May the source be with you, but remember the KISS principle ;-)
Bigger doesn't imply better. Bigger often is a sign of obesity, of lost control, of overcomplexity, of cancerous
cells
Subprime oil: Deflation of the USA shale oil bubble
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.
The cost of producing a large lithium battery is high and it is "perishable product",
which will not last even 10 years. The average life expectancy of a new EV battery at about
five (Tesla) to eight years. Or about 1500 cycles (assuming daily partial recharge, which
prolongs the life of the battery) before reaching 80% of its capacity rating. https://www.quora.com/What-is-the-cycle-lifetime-of-lithium-ion-batteries
Battery performance and lifespan begins to suffer as soon as the temperature climbs above
86 degrees Fahrenheit. A temperature above 86 degrees F affects the battery pack performance
instantly and often permanently. https://phys.org/news/2013-04-life-lithium-ion-batteries-electric.html
It is also became almost inoperative at below freezing point temperatures. For example it
can't be charged.
So they need to be cooled at summer and heated at winter. Storing such a car on the street
is out of question. You need a garage.
And large auto battery typically starts deteriorating after three years of daily use or
800 daily cycles.
Regular gas, and , especially, diesel cars can last 20 years, and larger trucks can last
30 years.
This fracking can't go on much longer. They've drilled out much of the sweet spots already,
and from what I hear, there are already 7 'child' wells being drilled for every 'parent'
well. (as I understand it, a 'child' well is drilled in close proximity to the 'parent'
without – hopefully-hitting and drawing from the same formation') If fracking were to
stop tomorrow, you'd lose over 600k bbls/day in production immediately and the whatever is
leftover tapering off to zero over the course of two-three years.
The question is: Just how long will the USA be able to continue to increase production in
order to hold off peak oil?
Yes will it go bankrupt first or continue to run on until peak and depletion. Meanwhile it
drags down the oil price artificially making most other oil development less likely, and
increasing volatility.
The FED is reducing money supply by 50 billions per month at the moment. The first feeling it
will be comanies needing to sell junk bonds.
This is a big ploblem for the relentless "drill baby drill" programs of several LTO
companies.
And a global economic crises, even if only a few years long, will crash oil prices AND
credit supply. This will hurt LTO more than the oil price crash from 2015.
On the shale topic; it is marvelously stupefying to observe a heavily indebted shale
industry supplying increasing volumes of oil, to an extent that the price/bbl never hits a
level where any debt reduction can be realized. (to say nothing of profit)
Its' almost as if they have no intention of becoming solvent.
Some time ago presented estimate of oil used to create and move food in the US. My recall is
the number wasn't huge.
Recently came across new data. Will get around to laying it out.
25% of total US consumption. Tractors, insecticides, some fertilizer(transport of those to
the field), transport of animal food to hogs, beef, etc, transport of human food to shelves,
transport of people to the shelf and home. 15% pre transport of human food, 10% transport
human food.
Pretty efficient agriculture in the US. No squeezing that 5 mbpd.
There are a lot of things that you can running one trillion deficit ;-)
Notable quotes:
"... U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA's latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy's estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world. ..."
"... All of this bullshit is straight, I mean straight off Continental's self servicing investor presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some common sense and think for yourself. As opposed to letting someone else do your thinking for you. ..."
"... Watcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to? Never mind, you can't answer that. ..."
"... "If its wells are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year in interest on long term debt if it didn't have to?" ..."
"... We had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it. ..."
"... One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years? ..."
"... I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in 2007 and gas prices were the highest they had ever been, it was not cash flow positive. ..."
"... On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17. ..."
"... However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that. ..."
"... Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years. ..."
"... What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do. ..."
"... Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016. ..."
U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018,
according to EIA's latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is
the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil
production exceeded the Russian Ministry of Energy's estimated August production of 11.2
million b/d, making the United States the leading crude oil producer in the world.
Dennis, Coffee's comment did not turn me into a shale cheerleader. I suppose I am more in the
shale sceptic camp for the reasons you mention and others.
Nevertheless, I think Coffee's comment was correct, it does appear that shale producers in
the Bakken have expanded the area that produces exceptional wells. As one who underestimated
shale's viability before, I don't want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or
anywhere) will occur. I had thought that current drilling levels would be inadequate to
sustain 1.15 million bpd production levels, but somehow they are increasing production there.
It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro
factors such as debt, interest rates, and the economy will play out, and eventually Bakken
production will decline. But for now
I have not read Continental's conference call transcript yet (Seeking Alpha provides
them), but it seems the suit from Continental now feels they will recover – from
present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.
All of this bullshit is straight, I mean straight off Continental's self servicing investor
presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some
common sense and think for yourself. As opposed to letting someone else do your thinking for
you.
Watcher is correct, CLR's credit rating, its credit score, so to speak, is so bad it could
not in the real world buy a pickup truck without its mama co-signing the note. If its wells
are sooooooo much better, why don't they pay some of that $6 billion plus dollars of debt
back? I mean really, who in their right mind would actually WANT to pay $420MM a year in
interest on long term debt if it didn't have to? Never mind, you can't answer that.
If you are not in the oil business and have never balanced an oil well's checkbook in your
life, which Coffee hasn't, then you don't know that higher productivity comes with a higher
cost in the shale biz. The bottom line then is that the bottom line does not change if it did
the shale oil industry would be paying down some debt, right? Its not. Private debt is
skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure
Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion
dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are
down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about
day six.
"If its wells are sooooooo much better, why don't they pay some of that $6 billion plus
dollars of debt back? I mean really, who in their right mind would actually WANT to pay
$420MM a year in interest on long term debt if it didn't have to?"
I wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will
be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can
get away with it, and then declare bankruptcy and walk away.
We had 5-6 years of the highest, sustained oil prices in history and the shale oil
industry could NOT make a profit. People seem to think now things have changed for some
reason, that the shale oil industry has now become more ethical, and temporarily higher
productivity of wells, and some imaginary oil price off in the future (for most shale guys
its now down in the mid to low $50's) will allow them to pay down debt. Its absurd logic, but
keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm's 20% of OOIP in the Bakken is a
big 'ol whopper) and look at the shale industry's financial performance over the past 10
years and decide for yourselves if it is sustainable or not.
One thing to add. The shale companies did all this in the lowest interest rate environment we
have had in a long time. They could not pay off their debt or even put a dent in it. What is
going to happen when their interest costs increase 30-50% over the next 2-3 years?
I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in
2007 and gas prices were the highest they had ever been, it was not cash flow positive. It
actually ate all the revenue from the rest of the company. Getting to be in the black for the
play was always a year off. a decade later it never got there, they just got more and more
debt sold more producing assets to pay for it to keep the shell game going and just got
bought by Encanna. I have seen the same at every public company I have worked for, many of
them survived the downturn only because costs dropped and so did the cost of debt. Now with
increasing costs and cost of debt there will likely be many bankruptcies.
Yeah, I agree with Mike, Rystads announcements are mainly just self serving hogwash. Yes, oil
production in the US looks to be close to 11.3 million for August. EIA's reported production
for Texas is only about 50k over my high estimate, so I see nothing to argue about. GOM is
the main surprise, and George and others are better suited to comment on that. The
understanding I had was that it was temporary. As far as Texas goes, I'm pretty sure it is
the high, for awhile. Completions dictate how much oil comes out of the ground, not drilling
rigs. That is for unconventional wells, not conventional. That is why I think the EIA's DPR
is a ridiculous measurement assessment. Apples and oranges. Articles that I have read
indicate a significant decrease in completions in the Permian by the end of August. Texas
production is not all about the Permian. A significant amount was contributed by the Eagle
Ford and other areas. All completions have slowed to the point that by the end of September,
they were at slightly over 60% of June's completion numbers according to RRC statistics.
Significant drop, and it will show up in following months. First years decline rates will
assure that it will drop slightly from this point. $64 WTI won't motivate it to expand to any
extent. The next year will see US wavering along the 11.1 million barrel level, I still
think. Unless, George thinks the GOM increase is somewhat permanent, which I doubt.
And try to locate a time in history when production is trending up, while completions are
trending down. There is usually a several month lag by the time production slows. Takes a
while to get out of the ground if they are completed towards the end of the month.
Don't you just love simple logic? Like: fire burns, water is wet, stuff like that?
I second that. Being from Norway myself, and having actually been working in consulting some
years ago. It looks nice on paper, but the world is changing and it is wise to look out for
deception and that is often the case in consulting (customer/revenue first and reality
second).
Based on the shaleprofile data it looks as if well productivity increased alot in 2016 and
2017 due to longer laterals and increased proppant intensity. 2018 well productivity looks to
be trending pretty close to 2017, so the productivity gains from longer lats and increased
proppant might have been exhausted by now. Therefore, comparing 2018 well completion numbers
to any pre 2017 completion numbers won't tell you much, but a comparison of 2018 and 2017
numbers should. In the 4 months ending in September 2018 completions grew year over year by
almost 70% from 2017, hence the large assumed increase in production in the last four months
of 2018. What is interesting though is that it looks like the free lunch from increased lats
and proppant looks to be almost over, and any future increases in production must be the
result of an increase in completion activity, which should result in some inflation for the
service providers going forward. And, according to Schlumberger, if you adjust for the longer
lats and increased proppant it actually appears that productivity is starting to trend down
(and the increased usage of poor quality in basin sand will likely contribute to this as
well)
I take your word for it. Thank you, BTW. You are the only one left on this site that has any
common sense regarding shale oil economics and the burden all that massive, massive amount of
debt has on running a business where your assets decline at the rate of 28-15% annually.
Everybody else seems mesmerized by productivity.
Paying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells.
Investors will want these companies to pay dividends because they will not be in a position
to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile
in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.
The prices can be thought of as 3 year average prices, yes there will be volatility, my
"low price scenario" has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to
predict the exact oil price and of course oil prices will be volatile, but the average over
time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average,
some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will
continue, but the three year trend in prices (centered 3 year average) has been up $7/b for
the past year, my expectation is that this trend will continue and the 3 year centered
average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be
higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in
2017$) are likely to reach $100/b by 2024 or 2025.
I think company by company because I have an investment in a private company. I know how
important timing is in the upstream industry to individual companies.
Likewise, I understand you aren't all that interested in individual companies. No problem
there.
On the price, I understand why you use different scenarios. However, the average price
over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14
and 2015–17.
I was recently in a major city and saw more Tesla's than I ever had, including my first
Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a
2018.
Pretty doubtful it will be $50/b over the next three years, in my opinion. If you believe
that you should find another business More likely is a gradual increase in
oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price
(today's future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61
(Dec 2026). By Contrast the EIA's AEO 2018 reference oil price scenario for Brent crude has
the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too
low.)
As always clicking on the chart give a larger view.
The price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of
course).
So in that scenario I'd feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for
every year.
However, the price is far too volatile to model anything very far into the future, just
like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet
that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate
to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the
market prices of 2011-14, we would be bankrupt, absent having hedged everything for four
years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high
as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140
per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years.
Is that likely? No, but oil did drop below that level in 2016.
The volatility is a big problem, there is no doubt of that. When imagining the "big
picture". I use the estimates of the EIA's AEO as a starting point then add my personal
perspective (that at some point oil output will peak.) Below is a chart with my guess from
Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for
comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great,
but better than my guess. Future guesses will be equally bad.
In 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil
would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November.
However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to
a small company which employs 8 full time employees, one part time employee office manager
and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don't talk to me about that. It's
about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you
do SWAPS or Collars, you need to put up a lot of margin money.
Hedging seems a risky business, not sure I would come out ahead by hedging. You are in a
tough business, the volatility sucks. The silver lining is that prices will be
increasing.
Shallow Sand Wrote:
"Paying the debt off will depend very much on future oil and natural gas prices."
I don't think so. When energy prices rise, so do prices of everything else, included
interest rates. The only way the shale drillers could play off there debt is if the left
large number of completed wells untapped (ie leave it in the ground) while taking advantage
of cheap debt & low labor\material costs. Then selling the oil when prices & costs
have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices.
Thus when oil prices rise most of the oil is already produced & drilling new wells (using
more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well.
I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale
drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never
going to happen)?
FWIW: I don't believe any of the shale companies are in game for the long term. They are
simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity
by selling a product below cost. They will continue to play the game until investor capital
dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their
bonds come due & they won't have the ability to refinance it or pay it off. If I recall
correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds
between 2020 & 2022.
The key question not addressed by the author is how long the period of "plato oil
production" (the last stage of the so called "oil age", which started around 1911) might
last -- 10, 20 or 50 years. And the oil age is just a very short blip in Earth
history.
Let's assume that this means less the $100 per barrel; in the past, it was $70 per
barrel that considered the level that guarantees the recession in the USA, but financial
system machinations now probably reached a new level, so that might not be true any
longer. The trillion dollars question is "How long this period can be extended?"
It is important to understand the US shale oil is not profitable and never will be for
prices under $80 or so. At prices below that level, it actually produces three products,
not two – oil, gas and junk bonds.
I view it as a very sophisticated, very innovative gamble to pressure oil prices down
and get compensation for the losses due to large amount of imported oil (the USA export
mainly lightweight oil which is kind of "subprime oil" often used for dilution of heavy
oil in countries such as Canada and Venezuela, but imports quality oil).
If the hypothesis that Saudis and Russians are close to Seneca Cliff (Saudi prince
recently said that Russian are just 10-15 years from it) and that best days of the US
shale and Gulf of Mexico deep oil is in the past if true, then "Houston we have a
problem".
That means that in 20 years, or so the civilization might experience some kind of
collapse, and the population of the Earth might start rapidly shrinking.
