely expected
part of the operations," said Bob Barree, an industry consultant and president of
Colorado-based petroleum engineering firm Barree & Associates.
He added that frac hits are also an expensive problem that involve costly downtime to
prepare for, remediation efforts after the fact, and lost productivity in the older wells on
a pad site.
A frac hit is typically described as an interwell communication event where an offset
well, often termed a parent well in this setting, is affected by the pumping of a hydraulic
fracturing treatment in a new well, called the child well. As the name suggests, frac hits
can be a violent affair as they are known to be strong enough to damage production tubing,
casing, and even wellheads https://www.spe.org/en/jpt/jpt-article-detail/?art=2819
FWIW The first SPE paper referenced discusses mediating the negative nature of frac hits.
It discusses the refrakking of a six well pad drilled in 2010 in the middle Bakken and three
forks, North Fork Field, McKenzie. The six wells have a cumulative oil production to date of
3.6mmboe and 7.7bcf.
Since I am not in the field, much of the paper went over my head, I merely skimmed through
it, however it appears that well communication was observed for horizontal and vertical
spacing of 1000 feet.
"... Old "classic" land-based oil fields deteriorate to the tune of 5% per year, while deep sea deteriorate more and subprime wells much more. You can probably double the figure for each, although much depends on particular geology. Infill drilling accelerates depletion, allowing to maintain high production for sometimes so changes can be abrupt. ..."
"... Moreover, with each year, "subprime wells" (multi-stage shale well) costs more and now are at a range of n 6-10 million depending on the number and the length of horizontals and number of fracking stages and other factors. Only few area (sweet spots) can recover this capital investment during the life of the shale well at current prices). More at around $80 and almost all around $100 per barrel. The later is also the price that KSA needs to remain solvent (rumored to be in low 90th). ..."
"... The shale oil produced in the USA is really "subprime" because large part of it has lower energy content (by 20% or more) and different mix of various hydrocarbons that "classic" oil. Especially condensate from gas wells. Which optimally can be used only as diluter for heavy oil. EIA does not differentiate between different types oil and use wrong metric (volume instead of weight). May be intentionally. ..."
"... Another factor is that world consumption continue to grow and will do so because population in large part of Asia and Africa is still growing and number of cars on the road increase each year requiring on average 1-1.4 MB/d additionally. ..."
"... By continuing its' easy money policies well past any recession or growth scare, the Fed has created a monster. Most shale companies aren't profitable and are in fact losing money using any kind of GAAP. However, cheap financing allows them to survive and "drill baby drill." The unintended consequences may include destabilizing Saudi Arabia to the point of an economic and political collapse. One can always hope ..."
"... Economic collapse in Venezuela due to low oil prices – good! Economic collapse in Saudi Arabia due to low oil prices – bad! Solution – extend cheap financing to Saudi Arabia via Aramco IPO! ..."
"... The 36″ North Sea Forties pipeline is currently shut down for repairs. Short and medium term prices will carry the effect of that supply loss. In the long term, unexpected developments are common. Considering how completely wrong so many oil analysts have been over the past ten years, including the IEA, there is not a lot of credibility in oil market predictions. ..."
My impression is that this a gap (could be intentional) between IEA statistics and predictions and the reality. This is propaganda
agency after all, with the explicit agenda of keeping the oil price for Us consumers low. So typically that produce too "rosy"
forecasts that later are quietly corrected. Their short-term forecasts are based on oil futures and as such has nothing to do
with the reality on the ground. Which is quite disturbing.
It is undeniable that shale boom which played such a beneficial role for the USA allowing to squeeze oil price (with generous
help from KSA) for two and half years is dead.
Now is kept artificially alive by junk bonds and directs loans that will never be repaid. In other words, the USA now enjoys
a period of "subprime oil. Unless there is a new technological breakthrough there will be an only minor improvement in efficiency
of drilling and oil extraction in the next couple of years, but the lion share of those was already implemented, and on the current
technological level we are close to the "peak efficiency" in drilling and services.
Those minor efficiencies will be negated by rising prices of service industries, which can't take the current pricing any longer
and need to raise prices for their services.
Old "classic" land-based oil fields deteriorate to the tune of 5% per year, while deep sea deteriorate more and subprime
wells much more. You can probably double the figure for each, although much depends on particular geology. Infill drilling accelerates
depletion, allowing to maintain high production for sometimes so changes can be abrupt.
In any case each year you need somehow to find 5 MB/d of oil, finance new wells in those areas and infrastructure required.
All Us shale production is around 6 MD/day. So you get the idea.
Moreover, with each year, "subprime wells" (multi-stage shale well) costs more and now are at a range of n 6-10 million
depending on the number and the length of horizontals and number of fracking stages and other factors. Only few area (sweet spots)
can recover this capital investment during the life of the shale well at current prices). More at around $80 and almost all around
$100 per barrel. The later is also the price that KSA needs to remain solvent (rumored to be in low 90th).
The shale oil produced in the USA is really "subprime" because large part of it has lower energy content (by 20% or more)
and different mix of various hydrocarbons that "classic" oil. Especially condensate from gas wells. Which optimally can be used
only as diluter for heavy oil. EIA does not differentiate between different types oil and use wrong metric (volume instead of
weight). May be intentionally.
So the future remains unpredictable but general trend for oil prices might be up with some spikes, not down. Although many
people, including myself, thought so in early 2015 ;-)
Another factor is that world consumption continue to grow and will do so because population in large part of Asia and Africa
is still growing and number of cars on the road increase each year requiring on average 1-1.4 MB/d additionally.
So it looks like the situation gradually deteriorate despite all efforts and related technological breakthrough which allow
to extract more from the old wells and more efficiently extract shale oil.
The problem is that new large deposits are very hard to find now and several previously oil-exporting countries gradually became
oil-importers. Mexico is one, which will be huge hit.
Obama administration screw the opportunity to move US consumers to hybrid cars so the situation in the USA deteriorates too
despite rise of percentage of more economical vehicle in the personal car fleet each year. Rumors were that they pursue vendetta
against Russia and that was primary consideration - to crash Russian economy and install a new "Yeltsin".
The USA generally is in better position then many other countries as the switch to natural gas and hybrid electric cars for
personal transportation is still possible. It already happened in several European countries for selected types of cars, buses
and trucks (taxi, in-city buses and "daily round trip or short trips trucks).
But there is no money for infrastructure anymore and for example many miles of US rail remain non-electrified. Burning diesel
instead.
As maintenance was neglected for two and half year disruption of existing supply might became more frequent. also mid Eastern
war is also a possibility with Trump saber-rattling against Iran. Recently the leak in undersea pipeline removed 0.5 MB/d from
the market and caused a price spike to $65 for Brent (WTI remains cheaper and never crosses $60 this time).
Also with a young prince in charge and the revolution against "old guard" KSA became more and more unstable so the next "oil
shock" might come from them. They also have problem of depletion which until now they compensated pitting more and more heavy
high sulfur oil deposits online. At some point they will be exhausted too. They also pitch for war with Iran, but they would prefer
somebody else to do heavy lifting.
The only one or countries still can significantly increase oil production now – Libya (were we have problem because of the
civil war after US-sponsored Kaddafi removal and killing), and Iraq where there are still untapped areas that might contain some
oil; nothing big, but still substantial in the range of 1 MB/d. Looks like Iran now exports all it could. Same is true for KSA
and Russia. In this sense OPEN oil production cuts might an attempt to preserve impression that they are untapped reserved. I
doubt that there are much and those cuts are just a reasonable insurance policy against quick depletion of existing wells as higher
price gives some space for innovation.
There is also such thing as EBITRA which gradually deteriorates everywhere and can become negative for certain types of oil
(for oil sands it depends on the price of natural gas and they are primary candidate if the price doubles or triples from the
current level).
By continuing its' easy money policies well past any recession or growth scare, the Fed has created a monster. Most shale companies
aren't profitable and are in fact losing money using any kind of GAAP. However, cheap financing allows them to survive and "drill
baby drill." The unintended consequences may include destabilizing Saudi Arabia to the point of an economic and political collapse. One
can always hope
Economic collapse in Venezuela due to low oil prices – good!
Economic collapse in Saudi Arabia due to low oil prices – bad!
Solution – extend cheap financing to Saudi Arabia via Aramco IPO!
Meanwhile, China says it will be moving to all-electric cars and trucks to help solve its horrible urban air pollution problem.
. . Meaning global demand has nowhere to go but down.
Why do I feel that this will not end well for the American hegemon? Particularly with Trump in office working overtime with
boy genius Rick Perry to promote coal and sabotage renewable energy. . .
The 36″ North Sea Forties pipeline is currently shut down for repairs. Short and medium term prices will carry the effect of
that supply loss. In the long term, unexpected developments are common. Considering how completely wrong so many oil analysts
have been over the past ten years, including the IEA, there is not a lot of credibility in oil market predictions.
"... The fact is that the rise of the West to global dominance is due to a historical anomaly. It was fuelled (literally) by the discovery and harnessing of the chemical energy embedded in coal (late 18thC) and then oil (late 19thC). The first doubled the population, and as first movers gave the West a running start. The second turned on the afterburners, and population grew >3.5 fold. Again the West led the way. To fuel that ahistorical step-function growth curve, control of resources on a global scale became its civilizational imperative. ..."
From Patrick Armstrong's article (a good one, by the way):
A Russian threat is good for business: there's poor money in a threat made of IEDs, bomb
vests and small arms. Big profits require big threats.
Actually, I'd say the Russian threat is necessary to keep the Europeans too
frightened to protest while the U.S. steals wealth from them. After all, when the U.S.
imports goods and "pays" for them with printed money, it is basically stealing those goods.
The U.S. is draining a lot of wealth from Europe (like $150 billion a year), so something
must be done to keep them docile. Russia's perfect for that.
"(Failed) West and a multipolar Rest". The latter is what I think will actually happen
in the near and medium term.
I think we already have it, except I don't think West has failed yet. Or it has in a way,
the process of failing goes on, but the consequences have not been felt much in the West
yet.
Well, exogenous events aside, "decline and fall" is necessarily a process. A
series of steps and plateaus is typical. A major step occurred in 2007/8, when the money
failed. The bankers, in a frankly heroic display of coordination, propped up the $$$ and the
West got a decade long plateau. Things are going wobbly again, financially speaking and I
suspect the next step function to occur rather soon. Stays of execution have been exhausted, so
it'll be interesting how the West handles it, and how the RoW reacts.
Europeans have been invited to join the Eurasian Project, to create a continental market from
"Lisbon to Vladivostok". Latent dreams of Hegemony hold at least some of their elites back. The
USA has also been invited, but its dreams remain much more virile. That is, until Trump who's
backers seem to read the writing on the wall better than the Straussians.
I don't see any other power than the West (=US) aspiring to 'manage the world'....
The other 'powers' have very modest, regional aspirations... US seems to be obsessed with it.
The fact is that the rise of the West to global dominance is due to a
historical anomaly. It was fuelled (literally) by the discovery and harnessing of the chemical
energy embedded in coal (late 18thC) and then oil (late 19thC). The first doubled the
population, and as first movers gave the West a running start. The second turned on the
afterburners, and population grew >3.5 fold. Again the West led the way. To fuel that
ahistorical step-function growth curve, control of resources on a global scale became its
civilizational imperative.
That growth curve has plateaued, and the rest of the world has caught/is catching up
developmentally. The resources the West needs aren't going to be available to it in the way
they were 100 years ago. Them days is over, for everybody really, but especially for the West
because it has depleted its own hi-ROI resources, and both of its means of control (IMF$ System
& U$M) of what's left of everybody else's are failing simultaneously. So its plateau will
not be flat, or not flat for long between increasingly violent steps.
The West rode an ahistorical rogue wave of development to a point just short of Global
Hegemony. That wave broke, and is now rolling back out into the world leaving the West just
short of its civilizational resource requirements. No way to get back on a broken wave. In any
case, China now holds the $$$ hammer, and Russia holds the military hammer, and they've now got
the surfboard. Both of them, led by historically aware elites, know that Hegemony doesn't work,
so will focus on keeping their neck of the woods as stable & prosperous as possible while
hell blazes elsewhere.
What is really going on is that West has over-reached and can barely handle its own
problems.
IMHO, what's really going on is that the West's problems are simply symptomatic of
what "decline and fall", if not "collapse" looks like from within a failing system. A long time
ago I read the diary of a Roman nobleman who in the most matter-of-fact style wrote of exactly
the same things Westerners complain about today. How this, that or the other thing no longer
works the way it did. For all of his 60+ years, every day was infinitesimally worse than the
day before, until finally he decides to pack up his Roman households and move to his estates in
Spain. It took 170(iirc) more years of continuous decline until Alaric finally arrived at the
Gates of Rome. If wholly due to internal causes, collapse is almost always a slow motion train
wreck.
...
'there would be a vacuum' and 'Russians would move in'. This is obvious nonsense and only
elderly paranoid Cold Warrior types believe it (peterAUS?).
Actually, it's just stupid. Cold Warrior or not, the view betrays a deep and
abiding ignorance of both history and a large part of what drove the West's hegemonic
successes. That both militate against anyone else ever even trying such a thing on a global
scale can't be seen if you look at historical developments and the rest of the world through
10' of 1" pipe.
The idea that Russia wants/needs the Baltics is even more laughable than that it wants/needs
the Ukraine or Poland. None of these tarbabies have anything to offer but trouble. Noisome
flies on an elephant, it is only if they make themselves more troublesome as outsiders than
they would be as vassals would Russia move.
Venezuela's oil production has been sliding for years, but the descent accelerated in 2015
amid low oil prices and a deteriorating cash position for PDVSA and the government. Production
dipped below 1.9 million barrels in recent weeks, the lowest level in more than three
decades.
The problems will only grow worse, especially because they tend to snowball. Without cash,
PDVSA will struggle to import diluent to blend with its heavy oil – the result could be
steeper production losses. Again, without cash, existing facilities cannot be maintained,
likely leading to an accelerating pace of decline. An array of refineries are "completely
paralyzed," the head of an oil workers union told Bloomberg. Defaults on more debt payments
could spark retaliation from creditors, which could eventually put oil exports in jeopardy.
In short, the woes in Venezuela's oil industry contributed to the crisis, but the dire
economic situation will accelerate the decline of oil production.
A group of analysts told Bloomberg that they expect Venezuela's output to average 1.84 mb/d
in 2018, a level that seems surprisingly optimistic given the pace of decline underway. Other
analysts predict output will plunge much lower.
Venezuela's oil production has been sliding for years, but the descent accelerated in 2015
amid low oil prices and a deteriorating cash position for PDVSA and the government. Production
dipped below 1.9 million barrels in recent weeks, the lowest level in more than three
decades.
The problems will only grow worse, especially because they tend to snowball. Without cash,
PDVSA will struggle to import diluent to blend with its heavy oil – the result could be
steeper production losses. Again, without cash, existing facilities cannot be maintained,
likely leading to an accelerating pace of decline. An array of refineries are "completely
paralyzed," the head of an oil workers union told Bloomberg. Defaults on more debt payments
could spark retaliation from creditors, which could eventually put oil exports in jeopardy.
In short, the woes in Venezuela's oil industry contributed to the crisis, but the dire
economic situation will accelerate the decline of oil production.
A group of analysts told Bloomberg that they expect Venezuela's output to average 1.84 mb/d
in 2018, a level that seems surprisingly optimistic given the pace of decline underway. Other
analysts predict output will plunge much lower.
"... To render credible analysis of the future of unconventional shale resources in America one must have had actual first hand experience in the actual business of oil extraction. In other words, one must have had to write checks to drill wells, write checks to pay operating costs, write checks to the Federal government for taxes, write check after check, etc, etc., and watch their net revenue drop like a rock every month. Ignoring debt and economics to simply say there is 40GBO of recoverable shale oil in America is, forgive me, not in the least bit credible. ..."
"... The EIA, the IEA, almost every predictor of the future ignores the economics of shale extraction and it's debt. Those predictions are therefore meaningless. Hoping for higher oil prices to make the future work out like you want it to is not a tactic, it is not a plan. It is a disservice to people searching for knowledge. ..."
"... So, ignore the Million Dollar Way thing, and Michael Filloon, the self serving dribble in investor presentations, the "we are going to unleash America's oil 'might' on the rest of the world" Perry/Trump bullshit and listen instead to Shallow Sand. He has written some checks in his day. Best not run him off. ..."
In the interest of those few oily readers you have left on POB, Dennis (I see you ran Guy, a knowledgeable royalty owner from
Texas, off with that stupid comment about the Texas Railroad Commission), lets NOT say what you said.
Instead lets say that at $50 dollar hedged oil prices the net back, take home pay for a Bakken operator is actually $20 a barrel.
And it is. Costs are not going down, they are going up, and longer laterals and enormous frac's make true well costs actually
closer to $9M. Such a well would therefore require 450,000 BO to payout.
Some very learned people on this site, actually knowledgeable about the oil industry, who are now also gone, have proven it
will take $85 dollar plus oil prices, sustained, for the unconventional shale oil industry to pay back its debt and simply be
able to replace reserves. The days of all this enormous 'growth' crap are over.
To render credible analysis of the future of unconventional shale resources in America one must have had actual first hand
experience in the actual business of oil extraction. In other words, one must have had to write checks to drill wells, write checks
to pay operating costs, write checks to the Federal government for taxes, write check after check, etc, etc., and watch their
net revenue drop like a rock every month. Ignoring debt and economics to simply say there is 40GBO of recoverable shale oil in
America is, forgive me, not in the least bit credible.
The EIA, the IEA, almost every predictor of the future ignores the economics of shale extraction and it's debt. Those predictions
are therefore meaningless. Hoping for higher oil prices to make the future work out like you want it to is not a tactic, it is
not a plan. It is a disservice to people searching for knowledge.
So, ignore the Million Dollar Way thing, and Michael Filloon, the self serving dribble in investor presentations, the "we
are going to unleash America's oil 'might' on the rest of the world" Perry/Trump bullshit and listen instead to Shallow Sand.
He has written some checks in his day. Best not run him off.
"... I have mentioned this before, but SERIOUS TROUBLE will come down hard on the Bakken. Looks like someone hasn't been honest about its production figures. ..."
"... Fireworks will arrive shortly .. hehehe. ..."
I have mentioned this before, but SERIOUS TROUBLE will come down hard on the Bakken. Looks like someone hasn't been honest
about its production figures.
active wells increased by 158 from August to Sept and output increased by 19 kb/d for the Bakken Three Forks to 1055 kb/d.
Only 77 new wells were completed in the North Dakota in August 2017 and output increased that month by 23 kb/d.
They have added over 1,100 Bakken and/or Three Forks wells to boost production back to where it was in March, 2016.
So, conservatively $8 billion spent just to climb back up.
The amount of capital being burned on energy in the USA is truly remarkable.
Dennis, I have seen data that shows the total cost of all "shale" oil and gas wells from maybe 2003 forward, and then the gross
proceeds from same. Very interesting how far from payout the USA wells are, in aggregate.
This May 20, 2016 post was probably two years early ;-) I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that
anyone still takes their price or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious.
Notable quotes:
"... Eventually market sentiment focused on the recency bias of a 2 year glut is going to shift into the realization that disruptions, depletion, and growing demand have thrown the global balance into a dearth where inventories are being drawn to meet demand – such as the news about Saudi's relying on inventory to meet demand, the "missing" 800,000,000 barrels of OECD inventory from Q1 2016, or next weeks inevitable U.S. inventory draw. ..."
"... Suddenly, an extra outage (like say if anything happens to Venezuela) will cause meaningful rallies instead of being mostly written off. ..."
"... The best, live, interactive charts I am most fond of are here: https://www.dailyfx.com/crude-oil ..."
"... I expect one last fight around $50, a few day consolidation move lower. Then market realities will push WTI past $50, and shorts will have to cover pushing it even higher. ..."
"... Next thing you know were range bound in the mid-$50s at the end of June as everyone questions if shale production will magically skyrocket overnight. Maybe the rig count will go up by 3 or 4, and it'll spark a sell-off back to or below $50 because of the psychological recency bias of a "repeat of 2015". ..."