While the U.S. Shale Industry
produces a record amount of oil, it continues to be plagued by massive oil decline rates and debt.
Moreover, even as the companies brag about lowering the break-even cost to produce shale oil, the
industry still spends more than it makes. When we add up all the negative factors weighing down
the shale oil industry, it should be no surprise that a catastrophic failure lies dead ahead.
Of course, most Americans have no idea that the U.S. Shale Oil Industry is nothing more than a
Ponzi Scheme because of the mainstream media's inability to report FACT from FICTION. However,
they don't deserve all of the blame as the shale energy industry has done an excellent job hiding
the financial distress from the public and investors by the use of highly technical jargon and BS.
For example, Pioneer published this in the recent Q2 2018 Press Release:
Pioneer placed 38 Version 3.0 wells on production during the second quarter of 2018. The
Company also placed 29 wells on production during the second quarter of 2018 that utilized
higher intensity completions compared to Version 3.0 wells. These are referred to as Version
3.0+ completions. Results from the 65 Version 3.0+ wells completed in 2017 and the first half of
2018 are outperforming production from nearby offset wells with less intense completions. Based
on the success of the higher intensity completions to date, the Company is adding approximately
60 Version 3.0+ completions in the second half of 2018.
Now, the information Pioneer published above wasn't all that technical, but it was full of BS.
Anytime the industry uses terms like "Version 3.0+ completions" to describe shale wells, this
normally means the use of "more technology" equals "more money."
As the shale industry
goes from 30 to 60 to 70 stage frack wells, this takes one hell of a lot more pipe, water, sand,
fracking chemicals and of course, money
.
However, the majority of investors and the public are clueless in regards to the staggering
costs it takes to produce shale oil because they are enamored by the "wonders of technology." For
some odd reason, they tend to overlook the simple premise that
MORE STUFF costs MORE MONEY.
Of course, the shale industry doesn't mind using MORE MONEY, especially if some other poor slob
pays the bill.
Shale Oil Industry: Deep The Denial
According to a recently released article by 40-year oil industry veteran, Mike Shellman,
"Deep
The Denial,"
he provided some sobering statistics on the shale industry:
I recently put somebody very smart on the necessary research (SEC K's, press releases
regarding private equity to private producers, etc.) to determine what total upstream shale oil
debt actually is.
We found it to be between $285-$300B (billion), both public and
private
. Kallanish Energy Consultants recently wrote that there is $240B of long term
E&P debt in the US maturing by 2023 and I think we should assume that at least 90 plus percent
of that is associated with shale oil. That is maturing debt, not total debt.
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B
annually in interest on long term debt.
Using its own self-touted "breakeven" oil price, the shale oil industry must then produce
over 1.5 Million BOPD just to pay interest on that debt each year. Those are barrels of oil that
cannot be used to deleverage debt, grow reserves, not even replace reserves that are declining
at rates of 28% to 15% per year that is just what it will take to service debt.
Using its own "breakeven" prices the US shale oil industry will ultimately have to
produce 9G BO of oil, as much as it has already produced in 10 years just to pay its total long
term debt back
.
Using Mike's figures, I made the following chart below:
For the U.S. Shale Oil Industry just to pay back its debt, it must produce 9 billion
barrels of oil.
That is one heck of a lot of oil as the industry has produced about 10
billion barrels to date. Again, as Mike states, it would take 9 billion barrels of shale oil to
pay back its $285-300 billion of debt (based on the shale industry's very own breakeven prices).
Furthermore, the shale industry may have to sell a quarter of its oil production (1.5
million barrels per day) just to service its debt by the end of 2019.
According to the
EIA, the U.S. Energy Information Agency, total shale oil (tight oil) production is now 6.2 million
barrels per day (mbd):
The majority of shale oil production comes from three fields and regions, the Eagle Ford (Blue),
the Bakken (Yellow) and the Permian (light, medium & dark brown). These three fields and regions
produce 5.2 mbd of the total 6.2 mbd of shale production.
Unfortunately, the shale industry continues to struggle with mounting debt and negative free
cash flow. The EIA recently published this chart showing the cash from operations versus capital
expenditures for 48 public domestic oil producers:
You will notice that capital expenditures (
brown line
) are still higher than
cash from operations (
blue line
). So, it doesn't seem to matter if the oil price
is over $100 (2013-2014) or less than $70 (2017-2018), the shale oil industry continues to spend
more money than it's making.
The shale energy companies have resorted to selling assets,
issuing stock and increasing debt to supplement their inadequate cash flow to fund operations.
A perfect example of this in practice is Pioneer Resources the number one shale oil producer in
the mighty Permian. While most companies increased their debt to fund operations, Pioneer decided
to take advantage of its high stock price by raising money via share dilution.
Pioneer's
outstanding shares ballooned from 115 million shares in 2010 to 170 million by 2017. From 2011 to
2016, Pioneer issued a staggering $5.4 billion in new stock
:
So, as Pioneer issued over $5 billion in stock to produce unprofitable shale oil and gas,
Continental Resources racked up more than $5 billion in debt during the same period. These are
both examples of "Ponzi Finance." Thus, the shale energy industry has been quite creative in
hoodwinking both the shareholder and capital investor.
Now, there is no coincidence that I have focused my research on Pioneer and Continental
Resources.
While Continental is the poster child of what's horribly wrong with the shale
oil industry in the Bakken, Pioneer is a role model for the same sort of insanity and delusional
thinking taking place in the Permian.
Pioneer Spends A Lot More Money With Unsatisfactory Production Results
To be able to understand what is going on in the U.S. shale industry, you have to be clever
enough to ignore the "Techno-jargon" in the press releases and read between the lines. As
mentioned above, Pioneer stated that it was going to add a lot more of its "high-tech" Version 3.0+
completion wells in the second half of 2018 because they were outperforming the older versions.
Well, I hope this is true because Pioneer's first half 2018 production results in the Permian
were quite disappointing compared to the previous period.
If we compare the increase of
Pioneer's shale oil production in the Permian versus its capital expenditures, something must be
seriously wrong
.
First, let's look at a breakdown of Pioneer's Permian energy production from their September
2018 Investor Presentation:
Pioneer's Permian oil and gas production is broken down between its horizontal shale and
vertical convention production. I will only focus on its horizontal shale production as this is
where the majority of their capital expenditures are taking place. The highlighted yellow line
shows Pioneer's horizontal shale oil production in the Permian Basin.
You will notice that Pioneer's shale oil production increased significantly in Q3 & Q4 2017
versus Q1 & Q2 2018. Furthermore, Pioneer's shale gas production surged in Q2 2018 by nearly 50%
(highlighted with a red box) compared to oil production only increasing 5%. That is a serious RED
FLAG for natural gas production to jump that much in one quarter.
Secondly, by comparing the increase of Pioneer's quarterly shale oil production in the Permian
with its capital expenditures, the results are less than satisfactory:
The RED LINE shows the amount of capital expenditures spent each quarter while the OLIVE colored
BARS represent the increase in Permian shale oil production. To simplify the figures in this
chart, I made the following graphic below:
Pioneer spent $1.36 billion in the second half of 2017 to increase its Permian shale oil
production by 30,232 barrels per day (bopd) compared to $1.7 billion in the first half of 2018
which only resulted in an additional 10,832 bopd
. Folks, it seems as if something
seriously went wrong for Pioneer in the Permian as the expenditure of $340 million more CAPEX
resulted in two-thirds less the production growth versus the previous period.
Third, while Pioneer (stock ticker PXD) proudly lists that they are one of the lowest cost
shale producers in the industry, they still suffer from negative free cash flow:
As we can see, Pioneer lists their breakeven oil price at approximately $22, which is downright
hilarious when they spent $132 million more on capital expenditures than the made in cash from
operations:
The public and investors need to understand that "oil breakeven costs" do not include capital
expenditures. And according to Pioneer's Q2 2018 Press Release, the company plans on spending
$3.4 billion on capital expenditures in 2018. The majority of the capital expenditures are spent
on drilling and completing horizontal shale wells.
For example, Pioneer brought on 130 new wells in the first half of 2018 and spent $1.7
billion on CAPEX (capital expenditures) versus 125 wells and $1.36 billion in 2H 2017.
I
have seen estimates that it cost approximately $9 million for Pioneer to drill a horizontal shale
well in the Permian. Thus, the 130 wells cost nearly $1.2 billion.
However, the interesting thing to take note is that Pioneer brought on 125 wells in 2H 2017 to
add 30,000+ barrels of new oil production compared to 130 wells in 1H 2018 that only added 10,000+
barrels.
So, how can Pioneer add five more wells (130 vs. 125) in 1H 2018 to see its oil
production increase a third of what it was in the previous period?
Regardless, the U.S. shale oil industry continues to spend more money than they make from
operations. While energy companies may have enjoyed lower costs when the industry was gutted by
super-low oil prices in 2015 and 2016, it seems as if inflation has made its way back into the
shale patch. Rising energy prices translate to higher costs for the shale energy industry. Rinse
and repeat.
Unfortunately, when the stock markets finally crack, so will energy and commodity prices.
Falling oil prices will cause severe damage to the Shale Industry as it struggles to stay afloat by
selling assets, issuing stock and increasing debt to continue producing unprofitable oil.
I believe the U.S. Shale Oil Industry will suffer catastrophic failure from the impact
of deflationary oil prices along with peaking production.
While U.S. Shale Oil production
has increased exponentially over the past decade, it will likely come down even faster.
Oil prices are down a bit, but are still close to multi-year highs. That should leave the
shale industry flush with cash. However, a long list of US shale companies are still struggling
to turn a profit. A new report
from the Institute for Energy Economics and Financial Analysis (IEEFA) and the Sightline
Institute detail the "alarming volumes of red ink" within the shale industry.
"Even after two and a half years of rising oil prices and growing expectations for
improved financial results, a review of 33 publicly traded oil and gas fracking companies shows
the companies posting negative free cash flows through June," the report's authors write.
The 33 small and medium-sized drillers posted a combined $3.9 billion in negative cash flow in
the first half of 2018.
The glaring problem with the poor financial results is that 2018 was supposed to be the year
that the shale industry finally turned a corner. Earlier this year, the International Energy
Agency painted a rosy portrait of US shale,
arguing in a report that "higher prices and operational improvements are putting the US
shale sector on track to achieve positive free cash flow in 2018 for the first time
ever."
The improved outlook came after years of mounting debt and negative cash flow. The IEA
estimates that the US shale industry generated cumulative negative free cash flow of over
$200 billion between 2010 and 2014. The oil market downturn that began in 2014 was supposed to
have changed profligate spending, pushing out inefficient companies and leaving the sector as a
whole much leaner and healthier.
"Current trends suggest that the shale industry as a whole may finally turn a profit in
2018, although downside risks remain," the IEA wrote in July. " Several companies expect
positive free cash flow based on an assumed oil price well below the levels seen so far in 2018
and there are clear indications that bond markets and banks are taking a more positive attitude
to the sector, following encouraging financial results for the first quarter."
But the warning signs
have been clear for some time. The Wall Street Journal reported
in August that the second quarter was a disappointment. The WSJ analyzed 50 companies, finding
that they spent a combined $2 billion more than they generated in the second quarter.
The new report from IEEFA and the Sightline Institute add more detail the industry's recent
performance. Only seven out of the 33 companies analyzed in the report had positive cash flow
in the first half of the year, and the whole group burned through a combined $5 billion in cash
reserves over that time period.
Even more remarkable is the fact that the negative financials come amidst a production boom.
The US continues to break production records week after week, and at over 11 million barrels
per day, the US could soon become the world's largest oil producer. Analysts differ over the
trajectory of shale, but they only argue over how fast output will grow.
Yet, even as drillers extract ever greater volumes of oil from the ground, they still are
not turning a profit. "To outward appearances, the US oil and gas industry is in the midst
of a decade-long boom," IEEFA and the Sightline Institute write in their report. However,
"America's fracking boom has been a world-class bust."
The ongoing struggles raises questions about the long-term. If the industry is still not
profitable – after a decade of drilling, after major efficiency improvements since 2014,
and after a sharp rebound in oil prices – when will it ever be profitable? Is there
something fundamentally problematic about the nature of shale drilling, which suffers from
steep decline rates over relatively short periods of time and requires constant spending and
drilling to maintain?
Third quarter results will start trickling in over the next few days and weeks, which should
provide more clues into the shale industry's health. There is even more pressure on drillers to
post profits because the third quarter saw much higher oil prices.
"Until the industry as a whole improves, producing both sustained profits and
consistently positive cash flows, careful investors would be wise to view fracking companies as
speculative investments," the authors of the report concluded.
"... US tight oil output was about 6200 kb/d in August 2018 according to the EIA, not that the DPR includes oil from the region of tight oil plays that is conventional oil, also it is a model that is not very good so I ignore the DPR ..."
Any guess what the price of crude would be today if we had no fracking in N. America?
Wild guess is all I've got, but I'm saying $142 (and much lower economic growth over the past
9 yrs- maybe even flat averaged for the whole period).
Any other speculations on this?
USA LTO is ~7.5 million bpd. That exceeds global spare capacity over demand as-is today by at
least four times. So if the world was still trying to consume what it is today, we would be
several million short and would have been short by seven figures for several years.
I think we would have found out if there really are any huge but uneconomical fields out
there by now as the panic from that set in a few years ago. A shortage on that scale means
arbitrary prices pending demand cap/destruction.
US tight oil output was about 6200 kb/d in August 2018 according to the EIA, not that the
DPR includes oil from the region of tight oil plays that is conventional oil, also it is a
model that is not very good so I ignore the DPR .
WAG on oil price with zero LTO output is $120/b in 2017$, plus or minus $20/b.
Canada (offshore), Hebron is expected to produce around 150,000 barrels a day, from about
40,000 barrels a day now.
2018-10-22 (The Globe and Mail) It's been one year since ExxonMobil's long-awaited Hebron
platform off the southeast coast of Newfoundland started pumping crude from its first well.
It took four years, $14 billion, 132,000 cubic metres of concrete and a few thousand workers
to bring it online, and so far, it's churning out about 40,000 barrels a day, with the crude
bound for markets in the U.S. Gulf states, Europe and much of eastern North America.
Eventually, Hebron will drill 20 to 30 wells, and is expected to produce around 150,000
barrels a day.
With an expected reserve of 700 million barrels of recoverable crude, the Hebron project is
expected to operate for 30 years. As Newfoundland's fourth offshore platform, it will play a
key role in the province's plan to double overall production to more than 650,000 barrels a
day by 2030.
https://www.theglobeandmail.com/business/article-why-hebron-has-a-leg-up-on-albertas-oil-sands/
Hebron is already at 70 kbpd and has been for a few months. I thinks its expected annual
average for oil only is 135 and it will take a year or so to get there as the coming wells
will be less productive that the first ones. In the mean time the three other platforms are
in decline (Terra Nova was originally due to be taken off line next year – not sure
what the latest thinking is). They dropped about 35 kbpd last year but that may accelerate as
Hibernia is coming off a secondary plateau.
Yeah, that's going to get a lot worse. It's counting Iran production, and not what it can
sell. A lot in floating storage, and being stored close to China and elsewhere. US is the
only one with an increase, and that increase is on a hiatus until new pipelines come on,
regardless of the EIA overstated production numbers. So, we would be short before any demand
increase, or non-OPEC declines. But, never worry, as IEA says peak oil is just a figment of
our imagination
"The Saudi government said it would take another month to complete a full investigation,
which would be overseen by Mohammed.
Mohammad will find that Mohammad had nothing to do with the issue."
Perhaps an anti-KSA Boycott, Divestment, Sanctions (BDS) Movement will get started.
Consumers and competitors might find the idea appealing.
Nice ideas for new KSA flag designs at this link here (I most like the chainsaw instead of
the current sword design- reminds me of Scarface- Mo Bin Clownstick™ is about as
legitimate and sophisticated as a coke runner): https://www.moonofalabama.org/2018/10/saudis-admit-khashoggi-murder.html
The Sultan is playing his hand well (drip drip drip Turkish Int. leaks to the news with an
intensifying puke factor- one recent read that Khashoggi was dismembered alive and dissolved
in acid). Has Mo Bin Clownstick™ met his match? https://lobelog.com/the-geopolitics-of-the-khashoggi-murder/
I can't help but wonder about all those guys he threw into a hotel prison and shook down for
billions of dollars. They can afford a lot of media with the money they had remaining.
From the report: The $3.9 billion in negative cash flows in the first two quarters of 2018 represented an
improvement over the first halves of 2016 and 2017, when red ink totaled $11 billion and $7.2
billion, respectively.
These 33 companies have had positive net income since 2017Q4 and long term debt reached
its peak for these companies in 2018Q1 at 138 billion with a gradual decrease to 126 billion
in 2018Q2. As prices continue to rise debt will gradually be paid down,
When I look at that report I see an improving situation for these companies. I would
prefer it if they broke the data into two groups, oil focused and natural gas focused
companies. There has been a better recovery in oil prices than natural gas prices though it
looks like we might see a spike in natural gas prices if we have a colder than normal
winter.
India's crude oil imports, the average for the first 9 months of 2018 is up +279 kb/day
compared to first 9 months of 2017
Seasonal chart: https://pbs.twimg.com/media/DqGtWDoX4AAYDwJ.jpg
India's crude oil refinery processing, the average for the first 9 months of 2018 is up +231
kb/day compared to first 9 months of 2017
Seasonal chart: https://pbs.twimg.com/media/DqGttFOW4AAr0Uy.jpg
Saudi Arabia spare capacity, there seems to be a consensus that Saudi Arabia can produce 11
million b/day. I guess that producing above that level would be subject to maintenance,
outages and natural decline? (Also I'm guessing that the Khurais field expansion might not be
ready until later in 2019?)
2018-10-22 Saudi Arabia Energy Minister Al Falih speaks to TASS
Saudi Arabia now in October is producing 10.7 million b/day.
And is likely to go up, in the near future, to 11 million b/day on a steady basis.
Our total production capacity is currently 12 million b/day.
And that could be increased to 13 million b/day with an investment of $20 to $30 billion.
Interview with TASS: http://tass.com/economy/1026924
Exxon in Brazil holds potential 41 billion barrels based on preliminary studies
2018-10-18 RIO DE JANEIRO and HOUSTON (Bloomberg) -- In a single year, Exxon Mobil has
gone from being a tiny bit player in Brazil to the second-largest holder of oil exploration
acreage, trailing only state-controlled Petroleo Brasileiro.
The last 24 concessions the U.S. giant bought with its partners may hold 41 billion bbl,
based on preliminary studies, according to Eliane Petersohn, a superintendent at Brazil's
National Petroleum Agency, or ANP. While the existence of the oil still needs to be
confirmed, along with whether its extraction will be cost-effective, it's a huge figure --
almost double Exxon's current reserves.
The Irving, Texas-based company is betting big in particular on Brazil's offshore, where a
single block is currently producing more than all of Colombia and profitability compares to
the best U.S. tight oil, according to Decio Oddone, the head of ANP.
It should take six to eight years for oil to start flowing if economically viable deposits
are discovered, according to ANP.
https://www.worldoil.com/news/2018/10/18/exxon-makes-major-bet-on-brazil-as-petrobras-eases-its-grip
Mike Shellman writes again. No need for me to elaborate much on his persistent and very much needed gentle nudgings about debts
coming due in the U.S. Shale Oil industry.
Ignoring debt doesn't make it go away < cough > Venezuela < cough >
By year end 2019 I firmly believe the US LTO industry will then be paying over $20B annually in interest on long term debt.
...
In other words, at the moment about 29% of total LTO production in America is used just to pay debt interest.
Using its own "breakeven" prices the US shale oil industry will ultimately have to produce 9G BO of oil, as much as it has
already produced in 10 years...just to pay its total long term debt back. Essentially the only chance it has of doing that is
if oil prices go to $125 a barrel, and stays there for a very long time.
The debate about peak oil demand always tends to focus on how quickly electric vehicles will
replace the internal-combustion engine , especially as EV sales are accelerating. However, the
petrochemical sector will be much more difficult to dislodge , and with alternatives far
behind, petrochemicals will account for an increasing share of crude oil demand growth in the
years ahead.
"... "Barring technology breakthrough beyond what we already assume, we'll need new oil discoveries," ..."
"... "We haven't seen anything like this since the 1940s," ..."
"... "The most worrisome is the fact that the reserve replacement ratio in the current year reached only 11 percent (for oil and gas combined) - compared to over 50 percent in 2012." ..."
"... "The mind set for most E&Ps is still to be conservative, and default is to return capital to shareholders. Yet the duty to shareholders' interests cannot be myopically short term. More of the 'windfall' cash needs to find its way into exploration to sustain the business in the long term," ..."
"... "frontier areas," ..."
"... "Suriname, the Brazilian Equatorial Margin; Mexico; Senegal, Gambia, Namibia and South Africa; Australia and Alaska." ..."
"... "More explorers need to get in on the action if the spectre of 'peak supply' is to be kept at bay," ..."
"The warning signs are there – the industry isn't finding enough oil." That's the
start of a new report from Wood Mackenzie. The report concludes that a supply gap could emerge
in the mid-2020s as demand rises at a time when too few new sources of supply are coming
online.
By 2030, there could be a supply shortfall on the order of 3 million barrels per day (mb/d),
WoodMac argues. By 2035, it balloons to 7 mb/d, and by 2040, it reaches 12 mb/d. "Barring
technology breakthrough beyond what we already assume, we'll need new oil discoveries,"
the report says.
The seeds of the problem were sown during the oil market downturn that began in 2014. Global
upstream exploration spending plunged from $60 billion in 2014 to just $25 billion in 2018,
according to WoodMac. Unsurprisingly, that translated into a steep decline in new discoveries.
In the early part of this decade, the oil industry was discovering around 8 billion barrels of
oil annually. That figure has plunged by three quarters since 2014.
The precise figures vary, but Rystad Energy came a similar conclusion, noting that the total
volume of new oil and gas reserves discovered plunged to a record low in 2017. "We haven't
seen anything like this since the 1940s," Sonia Mladá Passos, Senior Analyst at
Rystad Energy, said in a December 2017
statement . "The most worrisome is the fact that the reserve replacement ratio in the
current year reached only 11 percent (for oil and gas combined) - compared to over 50 percent
in 2012."
This year, the industry has had a bit more success. Spending is on the rebound and new
discoveries are on
track to rise by about 30 percent, although that is heavily influenced by the developments
in Guyana, where ExxonMobil and Hess Corp. have reported nearly a dozen discoveries, and hope
to ramp up production to around
750,000 bpd by 2025.
It still may not be enough. Even if the industry were to somehow return to the good ol' days
prior to the 2014 market crash, and begin discovering around 8 billion barrels of oil each
year, it would only delay the supply crunch into the 2030s, according to WoodMac.
But, of course, that rate of discovery remains far below those levels, so the supply crunch
may take place much sooner. Moreover, because large-scale projects take several years to
develop, the activity taking place today will determine the supply mix in the mid- to
late-2020s.
WoodMac says that the rate of discovery is highly correlated with the level of spending, so
closing the supply gap will require more capital. And because of the run up in oil prices this
year, the industry will have a lot more cash to throw around.
The problem for the industry is that over the last few years the mindset, and the demands of
shareholders, have shifted from production growth to profitability and investor returns.
Shareholders are pressuring executives to return cash in the form of dividends and share
buybacks. Energy stocks are not the darlings of Wall Street in the way they once were,
particularly prior to the 2014 market meltdown. That puts extra pressure on oil and gas
companies to dish out more of their earnings to investors rather than plowing it back into the
ground.
But that means less spending on exploration. "The mind set for most E&Ps is still to
be conservative, and default is to return capital to shareholders. Yet the duty to
shareholders' interests cannot be myopically short term. More of the 'windfall' cash needs to
find its way into exploration to sustain the business in the long term," WoodMac said in
its report.
Shale output will continue to grow, especially after new pipelines come online in Texas,
which will ease the current bottleneck. But the large-scale increases in production in the
medium-term will come from "frontier areas," WoodMac says, as the string of
discoveries in Guyana prove. WoodMac says the areas with the highest potential include
"Suriname, the Brazilian Equatorial Margin; Mexico; Senegal, Gambia, Namibia and South
Africa; Australia and Alaska."
For now, the level of activity is not enough to stave off the supply crunch, WoodMac warns,
unless there is a dramatic increase in spending. "More explorers need to get in on the
action if the spectre of 'peak supply' is to be kept at bay," the consultancy says.
The breakout in Brent crude prices above $80 this week has prompted analysts at the sell
side banks to start talking about a return to $100 a
barrel oil . Even President Trump has gotten involved, demanding that OPEC ramp up
production to send oil prices lower before they start to weigh on US consumer spending, which
has helped fuel the economic boom over which Trump has presided, and for which he has been
eager to take credit.
But to hear respected petroleum geologist and oil analyst Art Berman tell it, Trump should
relax. That's because supply fundamentals in the US market suggest that the recent breakout in
prices will be largely ephemeral, and that crude supplies will soon move back into a
surplus.
Indeed, a close anaysis of supply trends suggests that the secular deflationary trend in oil
prices remains very much intact. And in an interview with MacroVoices , Berman laid out his argument using a handy
chart deck to illustrate his findings (some of these charts are excerpted below).
As the bedrock for his argument, Berman uses a metric that he calls comparative petroleum
inventories. Instead of just looking at EIA inventory data, Berman adjusts these figures by
comparing them to the five year average for any given week. This smooths out purely seasonal
changes.
And as he shows in the following chart, changes in comparative inventory levels have
precipitated most of the shifts in oil prices since the early 1990s, Berman explains. As the
charts below illustrate, once reported inventories for US crude oil and refined petroleum
products crosses into a deficit relative to comparative inventories, the price of WTI climbs;
when they cross into a surplus, WTI falls.
Looking back to March of this year, when the rally in WTI started to accelerate, we can on
the left-hand chart above how inventories crossed below their historical average, which Berman
claims prompted the most recent run up in prices.
Comparative inventories typically correlate negatively to the price of WTI. But
occasionally, perceptions of supply security may prompt producers to either ramp up - or cut
back - production. One example of this preceded the ramp of prices that started in 2010 when
markets drove prices higher despite supplies being above their historical average. The ramp
continued, even as supplies increased, largely due to fears about stagnant global growth in the
early recovery period following the financial crisis.
The most rally that started around July 2017 correlated with a period of flat production
between early 2016 and early 2018.
Meanwhile, speculators have been unwinding their long positions. Between mid-June 2017 and
January 2018, net long positions increased +615 mmb for WTI crude + products, and +776 for WTI
and Brent combined. Since then, combined Brent and WTI net longs have fallen -335 mmb, while
WTI crude + refined product net long positions have fallen -225 mmb since January 2018 and -104
mmb since the week ending July 10. This shows that, despite high frequency price fluctuation,
the overall trend in positioning is down.
And as longs have been unwinding, data show that the US export party has been slowing, as
distillate exports, which have been the cash cow driving US refined product exports, have
declined. Though they remain strong relative to the 5-year average, they have fallen relative
to last year. This has accompanied refinery expansions in Mexico and Brazil.
Meanwhile, distillate and gasoline inventories have been building.