"... I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that anyone still takes their price or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious. ..."
"... Most people are simply incapable of seeing a bigger picture, and they'll simply never understand the relationship between depletion, economic and population growth, and the long-term fact that this equals higher prices (and probably also, in the long run, higher poverty and unemployment). ..."
"... It is for that exact same reason that so many people we know will simply never get it. Physics doesn't have agency, it cannot be avoided, cajoled, or "blamed". It simply is, and that is so unsettling to our psyche that most people have a strong, unconscious drive to negate and ignore that conclusion even if they will acknowledge it is a sound and true explanation of how economics, growth, employment, wealth, energy (physics and thermodynamics), and depletion are woven of the same fabric. ..."
"... Brian – I think you are closer to reality than EIA or USGS, it will be interesting to see how it plays out against your scenario. ..."
"... There doesn't necessarily have to be more social breakdown in Venezuela to have an impact – Haliburton and Schlumberger are pulling out and will have immediate effect as the extra heavy oil production needs continuous attention to the wells. I'm surprised Angola and Algeria haven't seen disruptions yet either. ..."
"The joint-venture Syncrude project told customers to expect no further crude shipments for May, trading sources said on Thursday,
extending a force majeure on crude production from earlier in the month."
Eventually market sentiment focused on the recency bias of a 2 year glut is going to shift into the realization that disruptions,
depletion, and growing demand have thrown the global balance into a dearth where inventories are being drawn to meet demand –
such as the news about Saudi's relying on inventory to meet demand, the "missing" 800,000,000 barrels of OECD inventory from Q1
2016, or next weeks inevitable U.S. inventory draw.
Suddenly, an extra outage (like say if anything happens to Venezuela) will cause meaningful rallies instead of being mostly
written off.
In fact, judging by the price action on oil over the last 24 hours, I'd say that sentiment is very close to a shift. From 11
AM forward crude oil marched higher relentlessly, even in opposition to dollar strength. Most every single commodity was down,
as we're most every stock market except oil.
I expect one last fight around $50, a few day consolidation move lower. Then market realities will push WTI past $50, and
shorts will have to cover pushing it even higher.
Next thing you know were range bound in the mid-$50s at the end of June as everyone questions if shale production will
magically skyrocket overnight. Maybe the rig count will go up by 3 or 4, and it'll spark a sell-off back to or below $50 because
of the psychological recency bias of a "repeat of 2015".
That is, until rational minds, or the market itself pushes prices back up as it becomes obvious that a slowdown in U.S. production
declines will mean little in the face of mounting production declines around the globe, and "surprisingly" strong demand – because
apparently predicting that lower prices will cause stronger than average demand growth is beyond the economic capability of the
EIA or IEA, and markets tend to take their word as gospel.
I remember looking back on the IEA's 2005 World Energy Outlook and being perplexed that anyone still takes their price
or production forecasts with any seriousness whatsoever. Their 2003 WEO is even more hilarious.
Every step of the way analysts and talking heads will be confused that prices aren't dropping back to $30 just like they were
for 5 straight years from 2003 to 2008. They'll predict Saudi's will raise production to 12 mbpd any day now, or that shale will
magically take off overnight.
They'll never even realize that they don't understand the history of Saudi production, or the logistical and financial complexities
of shale production rising as fast as it did before. Instead they'll blame the banks, or speculators, or Big Oil for artificially
making oil prices rise (without questioning why they let them fall for 2 years in the first place)
But then again if gas is cheap, which average people are fond of, their brain says "I like this, so it must be right". If gas
is expensive their brain says "I don't like this, it must be wrong, what evil force made this happen?!?"
Most people are simply incapable of seeing a bigger picture, and they'll simply never understand the relationship between
depletion, economic and population growth, and the long-term fact that this equals higher prices (and probably also, in the long
run, higher poverty and unemployment).
Their lives will have ups and down, growth and recession, but they'll know and feel it is generally getting harder. They'll
never be aware that this is the "fault" of nothing but physics and thermodynamics, even if told directly and shown all the rather
clear evidence (I know every one of you has experienced this as I have). Instead, they'll blame those dang immigrants, or the
Chinese, or the Congress, or regulations.
They'll blame anything that fits their paradigm enough to allow cohesiveness so their fragile lives can at least MAKE SENSE.
You can't blame physics, and, frankly, I think that is a large psychological barrier for people comprehending what is happening.
We need to have some agent to blame for things, and physics has no agency. Blaming something for a problem is settling because
it gives us something to focus on to solve the problem, or, at the very least, avoid it. The evolutionarily beneficial need to
assign agents as the cause of events is what pre-disposes us to believing that events we cannot easily assign agency to are, nonetheless,
the will of a greater, invisible, omnipresent agent.
It is for that exact same reason that so many people we know will simply never get it. Physics doesn't have agency, it
cannot be avoided, cajoled, or "blamed". It simply is, and that is so unsettling to our psyche that most people have a strong,
unconscious drive to negate and ignore that conclusion even if they will acknowledge it is a sound and true explanation of how
economics, growth, employment, wealth, energy (physics and thermodynamics), and depletion are woven of the same fabric.
Brian – I think you are closer to reality than EIA or USGS, it will be interesting to see how it plays out against your scenario.
A couple of other impacts are summer maintenance season in North Sea (Buzzard and, I think, Ekofisk have major turnarounds),
Alaska and Canada (maybe Russia as well) and increased demand from driving season in USA and AC use in Middle East.
There doesn't necessarily have to be more social breakdown in Venezuela to have an impact – Haliburton and Schlumberger
are pulling out and will have immediate effect as the extra heavy oil production needs continuous attention to the wells. I'm
surprised Angola and Algeria haven't seen disruptions yet either.
Thank you George. IEA will release their WEO next week (14th).
From the OPEC-report:
"Total non-OPEC liquids supply is now forecast to grow from 57 mb/d in 2016 to 62 mb/d in
2022, with the US alone making up 75% of that increase."
The section on decline rates was interesting too (p.184): "the WOO analysis suggests an
average implied decline rate of around 4.4 mb/d in the 2018–2028 period, or 7%, of
underlying non-OPEC suply. Note that this compares with previous, more in-depth, work done by
the Secretariat, which indicated
that underlying observed decline rates in non-OPEC were lower – on average around 5.4%
– though with significant regional variations.
On the one hand, this analysis shows the challenge facing the upstream sector, with a
requirement for more than 5 mb/d p.a. of new supply, if annual average demand growth of 0.9
mb/d in the Reference Case is added to the implied 4.4 mb/d 'lost' due to natural decline. On
the other hand, the calculated implied decline rates and substantial new upstream volumes
coming online suggest that overall upstream investment activity is perhaps higher than a
quick glance at headline capex numbers would suggest "
"with tight oil making up a substantial and growing share of total non-OPEC supply (around
12% in 2016), and given its innate rapid decline rates after initial production, this may in
a sense have accelerated the underlying decline. In other words, the system can said to be
coping, with supply growth meeting demand needs at the moment"
"that overall upstream investment activity is perhaps higher than a quick glance at headline
capex numbers would suggest "
Nope it would suggest that the developments coming on line now follow a normal project
S-curve with the big investment costs in the middle then slowing down during installation and
commissioning.
There aren't many projects in the middle of the development so costs are down but the new
production coming on line is still fairly high (until the second half of next year). The
investment problem isn't going to show up really until a couple of years out, but it can't be
halted by anything that's done now, just like the over-investment impact kept running even as
oil prices crashed.
With all the kerfuffle in Saudi whatever happened to the independent assessments of their
reserves? There was a leaked report that said everything was exactly as the Saudi had been
reporting, which couldn't possibly have credibility as it came out about a week after the
consultants had started work so they wouldn't even have got their computers working properly
yet, and then something about the reports being released early next year – and since
then nothing.
"... So perhaps Bakken oil production peaked in 2015. But that depends on how many new wells will be added the coming years. ..."
"... Regarding downspacing, it has been a real crapshoot throughout all the shale plays. Operators had been purposefully drilling closer and closer and monitoring results. The biggest influencing factors (among many) seems to be the permeability and brittleness of the rock. ..."
"... Utica operators are back to 1,000 foot spacing while Marcellus operators continue to drill 500′ or less. Again, the thickness of these formations plays a big role as 3 dimension, not 2, come into play. 80% production in offset wells is the commonly quoted figure from several operators, and they seem to be okay with that. ..."
"... Be advised, Bakken operators have recently changed their flowback procedures and early month produced water numbers have skyrocketed. New wells now show 150/200 thousand barrels produced water their first few months online. ..."
Thanks that is really interesting. As most wells in Bakken are 10000 feet long, 500 feet well
spacing would translate into about 5 wells per section in Bakken. As I mentioned some time
ago, the Grail area in McKensey has close to 5 wells per section now. The 2016 wells there
had worse production than previous years and they have almost stopped drilling new wells
there. As there are maybe 1500 well locations left in the sweet spot area of McKensey
(assuming 5 wells per section) and they are adding perhaps 40 wells per month now, it means
that there are only some 3 years of new wells left. But it's not like they will add 40 wells
per month and then suddenly stop.
So more and more wells need to come from outside the sweet spots the coming years. Because
of the red queen phenomena, if new wells start to produce less, then more wells are needed
just to keep total production flat. So perhaps Bakken oil production peaked in 2015. But
that depends on how many new wells will be added the coming years.
One needs to remember the Three Forks formation when doing those kind of calculations.
Some of the higher producing wells in North Dakota these past 2 years targeted the second
bench of the TF.
There have been very few third bench TF wells and, I believe, only a couple targeting the
fourth bench so far.
Regarding downspacing, it has been a real crapshoot throughout all the shale plays.
Operators had been purposefully drilling closer and closer and monitoring results. The
biggest influencing factors (among many) seems to be the permeability and brittleness of the
rock.
Utica operators are back to 1,000 foot spacing while Marcellus operators continue to
drill 500′ or less. Again, the thickness of these formations plays a big role as 3
dimension, not 2, come into play. 80% production in offset wells is the commonly quoted
figure from several operators, and they seem to be okay with that.
BTW, I appreciate the charts you regularly post here.
Be advised, Bakken operators have recently changed their flowback procedures and early
month produced water numbers have skyrocketed. New wells now show 150/200 thousand barrels
produced water their first few months online.
As much as
US$1 trillion
of investments has either been deferred or canceled
with the lower-for-longer oil prices, and this underinvestment will
impact the future of energy, Amin Nasser, the chief executive of Saudi
Aramco, said on Tuesday.
"Not much investments have been going into the
energy sector... $1 trillion has been either deferred or cancelled,"
Nasser said at the Future Investment Initiative conference in Riyadh.
Of the US$1 trillion investment, US$300 billion was earmarked for oil
exploration and another US$700 billion for project developments,
according to the CEO of the state-held oil giant of OPEC's biggest
exporter and de facto leader Saudi Arabia.
"This will have an impact on the future of energy if nothing happens,"
Nasser noted, adding that investments are necessary because of "natural
depreciation of fields and normal rise in demand."
"We are witnessing a transformation... But it will be decades before
renewable energy takes a major share in the energy mix," the head of the
oil giant said.
In July, Nasser said that if the oil and gas industry didn't start
investing again, the global oil supply/demand curve will
reach a turning point
in "a couple of years."
"About $1 trillion in investments have already been lost since the
current downturn began," Nasser said in a
speech
at
the World Petroleum Congress in Istanbul in July.
One of the world's largest fossil fuel companies is betting on electric cars.
Royal Dutch Shell (RDSA) revealed a deal on Thursday to acquire NewMotion, one of Europe's
largest electric vehicle charging providers. NewMotion specializes in converting parking
spots into electric charging stations. The Dutch firm has more than 30,000 electric charge
points in Europe.
The acquisition, Shell's first in this space, shows how Big Oil is being forced to confront
the long-term threat posed by electric cars and efforts to phase out gasoline and diesel
vehicles.
Or maybe the other way round – there's no oil left to develop so they have to find
something else to do – or both supply and demand influences, which is the reality of
all economic decisions, not one or the other however much the media feels it has to simplify
things to that level.
Interesting article. I believe we are going to see a more rapid disintegration of the
Ultra-Deepwater Drilling Industry when the markets finally correct by 20-50%. The notion that
the Ultra-Deepwater Drilling Industry will recover by 2020 or 2024 doesn't take into account
that the broader U.S. Stock markets have experienced a 230% increase from the lows without a
typical 15-20% correction.
Hell, I believe the S&P 500 just hit a record of not experiencing a 3% correction for
more than 453 days.
Transocean drilling rig utilization fell from a peak of 95% in 1H 2013 to 37% in the 1H
2017. Of the 17 Ultra-Deepwater rigs currently drilling for oil in the GoM (source: Baker
Hughes), one leased by Chevron was terminated early. So, the total will be down to 16 in
November.
Again, the wild card of much higher oil prices will only occur if the Fed and Central
banks start up the printing press BIG TIME. When the Fed's QE3 program ended, the price of
oil plummeted.
However, when the Central banks print like crazy, this won't last long. Thus, it won't be
enough to allow the Ultra-Deepwater Drilling Industry to recover.
No idea – I don't do the oil price prediction thing because I'm pretty sure nobody in
history has ever got it right for the right reason. For real 'frontier' type exploration to
start again then there would have to be a pick up in lease sales and really they have been
tailing off even in the high price years (I think I put some charts in a previous post on the
GoM showing how the percentage of offered leases taken up has been falling off. I doubt if
shallow a lot of the deep lease areas will pick up again though, there's little left.
In my opinion, exploration will not pick up too much regardless of oil price because of the
maturity of the basin, as George suggests above. (Actually, exploration may pick up a fair
bit with higher oil prices, but significant successes probably won't).
Now there certainly are those that would disagree with that, and, since I'm still in the
industry, I often hear the message about the tremendous remaining potential in the northern
deepwater GOM coming from those in the ra-ra corner.
Not much and no. I think, if anything, the future GoM production will be a bit less than I
expected about six months ago. As far as STEO goes I think they come up with a future profile
once a year and then just bias it up and down to meet this month's production number –
I think a new profile must be due soon. There is about a 10% decline per year, which might
increase a bit now, so about 170,000 bpd is needed to maintain a plateau, but the STEO has
another 100,000 per year of growth. Next year there is only Stampede early on, which has
topsides nameplate of 60,000, but only 50,000 planned with the rest available for tie backs
and probably only about 70% availability in the first year; plus Constellation – which
has maybe 30,000 but depends on decline in the rest of the Caesar-Tonga field to allow
capacity for some of it, so not all of that is net gain; the LLOG fields I described above;
and Big Foot at the end which won't contribute much in 2018. So from July 2017 to Dec. 2018
they lose maybe 230,000 and add about 90,000 to 110,000 maybe with a bit of brownfield as
well. There's also Atlantis North but I think that only maintains a plateau against fast
declines from their other wells. But EIA are saying the GoM adds 330,000. Also in 2019 Big
Foot isn't going to ramp up fast, contrary to what I previously thought. It has dry trees,
only two have been fully predrilled, the others have the top two conductor sections drilled
but the on-platform rig will have to complete them. I think the oil is pretty heavy so not
huge production from a single well, therefore even with a 70,000 nominal topsides nameplate,
the wells and the usual low availability in the first year will be limiting.
EIA's monthly production data to end of July says US production vs 2016 is averaging about
3.4 million barrels per month higher. divided by 30 is 114K bpd increase over last year
averaged month by month. (not month to month)
For Texas it's 90K bpd increase over last year, as of end of July, averaged month by
month. That's most of the 114K.
Don't know if that's far enough back in months for the correction we get here to have
moderated.
It contains a lot of interesting information. For example on page 15 we can see that oil
field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has
fallen of a cliff is not an exaggeration.
"... I already picked the peak, 2015. So I was slightly off, but not by all that much as you can clearly see by the chart. I think we are on the peak plateau right now. ..."
I already picked the peak, 2015. So I was slightly off, but not by all that much as you can
clearly see by the chart. I think we are on the peak plateau right now.
The actual 12-month
peak could be anywhere from 2017 to 2019 but no later than that. Well, in my humble opinion
anyway.
The question was about US LTO, you have picked the World C+C peak, but as far as I
remember you have not said anything recently about US LTO except that it will be before
2025.
So far the 12 month centered average for US LTO peaked in June 2015.
If US LTO output continues at the August output level (4750 kb/d) for 5 months, then a new
12 month centered average peak will be reached by Aug 2017 (average output from Feb 2017 to
Jan 2018). US LTO output has risen about 600 kb/d over the past 12 months so an assumption of
no further US LTO output increases over the next 5 months is a conservative estimate in my
view.
"... A bit old so you may have seen it already. But if you haven´t then I highly recommend you to read the global oil supply report from HSBC: YouTube clip: https://www.youtube.com/watch?v=7KfVJBNX2U4 The report: https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has fallen of a cliff is not an exaggeration. ..."
Iraq's oil production has increased by 1.4 million b/day since oil prices last averaged $100
in July 2014. More than any other country
Chart on Twitter: https://pbs.twimg.com/media/DMHrqLZXkAAFiro.jpg
The report:
https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view contains a lot of interesting information. For example on page 15 we can see that oil
field discovery rate has dropped from around 20% to only 5% in 2015. Saying that it has
fallen of a cliff is not an exaggeration.
Great to see you posting an update. I can honestly tell you that the "WEIRD" rise in
production per well in the Bakken may not be as high as the data shows. Unfortunately, I
can't publicly state the reason I know this. If you contact me via my email address: SRSroccoReport@gmail.com , I can provide a few more
clues.
However, the SHITE is going to hit the fan in the U.S. Shale Oil Industry once this news
gets out which will likely be made public shortly.
2017-10-11 BSEEgov: From operator reports, it is estimated that approximately 32.68 percent
of the current oil production in the Gulf of Mexico remains shut-in, which equates to 571,854
barrels of oil per day. It is also estimated that approximately 20.51 percent of the natural
gas production, or 660.55 million cubic feet per day in the Gulf of Mexico is shut-in.
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-tropical-storm-nate-activity-4
Estimate of "Lost" Gulf of Mexico crude production due to Hurricane Nate is 7.82 million
barrels of oil.
(Possible paywall, I can't quite figure out how it works on Energy Voice)
"This is particularly evident when we look at investment. While investments are expected
to pick up slightly this year and in 2018, it is clear that this is not anywhere close to
past levels and it is more evident in short-cycle, rather than long-cycle projects, which are
the industry's baseload.
"The issue of a potential investment shortfall was a recurring theme at last week's
Russia Energy Week conference, with President Vladimir Putin, as well as many oil and
energy ministers making reference to the critical investment challenge.
"As we have all learned from previous price cycles, such pronounced and long-term
declines in investments are a serious threat to future supply. But given our projected
future demand for oil, with our upcoming World Oil Outlook 2017 expecting demand to reach
over 111 million barrels a day by 2040, an increase of almost 16 million barrels a day, the
world simply cannot afford a supply crunch."
It's noticeable that OPEC, IEA and drillers/service companies, even the Aramco CEO are
raising the lack of investment more and more, but they all stay away from discussing the fall
in discoveries and lack of attractive prospective projects. Part of it is real concern,
though it's noticeable they don't offer much in the way of solutions, and definitely none
that might impact their bottom lines in the short term, but part is pre-emptive
arse-coverage.
A lot of factors seem to be lining up for an economic bust next year, but then they have
looked like that for a few years (maybe the low oil price has contributed to staving off the
problem), if it happens a supply crunch might go unnoticed for some time, and only come
appear as the real problem it will be when there is some sort of recovery expected.
"... This year's rise is likely to be closer to about 500,000 barrels, far off an initial forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of Continental Resources Inc. and a pioneer in the shale industry. ..."
"... The EIA projection is "just flat wrong," failing to take into account a new discipline among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability of producing a whole lot, but you have to get a return on investment," he said, adding, "that's where people have been this last quarter and this year." ..."
"... . "When we're lagging the Brent world price by $6 a barrel, that's not putting America first, that's putting America last. And that's the result of this exaggerated amount that EIA has out there." ..."
"... Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50 now, Hamm said. ..."
Shale oil entrepreneur Harold Hamm is back doing interviews on the business networks again.
Now he is speaking out against how the oil prices are low due to the EIA.
Shale Billionaire Hamm Slams 'Exaggerated' U.S. Oil Projections
Billionaire oilman Harold Hamm says the government was way too optimistic with its
prediction of more than 1 million new barrels a day in U.S. production, and the snafu is
"distorting" global crude prices.
This year's rise is likely to be closer to about 500,000 barrels, far off an initial
forecast by the U.S. Energy Information Administration, according to Hamm, the chairman of
Continental Resources Inc. and a pioneer in the shale industry.
The EIA projection is "just flat wrong," failing to take into account a new discipline
among U.S. drillers, Hamm said in an interview Thursday on Bloomberg TV. "We have capability
of producing a whole lot, but you have to get a return on investment," he said, adding,
"that's where people have been this last quarter and this year."
The government scenario has contributed to worries about an oversupply that puts U.S. oil
at a steep discount to international crude, according to Hamm. "It's distorting," he said
. "When we're lagging the Brent world price by $6 a barrel, that's not putting America
first, that's putting America last. And that's the result of this exaggerated amount that EIA
has out there."
Once it's clear the EIA is off base, prices could rise to $60 a barrel from around $50
now, Hamm said.
The EIA is making these projections because knuckleheads in the C suite at US shale companies
went hog wild at the first sign of oil price improvement and made these growth projections
for their individual companies, and the EIA just totaled them up.
Every Shale CEO bashes OPEC. OPEC tried to give shale a break by cutting production, and
shale absolutely blew it, just like shale absolutely blew it in late 2014 by not pretty much
shutting down. Instead, shale has lied about profitability for 3 years, and the world E &
P industry has paid the price.
Too bad Oilpro shut down. Lots of non-US E & P Industry folks posted there. They
absolutely could not stand US shale and the US shale CEO smack talk. Hundreds of thousands
out of work, because of shale smack talk and Wall Street encouragement of same, which crashed
oil prices below $30.
Shale better come through. No one seems to be taking serious the possibility of a supply
shock if it cannot.
When shale clearly peaks, what is to keep OPEC and Russia from suddenly making a big cut,
driving prices past $200 and crashing Western economies? Why wouldn't they afterthe hubris of
US shale CEO's, the Wall Street guys who pull their strings, and the US business media who
report everything they say as gospel?
I'd guess a lot of the non-US E&P people complaining about LTO would by from offshore,
and I think that side has been just as much to blame for boom and bust mentality with rose
tinted specs. (see below the UK investment which went nuts when oil went above $100 and now
they have nothing much left). I'd question with the jobs are going to come back offshore even
with a big price rise. As I keep pointing out, there have to be discoveries before
development, and there have to be lease sales before that. We're not seeing either, and
though exploration is down compared with 2011 to 2014, there's still a significant amount
going on, but wildcat, frontier success rates are what have fallen the most (even with the
best seismic methods and computer models we have ever had).
Shallow, I too miss the hell out of Oilpro. That community could debate the unconventional
shale phenomena without bias and with a clear understanding of how it has completely changed
the world oil order.
American's, on the other hand, simply enjoy cheap gasoline; they don't care how they get
it, what it costs, who ultimately pays for it or that it will not last forever. The American
public, and the politicians that govern it, have been lied to and completely deceived about
shale oil and shale gas abundance. It is a matter of American nationalistic pride to believe
what one reads on the internet and to otherwise be stupid about our hydrocarbon future.
I suggested to you several years ago that OPEC and the rest of the world's producing oil
countries were not dumb; they read shale oil K's and Q's and have the same access to SEC
filings we do. They know the shale oil phenomena is failing financially and that in the
process America is drilling the snot out of its last remaining, bottom of the barrel oil
resources. OPEC's production cuts in late 2016, in my opinion, were an effort to give the US
shale oil industry just enough rope to eventually hang itself. It has done just that; in the
past 24 months it has bankrupted out on another $50B, borrowed yet another $50B and is now
back over $300B of upstream long term debt with no current ability to pay that back. Hope
(for higher oil prices) is not a plan. The Bakken and the Eagle Ford have peaked and now well
productivity in the Permian is starting to fade. In a few more years the rest of the world
will have the US right back it its teet and will dictate what the price of oil well be. I
think in the next 12-18 months we are going to see big reserve impairments in the US, again,
and a pretty big shale oil company will end up the toilet, bankrupt. They'll be a bunch of
fist pumping going around the world when that happens.
Harold Hamm is whiner; he has always blamed OPEC for lower oil prices, demanded that OPEC
cut more production, he needs more pipelines, fewer regulations (where are those, by the
way?), needs to be able to export his oil, warned OTHER shale oil companies in the Permian
not to overproduce and drive the price of HIS oil down, the sun is always in his eyes now its
the EIA's fault. He, like the rest of America's shale oil industry, is desperate for
attention and desperate for help. Once again, Shallow, you are spot on.
Mike. It might be worth mentioning here the recent judgment a small OK producer won against
Devon Energy.
Apparently one of Devon's high volume fracs destroyed one of the the conventional
producers' wells.
When I read about these frac hits, I really worry that US is not properly managing these
shale oil resources.
From some reading it appears frac hits are a big deal in PB, and that just a few years in,
PB shale could wind up unperformimg due to reservoir damage from these massive fracs.
So if we assume that since 2014 at least 8 million barrels per day were lost due to aging
fields. Who provided additional supply to keep it steady. Something is fishy here.
Notable quotes:
"... If you're not bringing new production online and the global decline rate is call it 5% then each year from now until 2020 we should see a loss of about four and a half million barrels per day off of supply ..."
"... And in 3 years that's 13 million barrels per day supply reduction and there is no way countries can feed themselves with that quick level of scarcity. ..."
"... Venezuela dropping to 0 while the Lybian civil war flames up again – and there isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for capacity he don't need and use. Or develops fields and put them on idle. ..."
"... Venezuela is the best example of low oil prices making high one – the production will halt sooner or later. ..."
Way too glib a presumption of supply shortage in the 2020 time frame.
If you're not bringing new production online and the global decline rate is call it 5%
then each year from now until 2020 we should see a loss of about four and a half million
barrels per day off of supply
And in 3 years that's 13 million barrels per day supply reduction and there is no way
countries can feed themselves with that quick level of scarcity.
When one says "supply shortage" the consequence of significance is not higher prices; the
consequence is unfilled orders.
RIO DE JANEIRO, Sept 27 (Reuters) – Only one block in Brazil's prized offshore Santos
basin received a bid in the country's 14th oil round on Wednesday, a sign low global oil
prices may have reduced the allure of potential new crude and gas investments in Latin
America's largest economy.
A lot more interest in the other basins though, especially Campos. It can't be just oil price
that is against Santos, maybe it's similar to the mirror province in Angola, Kwamza, and it's
turning out to be a bust.
I think this year has killed off a few of the promising frontier basins now – Kwanza in
Angola – bust, deep water offshore Canada – mostly bust, Barents – mostly
bust, Santos – looks bust, ultra deep US GoM – mostly played out or uncommercial,
offshore Colombia – looks bust for oil, couple of West Africa areas – dry holes,
offshore Ireland – half way to bust, UK North Sea – very poor lease sale, also
one other lease sale (maybe Oman?) I think didn't do very well from memory.
MARKET SHOULD PREPARE MORE FOR OIL SQUEEZE THAN OPEC SUPPLY GAIN, CITIGROUP SAYS
Those in the oil market fearing a flood of OPEC supply next year will probably be better
off preparing for a shortage, according to Citigroup Inc.
Five countries in the group -- Libya, Nigeria, Venezuela, Iran and Iraq -- may already
be pumping at their maximum capacity this year, Ed Morse, the bank's global head of
commodities research, said in an interview. Rather than a surge in output, there's a risk
of a market squeeze emerging as early as 2018, driven by those nations because of weaker
investment in exploration and development, he said.
"Fear in the market has been that OPEC production will rise dramatically," said Morse.
However, "there could be a supply gap emerging, which could point to a tighter market," he
said in Singapore on the sidelines of the S&P Global Platts APPEC Conference.
Geology has to do a lot with oil prices – the run up in price the last 40 years is
mostly due to geology.
Why? The original oil was the kind of very conventional land based oil. Once discovered,
the most costly thing was the infrastructure to transport it away.
This came to a limit in the 70s. After this, more and more expensive projects where
necessary.
Off shore oil, deep sea oil, small spots on land, arctic oil and last fracking oil. And
old fields with injections, infill, pressure control.
All things with big investments – much more than "we build an oil terminal for
supertankers and drill a few holes".
And so the market gets more and more unstable – these big investments have to pay
out, even when done by a state. And you have bigger and bigger planning time lags, so the
classical pork cycle can get investors in the false moment.
US fracking oil adds to the chaos – it's expensive, but fast rampup – but not
able to replace deep sea oil due to it's pure size.
Old cheap fields are in decline, or not longer cheap as the chinese giants on secondary or
tertiary recovery enhancements. So more and more expensive technology with long planing
horizonts comes to a short paced market, together with the political chaos describes by
you.
And geology gets more complicated, so the long project times you describe will get
longer.
I, without a mathematically model, expect a chaotic market in the future until oil gets
(hopeful) phased out and put in the steam engine age.
Low oil prices make high oil prices, and high ones low. The demand is very inelastic on
the short term, trucks have to drive and people have to drive to work (and the aunt wants the
chrismas visit). Only mid way demand gets flexible, a japanese car instead a SUV next or a
house nearer at the job. Or a company reduces work travelling.
Many 3rd world countries have regulated gas prices – so a price spike don't reduce
demand here on the short term. That makes things even more scary when something happens on
the political scale.
Venezuela dropping to 0 while the Lybian civil war flames up again – and there
isn't 3 MB/D spare capacity left. Nobody besides SA perhaps does frenetic infill drilling for
capacity he don't need and use. Or develops fields and put them on idle.
Venezuela is the best example of low oil prices making high one – the production
will halt sooner or later.
Higher than $50 per barrel WTI essential for a meaningful return on capital. May be even
higher then $65 per barrel. right now shale oil production is possible only by simultaneous
generation of junk bonds.
Notable quotes:
"... Higher than $50 per barrel WTI essential for a meaningful return on capital ..."
"... if WTI remains stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their ambitions, because they won't generate enough cash to reinvest in growth. Second, shale drillers might actually worsen their financial position if they pursue growth. Spending more to produce more -- while that could lead to more oil sales -- might not necessarily be the wisest strategy. ..."
"... For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has made some headlines shorting Continental Resources. He argues that shale companies simply have to spend too much to keep production going. Shale drillers "are creatures of the capital markets," he told Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to replace the assets. And this is the crux of the story." ..."
"... Another significant observation is that the shaky financial position for some shale drillers also suggests that the downside risk to oil prices might not be as serious as once thought. ..."
"... "The market may well discover it has been asleep at the wheel and far too relaxed about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil trader Trafigura, told an industry conference in Singapore last week. ..."
"... All of the highly-touted cost reductions and efficiency gains have already been "realized." Moody's lowered its outlook for these large oil companies in 2018 from "positive" to simply "stable ..."
The
extraordinary cost reductions achieved by North American oil and gas companies have likely
reached their limit, and any boost in profitability for much of the U.S. shale and Canadian
oil sands industries will have to come from higher oil prices, according to a new report from
Moody's Investors Service.
Moody's studied 37 oil and gas companies in Canada and the U.S., concluding that although
the oil industry has dramatically slashed its cost of production in the past three years and
is currently in the midst of posting much better financials this year, there is little room
left for more progress.
"After substantially improving their cost structures through 2015 and 2016, North American
exploration and production (E&P) companies will demonstrate meaningful capital efficiency
to the extent the West Texas Intermediate (WTI) oil price is above $50 per barrel and the
Henry Hub natural gas price is at least $3.00 per MMBtu," Moody's
said . In other words, WTI will need to rise further if the industry is to improve its
financial position.
The report is another piece of evidence that suggests the U.S. shale industry is perhaps
struggling a bit more than is commonly thought. U.S. shale has been portrayed as nimble, lean
and quick to respond to oil price changes. And while that is largely true, strong profits
remain elusive, despite the huge uptick in production.
Shale drillers have substantially lowered their breakeven prices, but further reductions
will be difficult to achieve, Moody's Vice President Sreedhar Kona said in a statement.
" Higher than $50 per barrel WTI essential for a meaningful return on capital ,"
Moody's said.
The findings are important for a few reasons. First, it suggests that if WTI remains
stuck at about $50 per barrel, U.S. shale drillers might be forced to reign in their
ambitions, because they won't generate enough cash to reinvest in growth. Second, shale
drillers might actually worsen their financial position if they pursue growth. Spending more
to produce more -- while that could lead to more oil sales -- might not necessarily be the
wisest strategy.
For similar reasons, Jim Chanos, short-seller and founder of Kynikos Associates, has
made some headlines shorting Continental Resources. He argues that shale companies simply
have to spend too much to keep production going. Shale drillers "are creatures of the capital
markets," he told
Bloomberg . "Because the wells deplete so quickly, they constantly need to raise money to
replace the assets. And this is the crux of the story."
Another significant observation is that the shaky financial position for some shale
drillers also suggests that the downside risk to oil prices might not be as serious as once
thought. The oil market has tried to assess how quickly shale production would come
roaring back. Reports that shale companies were posting juicy profits at very low oil prices
has likely factored into heady projections for shale output. The EIA has repeatedly projected
that shale output would average 10 million barrels per day next year (although they have
revised that down recently to just 9.8 mb/d).
But that might be overly optimistic if a long list of shale companies are not posting
"meaningful" returns on capital.
"The market may well discover it has been asleep at the wheel and far too relaxed
about shale keeping a ceiling on prices forever," Ben Luckock, a senior executive at oil
trader Trafigura,
told an industry conference in Singapore last week. Bloomberg surveyed a bunch of
oil traders and energy executives at the conference, and the general sense was that oil would
trade between $50 and $60 per barrel, up from an informal consensus of between $40 and $60
last year. While there are many reasons for the newfound bullishness, more modest
expectations about shale growth is certainly one of them.
In a
separate report focusing on larger integrated oil companies, Moody's came to a similar
conclusion -- that the substantial improvement in the financial position of the oil industry
over the past year is poised to slow down. All of the highly-touted cost reductions and
efficiency gains have already been "realized." Moody's lowered its outlook for these large
oil companies in 2018 from "positive" to simply "stable ."
How comes? Annual world demand raises around 1.5 million BPD per year. So since 2014 it rose
probably 4 million BPD. And there is no sizable new discoveries. Iran and Libya cards were
already played and total from them is less then 4 million barrel per day. US output is stagnant.
Canadian is down. Where all this additional oil is coming from ?
Iran is currently exporting about 3 million BPD of crude and condensate vs. less than 1
million BPD when the sanctions were in place.
Libya and Nigeria have increased production by about 0.5 BPD undercutting the 1.2 million BPD
OPEC production cut.
Turkey already threatened to close their border with Iraqi Kurdistan, halting the 0.6 BPD of
oil that the Kurds are exporting through Turkey.
Venezuela problems might take another million BPD off the global market.
KSA has recently been forced to borrow $12.5 billion after borrowing $17.5 billion last
year.
Notable quotes:
"... The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day (BPD) to 1.42 million BPD. ..."
"... China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY) increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded during the same period in 2016. ..."
OPEC crude oil production decreased by 79,000 BPD in August to average 32.8 million BPD.
This marks the first OPEC production decline since April and was primarily driven by sizable
outages in Libya.
The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day
(BPD) to 1.42 million BPD. The group reports strong growth from the OECD Americas, Europe,
and China. Global oil demand for 2018 is expected to grow by 1.35 million BPD, an upward
revision of 70,000 BPD from the previous report. Growth next year is expected to be driven by
OECD Europe and China.
China's oil demand rose by 690,000 BPD in July, marking a 6 percent year-over-year (YOY)
increase. China's total oil demand reached 11.67 million BPD in July. Year-to-date data
indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded
during the same period in 2016.
China's gasoline demand was higher by around 0.10 million BPD YOY, driven by robust sports
utility vehicle (SUV) sales, which were around 17 percent higher than one year ago. China's
overall vehicle sales in July rose by 4 percent YOY, with total sales reaching 1.7 million
units.
The numbers from China are interesting given the constant refrain of weakening Chinese
demand. This seems to be wishful thinking based on China's investments in clean technology.
Proppant isn"t free. If you use more of it, it costs more. If you add a different kind it
costs more.
And the executive bonuses are production based, not profit based. If they can get other
people to fund via loans those bonuses then of course they will do it.
You want evidence the proppant pays for itself in production? You can find it. It appears
in the earnings per share number. If it doesn't then there is no evidence.
This is no different than drilling holes to recover pores of oil amounting to 20 barrels,
total. At $45/b you get $900 from that. If someone else pays the $7 million for the hole, why
not drill?
"Investors who'd plowed $2 billion four years ago into a private equity fund that had also
borrowed $1.3 billion to lever up may receive "at most, pennies for every dollar they
invested," people familiar with the matter told the Wall Street Journal."
It is the same WSJ that last 4 years were writing about "resilience of shale" like
parrots, every day. Of course it is resilient with Gran Ma and Gran Pa money if you look that
it was mostly pension funds that are invested.
"Only seven private-equity funds larger than $1 billion have ever lost money for
investors, according to investment firm Cambridge Associates LLC. Among those of any size to
end in the red, losses greater than 25% or so are almost unheard of, though there are several
energy-focused funds in danger of doing so, according to public pension records."
So now those evil shale people are screwing Grand Pa and Grand Ma out of their hard-earned
savings?
After all, we have it straight from WolfStreet. Wolf Richter blasts the unscrupulous shale
industry when he writes:
"
The renewed hype about shale oil – which is curiously similar to the prior hype
about shale oil that ended in the oil bust – and the new drilling boom it has
engendered, with tens of billions of dollars being once again thrown at it by institutional
investors, has skillfully covered up the other reality: The damage from the oil bust is far
from over, losses continue to percolate through portfolios and retirement savings, and in
many cases – as with pensions funds – the ultimate losers, whose money this is,
are blissfully unaware of it."
There's a problem, however, with using EnerVest to bash the shale industry. And the
problem is very easy to spot for anyone who has even the most rudimentary knowledge of the
oil and gas industry (which of course leaves Richter out): EnerVest's portfolio has very few
shale assets.
• EnerVest is the largest
conventional
oil and natural gas operator in
Ohio
• EnerVest is the largest producer in the Austin Chalk, another
conventional
field.
• EnerVest is the fifth largest producer in the Barnett Shale, which is the only
shale holding listed in the company's list of core areas.
• EnerVest has spent $1.5 billion purchasing assets in the Anadarko Basin since 2013,
again in
conventional
fields.
• EnerVest is a top 20 producer in the San Juan Basin, again a
conventional
field.
So Richter uses the implosion of EnerVest, a company that is predominately a
conventonal
oil and gas producer, to bash shale? That really makes a lot of sense.
Glenn,
shale/no shale, they lost every single penny. and btw wsj lied to you every single day for
the last 4 years about milk & honey in oil patch. how do you feel about it?
Freddy, I doubt you can get this data, but a gassy geology flows liquid that isn't oil. The
relentless march upward of API speaks of NGLs rather than oil. If people just ignore API
degrees and flow liquid that is API 47 or even 51, but still call it oil, the numbers will
all be corrupted and no one will know.
I gotta go research NoDak's taxation regulation on liquids that are not crude.
coffee: Thanks for the heads up on Rockman BK discussion on PeakOil.com. I had quit looking
at that site because it seemed to have become very radical. Rockman is a good poster,
however, lots of knowledge, and a down to earth guy too.
What he describes there is why this is probably going to play out like 1986-1999. Takes
years for US onshore upstream to be placed in the category of "not investible". So $40s or
lower, on average, until mid-2020's, unless there is a prolonged major supply disruption,
which necessarily means a major Middle Eastern war lasting for years.
The possibility of $90 WTI has to be erased from memory, just like $30 WTI had to be
erased from memory from 1986-1998.
Over the course of the history of mankind, more assets have changed hands at a price
completely absent any effect of supply and demand than those that might have cared about such
things. Vastly more. Let's count a few.