Meanwhile, US exports of crude have remained below the 2018 average in recent weeks, even as
prices have continued to climb.
This could reflect supply fears in the global markets. The blowout in WTI-Brent spreads
would seem to confirm this. However, foreign refineries recognize that there are limitations
when it comes to processing US crude (hence the slumping demand for exports).
In recent weeks, markets have been sensitive to supply concerns thanks to falling production
in Venezuela and worries about what will happen with Iranian crude exports after US sanctions
kick in in November.
But supply forecasts for the US are telling a different story than supply forecasts for
OPEC. In the US, markets will likely remain in equilibrium for the rest of the year, until a
state of oversupply returns in 2019. But OPEC production will likely continue to constrict,
returning to a deficit in 2019.
Bottom line: According to Berman, the trend of secular deflation in oil prices remains very
much intact. While Berman expects prices to remain rangebound for the duration of 2018 - at
least in the US - it's likely markets will turn to a supply surplus next year, sending prices
lower once again.
Perhaps the Eagle Ford will never be profitable, it will depend on the price of oil and
many other factors.
I guess I have a little more faith in the oil industry than you.
EOG has produced a fair amount of oil in the Eagle Ford and their net income in 2014 (when
oil prices were high) was $2.9 billion, about 178 kb/d of C+C was produced from Eagle Ford in
2014 (about 65 million barrels) by EOG (about 62% of total 2014 EOG C+C output). The average
price for C+C in the US received by EOG was about $93/b in 2014.
So it seems in 2014, for a well run oil company, $93/b worked just fine. Over the period
from 2010 to 2014 EOG's net income was about $6 billion. From 2010 to 2017, the total net
income was about $2.6 billion (not adjusted for inflation) as 2015 and 2016 were bad years
with 5 billion losses in net income.
Debt to assets at the end of 2017 was about 21% with debt at $6.4 billion and assets at
$29.8 billion. In 2017 Eagle Ford output was about 47% of EOG's C+C output, the average oil
price EOG received in the US was $50.91/b in 2017, about $600 million of long term debt was
paid off in 2017 with no new long term debt issued, but net cash flow was negative $766
million.
A discounted cash flow at a 10% annual discount rate results in a breakeven oil price (10%
annual ROI) of $90.3/b for the average 2016 Eagle Ford well, if we assume a well cost of 9
million. Note that this is a "real" discount rate as I do costs in real inflation adjusted
dollars, so it is equivalent to a nominal discount rate of 12.5% so would be equivalent to a
nominal annual ROI of 12.5%.
EUR is 238 kb over 13.8 years and the well is shut in at 10 b/d. An assumption of 15 b/d
shut in reduces EUR to 220 kb and well life to 9.75 years, and breakeven oil price rises to
$91/b, an increase of 70 cents per barrel. Well payout is in 46 months at $91/b.
What is the full cost of the average Eagle Ford well?
Note that I have assumed zero revenue from natural gas or NGL in my breakeven analysis and am
considering C+C output only, not sure if there are natural gas pipeline bottlenecks in the
EFS as there seems to be in the Permian basin. In any case, the economics might be slightly
better when natural gas is included.
There wasn't significant drilling in the Eagle Ford Shale until 2011. How many of the 700
inactive wells started producing in 2009 and 2010? By Enno Peters data using Eagle Ford and
unknown wells in Karnes County from Jan 2011 to Dec 2016, I get 2487 horizontal wells
completed in total over that period. Note that the productivity rate distribution at Enno's
site gives some funky numbers at the low end, so they should probably be ignored. "Zero"
output after 24 months should probably be less than 15 b/d after 24 months. For Eagle Ford
2014 wells, supposedly there are 1747 wells with zero production rate after 24 months out of
3962 total wells, this is just a programming error. That is, zero does not mean zero in this
case, would be my guess.
I checked with Enno Peters on this and the lowest column means output at 24 months is 0 to 50
b/d, same is true for each column it is from the previous to the next label so 0-50, 50-100,
etc.
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over
one year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at
all? Less than 10 year economic life?
No the wells have not been shut in as you think, for 2009 to 2016 wells in Karnes county
and Eagle Ford Formation I get 763 wells with "zero" production rate at Enno's site. He has
pointed out that this is really 0 to 50 bopd for those 763 wells out of a total of 2425 wells
producing that started production from 2009 to 2016. The average production rate was 86 bopd
for all of the Karnes county Eagle Ford formation wells.
For all counties there were 15,600 wells with 7754 wells with output at 0 to 50 bopd at 24
months. Average for all counties is 63 bopd at 24 months. At 12 months the average rate was
127 bopd for all counties with about 25% of the wells at 0 to 50 bopd at 12 months.
Older article, but more important, now. EIA, and most of the Rystad type companies are
continuing to report significant increases in the Permian. Latest monthlies are from June,
all else is estimated, including drilling info. Completions are happening, and the new wells
included in drilling info are, no doubt, true as to production. Who measures shut ins until
final numbers are accumulated? Who spends significant time communicating with the small
producer? Heck, they make up half the wells drilled in the Permian. I think there are
considerable shut ins that will eventually reduce the magnificent increases that are
currently being reported.
I ran a quick search on horizontal wells in Karnes Co., TX.
I found 2,778 active horizontal wells with first production from 1/1/2009 to
12/31/2016,
In the most recent month, here are the numbers:
170 wells produced 3,001+ BO
1,034 wells produced 1,001-3,000 BO
872 wells produced 501-1,000 BO
702 wells produced 1-500 BO
Could that be correct?
Furthermore, there appear to be over 700 inactive wells, which are defined as wells that
have no recorded oil or gas production in the last 12 months.
Could over 20% of the horizontal wells in Karnes Co., TX already be shut in for over one
year? These wells first produced 1/1/2019 to 12/31/2016, so they are not old wells at all?
Less than 10 year economic life?
I know Mike has commented on how bad the EFS really is economically. It seems the hyper
focus is now on the PB. However, EFS produces significant volumes of oil. Looks like this one
could really collapse once the last locations are completed.
I saw many, many wells with cumulative production of 250K oil, that are now producing
under 500 BO per month.
I ran the same search on De Witt Co., TX. Less wells, but similar results. Interesting to
see all the wells in both counties that have maybe paid out, but are now producing less than
500 BO per month.
Even Karnes County has it's less than tier one oil areas, and a lot of the wells were not up
to par in the beginning. The well has to pay out capex in the first year, or its not worth
drilling. Profit in year two and three, and not much after that. Period. End of story. I
don't see much better out of the Permian, and may be getting worse. Yes, on the whole, less
than a ten year economic life. Gets a lot worse in tier two stuff, and tier three stuff is,
at these prices, a definite loss. But they are still drilling in tier three areas, go figure.
My lease area is producing around 250k to 300k total, and it is barely touched, because EOG
wants 300k. Yeah, when the tier one areas play out, costs to maintain will be prohibitive.
Increase? Just a dream.
Look at EOG's economics of which wells are "premium" locations. There are not many left, and
EOG probably owns the lion's share. It has to produce 200k barrels the first year. They
priced that at $40 oil price, but it makes no difference, because it doesn't change the
number of locations that can generate 200k barrels. They are justifying production to a 5200
ft lateral. Some make significantly more, some less. I have that memorized, as my wells have
proven from the 125k to 175k the first year. Probably, a 250k to 300k EUR. So, I have to
wait. They will be venturing into my area sometime before their "premium" locations are
depleted. Beginning of the year, that count was at 2300. About 10 years at their current
drilling rate, and less if they pick up activity. These are developmental wells, the Permian
is still largely exploratory.
As far as holdings go, EOG is the cream of the crop. So, you can't make averages based on
one company. Most look far, far worse. Their financial info was shit before, as were all the
rest. Setting a bar for where to drill, will, in all likelihood, make them much better. There
are a large number of smaller companies who still complete wells in tier three acreage. It's
amazing, they know what they will get. I see initial production at 500 barrels a day, or
less, and I know that someone is losing money.
Now, do the math. There is not 10 years, or in most cases even five years of economically
recoverable oil from shale. A 60 month payback???? At the highest bracket, it includes wells
with about 3000 barrels a month. And there are only about 10k of those. Less than 3 years of
completions. And if you look at the total number of producing wells it is slightly less now
than in 2014. So, what happened to them??! To make it clearer, the number of wells that has
become inactive is pretty close to the number of wells that has been drilled in four years.
Yeah, production is up, because the wells producing over 3000 a month is up. But applying a
ten year, or even five year economic life to them is pretty stupid. But, I don't have to look
at total numbers to get to that conclusion, I look at individual wells, or groups of wells in
a lease. It's a lot steeper treadmill than the hoopla indicates. Here's the count from Dec
2014. Shale wells will probably not drop down into the last category, so just look at the
first two to compare them to current. If they do drop into the last category, the production
doesn't mean much to the cost of the well, or profitability. About four thousand more, and
tens of thousands of new wells since then. http://www.rrc.state.tx.us/media/26405/welldistribution1214.pdf
So, think about this when your looking at Eno's data, averages are deceiving. Whether they
are tier one, two, or three makes a huge difference.
The links to the report show plugging activity. Substantial. In August EF had 120 oil
completions, and 50 something oil wells plugged. Completions were higher in August. Dec 2017,
oil wells completed and plugged were almost equal. That is not an exact description of EF
horizontals, but that is the main thing going in these districts. $250 sounds low, I think.
Shallow, FTR, last thread: my current est. economic limits of 15-18 BOPD for LTO wells will
be much higher for major integrated companies, yes. The everything is peachy 'assumption' is
that smaller companies will buy those wells and carry on. I do not believe that. A 6-10%
decline in total UR because of premature economic limits IS a big deal. It makes or breaks
thousands of wells.
The liquids rich gas leg of DeWitt and Karnes Counties IMO will see <35% of its wells
be 'significantly' profitable, for instance above 150 ROI. Your data you are showing is a big
deal that seems to be going plum over peoples heads. Sorry. Time will show that the Eagle
Ford was, is the biggest financial toilet of all three shale basins; the economics are indeed
awful. I operate conventional production IN the EF trend and have interest in wells. Folks
don't realize how many $10-12MM dollar wells were drilled from 2009-2013. Jeff Brown and I
guessed eight years ago only 35-40% of shale oil wells in the EF will even pay back
D&C&A costs. I think that is way too high now.
Whatever the definition of "works," means, Dennis, for the EF; newer well designs are
leading to much higher IP180-360, but not higher UR. It does not look that way to me. Now new
wells in the EF must carry the burden of the highest level of legacy debt in the LTO
industry. To maintain and actually pay that debt back will take much higher oil prices than
you think as the play is now pretty much exhausted. At current oil prices it takes 325-350K
BO to pay new wells with longer laterals and much bigger frac's out.
The LTO industry is not in business so people can speculate about how much oil it is going
to make, or the jobs it provides, or how much cheaper gasoline it can provide for
consumers https://www.oilystuffblog.com/single-post/2018/09/12/Cartoon-Of-the-Week
; its in business to MAKE money. 150 ROI's is not making sufficient money to be self
sustainable and be able to kick the credit/debt addiction.
Longhorn is correct, Matador did indeed pay $95K an acre for PMNM acreage. I suggest we
bow our heads and honor its shareholders with a moment of silence and a little prayer to the
Goddess of Wolfcamp in order that she be merciful. Another bench Matador is touting to
justify its "wisdom" is the (De) Cline shale interval. Phftttttt.
The irony is that the majors and large independents divested of many assets in the US lower
48 in the 1990s because they were perceived as high cost with little economic future.
However, folks like us are still producing that stuff profitably.
OTOH the same companies are now spending large sums on shale, which is economically
inferior to what they divested 20-30 years ago.
Mr.Simmons likely never considered the productive wonders of a cash flow negative oil boom
aka USA LTO sarc/
I wonder how many more cash flow negative oil booms the world can endure, and how long USA
LTO will last. While we're at it, I wonder how the pension funds invested in USA LTO are
gonna do for their members once the rats under the floorboards get flushed out.
Buckle your chin strap. Within a few to several years we'll perhaps know better how this
is gonna shake out. George Kaplan and Dennis Coyne had some future production charts in the
comments of last post. By my rough eyeball and memory, I think George Kaplan had future
production down to about 40 million barrels a day by 2050 (see link below). Dennis, ever the
optimist ;), had us down to about 50 million barrels a day by 2050 (see Mr. Coynes comments
in response to George). Either way, those alive in 2050 are gonna be living in a very
different world!
A lot depends on how much oil can be extracted. George Kaplan's scenario looks to be
roughly a URR of 2400 Gb if the 2020 to 2063 trend continues in future years (it is roughly
straight line decline over that period so I just extended the line to zero and estimated URR.
It is more likely, in my view that URR will be about 3060 Gb (including 260 Gb of extra heavy
and LTO oil), that's about midway between a pessimistic HL scenario(2600 GB) and optimistic
USGS scenario (3000 Gb) for conventional oil.
Also higher rates of extraction could keep production a bit higher maybe 64 Mb/d in 2050,
it will depend on the length of Great Depression 2 in 2030. Of course I think that might only
last 4-5 years, being an optimist.
I haven't worked it out but I'd guess the ultimate recovery is more than your estimate.
First, as I said before, the XH production is based on long cycle projects, so it would have
a fat tail extending beyond when most of the conventional oil is exhausted (there are a few
reasons for that but one is that it needs upgraders and those are not built with excess
capacity). Second, as I said twice before, Laherrere has about 180 Gb of "rest of the world"
reserves that I didn't include as I don't know what they represent – if they are
undiscovered oil then at current rates it will take about 40 years to find them, or if the
recent trend for declining discoveries holds then forever.