1) Every single inheritance. In the history of mankind, every single inheritance.
2) All gifts.
3) All conquests.
4) All manifestations of economic predation. Predatory pricing established those
levels.
5) All monopolies
6) All thefts
7) All taxation
8) All govt decreed excise or tarrif
Want more proof? How about the ultimate:
The purchase of about 2 Trillion dollars of mortgage backed securities by the Federal
Reserve from 2009 to 2015. The pricing of those securities was 0 at mark to market, so mark
to market was disallowed, but even with that, the Fed specified the price to be whatever they
wished, and the sellers didn't have any reason to complain. The price paid was far above
supply and demand (aka 0). $2 Trillion. That probably exceeds amounts for assets from all
history that someone imagined was taking place at a free market price. Not to mention the
ongoing buys from the ECB in progress today.
So the price of oil will be what the lowest priced large sellers want it to be, and they
have no reason to imagine that their victory should be measured in a whimsically created
substance.
The upside potential might be stronger than appears at present for many reasons.
Although the Enervest situation has been conflated with the shale industry, the exact
opposite reality might prove to your (smaller operators) collective benefit as you ride out
this current storm.
Time was, ss, that some camel upwind in the desert somewhere would fart and global oil
markets would reverberate for days.
Now, in hydrocarbon producing countries from Nigeria to the Philippines, including Iraq,
Libya, Yemen, Syria, KSA and others there is conflict raging from low level to all out
warfare. Heck, there were reports the other day of a thwarted attack on a Saudi offshore
facility.
Qatar is virtually quarantined.
Russia is battling international sanctions.
And $46 WTI???
You kidding me???
We ain't in Denmark (most of us), but something's sure is rotten,
SS – It has been my experience that concerning financial matters, nothing "plays out"
like the past. Consider the period 1986-1999: No one was concerned that the world was near
peak oil. OPEC spare capacity was at least 4 times what it is today, [ask Ron], at a time
when final demand was much less. Iraq invaded Kuwait, and then we went to war to get them out
– remember the oil well fires. Russia collapsed. The "BRIC" countries [Brazil, Russia,
India and China] were inconsequential. The Dow Jones was down 22.6% in ONE DAY in 1987. The
International Monetary system almost collapsed in 1997. The world was transitioning from a
period of high inflation to much lower inflation. Japan was booming [until 1990].
You can probably add a dozen significant happenings to the list without thinking too hard.
The point is, so many variables have changed that something as significant as oil is going to
"play out" based upon today's factors, not "like" 1986-1999. Some people are still trying to
analog to the 1930's in order to predict the next great depression in the stock market
– do not listen to them.
I know things never play out exactly as in the past.
However, one has to prepare for the worst, and prices will be low for awhile IMO.
The Rockman BK discussion helped put it in focus for me. The wells will be drilled, and
only when it is clear all large US shale oil basins have hit their limit, will prices begin
to rise. That might not take 12 years, but I think at least 5 is likely.
The only intervenor would be a supply shock from the Middle East.
Another poster on another site also has given me some clarity. He states there has not
been enough suffering experienced yet in the US oil patch by those responsible for the
production boom.
We just went through two bad years of prices in 2015-2016, and at the first sign of light,
the industry was able to raise a ton of cash and go back with guns a blazing. There were no
consequences to the powers that be from the 2015-2016 low prices. Heck, the strip was higher
this time last year, yet we are still adding rigs.
It will take a minimum of five years, until it is universally believed that prices will be
low forever, that supply will be abundant forever, and that the sector is a bad
investment.
Once that happens, look out, price could rocket. But it will be awhile IMO.
Some difference between now and 86-99: i) decline rates are higher, ii) Spare capacity is
_much_ lower (oil stocks are high which apparently is what traders observe) – back in
86 KSA could flood the market, iii) not much new big projects in the pipe after 2019 and
North Sea is declining this time while it was increasing back then.
Rebalancing should go faster this time if (!) demand continues to increase.
EIA numbers are basically worthless, as far as the Permian goes. To analyze it like they are
trying to do, you would have to separate conventional production from horizontal production.
Take more gathering tools than they are using to accomplish that. Until 2015, they were still
drilling 800 a month or so vertical wells, which dropped down to 100 to 150 a month since
then. Looking at district 8A, that production is dropping like a rock. Combining the two,
production appears to be pretty flat for Texas since the first of the year.
"... Intensive drilling is causing a problem called 'frac-hits', which are cross-well interferences. These happen when fracking pressure is accidently transferred to adjacent wells that have less pressure integrity. As a result a failure of pressure control occurs, which reduces production flow. ..."
"... as the following chart from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and if so, just how high will oil surge? ..."
"... They want control of Russian oil and resources, so it may be cheap for a long, long time. This means the banksters will fund shale production 'til hell freezes over. They want another Russian revolution. ..."
"... Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I think it will be harder this time for Oil prices to increase to make these non-convensional oil projects profitable. ..."
From Horseman Capital Management's July Monthly Newsleter
...Having grown up, and spent my entire investing career in periods of bubble inflation and
deflation , I am constantly minded to look for where the market is deceiving itself, and then
positioning the fund to benefit from the process of realisation. Many years ago, I could see
that the commodity bubble was ending, and Chinese growth was peaking. This meant that
commodities would be weaker and inflation lower, making a short commodities, long bond position
very effective. It was a great strategy, but its effectiveness ended early last year.
The good news is that new market delusion is now apparent to me. When I moved long emerging
markets, and short developed markets, the one commodity I could not give detailed bullish
reasons for was oil. Unlike most other commodities, the oil industry, in the form of US shale
drillers has continued to receive investment flows throughout the entire downturn
I had shorted shale producers and the related MLP stocks before, and I knew there was
something wrong with the industry, but I failed to find the trigger for the US shale industry
to fail. And like most other investors I was continually swayed by the statements from the US
shale drillers that they have managed to cut breakeven prices even further. However, I have
taken a closer look at the data from EIA and from the company presentations. The rising decline
rates of major US shale basins, and the increasing incidents of frac hits (also a cause of
rising decline rates) have convinced me that US shale producers are not only losing
competitiveness against other oil drillers, but they will find it hard to make money . If US
rates continue to stay low, then it is possible that the high yield markets may continue to
supply these drillers with capital, but I think that this is unlikely. More likely is that at
some point debt investors start to worry that they will not get their capital back and cut
lending to the industry. Even a small reduction in capital, would likely lead to a steep fall
in US oil production. If new drilling stopped today, daily US oil production would fall by 350
thousand barrels a day over the
next month (Source: EIA).
What I also find extraordinary, is that it seems to me shale drilling is a very unprofitable
industry, and becoming more so. And yet, many businesses in the US have expended large amounts
of capital on the basis that US oil will always be cheap and plentiful. I am thinking of
pipelines, refineries, LNG exporters, chemical plants to name the most obvious. Even more
amazing is that other oil sources have become more cost competitive but have been starved of
resources. If US oil production declines, the rest of the world will struggle to increase
output. An oil squeeze looks more likely to me. A broader commodity squeeze also looks likely
to me.
In the latest letter's sector allocation, Clark also added the following section providing a
more detailed explanation why he has boosted his shale short to 15.5%:
We are negative on the US shale sector, during the month we increased the short exposure to
oil exploration and MLPs to about 15.5%. Conventional oil wells typically produce in 3 stages:
the start-up rising production stage lasts 2 to 3 years, it is followed by a plateau stage
which lasts another 2-3 years and a long declining stage, during which production declines at
rates of 1% to 10% per year. These wells generally produce over 15 to 30 years ( Source:
Planete energies).
In contrast, production from unconventional / shale wells peaks within a few months after it
starts and decreases by about 75% after one year and by about 85% after two years (Source
Permian basin, Goldman Sachs). This means that, in order to keep producing, shale producers
need to constantly drill new wells.
Shale drilling is characterised by drilling horizontally into the layers of rock where
hydrocarbons lie. Then hydraulic fracturing which consists of pumping a mixture of water,
proppant (sand) and chemicals into the rock at high pressure, allows hydrocarbons to be
extracted out to the head of the well.
Since 2016, as oil prices rallied, the number of rigs in the Permian basin, which is
currently the most sought after drilling area in the US, rose from about 150 to almost 400 .
Furthermore, operations have moved into a high intensity phase as wells are drilled closer
together, average lateral lengths increased over 80% from 2,687 ft in early 2012 to 4,875 ft in
2016 and the average volume of proppant per lateral foot more has than doubled (Source: Stratas
Advisors).
Intensive drilling is causing a problem called 'frac-hits', which are cross-well
interferences. These happen when fracking pressure is accidently transferred to adjacent wells
that have less pressure integrity. As a result a failure of pressure control occurs, which
reduces production flow.
In the worst cases, pressure losses can result in a total loss of
production that never returns. According to a senior reservoir engineer at CNOOC Nexen,
frac-hits have now become a top concern, they can affect several wells on a pad along with
those on nearby pads (Sources: Journal of Petroleum Technology).
A former engineer for Southwestern Energy said that frac-hits are very difficult to predict,
the best way to respond is with trial and error and experimenting with well spacing and frac
sizes to find the optimal combination.
In May Range Resources reported that it was forced to shut wells in order to minimise the
impact of frac-hits. This month Abbraxas Petroleum said it will be shutting in several
high-volume wells for about a month (Source: Upstream).
In the Permian basin new well production per rig continued to decline in June, from 617
barrels per day down to 602 . In the meantime , legacy oil production, which is a function of
the number of wells, depletion rates and production outages such as frac hits, is continuing to
rise . (Source: EIA)
In light of the above growing short bet on shale, this is how Clark is positioned:
The analysis leads me to be potentially bearish on bonds, bearish on US shale drillers, but
bullish on commodities. Over the month, we have added to US shale shorts, while also selling
our US housebuilder longs . We continue to build our US consumer shorts, where the combination
of higher oil prices and higher interest rates should devastate an industry already dealing
with oversupply and the entry of Amazon into ever more areas . The combination of long mining
and short shale drillers has the nice effect of reducing volatility, but ultimately offering
high returns. The combination of portfolio changes has taken us back to a net short of over
40%. I find market action is supporting my thesis, and the research and analysis is compelling.
Your fund remains short developed markets, long emerging markets.
While we will have more to say on this, Clark may be on to something:
as the following chart
from Goldman shows, the number of horizontal rigs funded by public junk bond issuance has not
changed in the past 3 months. Is the funding market about to cool dramatically on US shale, and
if so, just how high will oil surge?
LetThemEatRand
•Jul 22, 2017 5:44 PM
A short bet on shale is also a bet on no war that disrupts supply/increases demand. It is
also a bet against any kind of crisis in the dollar. As it stands now, that seems pretty
risky to me.
NoWayJose -> LetThemEatRand
•Jul 22, 2017 6:12 PM
I'd rather be long oil services - the inevitable conclusion of the author is that fracked
oil depletes faster, the quality drops, that they cannot get more financing and that
production will fall? And you want to be 'short' when all this happens?
LetThemEatRand -> NoWayJose
•Jul 22, 2017 6:31 PM
Agreed. A lot of people have already forgotten that oil dropped massively after the US
decided (under zero) that it wanted to punish Russia because "Russia invaded Crimea."
I didn't fully believe that TPTB had so much control over the price of oil before it
happened, but the timing could not have been coincidental. When they want oil to go back up,
it will.
When that happens is anyone's guess for those of us not in the Big Club, but the idea that
oil is in a new normal price range is not supported by history. Oil was double or almost
triple its current price under similar economic conditions in the past.
daveO -> LetThemEatRand
•Jul 22, 2017 10:10 PM
They want control of Russian oil and resources, so it may be cheap for a long, long
time. This means the banksters will fund shale production 'til hell freezes over. They want
another Russian revolution.
AGuy -> NoWayJose
•Jul 23, 2017 2:43 AM
"I'd rather be long oil services"
Seems likely oil services will get hit hard when the shale bubble pops. Its likely they are
owed money by shale drillers.
Outside of Shale is DeepWater, Artic and Oil Sands. None of these are much better, and I
think it will be harder this time for Oil prices to increase to make these non-convensional
oil projects profitable.
Consumers and business are even deeper debt than they were in
2008-2009. With the Boomers entering retirement, Companies moving to automation and
technology reducing the need for travel, its likely that Oil consumption will start to
decline. Hire energy prices would accelerate the declines via demand destruction
Deep Snorkeler
•Jul 22, 2017 6:00 PM
1. Fracked fields deplete fast.
2. Frackers need low interest financing for more fracking.
3. Increased fracking density depletes fields even faster.
4. Fracked wells produce ever poorer oil quality.
EROI is against all you frickn fracking f**kers. There is no economic theory that addresses
resource depletion.
fattail -> Deep Snorkeler
•Jul 23, 2017 8:08 AM
There is no economic theory that addresses resource depletion.
How about printing a fiat currency so that you can buy them all up? Backed by nothing.....
Except.... 11 carrier groups and 18 submarines loaded with nuclear missles?
TeraByte
•Jul 22, 2017 10:18 PM
This is not at all that black and white. Dirty and expensive shale extraction however had
advantages and saved trillions dollars in war expense now required to keep the "cheap" ME oil
flowing...
"I had shorted shale producers and the related MLP stocks before, and I knew there was
something wrong with the industry, but I failed to find the trigger for the US shale industry
to fail.
And like most other investors I was continually swayed by the statements from the US shale
drillers that they have managed to cut breakeven prices even further. However, I have taken a
closer look at the data from EIA and from the company presentations.
The rising decline rates of major US shale basins, and the increasing incidents of frac
hits (also a cause of rising decline rates) have convinced me that US shale producers are not
only losing competitiveness against other oil drillers, but they will find it hard to make
money.
If US rates continue to stay low, then it is possible that the high yield markets may
continue to supply these drillers with capital, but I think that this is unlikely.
More likely is that at some point debt investors start to worry that they will not get
their capital back and cut lending to the industry. Even a small reduction in capital, would
likely lead to a steep fall in US oil production. If new drilling stopped today, daily US oil
production would fall by 350 thousand barrels a day over the next month. (Source: EIA)."
"... Not only will enhanced recovery affect the economics of present unconventional operations, it has the potential to greatly expand the application to numerous, older conventional sources as well as undeveloped – yet recognized – formations with hydrocarbons within them ..."
"... But the problem isn't so much whether oil is still in the ground, but how much it costs to get it out. ..."
"... New technologies that don't reduce costs to make oil profitable to drill aren't all that helpful in keeping the oil flowing. Right now we have LTO because the system accepts financial loss. That could change if alternatives promise a better financial return. ..."
"... The way I understand the term Maximum Reservoir Contact (MRC) is that it refers to multiple laterals being drilled from a single vertical wellbore. ..."
"... From what I have read MRC technology is a great fit for a number of fields in the gulf countries and may be practical in other places including USA. Of course one of the problems applying it here is that I think you need a unitized field, or at least a very large area to be implemented. ..."
"... At that time, I was amazed to learn of the multi lateral, extended reach drilling using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves – Sakhalin. Probably do need large reservoir to be viable. ..."
"... The article says this: "On the supply side, global oil production advanced by 0.5 percent to reach 92.2 million BPD." You know, factoring in both population growth and world economic growth, this isn't much. There might be a crunch coming. ..."
New technologies did postoned the day f reconing, but they can't increase the total amount
of oil availble so the effects are temporary. Adn they are costly. right now low oil price is
financial scam.
I agree with George that getting stuff wrong is no reason to quit trying. To do so would be
stupid. To look back at why projections were wrong is a much more interesting thing. To that
end, I have been looking back at predictions from the 2005 to 2010 period, starting with
Simmons and progressing to the oil drum and some others. I do not have the technical
expertise that many of these people had, but looking back is a lot easier than looking
forward.
In my opinion, there are two big reasons the projected decline hasn't come about yet.
First, most of the work done was based upon inferred data. Because, the GCC countries don't
release much, most of the folks making these projections took whatever info was available and
ran with it. I don't blame them for this, as I believe they did what they could with what was
out there, but I think they went too far in some instances, and confirmation bias is
evident.
A part of Mr Simmon's efforts to deal with the lack of hard data was his review of many
SPE papers dealing with various issues. I believe one of these papers is a key to
understanding how KSA and others have exceeded projected production. Paper (SPE 88986) deals
with well "Shaybah-220 A Maximum Reservoir Contact (MRC) Well and its implications for
developing tight-facies reservoirs."
https://www.onepetro.org/download/journal-paper/SPE-88986-PA?id=journal-paper%2FSPE-88986-PA
This paper by N.G. Saleri describes the efforts to develop the Shaybah Field. After some
initial efforts to produce there were unsatisfactory, Aramco kept on trying and came up with
the Shaybah 220, a well with eight laterals of around 40,000 feet of reservoir contact, and
producing around 12,000 bbls per day for its first year. Saleri describes this as a
"disruptive technology".
Simmons devoted a lot of attention to Shaybah, calling it "The difficult last Giant". He
included a discussion of horizontal and MRC wells including the aforementioned paper, but I
don't think he fully appreciated these MRC wells. They have allowed KSA to produce lots of
oil in many fields that were in decline. Another example is shown by the 2008 paper by Mr
Asaad Al-Towalib on "Advanced completion technologies in successful extraction of attic oil
reserves in a mature giant carbonate field." In this paper they describe how this technology
was adapted to produce the attic oil of Abqaiq, KSA's oldest giant. To summarize, Abqaiq had
been produced since the 40's, and had produced about 57% of the original oil, but had around
25 feet of attic oil in poorer reservoir that they had not been able to produce. They tried
to produce this attic oil via vertical and conventional horizontal wells with little success.
They improved their technology and eventually completed many successful MRC wells with
geosteering which allowed them to follow structure, and intelligent completions which delay
the effects of coning.
So, much as most of us would have underestimated how successful our light-tight frac oil
has now become, many underestimated how successful MRC, and associated technology has been
for many gulf nations.
I think the next question is what happens next, so using Abqaiq as an example, after
successfully producing that attic oil is there another encore or does it become just a
depleted field? They have also used this technology to get more out of Ghawar and many other
fields, do they have room to run, or are they done?
That is simply an outstanding display of, and description of, a serious effort in
understanding what is unfolding in the world of hydrocarbon production.
I would suggest that the entire concept of MRC is being currently applied in this 'shale
revolution' primarily in the area of maximizing recovery rates, aka better
fracturing/completion processes.
Not only will enhanced recovery affect the economics of present unconventional
operations, it has the potential to greatly expand the application to numerous, older
conventional sources as well as undeveloped – yet recognized – formations with
hydrocarbons within them
But the problem isn't so much whether oil is still in the ground, but how much it costs
to get it out.
New technologies that don't reduce costs to make oil profitable to drill aren't all
that helpful in keeping the oil flowing. Right now we have LTO because the system accepts
financial loss. That could change if alternatives promise a better financial return.
I kind of 'flipped' the MRC concept in dc's post of 'more iron meeting' oil to 'more oil
meeting iron' via the greatly enhanced fracturing/conductivity recently taking place in the
shales.
Regarding multilaterals, the early (2007-2009) Bakken wells regularly contained 2 or 3
lateral from one vertical.
They used the term "turkey legs' and can still be easily seen on the ND DMR Gis map.
Virtually no one except Slawson still does this and even then, only rarely.
(Correction, might still be done in Madison formation, especially Bottineau county. Would
have to check. Gis map is easiest way to literally see this).
BHP said a year ago that they would attempt to try this in the future, but I've not kept
close track of their efforts.
Thank you very much coffee, I appreciate your kind words.
From what I have read MRC
technology is a great fit for a number of fields in the gulf countries and may be practical
in other places including USA. Of course one of the problems applying it here is that I think
you need a unitized field, or at least a very large area to be implemented.
I'm pretty sure you know a whole lot more about this stuff than I do.
I started digging into it a few years back when the series of stunningly high IPs started
to emerge from the Deep Utica.
Big buzz developed about feasibility of sharing hardware/facilities to develop Marcellus and
Utica together.
At that time, I was amazed to learn of the multi lateral, extended reach drilling
using ultra sophisticated whipstocks in the mid east, offshore, and – if memory serves
– Sakhalin. Probably do need large reservoir to be viable.