And that is the last I am going to write – or read – on that Laherrere paper. It
was just a comment on a blog, not an article in Nature or the Times or even a letter to
either of those, or even a letter to the local free advertising paper. I wrote it most for my
own interest, writing things out help clarify ideas, but I rarely do more than a cursory
proofread. Most people who bothered to look at it would have read a couple of sentences and
skimmed the rest, a very few might have got more out of it. It didn't change anything
fundamental. If somebody was going to write another comment they wrote exactly what they were
going to write anyway.
It won't take to 2050 to see a different world. Just a small fall in supply has effects
well out of proportion to the nominal cash value of the oil lost. Cheap flights would
disappear, trade would plummet, GDPs shrink – the books have to balance one way or
another (see recent paper on impact on trade, I think by Barclays, and works by Hall and
Kummel). The biggest impact might be food prices, they could easily double and more short
term, then the few billion who spend half their income on food suddenly have to spend it all.
Turmoil would ensue and likely knock more oil supply off line. There was a paper about Sweden
I think – from memory (don't quote me) a rapid fall by a quarter of the oil available
leads to collapse and by a half to complete loss of civilization.
At the same time the declining cheap and efficient energy would hamper efforts to address
the other big ticket, long term issues: rising population, evolutionary inevitable
aspirations – "poor man wanna be rich, rich man wanna be king, and a king ain't
satisfied till he rules everything" (of course); declining levels in some of the big aquifers
(a few are getting to the point where the basic pump designs don't work, the replacements
needed are much more expensive and much more energy intensive); declining soil loss (at
current rate all the soil on sloped arable land will be gone in 50 years – that's a
third – and most of the rest in another 50); and of course climate change related
extreme weather. This year we've had record heat waves, wild fires, typhoons and (soon)
hurricanes plus droughts etc. Soon those will be weekly events (we're not far off now) but on
top of that we will be having two or three extreme extreme-weather events per year. More and
more of the oil will be going simply to triage on these (but the patient will get worse
anyway). At some point countries will cease to be liberal democracies, the USA seems to be
leading the way there, and say what you like about liberal democracies they have never
declared war on each other, dictatorships on the other hand
People will say oh we just need to do this, that or the other – but there is no
"just" about any of it, and especially as oil disappears: ignoring the externalities there is
absolutely no better real energy source imaginable by some way, especially the cheap stuff we
used to have.
You of course know all this and are preparing much better than me, I do not much more than
appease my conscience by not flying and hardly ever riding in a car, but I think I'm getting
to the "acceptance" stage and pretty much missed out on depression (no physical symptoms
anyway).
[end of rant].
I tend to agree with you George. Only a small decrease a short time after peak, and the
realization that it's not going back up, will likely open a lot of people's eyes to the fact
that almost every stock and equity is overvalued (come to understand that anticipated future
growth will not be realized). I plan to hunker down and catch up on my reading while the dust
settles, and I'm thinking there'll be a lot of dust. I'll send you a map. Password is 'I
think I'm with the band'.
I find this to be also an interesting take on the future of oil
"The short-term investment focus adopted since 2014 offers a finite set of opportunities
over a limited period of time, and this period is now clearly coming to an end as seen by
accelerating decline rates in many countries around the world," Kibsgaard pointed out.
BAU won't get it done – no quick fixes, 'new shale revolution' or 'reserve
production' to get us through – my interest is mostly how we (as a society and culture)
will react as constraints on the resource 'haves' and 'have nots' set in.
Went through Irma in South Florida last Fall – and in general order was maintained
– but really only out of Gas for about 3 days – and was more of a shock type
shortage. A very slow decline of world supply will hit those who can't pay for it most
– and maybe wake up enough through higher prices to begin planning for what will be the
greatest energy transition that must take place!
The big oil companies are selling a story of long term stability to their investors, partly
so they can justify the long term investments needed for the mega-projects where they get
most of their oil and cashflow (some of those see no net return for many years). They only
need to sell themselves to their investors, not their customers who just buy the cheapest or
most convenient, be it crude to refineries or petrol to motorists.
The service companies live more year to year – they get hired to help develop and
drill a field and then their workload drops a lot except for some well servicing during
operation. Schlumberger is selling itself to its customers (the 'operators' who are the
E&P companies) and investors as the go to guy for the next couple of years as activity
tries to pick up but faces increasing issues as the easy (and now not so easy but still
OK-ish) oil goes away.
Schlumberger is not a typical service provider to the producers, although that is a large
portion of their business. Since their purchase of Cameron International and other oilfield
manufacturing companies, they have been providing facility engineering and fabrication
services to the oil producers worldwide.
In point of fact, Schlumberger does have the information that the producers have, and then
some. They use those numbers as a basis for facility engineering, and as such are arguably in
a better position to interpret them than the producer as of late.
I've regularly read the BP annual report, and have come to regard it as little more than a
curiosity. Schlumberger, Shell and Total have a firmer grip on the world oil situation, based
on my read of their CEO's comments. However that may be confirmation bias on my part. We
shall see .
Probably the more important item is Russian reserves my estimate is we are at 90% depletion
for existing technology and OIP at cost for western Russian reserves. At this point a squeeze
plan in Syria would ensure foreign reserve earnings to into wars and not fuels outcome is
standard wars as a result of miss spending income
Yes, I assume they have some problems since they reformed the tax system in favor of upstream
risky projects and at the same time imposed more taxes on downstream refineries. But to
assume Russia has problems is like assuming the whole world has a problem. Could be perfectly
right, but why expose Russia as opposed to others? Russia has a lot of higher cost oil; just
look at the land mass and offshore mass. How could there not be prospects? Some inside
knowledge is sorely lacking, since I like most western people don't have connections in that
part of the world.
80% of the world's oil has peaked, and the resulting oil crunch will flatten the
economy.
New scientific research suggests that the world faces an imminent oil crunch, which
will trigger another financial crisis.
A report by HSBC shows that contrary to the commonplace narrative in the industry, even
amidst the glut of unconventional oil and gas, the vast bulk of the world's oil production
has already peaked and is now in decline; while European government scientists show that the
value of energy produced by oil has declined by half within just the first 15 years of the
21st century.
The upshot? Welcome to a new age of permanent economic recession driven by ongoing
dependence on dirty, expensive, difficult oil unless we choose a fundamentally different
path.
Then they say: The HSBC report you need to read, now
Real issue is giants, your article in 2015 real issue is 90% ..real issue is squeeze play in
motion in Syria..goal? if don't have it, don't drill it at home, no rig increases so 'end
game' is cut off Isreali/Saudi friendly arab gas to Europe own Caspian area (city I recall
owned by Ukraine under British treaty Yelsin) in end no WW2 buildup during economic issues
(Russia 5M/day, Saudi similar) no Hilter, just preempt what's left..
I downloaded it then, and just had to look at the date the file was created. You probably
also have it in your hard-drive.
It provided a nice confirmation to my thesis that Peak Oil won't happen in the future. It
is taking place now, and the date we entered the Peak Oil plateau was 2015. You also
forecasted that, as I did.
You are correct. Hey, I am 80 years old and I just can't remember shit anymore.
Okay, I posted a few days ago that I thought peak oil would be in 2019. Perhaps I was
wrong. Hell, I have been wrong quite a few times. But now perhaps peak oil is right now.
Perhaps? We shall see.
But my point is everyone seems to be agreeing with me now. Old giant fields are seeing an
ever increase in decline rates. I predicted this a long time ago. Once the water hits those
horizontal laterals at the very top of the reservoir, the game is over.
The decline rate in those old giant fields is increasing at an alarming rate.
Obviously! Fucking obviously. It could not possibly be otherwise. Thank you and
goodnight.
Memory is less necessary these days with internet, computers, and smart phones, where
searches can be run in a moment. Don't worry too much about that.
"But my point is everyone seems to be agreeing with me now."
I discovered your blog in 2014 when looking for confirmation on my suspicion that the oil
price crash was going to result in Peak Oil. I was impressed to see that you were there years
before through your analyses. I have a lot of respect for you and your intellectual capacity,
and I agree with you in many things, besides Peak Oil, including the population problem, and
your worries about the environment.
I don't believe the world cannot increase its oil production, I just believe it won't do
it. Both Saudi Arabia and Russia have the capacity to go full throttle on what they have
left. Shaybah is the most recent supergiant in KSA and expected to produce until 2060 at
current output. No doubt they could increase production from Shaybah by a lot, but it is not
in their interest to do so. Russia lacks the capacity to quickly increase its production, but
there's still plenty of oil in Eastern Siberia, so they could also produce more. Again it is
also unlikely, as it would require an investment and effort that goes against their own
interest.
Peak Oil is not happening because the world is trying to produce more oil and failing, it
is happening by a combination of economical, geological, and political factors that could not
be easily predicted and that were set in motion in the early 2000's when the low-hanging
fruit of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached
its production limit. Political errors, like taking out Gaddafi, added unnecessary
difficulties. The collapse of Venezuela is the latest political cause. And when things start
to go wrong, it never rains, but it pours.
"Peak Oil is not happening because the world is trying to produce more oil and failing, it is
happening by a combination of economical, geological, and political factors that could not be
easily predicted and that were set in motion in the early 2000's when the low-hanging fruit
of conventional on-shore and off-shore crude oil (the cheapest kind to produce) reached its
production limit."
Isn't this just a distinction without a difference? It's peak oil.
The issue is that Peak Oil has been misunderstood by most people. The argument that Peak Oil
won't happen until this or that date because ultimate reserves are such or such, so often
read in this forum, is incorrect. Even economically recoverable reserves are not decisive. To
make the problem intractable there are many liquids so some might peak while others don't so
discussions about Peak Oil are endless.
But it is very simple. Peak Oil is when the world no longer gets the oil it needs to keep
expanding its economy. And the best way to measure it is through C+C, because crude oil is
what we have been getting since the late 19th C ans is the stuff that produces everything our
economy needs, from asphalt to diesel, plane fuel, and gasoline. NGL won't cut it. Biofuels
won't cut it.
And Peak Oil is being determined by economical and political factors, besides the
geology.
The difference matters because Peak Oil is going to get almost everybody by surprise. Most
won't realize what is the cause of all the troubles we are going to get and they'll be
reassured that there is plenty of oil to be extracted, which is true but irrelevant.
Thanks for the reply. I also tremble at the prospect of what is to happen because of the
failure of the predictions last decade. I can only describe it through an analogy (being a
lay reader and a writer):
In the 2000s, people were saying that we had an ugly wound and that we had better do
something about it. But instead of properly addressing the wound, we just wrapped it in
gauze, and when the blood stopped showing through, we said, "See? All better." That's my
analogy for the "shale revolution" -- it was essentially a Bandaid. The complacency has only
worsened in the last ten years.
This has just made the infection all the worse. When pus starts showing through the
dressing and we unwrap it this time -- we're going to find gangrene.
I am re-reading Joseph Tainter's 1998 book "The collapse of complex societies." It is a
sober reading that shows that in the end the laws of entropy and diminishing returns always
produce the same result. We are not more intelligent than the people that preceded us. If
anything we can only be stupider on average. We just have a very high opinion of
ourselves.
Time for a wake up and a little bit more darwinism in our lives. The problem is the pain.
With so many people it is just going to be unbearable. On a scale never imagined, not even by
writers of bad sci-fi.
That would be a more important definition of peak oil to me, and I think we are definitely
there. Then we have the absolute production definition, which was the original definition, as
to production. It is now anticlimactic to your definition. As to the date or year it happens,
who cares? More importantly, now, is when demand will lower enough to stop draining
inventories. At what oil price will that start occurring? How fast will alternate sources
replace unmet demand? New directions and everyone is likely to be wrong on estimates. EIA and
IEA were totally useless before, and that will probably not change in the near future.
Looking in the past won't give us much, and the future is anybody's guess.
As to current prices, $68 oil won't get any extra interest from E&Ps outside of the
Permian that is stalled. To any measurable extent. Close to $80 oil is not expanding interest
very much outside of the US. We are just living on borrowed time.
Oil prices are likely to continue to rise, especially if your estimates of future
production (roughly similar to my estimates, but perhaps a bit more pessimistic) are correct,
unless consumption of oil stops increasing. My guess is that oil (C+C) consumption will
continue to increase at 400 to 800 kb/d each year , until oil prices get to about $150/b or
more (around 2025 to 2027),by that time or soon after ( maybe 2030) oil consumption growth
may stop either because of the expansion of electric and natural gas powered transport or
because of a second Great Financial Crisis. My hope is it will be the former, but I think the
latter scenario is much more likely.
Hopefully Keynes' General Theory will make a comeback before then.
Ron Wrote:
"I predicted this a long time ago. Once the water hits those horizontal laterals at the very
top of the reservoir, the game is over. "
FWIW: That's already happened. when it occurs, they drill a new horizontal above the old
one. The new lateral also have valves on there ports. so that when the water breaches one or
more of the ports, they shut them off to reduce water cut. I posted Saudi Aramco tech
articles here back between 2014 and 2016 when they were available on the SA website.
Hi Carlos, thanks for the trip down memory lane. I tend to agree with peak oil being now
(ish). From what I recall the peak month for C+C was, so far, in November 2016. I suppose
there is also a peak day, a peak weak, and a peak year. Folks seem to like packaging time in
various proportions. Hell, there's probably a peak decade and a peak hour. My guess is the
peak year will be 2018. I like, because I'm a bit thick at maths, how Ron has added trailing
12 month average to his world production chart. I just look at the 12 month trailing average
for each December to get an idea of how much was produced in each calendar year. It seems
that 12 month trailing average for December 2018 will beat that of 2017. My guess is 2019
won't beat 2018. Or will any other year after that. So, if Ron say's 2019, and I say 2018,
then it seems that I think he is wrong lol he's probably 100 times smarter than me so doesn't
lose sleep over it lol. Up until this time I have always agreed with Ron on peak oil. But
now, I throw down the gauntlet! 2018 vs 2019. Two will enter, one will leave.