Time will tell if this approach makes sense in the shales. Like everything else, economics
will be the ultimate determinator.
The article says this: "On the supply side, global oil production advanced by 0.5 percent
to reach 92.2 million BPD." You know, factoring in both population growth and world economic
growth, this isn't much. There might be a crunch coming.
The 1973 so-called "oil embargo" which reduced oil supply to the USA by somewhere around 3%
or 4%. It slammed the US economy, caused the largest stock market crash since the great
depression, doubled gasoline prices, severely damaged US industry and caused a 55 MPH
national speed limit which remained in effect for ten years.
Just wait until we experience a 10% or 20% drop in oil supplies. In a few years or sooner
we certainly will. When it hits the economic and social damage will be catastrophic.
The end of Western Civilization, from China to Europe, to the US, will not occur when oil
runs out. The economic and social chaos will occur when supplies are merely reduced
sufficiently. As former Saudi Oil Minister Sheikh Yamani once said "The Oil Age may come to
an end for a shortage of oil".
They are talking about 25-30% and the verbage talks about it being in railcars . . . the
suggestion is it's part of the total Bakken flow of 1 million bpd. 25-30% of that is ethane?
What a scam this would be.
"Big Ships Account for 80 Percent of Shipping's CO2"
By Paul Benecki...2017-06-13...20:16:44
"At Nor-Shipping 2017, researchers with DNV GL released a study that points to the difficulty
of reducing the industry's CO2 output below current levels. The problem is structural: big cargo
vessels emit 80 percent of shipping's greenhouse gases, but they're also the industry's most efficient
ships, and squeezing out additional improvements may be a challenge.
Just 35 percent of the fleet – mostly large bulkers, tankers and container ships – is responsible
for 80 percent of shipping's fuel consumption, according to Christos Chryssakis, DNV GL's group leader
for greener shipping. Unfortunately, these are already the fleet's most efficient vessels per ton-mile.
"This is a paradox, but if we want to reduce our greenhouse gas emissions, we actually have to improve
the best performers," Chryssakis says."...
Similar situation with trucking, but in the USA around one half of gas consumption goes into
private cars. So by improving efficiency of private fleet by 100% you can cut total consumption
only by 25%. All this talk about electrical cars like Tesla Model 3 right now is mostly cheap talk. They
by-and-large belong to the luxury segment.
"the President cited this NERA study, commissioned by the American Council for Capital Formation,
and the U.S. Chamber of Commerce. Why didn't the President rely upon his own experts within the
White House?"
Because his CEA is not yet staffed. The NERA "study":
NERA uses its "model" to forecast that the cost to real GDP by2040 will be a 9% shortfall and
the cost to employment will by 31.6 million jobs. Now that sounds BAD, BAD. But it sort of reminds
me of the kind of "quality analysis" we might expect from the Heritage Foundation. Of course that
is what the American Council for Capital Formation, and the U.S. Chamber of Commerce paid NERA
to do.
I learned much reading this about Russia's taxing of its crude oil...you may find it interesting
as well...
Careful though, Irina Slav neglected to mention that Russia never stopped producing as much
oil as it could during OPEC's deal to cut production so this is hardly a balanced article
Putin and the Russian Oligarchs are not going to cut production, Mother Russia (Putin) needs
the cash flow (as do the other OPEC cheaters)
"OPEC Cuts Send Russia's Oil Heartland Into Decline"
By Irina Slav...Jun 03, 2017,...2:00 PM CDT
"Western Siberia is to Russia what the Permian is to the U.S. Well, kind of. Kind of in a sense
that it's one of the longest-producing oil regions and there's still a lot of oil in it. Yet,
thanks to the production cut deal with OPEC, Russian companies have had additional motivation
to move to new territories in the east and the north, where taxes are lower.
In Russia, the older the fields, the higher the taxes operators have to pay. Now that the country
has pledged to continue cutting 300,000 bpd for another nine months, the most obvious choices
for the cut are the mature Western Siberian fields. In the first quarter of 2017, for example,
output at Rosneft's Yugansk field fell by 4.2 percent, Bloomberg reported.
Production at other Western Siberian fields is set for a decline as well, with the daily output
rate from lower-tax deposits in the Caspian Sea, Eastern Siberia, and the North seen to rise to
866,000 bpd by the end of the year, or 74 percent on the year. The shift away from mature fields
to new ones will continue over the medium term, according to BofA analyst Karen Kostanian, as
overall Russian output grows. No wonder, as tax relief on new projects sometimes reaches 90 percent.
Lukoil's output from the Filanovsky field in the Caspian, for instance, is taxed at 15 percent
at a price per barrel of US$50. The average for mature fields is 58.1 percent, in a combination
of mineral resource tax and export duty.
And this is not the end of it: in 2018, the Kremlin will test a new tax regime for the oil
industry as it seeks to maintain production growth and the respective revenues, contributing a
solid chunk of federal budget revenues. The new regime, Deputy Energy Minister Alexei Texler told
Reuters, will first be introduced for a selection of 21 fields with a combined output of 300,000
bpd for a period of five years.
In case the government is happy with the results from the test, the new regime would be expanded
to the whole industry. Hopes are for a substantial increase in output thanks to the new tax regime:
up to 20 percent over the five-year period. These hopes seem to be limited to the Energy Ministry,
however, the Finance Ministry worries that the new regime will make it harder to control the flow
of tax money. The treasury is also against combining the new regime with already existing tax
incentives for the industry.
So, the move away from what Bloomberg calls the oil heartland of the world's top producer is
all but inevitable. It will come at a cost for the state coffers of some US$25 a barrel of Western
Siberian oil, or US$2.7 billion annually, according to a Renaissance Capital analyst, but the
cost will be worth it. The cost would increase, too, if the current output cut arrangement with
OPEC fails to push up prices, which for now is exactly what we are seeing, while the ramp-up in
the U.S. oil heartland continues."
"With enough thrusts pigs can fly. It is just dangerous to stand were they are going to land."
This quote is perfectly applicable to OPEC and Russia oil production now.
Neglecting maintenances and using "in fill" drilling just shorten the life of the traditional
oil fields. And new large oil fields are difficult to come by.
My impression is that most of "cuts" in production by Russia and OPEC are "forced moves". Production
was declining from mid 2016 when old investment were already all put into production and few new
investments were made since late 2014.
If we assume the lag period of two years, than in mid 2018 we will feel the results of decisions
to cut investments made in 2016.
In this situation announcing cuts allow to save face.
The net result is the same -- the oil price should rise to the level when it is economical
to develop "more expensive oil" (deep see drilling, Arctic oil and such) as replacement rate in
traditional fields is insufficient to maintain the production.
As long as The US government allow shale companies to generate junk bonds (which will never
be repaid representing kind of hidden subsidy) along with "subprime oil", shale can slightly compensate
the decline in production, but my impression is that this card was already played. Despite all
hoopla from WSJ and other major MSM.
The fact that oil production for some time was artificially kept flat or slightly rising is
strange and might be politically motivated (Saudi) which put other producers in situation when
they were force to follow Saudi lead or lose customers. China played Russians against Saudi pretty
well and got what they want at lower prices.
Those "intensification of production" were short term measures which in a long run are detrimental
to old oil fields output.
They might even lessen the total amount of oil that can be extracted from a given field.
The key question here is: Does Russian oil firms has the amount of money needed to maintain
production on the current level (at the current oil price levels ) or not.
Obama has a chance to move the US personal fleet to hybrid and more economical cars. He lost
this chance. SUV is now dominant type of personal cars int he USA, the trend opposite to what
it should be. Even hybrid SUVs like RAV4 hybrid get only around 33 miles highway, less in city
traffic.
Transition to Prius type cars (with their around 50 miles per gallon) would allow US consumers
to save almost half of oil spend on personal transportation (which probably represent around 60%
of total US consumption
http://needtoknow.nas.edu/energy/energy-use/transportation/
)
US shale production increase scenarios at different $WTI prices and cost inflation levels assuming
no new debt (no mention of paying down existing debt?)
May 24, 2017 – Leslie Wei – Rystad Energy
Figure 3 shows the estimated Y/Y growth in NA liquids shale production for different WTI oil prices
and cost inflation scenarios compared to 2016 cost levels. The "Call on shale" highlighted section
represents the 1.3 million bbl/d average taken from figure 2. The key assumption for this analysis
is that the E&P companies will balance the investments with operational free cash flow (cash neutrality).
For example, in a 70 USD/bbl oil price range, cost inflation within the range of 0% to 25% is
required to meet the 1.3 million bbl/d y/y growth in the "call on shale." In a 50 USD/bbl scenario,
the liquids production may only grow as much as 0.5 million bbl/d on a yearly basis even if the
costs remain flat. To reach the call on shale of a yearly growth of about 1.3 million bbl/d, the
oil price needs to move into the range of 70 to 80 USD/bbl for the companies to stay cash flow
neutral.
https://www.rystadenergy.com/NewsEvents/PressReleases/the-call-on-shale
"Figure 2 shows the necessary yearly growth in shale production to balance supply and demand
from 2017 to 2021. To achieve this, shale has to grow by 1.6 million bbl/d in 2017, and more than
2 million bbl/d in 2021. This implies a total shale oil production of 14.1 million bbl/d in 2021.
To achieve such growth in shale production, the number of spudded shale oil wells has to reach
~20,000 wells in 2021, or two times the number of spudded wells in 2016."
Now we have roundabout 4-5 million b/d shale production – how can only the double number of new
wells bring the triple production?
On the other hand, is shale now unlimited in resources and can supply the whole world with
oil, enough wallstreet silly money (TM) provided?
Oh, and another thing: Do the shale oil wells no more decline rapidly after drilled, but add
up nice to such production numbers.
PS: Here in financtial newspapers the typical shale break even price is now at 23$/barrel.
There are only a few oil wells left production cheaper than US shale oil.
Let us see the well completion numbers from Texas for May first (RRC), and step by step judge
if enough wells are actually completed. The trend is not going right through the roof when looking
at the April oil well completion numbers tbh.
I don´t like the expression "call on shale" as it implies that there is a vast base of resources
there to be exploited, which could turn out to not be true. I also do not like the term "call
on OPEC" as it implies the same.
The countries in OPEC are very different and just some of them can ramp up I can imagine. Who
knows actually with all the secrecy and lack of accurate oil field data coming from some of the
participants in the organisation.
2. The shale column in the Permian Basin is about 4,000 feet thick, whereas in the Eagle Ford
and Williston Basin it is only a few tens or hundreds of feet thick.
3. There are at least seven productive shale zones (which have already been tested), and several
more that have not been tested, stacked like pancakes, one right on top of the other, in the Permian
Basin.
4. The stacked plays in the Permian Basin allow for economies of scale not offered by the other
shale plays.
5. Improved drilling techniques have cut the number of drilling rig days needed from spud to
finishing of drilling operations (that is, the cementing of production casing) substantially.
6. Post-2015 fracking techniques (Fracking 2.0 and Fracking 3.0) are producing far more prolific
wells. Offsetting wells, with identical lateral lengths, and completed with Fracking 3.0 are producing
almost twice as much oil as the pre-2015 wells completed with Fracking 1.0.
7. The Permian Basin, being a mature oil and gas basin, already has a great deal of existing
infrastructure already in place, and is not too terribly far from the refinery complex on the
Gulf Coast, as the Williston Basin is.
The only public company that is solely focused on fracking services in the US shale basins in
Keane Group, ticker symbol FRAC. The company just went public at the end of 2016.
Keane's 10Q for 1/17 is interesting. The company lost $72 million. Their costs of services,
which excludes depreciation, selling, general and administrative expenses and interest, was just
$16 million less than revenues. The margin between revenues and costs of services was just 6%.
This was an improvement over 2016, where costs of services were actually more than revenues.
In the business outlook section, the company states they are seeing higher pricing for services.
In particular, due to greatly increasing volumes of sand per well, the company has seen certain
grades of sand doubling in price since the second half of 2016.
This is not a small company, they are in all shale basins and do work for some of the big names.
Clearly, as more fracking crews are utilized, costs are headed up.
Of course, they still do not have all of their frack crews working. There is still overcapacity
in all service areas, as active rigs are still far below the peak in 2014. Well costs have fallen
several million dollars since 2014. It is interesting that even with the price recovery in Q1,
2017, most upstream US shale companies showed losses or small earnings per share. ExxonMobil,
Chevron, Pioneer, Marathon and EOG all either showed small positive or negative EPS in Q1 from
US upstream.
There were outliers, such as Diamondback(FANG), which showed high EPS. However, a close look
shows FANG's CAPEX is still significantly higher than D,D&A.
Looking back since 2014, very interesting how the US shale industry battled to maintain production.
Saudi Arabia surely didn't anticipate the ability of US firms to operate at a loss for such a
long time. 2 1/2 years later, US service firms are still operating at a loss, if Keane's example
is accurate. US financial markets are very deep, interest rates remain very low on a historic
basis, and executives earning 7-8 figures annually are not simply going to shut down, as no growth
equals lower bonuses.
The numbers reported in 2015 and 2016 in aggregate by US shale firms clearly show that the
vast majority of 2015 and 2016 shale oil wells were operated at a loss. Almost all will not reach
payout in 36-60 months at the current futures strip. Hopefully, when this shale phenomenon has
concluded, there will be some in depth studies conducted of the financial side. Those reports
should make for very interesting reading.
Our small family business was not immune from cutting, such that 2016 was in the black, despite
well head prices for the year it just $36. True, we are not drilling still, and production is
slowly declining. This will continue until prices solidly rise into the $55-65 WTI band we desire.
However, we can take several more years of $45-53 WTI, if that is what the future holds. The consensus
in our small oil patch is that we need to be more worried about future demand, than future supply.
As US shale continues to climb the wall, taking total US C+C to 10, 11 or even 12 million BOPD,
that climb will get tougher, and more expensive per barrel. Maintaining 10-12 million BOPD for
a few years will take more CAPEX than is currently being spent. Maybe Dennis knows how much more?
It seems more of the public is pushing for EV, ride sharing, autonomous vehicles, etc. I have
tough time envisioning this, living in the middle of nowhere, in the middle of "fly over territory".
But, even though these initiatives are also generally hemorrhaging cash, just as shale has, dollars
and cents do not seem to matter. Kind of like how a company like Facebook can be worth $450 billion,
yet I have not used it once and see it as nothing but online gossip and a complete waste of time.
I can't understand it, but it is reality.
> In particular, due to greatly increasing volumes of sand per well, the company has seen certain
grades of sand doubling in price since the second half of 2016.
Son of a gun. Imagine that. Here's my fave photo of fracking in the Bakken. It's from 2012:
Look real careful. Bags of ceramic proppant. From China. It's better at holding fractures open
than sand. Sand was the downshift because of cost. hahahahahaha
We never do hear about the lower ultimate recoveries simply accepted from use of inferior proppant.
Not part of the narrative.
There seems to be increasing mention of Occidental being bought out by someone with extremely
deep pockets. Owning over 2 million net acres, Oxy is the biggest leaseholder in the Permian.
Two points in following up on Glen's post
The productive footprint of the Permian continues to expand up into New Mexico.
The output from wells in many of the basins has significantly increased in the past 12 months.
More precise targeting, staying in zone near 100%, and diversion processes are the biggest reasons.
aaannd, speaking of Oxy, they just loaded the first VLCC – Very Large Crude Carrier, capacity
2.2 million barrels – at their dock at Corpus Christi.
66 foot draft is too deep, presently, for the channel so 60% loading at dock and balance from
smaller vessel when out in deeper water.
Red balance sheet ink doesn't matter for shale companies – as long as there is a story. They'll
get new loans, or enough investors buying new stock.
Shale companies are like .coms in the 2000s – they are about the story, not paying big dividents.
That's what old oil is for.
If now everyone of big oil drills in perminal and abandones deep water and other long run projects
– it's a 0 sum game in global supply. Perhaps permian can get really 15 millions or more barrels
a day, but without deep see and Alaska + other difficult projects, that's not 1 barrel more in
global supply.
And it will be the mother of all oil rushes, with not being able to see a piece of Texas without
drilling towers.
HOUSTON - May 4, 2017 - Occidental Petroleum Corporation (NYSE:OXY) today announced reported
net income of $117 million, or $0.15 per diluted share, compared with a reported loss of $272
million, or $0.36 per diluted share, for the fourth quarter of 2016 .
"Our focus remains on areas that generate the best returns and we are seeing improvements
in margins across all of our businesses," said President and Chief Executive Officer Vicki
Hollub.
"Permian Resources continues to be a growth engine for our company, with a 5 percent improvement
in production this quarter, reflecting increased drilling activity and well productivity in
the Delaware Basin."
I know the information I am providing is anathema for those who have been waiting around with
baited breath for the last forty years, hoping to see the last gasps of the Age of Oil. But it
looks like you might have to wait a bit longer for that longed-for event, maybe quite a bit longer.
It is also anathema to those like Mike and shallow sands, and OPEC and Russia, who with their
conventional oil portfolios had hoped for the quick demise of shale. After all, if the cost to
produce that marginal barrel is now $50 to $60, and it remains at that cost, there is little hope
for an oil price recovery much above that price. Shale killed the price of oil, and may continue
to do so for some time in the future. This is not what those vested in conventional oil had hoped
for, and continue to hope for.
When Khalid Al-Falih arrived at Davos in late January, the Saudi oil minister was exultant .
Almost five months later, U.S. production is rising faster than anyone predicted and his
plan has been shredded .
[S]hale has defied the naysayers. By the time OPEC meets in Vienna on May 25, U.S. output
will be approaching the 9.5 million barrels a day mark - higher than in November 2014 when
OPEC started a two-year price war. The rebound has been powered by turbocharged output in the
Permian basin straddling Texas and New Mexico.
Forced to adjust to lower prices, shale firms reshaped themselves into leaner operations
that can thrive with oil just above $50 a barrel.
Since OPEC agreed to cut output six months ago, U.S. shale production has risen by about
600,000 barrels a day, wiping out half of the cartel's cut of 1.2 million barrels a day and
turning the rapid victory Saudi Arabia foresaw is turning into a stalemate .
On Thursday, OPEC's own monthly oil market report said that production from non-members
would rise 64 percent faster than previously forecast this year, driven mainly by U.S. shale
fields.
So far, OPEC hasn't been able to "cut supplies faster than shale oil can increase," said
Olivier Jakob of consultant Petromatrix GmbH .
[T]he cartel faces big risks. The most prominent is that extending cuts lifts the oil price
high enough for shale to hedge again, as it did earlier this year .
Increasingly, the oil market believes the real battle between OPEC and Russia, on one side,
and shale, on the other, will take place in 2018, when an increasing number of observers predict
U.S. production will flood the market as it did in 2014 .
U.S. shale producers used the price spike that OPEC triggered earlier this year to lock-in
revenues for 2017, 2018 and, in some cases, even 2019. With their financial future relatively
secure, they started deploying rigs. Since the count of active rigs in the U.S. reached a low
last, producers have added an average seven units per week, the strongest recovery in 30 years .
According to the U.S. Energy Information Administration, American crude production will
surpass the 10 million barrel a day mark by late next year, breaching the record high set in
1970. The shale boom will propel non-OPEC output up 1.3 million barrels a day next year, effectively
filling up almost all the expected growth in demand.
"The supply and demand balance for 2018 looks very bad," said Fared Mohamedi, chief economist
at consultant The Rapidan Group in Washington. "That's when the big fight is going to happen."
Occidental
profit beats; shares fall on weak output forecast | Reuters : "Occidental Petroleum Corp's
quarterly profit beat estimates on Thursday but the company's shares fell to a near eight-year
low as the oil and gas producer forecast lower-than-expected production for the current quarter."
Oxy is still largely a conventional producer.
Permian EOR is conventional, not sure about South Texas. Non-US accounts for almost half of total
output.
So Oxy's 1Q results are not representative for the shale sector in general
In fact, during the years of the shale boom, in 2011-14, OXY was one of the very few publicly
traded U.S. E&Ps with positive free cash flow. All of those 3 or 4 companies had large non-shale
operations. On the contrary, all pure shale players had significant negative free cash flows.