The exact week, month, or year when maximal production is reached has only historical
interest. The point is that since the end of 2015 the 12-month averaged C+C production has
barely increased (EIA data) despite the increase in demand.
Dec 2015 80,564 100.0%
Dec 2016 80,579 100.0%
Dec 2017 80,936 100.5%
Apr 2018 81,363 101.0%
We will have to see how it evolves over to the next December, but so far it is annualized
to a 0.4% increase. To me we are in a bumpy plateau since late 2015 and all those meager
gains and more will be lost in the next crisis. The problem will be evident to many when
after the crisis we are not able to increase production above those values.
Peak Oil is a situation, not a date, and we are in that situation since late 2015. The oil
that the world demands cannot be produced so prices are going up, and up. I suppose it is
possible that the powers that be intervene to reduce global oil demand by favoring a crisis
in developing countries, like Argentina, Brazil, Turkey, South Africa, through interest rate
changes. Wait, it is already happening. It is a dangerous tactic, as crises can spread
around, and the interest rise weakens the economy.
Well one has to define the plateau a bit better. If we make the bounds wide enough one
could say the peak was 2005 or even 1980 and we have been on a bumpy plateau since that
point.
Better in my view to define peak as peak in centered 12 month average output wth center
between month 6 and 7.
I use a 13-month centered average, so it is symmetrical with 6 months at each side.
But really, after a clear period of production growth 2010-2014, there was a strong growth
in production 2014-2015 in response to falling prices, and then production got stuck in late
2015.
It is not a question if we are in a plateau (or very reduced growth) period, but what
happens afterwards. After the previous plateau 2005-2009 there was a clear fall 2009-2010,
before tight oil saved the day.
The recent plateau is due to excess inventory and the resulting low oil price level. Oil
inventories have been reduced over the past 12 to 18 months and as oil prices increase,
output will also increase with perhaps a 6 to 12 month lag. How much will it need to rise
above the Dec 2015 level before you no longer consider that output has not risen above your
"plateau". Give me a number, is it 81.5 Mb/d, 82 Mb/b, I prefer to use a year rather than 13
months, that's 182 days on either side of the middle of the 12 month period. On leap years we
can use Midnight of day 183
One issue that has been corrected is that reserve requirements for large banks have
increased.
Also lenders are more careful with their mortgages making a housing bubble less
likely.
In addition, the assumption that higher oil prices played a major role in the GFC is
incorrect.
Perhaps there is a looming recession, whether this happens in 2018, 2030 or some other
year we will only know when it occurs.
Someone who predicts a recession every year will be right eventually.
I maintain my guess of 2023 to 2027 for the 12 month centered average c+c peak and severe
recession GFC2 starting 2029 to 2033, lasting 5 to 7 years.
Second oil reserves have been flat since around 2010, and declining recently for the first
time since the 1970s. Note, before someone points it out, they don't count Canadian Bitumen.
This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way
below replacement level. Yet so-called "proven" reserves keep going up, up and up.
"This is so ridiculous it is funny. Oil discoveries have been going down, down, and down, way
below replacement level. Yet so-called "proven" reserves keep going up, up and up."
Well to some degree, technology has been able to extract more oil from a field. Thus a
field discovered in 1950 with an initial proven reserve of 100mbbls, may have 125mbbls or
proven reserves as technology has improved recovery rates. That said technology improvements
likely don't match the paper proven reserves.
The Venezuelan heavy oil reserves are overstated (I assume the large bump prior to 2010 is
the booking of the Magna Reserva in the Orinoco Oil belt, which i know are fake). It's fairly
easy to eyeball the better number by substracting 300 billion a flat line around 1200. If you
want to add future bookings in that heavy oil belt, add up to 50 billion gradually. Dont
forget that at the current decline rate Venezuela will be producing about 1.1 million BOPD in
december, and IF things go as I think they will sometime in the first half of 2019 exports
will drop to zero for a few months.
Third gas reserves also flat. If condensate and NGLs have been meeting the increased demand
that crude has been unable to, then that might be about to stop.
"... Fracking has indeed produced oil and gas, but the fields deplete rapidly without massive additional investment. Only the zero-interest rates of the Fed's Quantitative Easing could have financed the fracking boom - without QE, US oil and gas would not even exist on the world's radar. ..."
The Keiser Report has a very upbeat show today on RT, in which they celebrate how the NYT
has finally come round to reporting the truth about US fracking, in ways that Max and Stacy
were reporting 9 years ago.
Fracking has indeed produced oil and gas, but the fields deplete rapidly without massive
additional investment. Only the zero-interest rates of the Fed's Quantitative Easing could
have financed the fracking boom - without QE, US oil and gas would not even exist on the
world's radar.
And yet Neocons are taking the US production of hydrocarbons as a major plank in their
platform of war, building castles in the air from a mythical "energy supremacy" and treating
current production levels as a weapon of war -- but the economics of this relatively minor
industry will shut it down soon.
In the second half of the 30-minute show, Max interviews Wolf Richter and they discuss
Argentina mostly. It's a rapid and valuable overview of how the US Hegemon deals with its
favorite suckers south of the border, and how currencies and bonds work - and also why the
IMF acts only to bail out investors and bond-holders, and never the real economy of the
victim nation.
"... The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e. Federal Reserve policy. Even The New York Times said so yesterday ( The Next Financial Crisis Lurks Underground ). ..."
"... As with shale oil, they depend largely on dishonest financial legerdemain. They are also threatened by the crack-up of globalism, and its 12,000-mile supply lines, now well underway. Get ready for business at a much smaller scale. ..."
"... Hard as this sounds, it presents great opportunities for making Americans useful again, that is, giving them something to do, a meaningful place in society, and livelihoods. ..."
"... Pervasive racketeering rules because we allow it to, especially in education and medicine. Both are self-destructing under the weight of their own money-grubbing schemes. ..."
"... A lot of colleges will go out of business. Most college loans will never be paid back (and the derivatives based on them will blow up) ..."
"... The leviathan state is too large, too reckless, and too corrupt. Insolvency will eventually reduce its scope and scale. Most immediately, the giant matrix of domestic spying agencies has turned on American citizens. ..."
"... It will resist at all costs being dismantled or even reined in. One task at hand is to prosecute the people in the Department of Justice and the FBI who ran illegal political operations in and around the 2016 election. These are agencies which use their considerable power to destroy the lives of individual citizens. Their officers must answer to grand juries. ..."
"... As with everything else on the table for debate, the reach and scope of US imperial arrangements has to be reduced. ..."
And so the sun seems to stand still this last day before the resumption of
business-as-usual, and whatever remains of labor in this sclerotic republic takes its ease in
the ominous late summer heat, and the people across this land marinate in anxious
uncertainty.
What can be done?
Some kind of epic national restructuring is in the works. It will either happen consciously
and deliberately or it will be forced on us by circumstance. One side wants to magically
reenact the 1950s; the other wants a Gnostic transhuman utopia. Neither of these is a plausible
outcome.
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues."
Let's try to take stock of what the real issues might be.
Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e.
Federal Reserve policy. Even The New York Times said so yesterday ( The
Next Financial Crisis Lurks Underground ).
For all that, the shale oil producers still
couldn't make money at it. If interest rates go up, the industry will choke on the debt it has
already accumulated and lose access to new loans. If the Fed reverses its current course - say,
to rescue the stock and bond markets - then the shale oil industry has perhaps three more years
before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will
affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced
by other means than fossil fuels , so-called alt energy. This will only happen on the most
limited basis and perhaps not at all. (And it is apart from the question of the decrepit
electric grid itself.) What's required is a political conversation about how we inhabit the
landscape, how we do business, and what kind of business we do. The prospect of dismantling
suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen
whether we make plans and policies, or we're dragged kicking and screaming away from
it.
Corporate tyranny
The nation is groaning under despotic corporate rule. The fragility of these operations is
moving toward criticality. As with shale oil, they depend largely on dishonest financial
legerdemain. They are also threatened by the crack-up of globalism, and its 12,000-mile supply
lines, now well underway. Get ready for business at a much smaller scale.
Hard as this sounds, it presents great opportunities for making Americans useful again, that
is, giving them something to do, a meaningful place in society, and livelihoods.
The implosion
of national chain retail is already underway. Amazon is not the answer, because each Amazon
sales item requires a separate truck trip to its destination, and that just doesn't square with
our energy predicament. We've got to rebuild main street economies and the layers of local and
regional distribution that support them. That's where many jobs and careers are.
Climate change is most immediately affecting farming. 2018 will be a year of bad harvests in
many parts of the world. Agri-biz style farming, based on oil-and-gas plus bank loans is a
ruinous practice, and will not continue in any case. Can we make choices and policies to
promote a return to smaller scale farming with intelligent methods rather than just brute
industrial force plus debt? If we don't, a lot of people will starve to death. By the way, here
is the useful work for a large number of citizens currently regarded as unemployable for one
reason or another.
Pervasive racketeering rules because we allow it to, especially in education and medicine.
Both are self-destructing under the weight of their own money-grubbing schemes. Both are
destined to be severely downscaled.
A lot of colleges will go out of business. Most college
loans will never be paid back (and the derivatives based on them will blow up).
We need
millions of small farmers more than we need millions of communications majors with a public
relations minor. It may be too late for a single-payer medical system. A collapsing oil-based
industrial economy means a lack of capital, and fiscal hocus-pocus is just another form of
racketeering. Medicine will have to get smaller and less complex and that means local
clinic-based health care. Lots of careers there, and that is where things are going, so get
ready.
Government over-reach
The leviathan state is too large, too reckless, and too corrupt. Insolvency will eventually
reduce its scope and scale. Most immediately, the giant matrix of domestic spying agencies has
turned on American citizens.
It will resist at all costs being dismantled or even reined in.
One task at hand is to prosecute the people in the Department of Justice and the FBI who ran
illegal political operations in and around the 2016 election. These are agencies which use
their considerable power to destroy the lives of individual citizens. Their officers must
answer to grand juries.
As with everything else on the table for debate, the reach and scope of US imperial
arrangements has to be reduced. It's happening already, whether we like it or not, as
geopolitical relations shift drastically and the other nations on the planet scramble for
survival in a post-industrial world that will be a good deal harsher than the robotic paradise
of digitally "creative" economies that the credulous expect.
This country has enough to do
within its own boundaries to prepare for survival without making extra trouble for itself and
other people around the world. As a practical matter, this means close as many overseas bases
as possible, as soon as possible.
As we get back to business tomorrow, ask yourself where you stand in the blather-storm of
false issues and foolish ideas, in contrast to the things that actually matter.
Most of the arguments ranging around them are what Jordan Peterson calls "pseudo issues."
Let's try to take stock of what the real issues might be.
Energy
The shale oil "miracle" was a stunt enabled by supernaturally low interest rates, i.e.
Federal Reserve policy. Even The New York Times said so yesterday ( The
Next Financial Crisis Lurks Underground ). For all that, the shale oil producers still
couldn't make money at it. If interest rates go up, the industry will choke on the debt it has
already accumulated and lose access to new loans. If the Fed reverses its current course - say,
to rescue the stock and bond markets - then the shale oil industry has perhaps three more years
before it collapses on a geological basis, maybe less. After that, we're out of tricks. It will
affect everything.
The perceived solution is to run all our stuff on electricity, with the electricity produced
by other means than fossil fuels , so-called alt energy. This will only happen on the most
limited basis and perhaps not at all. (And it is apart from the question of the decrepit
electric grid itself.) What's required is a political conversation about how we inhabit the
landscape, how we do business, and what kind of business we do. The prospect of dismantling
suburbia -- or at least moving out of it -- is evidently unthinkable. But it's going to happen
whether we make plans and policies, or we're dragged kicking and screaming away from it.
The message I get from that piece is that companies are getting ready for next year so
they can hit the ground running when the pipeline bottleneck is removed. Output has not
decreased, it is just rising more slowly than capital expenditures. No point in completing
wells if there is not pipeline space to move the oil, so they are building pads and other
facilities and drilling wells, but waiting on completion.
So far this year Permian tight oil output has increased by 478 kb/d, an annual rate of
increase of about 820 kb/d. The annual rate of increase from Jan 2017 to July 2018 has been
about 829 kb/d.
Output has not decreased, productivity has. There's a lot in that article. Yeah, DUCs are
increasing for next year. Late next year. Conoco is the only company that I read about, that
said we do not intend to expand much in the Permian, until they get the infrastructure in
place (pipelines). They started running out of pipeline capacity the beginning of the year. I
don't know about you, but if I was a CEO, I'd feel like an absolute idiot for not figuring
that into the plans. So, for another year, they get to feed the DUCs.
Many a show and tell from the operators, is how they have brought down costs. Now, I have
tell everyone that costs are higher than before. That will never go into an annual report, as
it makes the CEO look like an idiot.
The companies are not making the production per well that was hyped. Er, maybe we should
not include that in the annual report, either. That's what I got from the article.
You don't want people to say you wound up with egg on your face, so you tell them you have
decorated your face with egg. It was your intent to look better. Spin.
I don't follow the dog and pony shows given by the oil companies, I just look at the data
from the EIA, OPEC, and shaleprofile. I guess everyone interprets information differently,
what I see in the article is that output has not risen as high as previously projected
because fewer wells are being completed than was projected. It is also probably true that the
average completed well has lower EUR than the ridiculous well profiles that are typically
presented to investors, but I always dismiss those as hype and smart investors do the same
and look up the information at drilling info, frac focus or shaleprofile.com.
The average well productivity in the Permian basin has not decreased, also no decrease in
the North Dakota Bakken, or the Eagle Ford, or the Niobrara all based on Enno Peter's
presentations at shaleprofile.com.
I also ignore the estimates by the EIA's drilling productivity report as I think that
model is poorly done.
Dennis, respectfully, you need to stop whatever you are doing and go seek help
immediately. In an effort to be the eternal optimist, or the staff contrarian, you are losing
all credibility with regards to analyzing anything oily in the world. I have no charts, or I
would stick them here.
Guy is basically right, there is nothing good to draw from this article whatsoever and the
author is one of the best there is. All costs in the shale biz are significantly higher than
EVER before. Well productivity is declining, not from takeaway restraints but from well
interference, increasing GOR and depletion. Profitability has NOT improved thus far in 2018,
the Permian unconventional oil industry is still outspending revenue and interest rates are
on their way up, up, and up.
If anybody is spending $3.5MM to drill DUC's and not paying back debt, they too need to
seek immediate help. You have become the King of Debt on POB and are discounting completely
the role that debt will play in your lofty supply demand economic theories. Rune has just
written something very good on that and Art has good data now regarding declining gasoline
consumption in the US due to higher prices. That is all debt related, man. You have gone
freaking chart bonkers.
And why argue what the KSA says about its reserves? Its their oil, they can say whatever
they want to about it and no dumb ass American is going to change it. Right here in the good
'ol US of A, reserve reporting under the ever watchful eye of the SEC, is embarrassingly
awful. Shale oil EURS are exaggerated by 30% or more. We now lie in America way better than
the Saudis ever did and get this: a lot of people believe it !! Ahem.
Dennis, I have to work for a living but I don't want you to think I criticized you and
don't have the balls to respond to all your hours of research arguing with me. I got it. And
all the charts. And the models. And the criticism directed at others for guessing, which is
all you EVER do. Have you ever seen the back in of a drilling rig in your life? You gotta
balance about 500 oil well check books to even be allowed to analyze the oil industry,
IMO.
Look, even the EIA seems to thing productivity is declining in the Permian. Goggle it. I
get the full meaning of Enno's work, all of it, including this: "all shale oil wells drilled
in America before January of 2016 now only account for 27% of total LTO production." Let that
sink in a minute.
You embrace debt as thought that is an acceptable thing in the world we live in today, and
especially from the shale oil industry, and though you want to be un-hinged from fossil fuels
as much as any of the permanent residents you have on your blog, rational ones they are, one
and all, you believe strongly in the shale oil industry's ability to pay down its debt,
improve its dismal financial performance, and deliver the goods it has promised to America.
Its very confusing, actually. And hypocritical. I guess when the shale oil industry says past
performance is not indicative of future results, you believe them.
I think, really, all you are doing is defending your damn models.
I have some serious doubts about how much and how fast shale oil will grow over the next few
years. I have accumulated no statistics, and have prepared no computations and charts to back
up my doubts. However, they should be easily understood in theory, as that's all it is, a
general theory.
While I know of no industry standards to define the difference between tier one, tier two,
and tier three oil, I have made my own guesses based on operators statements. Tier one has EUR
of 600k barrels, or more. It will produce over 200k in the first year. Tier two has EUR closer
to 300k, and will produce 100k to 200k the first year, or an off the wall estimate of 150k.
Tier three is probably closer to 150k EUR, and it's long term profitability is dependent on a
very high oil price. It will be drilled, but only when price is high, and tier two is gone.
If you look at tier one, it can be drilled at today's prices, and income from the first year
will fund one or more wells the next year with cash flow, hypothetically.
You would need about twice the number of tier two wells to equal a tier one. At present
prices you would have to borrow money to fund the equivalent number next year.
We have a limited amount of tier one wells left in the Eagle Ford and Bakken. There is
beginning to be some question as to the number of tier one spots in the Permian. Plus
increasing GOR is raising questions.
As more wells are drilled, of course the price of the well increases. Simple micro
supply/demand.
Interest rates will increase, causing borrowing costs to increase.
Even at $100 oil price, I can't see over a two million barrel a day increase in a short
period of time (three to five years).
I could put numbers to this, but I could never reach what it actually would be, anyway. Do
your own figures and see what you come up with. I just can't get to over 2 million barrels, and
that would be tough.
I'm not saying that the estimates for recovery are wrong. I'm saying using past data to
estimate the future does not take into consideration that all rock is not the same, and that
costs and borrowing ability will put their own limits on how much, and how fast growth occurs.
REPLY
All very much guess work. There are factors such as improved well layout, better well
design and so forth that tend to drive well cost for some "optimized" well design (a given
lateral length, number of frac stages and pounds of proppant and other materials) lower that
may offset the microeconomic tendency for costs to go up as constraints are reached (not
enough workers, equipment, or infrastructure). That's the reason I assume for simplicity that
long term well cost in constant dollars remained fixed.
I also have no idea on the numbers of tier one to three wells that potentially can be
drilled. All I have used is average well output for ND Bakken, Eagle Ford, and Permian from
shale profile. That is simply a mix of all wells producing. I assume oil companies attempt to
drill the most prospective areas first (not an exact science) so that as the play is
understood average new well EUR will gradually rise to some maximum (as oil companies figure
out both the best areas to drill and the best well design) and then after some period
(probably 2 to 3 years) the best areas will become saturated with wells so that less
prospective areas will be drilled and new well EUR will gradually decrease. That is my model
in a nutshell and the result for the US is that tight oil output may be able to rise from
6000 kb/d in July 2018 to about 8000 kb/d by July 2023 (about 5 years). This scenario assumes
high oil prices and is optimistic, a "medium" oil price scenario would result in maybe a 1.5
Mb/d increase in tight oil output over 5 years and a "low oil price scenario" ($80/b in 2017$
maximum by 2025) might see only a 500 kb/d increase in tight oil output from 2018 to
2023.
Note that US tight oil output has risen by about 700 kb/d over the first 7 months of 2018.
I do not believe this rate of increase will continue for much longer and will gradually
decrease as we approach 2021.
For the Permian basin specifically the peak is about 1 Mb/d lower for my "low oil price"
scenario relative to the medium price scenario ($80/b vs $113/b max price). Other basins
would also be affected, but I haven't run the scenarios on all tight oil basins so I am not
sure how much the entire US tight oil peak would be affected, probably 1.5 Mb/d lower than
the medium price scenario. For Rune Likvern's near term oil price scenario tight oil output
would be fairly flat from current output levels in my opinion and that would tend to put
upward pressure on oil prices.
We have not had any difference of opinion on future shale output, in the last 6 months,
according to my recollection. Any minor differences that may have been discussed fit into the
"who knows" classification. My comment was for those "other" projections coming out, that
basically are surreal. They have caused, in my opinion, an excess of pipelines being built,
and massive expenditures to be able to export another 3 to four million barrels of oil a day
that will probably never show up.
700k a day out of the Permian, is actually what I am projecting for 2018. Even 800k is
within probability. 200k of extra pipeline is due sometime before year end. Not much more
than that until late 2019 when bigger pipelines may be available. But the amount you could
crank it up to would be limited by the number of months left in 2019.
Agree 100%. Note that 700 kb/d is roughly my estimate for Permian increase in 2018 as
well, for the US tight oil as a whole possibly 1000 to 1200 Kb/d increase in 2018. Many of
the estimates are too high on that point we are definitely on the same page.
I mean, there are only four months left. I know the Eagle Ford can't do hardly anything in
that time fraim, Bakken is stuck at a high of about a 100k increase, so what fields will add
that much?
From Bakken, Eagle Ford, Niobrara, and STACK/SCOOP.
So far non-Permian US tight oil has increased about 215 kb/d through the first 7 months of
2018, I would expect this to accelerate if anything as capital moves to other tight oil
basins due to the low oil prices at Midland. So a 400 kb/d increase from other tight oil
basins (exit rate for 2018), plus 700 kb/d from Permian basin would give us 1100 kb/d.
So far in 2018 we have increases of 92 kb/d in Bakken, 61 kb/d from Eagle Ford, 38 kb/d
from Niobrara, 479 kb/d from Permian, and 24 kb/d from all other US tight oil plays.
If all output stopped increasing in other tight oil plays besides the Permian after July
2018 we would have a 915 kb/d increase in US tight oil output in 2018, if my guess of a 700
kb/d increase for the Permian basin tight oil output in 2018 is correct. My best guess
remains 1100+/-100 kb/d for the US tight oil increase in output from Dec 2017 to Dec
2018.
I only have data through July 2018, so 5 months left for increases, if we extrapolate the
rate of increase for the first 7 months of 2018 we get 1190 kb/d for the 2018 increase in
tight oil output. I scale it back a bit because I expect Permian output increase will slow
down. Other plays might also speed up.
Ok, your looking at EIAs production estimate per play, again. I'm only going to go by
monthlies. There will be other field declines, besides tight oil. GOM, Alaska, and non tight
oil Texas.
Haven't looked at rig counts lately so it's a guess. Just figure the capial may move to
higher profit areas such as Bakken or Niobrara. Yes there are DUCs that could be completed.
There may be more available frac crews in other plays as everyone has flocked to Permian.
The Kashagan oilfield is proving to be a real nightmare for operators and partners. No
wonder a decision was made to expand capacity for the land based Tengiz field. No similar
call was made for Kashagan even if stated reserves are a bit higher than for Tengiz.
It is a bit like offshore deepwater. If the size of a new prospect warrants it, the cost
can be kept down reasonably. And the North Slope is probably one of the places it is possible
to find another or even several gigant oil fields (above 500 million barrels). Just shows
that some majors are betting on higher oil prices.
EIA Weekly U.S. Ending Stocks to Friday 17th August
Crude oil down -5.8 million barrels
Oil products up +1.5
Overall total, down -4.3 (shown on chart)
Natural Gas: Propane & NGPLs up +1.5 (not included in the chart) https://pbs.twimg.com/media/DlZH1X2X0AIPDLR.jpg
Big drop in Iranian exports the first of August, and not close to Nov. yet. One million
looks more likely, eventually. And for those that may have missed it, Sinopec has started
buying US oil, again. To me, that indicates China is attempting to remain somewhat
neutral.
It's pretty clever. They want money from the state before they do any work developing
their own lease. The money would fund . . . haha . . . management salaries, among other
things.
And if it proves out as no oil, well, then they got the state to fund exploration. If
there is oil, they get the money from selling the oil. It's no lose.
Big trouble is brewing in the mighty North Dakota Bakken Oil Field. While oil production in
the Bakken has reversed since it bottomed in 2016 and increased over the past few years, so has
the amount of by-product wastewater. Now, it's not an issue if water production increases along
with oil. However, it's a serious RED FLAG if by-product wastewater rises a great deal more
than oil.
And... unfortunately, that is exactly what has taken place in the Bakken over the past two
years. In the oil industry, they call it, the rising "Water Cut." Furthermore, the rapid
increase in the amount of water to oil from a well or field suggests that peak production is at
hand . So, now the shale companies will have an uphill battle to try to increase or hold
production flat as the water cut rises.
According to the North Dakota Department of Mineral Resources, the Bakken produced 201
million barrels of oil in the first six months of 2018. However, it also produced a stunning
268 million barrels of wastewater:
Thus, the companies producing shale oil in the Bakken had to dispose of 268 million barrels
of by-product wastewater in just the first half of the year. I have spoken to a few people in
the industry, and the estimate is that it cost approximately $4 a barrel to gather, transport
and dispose of this wastewater. Which means, the shale companies will have to pay an estimated
$2.2 billion just to get rid of their wastewater this year.
Now, some companies may be recycling their wastewater, but this isn't free. Actually, I have
seen estimates that it cost more money to recycle wastewater than it does to simply dispose of
it. So, as the volume of wastewater increases while the percentage of oil production declines,
then the shale companies are hit with a double-whammy... less oil revenue and rising wastewater
disposal costs.
To give you an idea just how much more water is being produced versus oil in the Bakken, I
went back to the North Dakota Department of Mineral Resources and looked at their data back to
2015. Unfortunately, the data published in excel only goes back to 2015, even though they have
figures published in PDF form starting in 2003.
Regardless, four years is plenty of time to show just how bad the situation is becoming in
the Bakken. In June 2015, the North Dakota Bakken produced 16% more water than oil. However
June this year, the Bakken field produced 38% more water than oil :
You will notice that overall oil and water production declined in 2016, due to the falling
oil price, but as production grew in 2017 and 2018, the percentage increase of by-product
wastewater surged to 32% and 38% respectively. Here is an interesting comparison:
Bakken Oil & Water Production:
June 2015 Oil = 34.4 million barrels
June 2015 Water = 39.8 million barrels (16% more water)
June 2018 Oil = 33.8 million barrels
June 2018 Water = 46.8 million barrels (38% more water)
As we can see, while overall Bakken oil production in June 2018 was less than it was in June
2015, the volume of waster water increased by an additional 7 million barrels.
I believe there are two negative forces at work in the Bakken as it pertains to the rising
volume of wastewater.
As the wells and field age, more water is produced than oil
Larger Frac Stages, which require more water and sand, are now being utilized to keep
production growing or to keep it from falling
While a rising water cut isn't a surprise to the industry as it is a natural progression of
an aging oil well or field, the use of Larger Frac Stage wells should be a WAKE-UP CALL to
investors. Why? Because Larger Frac Stage wells consume a great deal more water and sand to
produce more oil initially, but the decline rates are even more severe than regular shale
wells.
So, when the Investor Relations are bragging how the companies are using the newer
technology of more complex Large Frac Stage wells, this isn't a good sign. This means that the
company is now desperate to try and grow production, or at worst, to keep it from falling.
Unfortunately, the U.S. Shale Industry is in serious trouble. Most of the shale fields have
reached a peak and when production starts to decline, especially during a collapsing oil price,
I forecast a rapid disintegration of the industry. We must remember, as the oil price and oil
production falls, then company stock and asset values will plummet while the high debt levels
remain. Thus, the shale industry will have increasing difficulty in servicing its debt.
I will continue to monitor the production of oil and wastewater in the Bakken. Please check
back for updates.
It is a little early to really get a sense of how much the Permian is slowing down. Most
analysts have been assuming an overall slowdown over the next 12 months because of pipeline
constraints. However, the EIA figures might suggest that the problem has already started to
bite. In April, the EIA predicted in its Drilling Productivity
Report that Permian production would jump by 73,000 bpd in May. But the monthly data just
released finds only modest gains in Texas (+20,000 bpd) and New Mexico (+3,000 bpd).
Second, the EIA thinks output broke 11 mb/d in July, an all-time high. But judging by the
overly-optimistic monthly data from April and May, perhaps the agency is also overstating July
figures, which raises the possibility that production is not nearly as high as we currently
think.
In the coming months, if monthly U.S. production figures continue to show output
undershooting expectations, that would have global ramifications. Most analysts still are
baking in strong U.S. shale growth figures into their forecasts. If that additional output
fails to materialize, the oil market could end up being a lot tighter than we all expected it
to be.
Earlier estimates of OPEC have now changed, and there is no increase from June. Probably, a
slight decrease from SA. From OPEC sources, not Platts. I think they would start increasing
if Iran drops, but not much otherwise. I think Sauds and Kuwait joint venture is set up for
that potential.
Changing the way I gage things, into a much simpler format. Now, I look at world inventory
drops, and look at current increases from OPEC and US. Neither will change much, so inventory
drops should continue. Opec needs to come up with a lot more, or it will look damn scary in
2019. With pipeline constraints, Canada is pretty much out of the picture for further
increases this year, and not much, elsewhere.
Yes the outlook for OPEC's July production is looking more flat now. This is a strange
situation because Platts is one of OPEC secondary sources and so I assume that they see all
the numbers
Thank you. This news confirms that world production is stagnating. Possibly very close to the
decline. We will have to be attentive to the inventories. It will be the first place that the
nations get hold of in order to supply themselves with oil.
It is a little early to really get a sense of how much the Permian is slowing down. Most
analysts have been assuming an overall slowdown over the next 12 months because of pipeline
constraints. However, the EIA figures might suggest that the problem has already started to
bite. In April, the EIA predicted in its Drilling Productivity
Report that Permian production would jump by 73,000 bpd in May. But the monthly data just
released finds only modest gains in Texas (+20,000 bpd) and New Mexico (+3,000 bpd).
Second, the EIA thinks output broke 11 mb/d in July, an all-time high. But judging by the
overly-optimistic monthly data from April and May, perhaps the agency is also overstating July
figures, which raises the possibility that production is not nearly as high as we currently
think.
In the coming months, if monthly U.S. production figures continue to show output
undershooting expectations, that would have global ramifications. Most analysts still are
baking in strong U.S. shale growth figures into their forecasts. If that additional output
fails to materialize, the oil market could end up being a lot tighter than we all expected it
to be.
Dearth of investments in oil projects mean a spike in prices above $100 could be on the
horizon
Crude across the globe is being used up faster than it is being replaced, raising the
prospect of even higher oil prices in the coming years. The world isn't running out of oil. Rather, energy companies and petro-states -- burned by
2014's price collapse -- are spending less on new projects, even though oil prices have more
than doubled since 2016. That has sparked concerns among some industry watchers of a massive
price spike that could hurt businesses and consumers. The oil industry needs to replace 33 billion barrels of crude every year to satisfy anticipated
demand growth, particularly as developing countries like China and India are consuming more
oil. This year, new investments are set to account for an increase of just 20 billion barrels,
according to data from Rystad Energy.
The industry's average decline rate -- the speed at which output falls without field
maintenance or new drilling -- was 6.3% in 2016 and 5.7% last year, the Norway-based
consultancy said. In the four years before the crash, that decline rate was 3.9%.
Any shortfall in supply could push prices higher, similar to when oil hit nearly $150 a
barrel in 2008, some industry participants say. "The years of underinvestment are setting the scene for a supply crunch," said Virendra
Chauhan, an oil industry analyst at consultancy Energy Aspects. He believes a production
deficit could come as soon as the end of next year, potentially pushing oil above $100 a
barrel.
SNIP In parts of Brazil and Norway, decline rates are already above 10-15%, Energy Aspects' Mr.
Chauhan said. Output from Venezuela's aging fields fell by more than 700,000 barrels a day over
the past year, according to the IEA. In June, Angola's output hit a 12-year low, while Mexico's
production is down nearly 300,000 barrels a day since the middle of 2016, despite efforts to
open up the industry and reverse declines, the IEA said. "Nobody is really stepping in," said Doug King, chief investment officer of the $140 million
Merchant Commodity hedge fund. "People still got burned by the downturn."
Rystad has first half figures for discoveries a bit better than last year, though more on the
gas side than oil, but there was a billion barrel Equinor discovery in Brazil this week that
will make things look better. I thought things were worse, partly because I assumed the
Guyana discoveries would count as appraisals and be back dated against 2016 and 2017, but it
looks like they are new fields. Overall though it still shows a big drop over the past few
years.
A "remarkable" recovery from "abnormally" low levels – complete bollocks, and pretty
close to self-contadictory. Everything is, and always will be, awesome in the oilprice
universe, if not they'd lose their revenue stream.
x
Ignored says:
07/27/2018 at 3:53 am Iran would not try to block anything unless it is under attack by the
US. The Pentagon is opposed to such an attack, but Trump is heavily influenced by Netanyahu and
is advised by the same neocons who got the US into the fiasco in Iraq. Given the inability of
the US Congress to enforce the constitution by denying the Prsident to start a war without a
congressional declaration of war, it seems the USA may be on its way to destroy the world
economy to please an extremist Israeli right wing government.
I write destroy the world economy because it's doubtful Iran would respond as anticipated by
the Americans, who have a tendency to fight wars with strategies based on previous wars and an
excess of complex gadgets and extremely expensive technology. I don't know what they have in
mind, but I'm sure it would be unexpected, calibrated to avoid nuclear retaliation, and may
evolve over time. But I'm sure others will see the risks, and the oil market will take off into
the $100's and possibly $200's unless there's adults left in the USA senate to block this
craziness.
Hightrekker x
Ignored says:
07/26/2018 at 9:51 am I agree– and with all those KSA installations just
15 minutes away by unstoppable missile technology (1970 midrange seems a little
hard for current technology), we have a quandary, not a problem.
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 3:57 am Exactly. But I'm not sure US National Security advisor
Bolton knows anything about low technology midrange missiles and drones, some of
which, in a pinch, can be piloted by small light weight kamikaze martyrs.
Eulenspiegel x
Ignored says:
07/26/2018 at 10:24 am The worst thing for a date to guess is politics.
There are 10 countries that have to grow oil production to avoid peak oil –
these with still big reserves.
One knocked out itself – Venezuela
One is under attack from the USA – Iran
Irak isn't that stable, either.
A hot war can break out every moment, or a civil war devasting and blocking
infrastructure for years, while other countries deplete.
Or peace can come and these ressources can get used.
These combined 10 mb/d alone will determine peak oil – by 5 years or more in
either direction. These 10 mb/day can't be replaced by russion oil tsars, US rednecks
with too much Wallstreet money or Saudis opening secret valves of instant oil wonder
production.
Venezuela can get a new government and increase production by a big amount, helped
by international money. It has the ressources to get one of the big producers when the
tar oil is lifted.
So in my eyes, it looks like somewhere between 2020 and 2030, perhaps even
later.
Couldn't agree with you more regarding OPEC reserve estimates, they are all full of
shit, and no one except a handful of people in those countries would know how much they
have left.
Solving this peak oil timing is more similar to a quantum mechanics problem rather
than a Newtonian mechanics one. It complexity, lack of transparency and political and
economic implication make it impossible to have a deterministic answer, its pure
probability, and also speculations.
Like you i think all these projections are wrong. Maybe we will extract a lot more
oil with newer technologies or new field discoveries and end up cooking the planet with
climate change, and we won't see a "peak oil" for 100s of years who knows.
TechGuy x
Ignored says:
07/26/2018 at 2:54 pm "The peak oil experts were dreadfully wrong with their HL 15
years ago, so what prevents their being just as wrong now? "
Why is Oil at $70/bbl? Back in 1999 its was about $10/bbl. If there no supply
constraints why did the price increase ~7 fold in less than 20 years? Also why the need
to to drill for Shale Oil (Source Rocks) & develop in Deep & ultradeep
water?
Conventional oil peaked in 2005, All the growth is coming from offshore & Shale.
New Oil discoveries have dropped off the cliff. We found almost nothing in 2017. Oil
Discoveries peaked in 1960s and been in permanent decline. Thus if we are discovery
less and less new oil fields every year, below the rate of consumption, Oil production
will have to fall to match discoveries at some point in the future.
Other clues:
1. Oil Majors perfer to drill on Wall street (aka using debt to fund stock buybacks)
instead of developing new fields for future production.
2. Shale Debt: Shale drilling never made a profit, except for using OPM (other People's
money) to fund CapEx\OpEx.
3. US invaded or targeted with Regime change in Middle East Oil producing nations. Only
Iran remains and you can already hear the War drumbeats for Iran.
Reply
Michael B x
Ignored says:
07/26/2018 at 3:31 pm Indeed, and thanks. Note that your answer has to do not
with HL but with obvious signs & symptoms. Believe me, I've been watching, too.
The uncertainty is killing me.
Fernando Leanmex
Ignored says:
07/27/2018 at 4:25 am Michael, I have never been a peak oiler. I come at this from
a different perspective: about 30 years ago I noticed exploration results were
decaying, and started working in areas which would allow producing oil and gas in the
far future from sources we weren't tapping much at the time.
I remember sitting in a meeting around 1990 and suggesting to managers in a
committee I was briefing that we needed to focus on locking up hydrocarbon molecules,
wherever they were, cut down exploration and use that money on technology and getting
access.
This is one reason why eventually I got involved in gas conversion to liquids, heavy
oil, and the former Soviet Union, which to us appeared like a happy hunting ground,
including its Arctic targets in the Barents, Kara, Yamal, etc. I also had colleagues
who went into deep water, EOR, North America Arctic, and of course the hydraulic
fracturing of vertical horizontal wells drilled in low perm formations.
So in my case I've been about 30 years now working on replacing conventional oil
barrels with more difficult barrels. And those difficult barrels require higher prices.
So the question is, what can poor countries afford?
Reply
Michael B x
Ignored says:
07/27/2018 at 5:13 am So, "not a peak oiler" means you think the fate of
conventional oil is not really all that important, and cost is the ultimate
arbiter, not the resource?
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 6:19 am Not a peak oiler means I don't use Hubbert
Linearization or similar techniques. In the past, my job has included the
estimate of resources (not reserves). The preferred technique was to estimate
technical reserves, meaning we supposedly didn't focus on economics. But I
couldn't have staff working out numbers doing endless iterations and model runs
for highly speculative cases, so I gave them the guidance to assume a really
high price, a higher OPEX and CAPEX environment, and prepare conceptual field
redevelopments and marginal field developments or targeting really low quality
reservoirs. We devoted about 5% of the time budget for this effort. And I told
head office I wasn't about to use more manpower working such hypothetical
figures, because we had to focus on reserve studies, and preparing projects to
move reserves along the reserve progression pathway so we could meet our
targets.
The fate of conventional oil is already written, in the sense that most of
the extra oil we get from conventional fields comes from redevelopments which
rely on higher prices, and EOR. The typical field with say 45% recovery factor
can be pounded hard to push it to say 55%, going above 55% gets mighty hard,
and pushing to 60% is nearly impossible. So there are limits, which involve the
huge amount of resources (cash, steel, chemicals, and people) we use up to get
those extra barrels.
One issue to consider is that these redevelopments which include EOR are not
contributing that much extra rate. They stop decline, get a slight bump, and
then yield a slower decline rate for 10-20 years. This means investments take
tine to payout and if the world is suffering from acute shortages they don't
help that much. The on,y fast reaction comes from fracturing "shales" and low
permeability sands, infills in newer fields, and workovers.
Reply
Michael B
x Ignored says:
07/27/2018 at 6:53 am Thanks. If you were doing this in the 90s, sounds
like you were "predicting" the future!
Reply
Hickory
x Ignored says:
07/27/2018 at 9:20 am Sure sounds like a long explanation for your
understanding of 'peak conventional oil'. Nothing to be ashamed of.
Reply
AdamB x
Ignored says:
07/26/2018 at 10:08 am With oil discoveries the last 3 years in the toilet due to lack
of capital investment and lack of major fields its just a matter of time mathematically. Be
thankful we still have time before peak production hits cause I don't think it will be fun
post peak. Hopefully still 5 years until its official maybe less When will Ghawar give up
the ghost .?
Reply
Dennis Coyne x
Ignored says:
07/26/2018 at 11:21 am Saudi Arabia may keep going for many years at 10 Mb/d,
probably until 2030, perhaps beyond.
Reply
AdamB x
Ignored says:
07/26/2018 at 12:02 pm One can hope .they can produce 10 Mb/d to infinity
according to their reserve numbers which never budge .I'd be curious what posters
think their reserves are. 175-225 GB?
Reply
Survivalist
x Ignored says:
07/26/2018 at 2:27 pm It'll be interesting to see how KSA shakes out