I agree that "negative free cash flow is not bad in itself". The question is for how long
negative free cash flow is not bad?
Most shale companies had negative free cash flows since 2011 (already 6 years), having accumulated
large debts. There was a short period in 2H16 when, due to sharply reduced capex, the shale sector
was
free cash flow neutral. But recovering investments since 2017 will result in renewed period of
burning cash (as evident from 1Q17 results). So how many more years the markets will tolerate
shale companies' negative free cash flows?
I personally think that the shale sector could remain cash flow neutral or even slightly free
cash flow positive, especially with gradually rising oil prices. But that would imply very modest
growth in capex, and hence in production. And that still does not solve the problem of repaying
accumulated debt, unless shale companies sell part of their assets and/or issue new shares, diluting
existing shareholders.
Exposure to shale operations has actually proven a burden for the U.S. oil companies' financials
In Oxy's case,from 2014 to 1Q17, domestic upstream operations were a negative contributor to
the company's earnings (unlike international oil and gas). Positive 1Q17 earnings were due to
non-shale operations that offset a $122 million loss from the US oil and gas segment. For 2016
as a whole, U.S. oil and gas had a net loss of $999 million, while all other segments, combined,
have shown net earnings of $493 million. The same is true for the large US integrateds, like Exxon,
which consistently had negative earnings in its US upstream segment in the past few years due
to shale exposure.
"Most of the giant oil companies seem to think they're not, as they write off or sell their crown
jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and
as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It's called
creative destruction, as older producing properties and techniques can no longer compete with
the new ones."
Glenn,
To make a sale someone must buy. Logic does not apply that the sellers are smart and the buyers
are dumb at this point. There was a seller and there was a buyer and that is all that we can say
about oil sand deals. We don't know the real reasons for these sales. It is just interesting that
all deals with oil sands with majors happened in downturn and that all buyers are Canadian companies.
And there is nothing creative about Shell, Exxon, Conoco acquiring all these oil sands properties
at inflated prices when oil was at north of $100 during 10 years span and selling all at ultimate
bottom when price at one point was $26.
For Q1, 2017:
US upstream -$191 million
Foreign upstream $418 million
Chemicals $170 million
Marketing and Midstream -$47 million.
The above are pre-interest and pre-tax. Oxy paid quite a bit in foreign taxes, received a large
US tax benefit due to US losses, and paid over $70 million in interest, a good chunk being on
debt incurred by spending in excess of cash flow on US unconventional in 2010-2014. OXY lost a
good chunk of change in the Bakken and completely left the area including a multi-million $ regional
headquarters they had just built in Dickinson, ND. Took a big write down on it.
I have looked a OXY Permian unconventional wells. Many pre-2016 were bad, sub 100K BO to date.
I assume they are getting better, like the rest of the Permian.
If I am not mistaken, XOM, CVX and COP made positive EPS other than in US upstream in Q1, 2017.
CLR broke even, PXD posted a small loss, EOG posted small net income.
FANG and XEC were outliers with strong EPS, but upon closer look, these numbers were aided
greatly by low DD&A per BOE, as both elected to not place substantial CAPEX on DD&A yet.
Although I'd like $55-65 WTI, can live with $45-53. We will see how many years it takes for
Permian to top out, akin to Bakken and EFS. Could take awhile, given land area. Will take awhile
to see how much of the Permian is "good".
My issue isn't about production. It's the underhanded methods to switch from one measurement to
another to suit their narrative.
When US production was declining last year they stopped posting US production charts. The moment
that changed and production had consistent increases the charts reappeared. I don't understand
their issue with being honest.
They have some good stuff there, but for anyone paying attention it really detracts and casts
a dark light on them.
The EIA makes lots of predictions and many of them are wrong. Conventional output will decline,
GOM will be flat or declining and LTO may increase by as much as 2 Mb/d from the previous peak
by 2023 and will then decline sharply (peak LTO will be about 6.5 Mb/d at most, but other US C+C
output will decrease by 1 Mb/d at 3%/year annual decline). US output might reach 10.5 Mb/d, but
not until 2022 rather than 2018, note that this does not satisfy 2016 crude inputs to refineries
and blenders which was about 16 Mb/d, unless demand decreases by 5 Mb/d from 2017 to 2022.
I doubt that will be the case, by June 2019 we will probably see $80/b (2016$) for Brent crude.
and by June 2020 the price may be North of $100/b (2016$).
Texas oil production has increased in Districts 5,7c,and 8 since October 2014. All the other 10
districts have dropped by a total of 714,406 bbls per day. I am using Texas RRC District production
October 14 to January 17.
There's a plausible sounding theory, even though posted on Zero Hedge, that the Chinese have been
filling their SPR over the last two years, and that is about to stop. This would mostly account
for why OECD storage levels only took about 35% of the supply-demand imbalance. If they do stop
then about 1 mmbpd of demand would suddenly be lost, but it might also imply that the real economy
demand growth in the period since January 2015 has only been half what it looks to have been.
Taking account of the sudden drop and a slower growth in demand would mean a longer time would
be needed to draw down OECD stocks. However if the China SPR scenario is correct then almost all
the drawdown would come from OECD. By my reckoning this would push a balancing out to late 2018
(although by then we may be seeing some bigger supply drops as the pipeline for new project start-ups
will be drying up). But if the balancing is pushed out then the chances of many FIDs this year
or next will decline and the possibility of a sudden supply crunch in 2019 through 2022 would
be greater. The green curve below gives possible drawdown under this scenario. The red one was
a previous assumption that the OECD stocks would be drawn down at only about 35% of the imbalance
(as happened when they were rising). I seemed a bit iffy when I fitted it that way, and I think
the China SPR filling is a better explanation.
SPRs in general try to have 90 days of domestic consumption in them. This was a standard put into
place mostly in Europe. China has embraced it.
The US at 750ish million barrels and having a consumption (net of production) of about 11 million
bpd (remember, this is real stuff . . . consumption, no refinery gain BS allowed) and so not quite
70 days domestic consumption.
China, at net consumption of about 7 million bpd X 90 needs an SPR of 630 million barrels.
That's about what they have, but of course with 5% consumption growth they'll have to adjust up,
but for now . . . all is well.
There probably is no flow in or out of China for SPR reasons. Already full. Have been for a
while.
This is the chart Zero Hedge had, or linked to – the key is Xinhua CFC, who have Chinese data
not otherwise available and charge a lot of money for it. I don't know how you'd go about checking
if it's correct.
Hello, don't forget that Xinhua doesn't publish China's SPR figures. The SPR figure in the chart
is an estimate based on (Production + Imports – Refinery Inputs). I'm not sure if all the teapots
are included in the official refinery data.
I guess that Chinese demand must be higher than estimated. Like this article was suggesting
Bloomberg – October 11th 2016
China's appetite for oil.
Fuel use grew by about 5 percent in the first half of 2016, according to China's biggest oil refiner,
faster than the 0.4 percent derived from government data. That "official" number is clouded by
rising gasoline exports - blends that don't show up in official figures, according to the International
Energy Agency, Sinopec Group and Energy Aspects Ltd.
Chinese authorities are also having trouble tracking refinery activity because of the surge of
processing by independent refiners, known as teapots, according to Energy Aspects' Meidan.
http://www.bloomberg.com/news/articles/2016-10-10/gasoline-cocktails-mix-with-gaps-in-data-to-cloud-china-oil-view
?
Enno's shaleprofile.com is full of facts. I went back and looked at his 1/17 summary of all US
oil producing shale fields. Interesting that despite adding over 13,000 new wells since the peak
in 3/15, US as of 1/17 was still 600K bopd below the 3/15 peak.
I do realize data is somewhat incomplete due to TX. I also realize not all wells are included.
Still, going to take a lot of CAPEX to climb the ladder back to 5, 6 and maybe 7 million bopd
from the shale fields.
Soon, GOM will start declining. Onshore conventional is like the sun setting. Just 60 or so
straight hole rigs active, half of the 1998-99 trough. Alaska doesn't appear to add anything.
Unless demand tanks, per Tony Seba's theories, maybe its time to be bullish? When it is clear
US shale has hit the wall, price could sky?
XOM – Potential 2nd Downgrade – unless APPL or Bazos jumps to the rescue. /
sarc
"However,
unlike its peers such as Chevron and BP, Exxon Mobil is
not targeting meaningful growth in production.
Although Exxon Mobil is working on a number of shale oil, conventional oil
and LNG projects which will come online in the near term, they will largely
help the company in offsetting the negative impact of field declines and asset
sales -
Shell, Chevron, and BP carry debt loads of $91.6 billion, $45.3
billion and $61.8 billion, respectively. "
"... Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again. ..."
"... Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. ..."
"... Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out. ..."
"... A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices. ..."
Hopefully everyone involved in defending Bakken production upswings will not disappear into
the woodwork next month, or the month after, when production drops again.
Of course marginal shale oil wells that are at or below economic limits get shut in during
winter, or get shut in and stay shut in because workover costs to restore production simply do
not make economic sense. There are gazillions of those kinds of well in all three of America's
shale oil basins. There need not be a flush 'uptick' of production when those wells come back
on line (that's investor presentation dribble), in fact it can be just the opposite because of
bubble point/higher water saturations.
Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires
ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack
thereof); in the end the latter always wins out.
Imagine a situation where you are drilling these $6.5M wells so close together (Marathon at
330 feet, toe to toe) that you have to "protect" them by shutting them in for prolonged periods
of time while you frac a new well 3000 feet away. That makes a lot of sense, doesn't it?
A little more time and realized production data will prove that downsizing actually reduced
UR per incremental well and was yet another economic disaster in a string of economic disasters
for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices.
The actual reserve that is being produced in the Bakken was "discovered, undeveloped and developed"
in 2013, and not covered by the USGS. It's difficult to find break out information for individual
areas in most companies reports but I don't think there was more than about 5 Gb developed and
undeveloped reserves in 2013, and it might have declined a bit since then, even including actual
production.
When I give the cumulative output of the scenarios, it is
from the start of production in the Bakken/TF in ND, about 1.6 Gb had
been produced at the end of 2015 and Bakken Three Forks proved reserves
were about 5 Gb at the end of 2015, that gets us to 6.6 Gb, typically
there are probable reserves as well, though we would have to guess at how
much. Also as oil prices increase in the future 2P reserves are likely to
increase.
Note that the F95 USGS TRR estimate for the ND Bakken Three Forks is
about 7.2 Gb, if we assume probable reserves at the end of 2012 were zero
(in my view not a very good assumption). What do you think is a
reasonable estimate for probable reserves if proved reserves are 5 Gb?
Your guess would be better than mine. For UK North Sea a typical number
would be 3 Gb of probable for 5 Gb of proved (all UK North Sea reserves).
For the Bakken it would likely be lower, maybe 1 Gb of probable for 5 Gb
of proved reserves might be a reasonable guess.
Bakken average well profile from June 2015 to Dec 2017 shown below
(after that the EUR decreases).
If you pull up data at shaleprofile.com
and look at wells from 2014 to 2017, there are 1388 Three Forks wells
that have been producing for 20 months (cumulative is 118kb) and there
are 1689 Middle Bakken wells (cumulative is 143kb@20 months). So
lately (past 3 years) a fairly large proportion of wells have been
Three Forks wells (about 45%). After 36 months the difference in
cumulative output is about 30 kb (TF is lower at 155kb@36 mo, Bakken
is 185 kb at 36 months).
I think you are mixing proved reserves from EIA with the
undiscovered numbers from USGS. The proved reserves might have some
basis and 5 to 6 might be right, I haven't sen any kind of detail
of how they are arrived at. But that is not the same oil as in the
USGS report – it was mostly already known about in 2012 when the
E&Ps stopped drilling wildcats. Since then they have been
converting probable to proven, and in some cases writing off some
of the reserves. If you want to include the USGS data then it
should be added to whatever there was as 2P in 2012 as a final
recovery.
I don't know where there 1300+ Three Forks wells come
from – the ND production wells for January shows only 1 well in the
Three Forks and 45 Three Forks / Bakken. There are other pool's
like Sanish and Madison. Madison is a big producer so maybe that is
counted as Three Forks in USGS. The ND DMR overall production up to
2015 gives 10 million for Three Forks / Bakken, 1600 for Bakken,
950 for Madison and < 1 for Three Forks alone.
The 220,000 EUR I quoted was for the Three Forks alone from
USGS, not Bakken.
It's looking like the shorter cycle times for LTO just means the the
volatility acts over higher frequency but doesn't go away. A fundamental
problem remains that all the E&Ps use basically the same model, and
therefore they all make essentially the same decisions at around the same
time, and therefore you get boom and bust. Volatility may be the biggest
contribution to delaying or preventing long term investment in bigger
(principally deep water and oil sand) projects, but I think the impact of
the big drop off in discoveries is significant, and not being fully
appreciated.
The backlog of discoveries are mostly difficult and expensive
developments that were not considered as top prospects when oil was over
$100.
The few larger, new discoveries are also in frontier, and therefore
generally more expensive, regions. E&Ps are turning to gas, or near field
developments, or are giving up on offshore altogether. Much higher, and
stable, prices might be needed to get these big projects going. If high
prices cause a fast demand collapse, by whatever mix of mechanisms, then
they might well not get done.
"A few comments from Steven Kopits of Princeton Energy
Advisors LLC"
Mar 17, 2017:
• The US oil rig count was up by 14 this week to 631
• US horizontal oil rigs were up by 14 to 530
...
• This was another very aggressive rig add, but curiously
came from outside the major plays. This suggests that either
the business is spreading beyond its historical boundaries,
or that some technical and non-recurring issues may be at
play.
"... A large part of the problem is, as is often repeated, "the cheap oil is gone". How are prices going to fall no matter how efficient things get ("work smart not hard" the project managers used to say when budgets got bust – complete cobblers) when you need to use 15000# Duplex piping instead of 600# mild steel, use latest generation (is it 5th now?) ultra deep water rigs which still only hit one in twenty exploration successes, have miles and miles of anchor cables and riser tubing instead of a short jacket etc. ..."
"... Looking at what Exxon is doing to make itself look good to investors, and then reading articles like this, I wonder if we are seeing the decline of the majors, but people aren't openly saying that yet. They keep hedging their bets by saying the oil business is cyclical, but we are talking about not only lower oil prices, but also declining reserves and higher production costs. ..."
"... The title should be "cost per barrel developed increase 66%". Adjusting for inflation we see that each dollar develops about 70% of the oil it did before. This is reasonable when we consider deep water developments don't have such good wells anymore, and that other areas are mostly limited to pounding increasingly poorer reservoirs or implementing EOR in known fields. ..."
"... Successful efforts accounting methods, as opposed to full cost, are preferred by the shale oil industry because, in my opinion, it helps distort the economic picture and makes them look better than they actually are. Hardly ever is lease acquisition costs (lease bonuses), land work, curative title work, geophysical or infrastructure costs (upstream to midstream gathering systems) used when quoting well costs to the public. This might help answer your question in the Permian: http://info.drillinginfo.com/permian-premium-are-high-prices-justified/ ..."
"... I would say in OKLA the EUR is much to low by a factor of 2-4 for a single horizon, in other words a ~100 acres can be expected to produce any where from 400,000 to 800,000 BO and can have 3 or more productive horizons each capable of those types of production numbers. So for example a ~100 acres can produce 1,500,000BO or more. ..."
"... "Several companies which were early adopters of enhanced completion techniques and have their acreage concentrated in sweet spots have seen significant declines of their IP30 values of new wells, indicating an exhaustion of their acreage. More recent adopters of enhanced completion methods, by limiting drilling to their best acreage, have seen a boost of IP30 of new wells since 2014 but will sooner or later face the same exhaustion problems." ..."
"... The oil and gas sector was particularly hammered in the three-month period, according to the report. The industry employed 3,640 fewer jobs compared to third quarter 2015, a 26 percent drop." ..."
This could probably go into the previous post about petroleum, but I will
put it here.
Oil Majors' Costs Have Risen 66% Since 2011 | OilPrice.com
: "According
to new research from Apex Consulting Ltd., the oil majors are still spending
more to develop a barrel of oil equivalent than they were before the
downturn in prices – in fact, much more. Apex put together a proprietary
index that measures cost pressure for the 'supermajors' – ExxonMobil, Royal
Dutch Shell, Chevron, Eni, Total and ConocoPhillips. Dubbed the
'Supermajors' Cost Index,' Apex concludes that the supermajors spent 66
percent more on development costs in 2015 than they did in 2011, despite the
widely-touted 'efficiency gains' implemented during the worst of the market
slump. It is important to note that this measures 'development costs,' and
not exploration or operational costs."
Interesting article and so was the Reuters one it referenced. One thing I
missed was a discussion of gas versus oil versus oil sands, I assume the
figures are for all combined, but it would be interesting to see how
things changed for each section (though probably the data is only
available internally to the companies or at a big cost from IHS or Rystad).
2011 was an era of mega projects though especially for some huge LNG
(many of which ran way over budget) and oil sands, and would also include
the cost overruns from the Kashagan debacle.
He concludes:
"In other words, the decline in costs post-2014 are, at least in part,
cyclical. Costs will rise again as activity picks up unless oil producers
work with their suppliers to address the underlying structural costs of
oil production."
But is that possible?
A large part of the problem is, as is often
repeated, "the cheap oil is gone". How are prices going to fall no matter
how efficient things get ("work smart not hard" the project managers used
to say when budgets got bust – complete cobblers) when you need to use
15000# Duplex piping instead of 600# mild steel, use latest generation
(is it 5th now?) ultra deep water rigs which still only hit one in twenty
exploration successes, have miles and miles of anchor cables and riser
tubing instead of a short jacket etc.
Looking at what Exxon is doing to make itself look good to
investors, and then reading articles like this, I wonder if we are
seeing the decline of the majors, but people aren't openly saying that
yet. They keep hedging their bets by saying the oil business is
cyclical, but we are talking about not only lower oil prices, but also
declining reserves and higher production costs.
Just as coal
has seen its best days come and go, I think that is happening with
oil, too, but there is a reluctance to call it.
The title should be "cost per barrel developed increase 66%".
Adjusting for inflation we see that each dollar develops about 70% of the
oil it did before. This is reasonable when we consider deep water
developments don't have such good wells anymore, and that other areas are
mostly limited to pounding increasingly poorer reservoirs or implementing
EOR in known fields.
For LTO it's interesting how EagleFord are piling on rigs (5 more this week)
and the permitting seems to have increased dramatically, whereas the Bakken
is steady to maybe slightly down, certainly for permitting at the moment. I
don't know where the difference for this is and I expected the opposite, but
it seems EIA knows something as their predicted flattening in the EFS
decline rate is looking pretty likely know, while Bakken is looking
increasingly weary, with only the outstanding DUCs as a big potential source
of new oil.
During the past 2 years, there has been a tremendous amount of great quality
work concerning the economics of onshore LTO production. Much of it has been
done by those who post here.
But, although I may have missed it, I still have a question that I do not
recall being discussed. Buried in each of these economic models, is there a
land resource cost?
For example what I would like to see separated out for each model is
information such as this (a hypothetical by me, for illustrative purposes
only): "The 60 Gb scenario assumes that each average onshore LTO well
utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of
oil; at an average leasehold cost of $10,000 per acre. So each average well
has an upfront leasehold cost of $1 million, and that cost is [or is not]
included in the cost per well shown.
However, let me be clear: if that information is not available, I am not
asking anyone to go get it. Just state that it is up to the reader to make
their own assumptions of what the leasehold cost is for an average onshore
LTO well. But, in that regard, it would be usefull to know how many acres
are being used for an average well.
Successful efforts accounting methods, as opposed to full cost, are
preferred by the shale oil industry because, in my opinion, it helps
distort the economic picture and makes them look better than they
actually are. Hardly ever is lease acquisition costs (lease bonuses),
land work, curative title work, geophysical or infrastructure costs
(upstream to midstream gathering systems) used when quoting well costs to
the public. This might help answer your question in the Permian:
http://info.drillinginfo.com/permian-premium-are-high-prices-justified/
"The 60 Gb scenario assumes that each average onshore LTO well
utilizes 100 acres of oil resource; has an average EUR of 200,000 bbl of
oil; at an average leasehold cost of $10,000 per acre."
I would say in OKLA the EUR is much to low by a factor of 2-4 for
a single horizon, in other words a ~100 acres can be expected to produce
any where from 400,000 to 800,000 BO and can have 3 or more productive
horizons each capable of those types of production numbers. So for
example a ~100 acres can produce 1,500,000BO or more.
Current density plots indicate 113 acre drainage will be achieved with
a 7500′ lateral with 660′ between wells. A 10,000′ lateral would be 151
acres. I can also say, because of government interference, "forced
pooling" the average leasehold cost is something under $2000 an acre.
Leasehold cost are usually added to the first producing well as part of
the "full cycle" cost and are a one time expense.
Any given unit may ultimately have 10-15 wells. Once the Unit is HBP
and the primary term of the leases have expired the full land cost will
have been expensed.
My oldest well LTO well in SCOOP has produced over 300,000 barrels of
liquids from approximately 51 acres.
Thanks TT! Since I live in OK, your information appears to be very
positive information for OK – which currently is in a poor economic
environment due to low oil [and gas] prices. However, based upon your
information, why, in your opinion, has this OK play not attracted
nearly as much "hype" as the Permian [or Baaken or Eagle Ford]? Is the
long-term potential [ultimate oil to be extracted from the entire
play] much less?
Good presentation by BTU Analytics. And it shows
that SCOOP and STACK are not a new Bakken, Eagle Ford or Permian
in terms of oil production potential.
In Texas and New Mexico, there is private fee land
and state land. New Mexico also has federal land ownership. Texas has very
little Federal ownership but there are Relinquishment Act Lands, University
Lands, and School Lands, and Stare Fee Lands which would have public records
available to review.
The state and federal agencies are mandated to seek competitive fair
market prices for land leased for oil and gas exploration. If one obtained
the lease sale results from the appropriate state and federal agencies for
each scheduled lease sale for the last ten years you might approximately
determine an average lease bonus by year that the oil and gas industry paid
for both private fee and state lands in an area.
This would not help with acreage acquired early in a play and then
flipped to a subsequent purchaser but I think it would be a reasonable
number to work with for example the Eagle Ford, Delaware Permian or New
Mexico Permian. Colorado, South Dakota, Oklahoma all contain a combination
of private and state or federal lands.
Bakken Oil Producers: IP30 And Well Decline Rate Trends Since 2014 | Seeking
Alpha
:
"Several companies which were early adopters of enhanced
completion techniques and have their acreage concentrated in sweet spots
have seen significant declines of their IP30 values of new wells, indicating
an exhaustion of their acreage. More recent adopters of enhanced completion
methods, by limiting drilling to their best acreage, have seen a boost of
IP30 of new wells since 2014 but will sooner or later face the same
exhaustion problems."
The oil and gas sector was particularly hammered in the three-month
period, according to the report. The industry employed 3,640 fewer jobs
compared to third quarter 2015, a 26 percent drop."
Unburnable Wealth of Nations - Finance & Development, March 2017
: "[Poor
countries] face three special challenges. First, they have a higher
proportion of their national wealth at risk than do wealthier countries and
on average more years of reserves than major oil and gas companies. Second,
they have limited ability to diversify their economies and sources of
government revenues-and it would take them longer to do so than countries
less dependent on fossil fuel deposits.
Last, economic and political
forces in many of these countries create pressure to invest in industries,
national companies, and projects based on fossil fuels-in essence doubling
down on the risk and exacerbating the ultimate consequences of a decline in
demand for their natural resources (see map)."
This article gives a good overview of what is happening in Colorado.
There
is activity, but it is unlikely Colorado will have any sort of boom, like
was talked about a few years ago.
Rebound predicted for Weld crude oil production | GreeleyTribune.com
:
"DJ Basin crude oil sells at a discount of $2 to $3 per barrel to benchmark
West Texas Intermediate oil from the Permian Basin. 'Companies here still
need prices to go a bit higher before we will see a significant increase in
activity,' she said."
"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2
million barrels of crude per day, roughly double the levels seen at the end of last year.
Analysts told Bloomberg that the rising American exports are driven in large part by falling
domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below the
international Brent standard by $2 per barrel or more, and are now cheaper than some Middle Eastern
grades of lesser quality. This makes American crude more attractive to Asian buyers.
There is also an incentive for traders to sell their oil abroad: U.S. storage is costly. If
the price of crude is not expected to rise, brokers have no incentive to hang on to their supply
and pay rent on a tank to put it in."...
You are just regular incompetent chichenhawk. And it shows. Try to read something about US oil
industry before positing. It is actually a very fascinating topic. That's where the battle for
survival of neoliberalism in the USA (with its rampant militarism and impoverishment of lower
50% of population) is now fought.
If you list also domestic consumption, you will understand that you are completely misunderstanding
and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl; see
ilsm post), not an exporter. You can consider it to be exported only after drinking something
really strong.
It refines and re-export refined products and also export condensate and shale light oil that
is used for dilution of heavy oils in Canada and Latin America. That's it.
US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for well
started in 2009-2016), and if interest on already existing loans (all shale industry is deeply
in debt; ) and minimum profitability (2.5%) is factored in, probably $77.
That's why production is declining and will decline further is prices stay low because there
is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In 2017
they are mostly gone, so what's left is not so attractive at the current prices. And this is an
understatement.
The same is true to Canadian sands. Plans for expansion are now revised down and investments
postponed.
So in order to sustain the US shale industry prices need to grow at least over $65 this year
And those war-crazy militarists from Obama administration essentially continued Bush II policies
and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating conversion of
passenger cards to hybrids (and electrical for short commutes).
The US as a country waisted its time and now is completely unprepared for down of oil age.
The net result of Obama policies is that SUVs became that most popular type of passenger cars
in the USA. That can be called Iran revenge on the USA.
The conflict between Donald Trump and the US Deep State can be explained that deep state can't
allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East. That's
why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show him who is
the boss and warn "You can be fired".
Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that might
cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism
as social system) can well go off the cliff when cheap oil is gone.
The only question is when it happens and estimates vary from 10 to 50 years.
So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years
(1917-1991) by only something like 15 years.
"Noble Energy has sanctioned the first phase of the Leviathan natural gas project offshore Israel,
with first gas targeted for the end of 2019.
Noble Energy is the operator of the Leviathan Field, which contains 22 trillion cubic feet (Tcf)
of gross recoverable natural gas resources.
The announcement was hailed by Israeli Prime Minister Benjamin Netanyahu who has played a key
role in negotiations with Noble. Netanyahu says the discovery of large reserves will bring energy
self-sufficiency and billions of dollars in tax revenues, reports The Times of Israel, but critics
say the deal gave excessively favorable terms to the government's corporate partners...
Production will be gathered at the field and delivered via two 73-mile flowlines to a fixed platform,
with full processing capabilities, located approximately six miles offshore."...
"U.S. oil exporters set a new record last week: shipments leaving the country averaged 1.2
million barrels of crude per day, roughly double the levels seen at the end of last year.
Analysts told Bloomberg that the rising American exports are driven in large part by falling
domestic prices. West Texas Intermediate futures (the domestic benchmark) are trading below
the international Brent standard by $2 per barrel or more, and are now cheaper than some Middle
Eastern grades of lesser quality. This makes American crude more attractive to Asian buyers.
There is also an incentive for traders to sell their oil abroad: U.S. storage is costly.
If the price of crude is not expected to rise, brokers have no incentive to hang on to their
supply and pay rent on a tank to put it in."...
You are just regular incompetent
chichenhawk. And it shows. Try to read something about US oil industry before positing. It
is actually a very fascinating topic. That's where the battle for survival of neoliberalism
in the USA (with its rampant militarism and impoverishment of lower 50% of population) is now
fought.
If you list also domestic consumption, you will understand that you are completely misunderstanding
and misrepresenting the situation. The USA is a huge oil importer (Net Imports: 6.075 Mbbl;
see ilsm post), not an exporter. You can consider it to be exported only after drinking something
really strong.
It refines and re-export refined products and also export condensate and shale light oil
that is used for dilution of heavy oils in Canada and Latin America. That's it.
US shale can't be profitable below, say, $65 per barrel (so called "break-even" price for
well started in 2009-2016), and if interest on already existing loans (all shale industry is
deeply in debt; ) and minimum profitability (2.5% is factored in, probably $77.
That's why production is declining and will decline further is prices stay low because there
is only fixed amount of "sweet spots" which can produce oil profitably at lower prices. In
2017 they are mostly gone, so what's left is not so attractive at the current prices. And this
is an understatement.
The same is true to Canadian sands. Plans for expansion are now revised down and investments
postponed.
So in order to sustain the US shale industry prices need to grow at least over $65 this
year
And those war-crazy militarists from Obama administration essentially continued Bush II
policies and wasted money in Middle East, Afghanistan and Ukraine, instead of facilitating
conversion of passenger cards to hybrids (and electrical for short commutes).
The US as a country wasted its time and now is completely unprepared for down of oil age.
The net result of Obama policies is that SUVs became that most popular type of passenger
cars in the USA. That can be called Iran revenge on the USA.
The conflict between Donald Trump and the US Deep State can be explained that deep state
can't allow Trump détente with Russia and stopping wars on neoliberal expansion at Middle East.
That's why they torpedoed General Flynn. It is not about Flynn, it was about Trump. To show
him who is the boss and warn "You can be fired".
Due to "overconsumption" of oil inherent in neoliberalism with its crazy goods flows that
might cross the ocean several times before getting to customer, US neoliberal empire (and neoliberalism
as social system) can well go off the cliff when cheap oil is gone.
The only question is when it happens and estimates vary from 10 to 50 years.
So in the best case neoliberalism might be able to outlive Bolshevism which lasted 74 years
(1917-1991) by only something like 15 years.
A big contributor to the legacy oil decline is the unrelenting physics of fluid
phase behavior, with gas becoming more prevalent in the production stream.
Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells
will be worse (i.e. the newer wells dampen the effect, which have an initial
GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a "gas"
well or field.
Most of these LTO fields will eventually be abandoned as gas fields.
note – I tried to post a *.png graph, but the reply tool failed.
I missed to take into account the number of days in the month for
total producing days in my last post. I wanted to investigate this more.
So I did a bit of programing and adjusted each individual well for the
number of days it was in production in December to see what the
production would have been if it produced as many days as it did in
November (adjusted for number of days in that month). I looked at wells
that started production in 2014 and wells that started production in
2010. In short, both groups looked very similar and it turned out that
about 86% of the increase in decline rate, for both 2014 and 2010, were
because of fewer producing days and the rest for other reasons. However
there is more to it than that. First of all, adjusted for number of
producing days, the decline rate should stay the same or decrease a
little every month, not increase. Secondly wells that are of the same age
as the 2014 wells have historically had a monthly decline rate of around
3%. The decline rate in November (days adjusted) was 6,9% and in December
8,1. For the 2010 wells, monthly decline rates should have been around
1,5% but were 5,6% in November and 6,9% in December. So the decline rates
are currently very very high. The huge drop in December could not have
been that huge if the underlying decline rates would not have been that
large.
I think the decline in GOR has something to do with it. If the reason
for the increase in decline rates are that they are choking the wells,
then I expect these high decline rates to be rather temporary, because I
would guess that they adjust the choke only once per well. It may take
some time to adjust all wells they have planned to adjust, but when that
is done then decline rates should normalize. So if that is the reason
then maybe it will take a few months to normalize. If the decline rates
are still very high in a few months, then it doesn´t look good for
Bakken..
I found a bug in my code. For 2014 about 100% of the increase in
decline rates from November to December was because of fewer
production days and decline rate in November was 6,43% and December
6,35% (a bit conservative). For 2010 the numbers are 86%, 4,16% and
5,16%. So lower underlying decline rates, but still very high. Sorry
about that.
Is the 2000 GOR a North Dakota convention? There's no reservoir engineering
reason to designate a depleted well as a gas well when GOR increases to 2000
scf/bo. Depleted oil wells under depletion drive do experience very high
GORs, but they remain oil wells.
My recall is there's a regulation in Texas that classifies liquids from a
gas well as condensate vs oil from an oil well. Almost certainly has some
tax consequence.
Can any of you professional fellows explain the upsurge in "Legacy Oil Well"
production shown in the monthly EIA Drilling Productivity Reports? The major
fields, except. Permian, show that the legacy wells are rising after having
been on seemingly steady downslopes for the years leading up to about early
2015. Are they reworking old wells? What's the industry practice that has
reversed the declines.
The legacy well production graph represents the monthly expected change
in production.
In the example you referenced monthly legacy decline was
about 140,000 bopd at the beginning of 2015. This legacy decline
represents the decline of wells producing in the prior month. This
decline was large because there were many recently drilled legacy wells,
and the recently drilled wells decline more than wells which have
produced for a longer period.
By the beginning of 2017 the legacy decline had decreased to about
80,000 bopd per month because there hadn't been as many wells drilled
recently.
Some of y'all are newishcomers and cannot remember how very many times monthly
production reports would report completely inconsistent with new completions
totals and weather and more or less 15 gazillion other factors we'd throw in.
Point being, don't think you have why the big recent increase or why this big
decrease understood. Your odds on this are poor.
Reminder from last thread:. That Enno chart color coded by year - look at
how shallow the post Peak descent slope 2010, 2011, 2012 is vs 2014. Damn near
vertical. That would be the last non price smash year.
This speaks to EUR, but not loudly because of . . . Wait, do we have proof
these recompletions are happening? Or is this presumption.
Also suggest a read thru of the new rule making paras of the directors cut.
I can remember months when new completions and new wells operating numbers
completely failed to explain a change in quoted oil production that month .
. . and I embarked on chasing down traffic reports and stop light failures
at intersections because trucks hauling oil having been slowed down could
conceivably have been the explanation for the numbers. Nada.
What we DID
conclude was negative - zero explanation for oil output quotes from the
number of wells completed in a month. Number of days of bad weather
preventing completions also failed to explain. Bad weather slowing down
trucks remained a maybe, but for trucks hauling oil, not trucks hauling
proppant.
Ceramic proppant for Bakken. From China. Soon after this it was
magically discovered that special sand from the US was "superior"
(meaning cheaper, but didn't hold the fractures open as well).
Munger would have us import oil and gas now from OPEC so that we can save
our oil and gas for the future when the world is going to have major
shortages."
The day comes when a firebrand is in control and dares to rock the
societal systemic boat by declaring the price of oil will be non monetary.
You want oil from Russia, America? Disarm. You want oil from KSA, America?
Convert to Islam.
"We have enough of your dollars created from thin air. Let's have
something of real value to us before we send you oil. The price is described
above."
But if we haven't wasted our own oil, we'll still have it. And then if
other countries want to give us terms we won't accept, then we don't use
their oil.
Of course, without imports, we won't have enough to run our
country business as usual. But we're going to head that way anyway, as
global supplies become more scarce and/or expensive.
When the shit is well and truly in the fan, in terms of oil available for
import to the USA, which will probably come to pass within the next
couple of decades, barring the technocopians being right in predicting
electricity displacing oil, well
We have both economic and military muscle enough , assuming we wise up
about globalization , and don't export the rest of our industrial base,
to INSIST on oil being sold to us , although getting it for dollars will
be harder from year to year.
Saudia Arabia will never be self sufficient in food until the
population there falls by what, eighty percent or better? If anybody will
have the capacity to export food on the grand scale, it will be the USA.
And if anybody has a military umbrella under which smaller and less
powerful countries can shelter at relatively low risk of the people there
being treated like convicts, it will be the USA.
This is not to say we have been or are altogether NICE about the way
we treat our allies, but compared to other countries, we stack up pretty
well in this respect.
Nothing will move on the world ocean for quite some time if Uncle Sam
finds himself in a corner where in his own interests indicate that
nothing moves.
Of course considering that ninety percent of the leadership in China
consists of engineers and scientists, where as ninety percent plus of
western leadership consists of lawyers and other mostly parasitic types,
it 's only a question of WHEN, rather than IF China will be a military
superpower, and maybe the SOLE super power.
We need to account for the fact that shale oil production was
supported by junk bond issuance. The loss on shale oil junk bonds is
not that big: the U.S. energy companies have defaulted on ~$40 billion
in high-yield bonds in 2016, more then doubling the $15 billion for
2015 according to Fitch. But they do affect future junk bond issuance
What is interesting is that MSM stopped talking about shale junk
bonds in 2015 as if they got some order from above
Most warnings are from 2014, some from 2015:
In this sense, even $ 63 might be too low, if loans became more
expensive and well servicing costs continue t0 rise. Printing junk
bonds is a necessary side effect of shale oil production and this is
now definitely more expensive activity then before.
I think that the return to profitability for shale at oil prices
below $70 bbl is very problematic.
We have now graphed the whole of BP oil
production and consumption and calculated the net export balance which is not
in decline but it has been flat since 2005.
Nice, Thanks!
The net exports available on the global oil markets are some 60% of the
total production. In the case of dropping global oil production it will take
a while for the markets to dry out. If you make this same exercise on coal
and gas, you get different numbers. Only a tiny fraction of global coal and
gas production is available on the global markets. Dwindling global
production will result in disappearing global markets in a very short time
frame.
Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production
down
92,029 bpd
to 942,455 bpd. It was noted that this the largest decline ever in North Dakota
production. But it should not be overlooked that the October in crease in production was also the
largest ever increase in North Dakota production.
EIA wildly optimistic in Bakken, Gulf and Texas. Their current numbers have
to be way high in relation to what is actually happening. Even Texas RRC
site is not predicting an upturn until current permits and completions get a
lot higher. At $53 oil, it is not happening, or going to happen.
In my view there is simply a cost issue here. If a
well goes from 100 barrels to 20 barrels per day, the mainenance,
operating and transport costs go up fivefold per barrel, even if
they are the same for the well. So, it might not pay off to send a
crew there and pay for transport. Unless, the oil price does not go
up, these wells and many more wells are likely to shut down for a
while.
I saw a recent story about the rise in the cost of fracking to completion
for these DUC wells. Costs are said to have risen to something like $3.2
million in some of the areas where wells need completion. I believe the
Director's Cut said last month there were 86o wells awaiting completion.
If the story I read was true, then it will be around $2.8 billion to
frack those 860 wells. I don't know what the cost of getting a well to
the DUC stage is, but it sure seems a lot of money to have sunk in the
ground for wells that will be outputting just 100 barrel a day after
their first 24 months.
Bruno Verwimp wrote back in 2016, September 16th, " .Hold your breath for
the next winter. It might bring severe decline in oil production in ND
Bakken ."
I wrote at the same time: " FWIW my 'money' is on Verwimp's observation
and model for the Bakken. I for one will be interested to see your chart
next spring!"
Another 3 months will be interesting. By the look of it, it might well be
down to 700,000 bpd in a year if the uncanny accuracy continues. As I
understand it, his chart has nothing in it derived from price.
That is correct. Verwimp's model has no oil price input. This is a
serious problem since everybody recognizes that oil price has been
determinant in the current oil situation. Therefore one can only conclude
that Verwimp's model is accurate due to chance, and therefore has no
predicting capability. It will continue to be accurate until it doesn't.
It probably represents oil production decay in the absence of sufficient
economical incentive.
Geology absolutely plays a role, especially when oil
prices are relatively high it is clear which fields are constrained by
geology. When oil prices fall by a factor of 3 or 4 fields that are
not constrained by geology will decline due to economic constraints
(poor profitability.) The Bakken only increased in output due to high
oil prices and a high well completion rate. Eventually geology will be
the reason for Bakken decline, low oil prices clearly are the reason
at present.
In Jan 2018 your model predicts about 680 kb/d for ND Bakken/TF
output. My 61 well model predicts about 818 kb/d in Jan 2018 and the
85 well model predicts 900 kb/d in Jan 2018, I expect ND Bakken/Three
Forks output will be around 825 to 900 kb/d in Jan 2018, with a best
guess of 866 kb/d (847 kb/d in Dec 2018). This corresponds to a 75
well model, chart below.
A big contributor to the legacy oil decline is the unrelenting physics of
fluid phase behavior, with gas becoming more prevalent in the production
stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The
legacy wells will be worse (i.e. the newer wells dampen the effect, which
have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is
considered a "gas" well or field.
Most of these LTO fields will eventually be abandoned as gas fields.
note – I tried to post a *.png graph, but the reply tool failed.
Is the 2000 GOR a North Dakota convention? There's no reservoir
engineering reason to designate a depleted well as a gas well when GOR
increases to 2000 scf/bo. Depleted oil wells under depletion drive do
experience very high GORs, but they remain oil wells.
My recall is there's a regulation in Texas that classifies liquids
from a gas well as condensate vs oil from an oil well. Almost
certainly has some tax consequence.
Munger would have us import oil and gas now from OPEC so that we can save
our oil and gas for the future when the world is going to have major
shortages."
The day comes when a firebrand is in control and dares to rock the
societal systemic boat by declaring the price of oil will be non
monetary. You want oil from Russia, America? Disarm. You want oil from
KSA, America? Convert to Islam.
"We have enough of your dollars created from thin air. Let's have
something of real value to us before we send you oil. The price is
described above."
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require
the addition of an average of about 95 wells/month (61 wells/month were added through 2016).
In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent.
This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus
a steeper decline in production.
Looking at Bakken(ND) as one big project, it has now spent an estimated total of about
$36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach
pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI)
starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B
requires an estimated oil price of $77/bo (WTI).
To enable a debt reduction requires a net positive cash flow from operations and the
longer it takes before positive cash flow happens, the higher the required oil price becomes
to earn some return.
Some of this $36B debt has already been written down (also through bankruptcies (Chapter
11s), the business model is not sustainable with low oil prices!), which means that the companies
now needs to recover less than the $36B.
Write downs/impairments shrinks the affected companies' assets/equities and thus debt
carrying capacities. Some make forecasts about future developments without considering the
companies' balance sheets.
At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month
from cash from operations, this will likely be a mixture of DUCs and "new" wells.
For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated
from operations.
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated
this would require the addition of an average of about 95 wells/month (61
wells/month were added through 2016).
In 2016 an estimated $2.0 –
$2.5Billion more than (net) cash flow from operations was spent. This is
about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought
to flow and thus a steeper decline in production.
Looking at Bakken(ND) as one big project, it has now spent an
estimated total of about $36Billion more than generated from net operational
cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in
2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17.
To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B
requires an estimated oil price of $77/bo (WTI).
To enable a debt reduction requires a net positive cash flow from
operations and the longer it takes before positive cash flow happens, the
higher the required oil price becomes to earn some return.
Some of this $36B debt has already been written down (also through
bankruptcies (Chapter 11s), the business model is not sustainable with low
oil prices!), which means that the companies now needs to recover less than
the $36B.
Write downs/impairments shrinks the affected companies'
assets/equities and thus debt carrying capacities. Some make forecasts about
future developments without considering the companies' balance sheets.
At present oil pries (low/mid 50's) the companies may add an average
of 60-70 wells/month from cash from operations, this will likely be a
mixture of DUCs and "new" wells.
For 2017 I expect companies in Bakken(ND) will continue to spend
above what is generated from operations.
Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production
down
92,029 bpd
to 942,455 bpd. It was noted that this the largest decline ever in North Dakota
production. But it should not be overlooked that the October in crease in production was also the
largest ever increase in North Dakota production.
If I'm not mistaken, this means that the North Dakota production (BPD) is now
only slightly more than than the existing pipeline capacity leading out of
North Dakota (BPD), which is 851,000 at the end of 2016. Production will
probably be down to the existing pipeline capacity by March.
Now this isn't quite comparable because part of the Williston isn't in North
Dakota, so I'd have to look at the Montana numbers. But still, it looks likely
that the moment Dakota Access is built, there will be a pipeline capacity glut.
So is the Dakota Access Pipeline going to be half-empty, or will some of the
other pipelines be empty and go bankrupt? They're fighting over market share in
a surplus-capacity environment.
"The incremental investment is budgeted to deliver an average
estimated ultimate recovery (EUR) of, or approximately 15% over the
previous average EUR of 850,000 Boe per well. At $55 per barrel WTI,
these completions should generate a cost forward average rate of
return in excess of 100%"
The estimated EUR's appear VERY high
for Bakken wells by my untrained eye. Any thoughts from the
resident experts?
I am certainly not an expert on tight oil but see above. If they
get 30 to 40% extra from gas I think they might make it (GOR of
1500 adds 25% I think, and it looks like it will be more than
that for most wells). What I don't get is a 'previous average'
of 850,000. There's not even one well that looks like that at
the moment, based on Enno Peters' charts.
"The Company plans to complete 131 gross (100
net) operated wells out of its Bakken uncompleted well inventory with
first production commencing by year end. In addition, Continental
plans to complete with first production approximately 17 gross (8 net)
newly drilled Bakken wells in 2017. At year-end 2017, the Company
expects to have 140 Bakken wells in inventory, of which 72 gross (40
net) wells will have been completed but waiting on first sales and 68
gross (47 net) operated wells will be waiting on completion.
The Company also plans to participate in completing 40 net
non-operated wells in 2017, 35 of which will be in the Bakken.
Continental expects to grow Bakken production by approximately 26%
in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.
Approximately $550 million, or 70%, of the operated Bakken capital
investment in 2017 will be focused on completing wells from the
Company's uncompleted well inventory. The Company has five stimulation
crews working currently and plans to average seven crews for 2017 as a
whole.
Continental plans to apply various enhanced stimulation techniques
on all Bakken completions in 2017 to define the optimum designs for
future completions. This includes larger proppant loads, diverter
technology, shorter stage lengths and shorter cluster spacing. The
Company is also applying high-rate production lift technology to
accelerate fluid recovery and early production rates. Combined, these
techniques add an average of approximately $1.4 million to the
previous standard enhanced completion cost of $3.5 million.
For the uncompleted well inventory, the average budgeted completion
cost for the larger enhanced completion is approximately $4.9 million
per well. The incremental investment is budgeted to deliver an average
estimated ultimate recovery (EUR) of 980,000 Boe per well, or
approximately 15% over the previous average EUR of 850,000 Boe per
well. At $55 per barrel WTI, these completions should generate a cost
forward average rate of return in excess of 100%.
The Company also plans to maintain four operated drilling rigs in
the Bakken throughout 2017 and drill 101 gross (57 net) operated
wells, with 17 gross (8 net) of these wells completed in 2017 with
first production. The 17 gross wells will have an average budgeted
well cost of approximately $7.0 million. The average EUR for wells
drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price
of $55 per barrel, these wells should generate over a 40% rate of
return."
According to Enno, an average
Bakken well gives about 200k+ of oil, not 900k. It looks like it's
much more gas than oil, or the numbers are completely bogus. Or
they have bought the sweetest center of all sweet spots in Bakken?
As of 3Q16, oil accounted for 61% of total CLR output.
Apparently, oil's share in CLR production in the Bakken is
higher.
According to Enno, CLR Bakken wells with the first
flow in 2014 have on average already produced > 200kb of oil.
Their average EUR may exceed 400 kb and probably reach 500 kb.
Wells with first flow in 2015 and 2016 perform better.
That said, even including gas, EURs of 900 kboe look
unrealistic
I have mentioned company proved reserves and PV10 quite a bit
here in the past two years.
I am coming to the opinion that these numbers, required by the
SEC, have too many uncertainties to make them worthwhile, at least
as to PUD. PDP may be useful.
They appear to have been increasing well performance since 2014,
maybe getting above 400k for oil if the curves continue (as below).
It looks like they recomplete after some time. It will be
interesting to see how the two 2016 curves go – started high and
then the first took a dive. The late 2015 wells did the same and
then jumped up, which looks like a re-completion. How much area
does one of their new wells drain? Presumably the savings must
mostly be on reduced drilling and completions cost, and maybe front
loading the returns with higher initial production, not overall
additional recovery.
Marathon announced today they'd have six
rigs average this year – up one – not sure if that is enough to
hold the decline near present levels, mostly that depends on
completions rather than rigs though, but they are going for
"multiple enhanced completion trials" and expect to increase
overall USA production by up to 20% (also six rigs in Eagle Ford).
Bakken data were out yesterday and we have seen a steep drop below 900 000
bbl/d nearly 300 000 bbl/d below its peak of 1.164 mill bbl/d in December (see
below chart). Well performance (new and existing wells) is down to a five year
low of 83 bbl per well and falling -20% year over year. This means a cost
increase per produced barrel of 20%, even if new wells are performing better
and costs per rig are down.
Since the well production declines by -20% over two years now, costs per
produced barrel are up 40% and rising fast. No wonder companies seem to abandon
Bakken for less mature fields such as the Permian. New permits are at five year
low and rig count is also grinding down slowly. Inerestingly, number of wells
are also falling – down 100 wells in December – which has been deemed as
impossible in some forecasting models.
I looked at Mexico production by area as below. The numbers in brackets show
percentage year on year change for exit rate 2016 to 2017. Only the small area
in northern offshore, which is not LMZ or Cantarell, is not declining. Even KMZ
looks like it might be turning over. If it goes like Cantarell as Nitrogen and
or water start hitting the producers then the will be a big acceleration, if
not then the decline might flatten out as the other fields make up increasingly
less of the mix. The plateau that KMZ achieved after N2 injection was started
is now quite long for an offshore field.
"... For the past eight years we were fed the constant stream of stories of mythical economic "recovery" and all the wealth created in this period from the bankers and economist. And as a result of all that illusory "wealth" retail sector was able to sell goods to consumers with empty wallets and maxed credit cards only by smashing prices to the bone – leaving almost nothing for the profit. ..."
"... Imagine the state of economy without this extra unconventional 5-6 mbd and $100 per barrel as a consequence. ..."
Steve,
Oil industry, and particularly Shale & Oil Sands part, lives in hope for the
last 3 years. And that is not reality, because hope means dream. Unless
someone's live in reality, here and now, they are dreaming. They are dead
weight, and tomorrow which will fulfill all their hopes is never to come.
Shale and Oil Sands are mostly North American origin of production with 5-6 mbd.
where we have the most consumption per capita in the entire world.
For the past eight years we were fed the constant stream of stories of
mythical economic "recovery" and all the wealth created in this period from the
bankers and economist. And as a result of all that illusory "wealth" retail
sector was able to sell goods to consumers with empty wallets and maxed credit
cards only by smashing prices to the bone – leaving almost nothing for the
profit.
Imagine the state of economy without this extra unconventional 5-6 mbd
and $100 per barrel as a consequence.
I disagree that it implies subsidies. What is implied is that
when oil is scarce, the price of oil will increase and more of the expensive
oil will be profitable to produce. Eventually the high oil price will lead
to greater efficiency in the use of oil (as measured by real World GDP per
barrel of oil consumed) and also some substitution of natural gas, and
electricity for oil in the transportation sector and after 10 to 20 years
demand for oil might fall below the supply of oil and lead to lower prices.
My main point is that the supply of oil depends on profits, not on net
energy or exergy of the oil produced. Profits will depend on revenue minus
costs and revenue will be determined by the oil price which is a function of
both
supply and demand for oil.
There is strong evidence that the US economy can survive only oil
prices below $100 per barrel without sliding into recession. Some
researchers put this magic "perma-stagnation" oil price as low as $60
per barrel. I think understanding of this fact is partially behind
this prolonged "oil price crush".
So it might well be that we do not have the freedom of "arbitrary"
oil prices in the US economy. and in worst case scenario we have oil
prices already close to the celling, unless the economy is
restructured.
That's why your line of thinking about this problem might be wrong.
In other words, this is a very serious situation for the USA. "The
long emergency" as James Howard Kunstler aptly called it (not that I
agree with his line of thinking or endorse his book).
Meanwhile the US is wasting time and money on the wars of
neoliberal expansion, which partially is "brut force" way of securing
privileged access to remaining oil deposits. Around 5 trillion was
spent so far, or 167 millions of Toyota Priuses at $30K per car, or
half of the US passenger fleet (there were 260 million registered
passenger vehicles in the United States in 2014)
So instead on concentrating on this fundamental problem that nation
is facing, the USA is just "waiving dead chicken" with the military
force. If we add the possibility of Seneca cliff that situation might
be even worse then I described. The nation does need radically cut the
amount of oil spend on personal transportation. Using all ways for
this that are technologically feasible. Because this is the lowest
hanging fruit. But very little was done in this direction on both
federal and state levels.
Meanwhile we expanded the fleet of SUVs for personal transportation
- this is now the most popular "form factor" for personal car, which
overtook sedans. Growth of the fleet of hybrid cars is unacceptably
slow (over 4 million units sold through April 2016; Japan, a much
smaller and compact nation, sold 5 millions).
Even such a symbolic act as switching of all personal government
cars to hybrids was not done by Obama administration, which preferred
only talk about the problem and opened spigot for shale junk bond. The
only their "real" achievement was "Iran deal" which probably was
instrumental in crashing oil prices. Which probably helped Obama much
more than it helped the USA economy as whole, but we should not
inspect the teeth of the horse that was given as a gift, as old saying
goes.
Also attempts to lessen huge traffic jams in large cities like NY
and SF are feeble, despite the fact that the technology is available
both to reroute the cars and to optimize traffic lights.
Converting existing roads network into "one way" network is almost
unheard outside the city center, even when two more or less adequate
parallel roads exists with the short distance of each other.
Variation of the number of lines each way is practiced very rarely,
in some city centers and selected bridges.
Green wave for traffic using Wifi connections between traffic
lights and cameras is in a very rudimentary stage.
The only progress that I noticed is that more and more traffic
lights at night autodetect the presence of the car on intersection and
switch to green light if there is not traffic in "main" direction.
From what I have seen it is generally accepted that EROEI for FF has
been and will continue (lots of peer reviewed papers documenting this)
to be in a downward trend. Then it is open for projections how fast
this downward trend will develop and its consequences.
What matters
is net affordable energy that will be made available for societies.
In the short term it is about flows, longer term; size and quality of
remaining stocks.
Selling assets to pay down dividends/buy back stocks is
liquidation.
Further up in this post Nathanel shared some great insights;
"Personally, from my background in general financial analysis,
the two really big metrics I've been watching lately: Dividends in
excess of current earnings mean a company in decline. Borrowing money
to pay the dividend means a company which is in unmanaged,
uncontrolled decline. (Managed decline would involve liquidating
assets to pay dividends, and *paying off* debt.)
"
"Look at what they do and not what they say."
Several big oil companies have used money for stock buy backs, but
another trend I found interesting is also how they move into renewable
(solar and wind). This should be an indicator about what these
companies find profitable.
Just to be clear, I think renewables are great, but we also need to
recognize the dominant role of FF.
I had trouble following the logic – one line seems to be that investors
continue to put money into oil companies because they (the investors)
believe in abiotic oil. I'm pretty sure that is wholly incorrect.
I don't get why the recent uptick in USA production (much of which was
due to GoM projects that had been started several years ago, not just from
shale drilling) has got anything really to do with the losses of the
companies highlighted. Is the suggestion that without that uptick investors
would have suddenly realised that all the oil companies are going down the
toilet? I'm pretty sure that's wrong as well.
LTO is still a relatively small part of ExxonMobil and Chevrons portfolio
(note if you look only at the upstream parts of those companies the losses
actually have been worse than shown, they were saved by downstream profits).
The losses are because of over investment leading to a supply glut. There
has been almost no impact from falling global demand. The over investment
was in all sections not just in LTO. LTO stands out because the supply can
be seen to clearly increase over the past few years, but it had not much
more impact than oil sands (also showing a clear increase) or in fill
drilling in Russia and Opec ME, which just acted to stop decline, and
therefore doesn't stand out so much.
That ETP thing gets thrown in but, apart from being wrong in many
different ways, doesn't seem to be linked to any of the other observations
or conclusions.
Negative cash flow does not automatically translate into unprofitably if
CAPEX is a big portion of it.
There are no doubts that oil companies have taken on more debts, but it
would be more helpful if debts were presented on a specific basis that is $$
of debt per barrel of oil (or oil equivalent) of reserves.
So far I cannot see the author has made any real attempts to explain the
thermodynamic oil collapse.
Good to see you woke up from the DEAD. Haven't seen you posting
much. Glad to know I am able to get you out of BED once in a while.
Anyhow . I would imagine we can use any financial metric to show how
profitable or unprofitable a company is by relating it to this or that
metric, but in the end the figures speak for themselves. The U.S. Major
Oil Industry is in big trouble. Hell, the majority of the economy and
financial system is one big BUBBLE looking for a PIN.
Regardless, ExxonMobil and the rest of the U.S. energy sector is in
serious trouble. While ExxonMobil only has $29 billion in long term debt,
their total liabilities are $169 billion.
There's lots of garbage hidden in these companies that most investors
tend to overlook.
"... Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines. ..."
"... By contrast, new wells in the Permian continue to perform better than older wells. ..."
"... That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays. ..."
"There is no data on average well quality for the wells that started production
in 2016. Is that because the data for last year is incomplete?"
If you go to the "Well quality" tab in the first presentation, you'll see 2016 profiles
as well.
The "Ultimate Recovery" overview only supports displaying production histories for wells
of the same age. As there are still 2016 vintage wells on which I have no data (the ones
that started in Nov/Dec), 2016 is not yet shown if you display it by "Year of first flow".
However, if you change the selection to "Quarter of first flow", or "Month of first flow",
then you will see more recent data as well, incl 2016.
You may remember past discussions here where we discussed displaying or omitting incomplete
tails in the well profile graphs. The Well Quality tab can show incomplete tails, while
the Ultimate Recover tab can't.
I just found that the number 2016 in the legend was hidden.
Comparing well performance in the Permian and the Eagle Ford, it seems that average
IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month
of production), but declines in the EFS are much steeper.
As a result, by the tenth month, average well in the Permian produces 210.7 b/d, and
in the EFS only 122.6 b/d.
Furthermore, well productivity in the Eagle Ford is detereorating over time compared
to the wells drilled in previous years, which may suggest that
longer laterals and bigger fracs result in only slightly higher IPs but much steeper
declines.
By contrast, new wells in the Permian continue to perform better than older wells.
That may explain why drilling/completion activity and LTO production in the Permian
have remained more resilient and are quickly recoveri
Softpanorama
"Both production and demand are at record highs for oil natural gas and natural gas liquids. "Boomer II, says: 12/22/2017 at 6:40 pm
Glenn,Glenn E Stehle says: 07/18/2017 at 5:05 pm
Glenndclonghorn says: 07/20/2017 at 3:47 pm
Thank you for the link.AlexS says: 05/29/2017 at 9:14 am
Now we have roundabout 4-5 million b/d shale production – how can only the double number of new wells bring the triple production?Kolbeinh says: 05/29/2017 at 1:17 pm
Occidental profit beats; shares fall on weak output forecast | Reuters : "Occidental Petroleum Corp's quarterly profit beat estimates on Thursday but the company's shares fell to a near eight-year low as the oil and gas producer forecast lower-than-expected production for the current quarter."AlexS says: 05/30/2017 at 12:07 pmOxy is still largely a conventional producer.AlexS says: 05/30/2017 at 1:28 pm
"Most of the giant oil companies seem to think they're not, as they write off or sell their crown jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It's called creative destruction, as older producing properties and techniques can no longer compete with the new ones."shallow sand says: 05/30/2017 at 1:02 pm
Had to laugh, earlier in the week I noticed zero hedge suddenly started reporting in "Lower 48 production" after US production dropped last week.jed says: 05/28/2017 at 11:43 pm
SPRs in general try to have 90 days of domestic consumption in them. This was a standard put into place mostly in Europe. China has embraced it.Dennis Coyne says: 05/25/2017 at 12:30 pm
Hello, don't forget that Xinhua doesn't publish China's SPR figures. The SPR figure in the chart is an estimate based on (Production + Imports – Refinery Inputs). I'm not sure if all the teapots are included in the official refinery data.Energy News says: 05/26/2017 at 8:49 am
China's April diesel stocks fall for second straight month -XinhuaGeorge Kaplan says: 05/26/2017 at 1:54 pm
Most warnings are from 2014, some from 2015:
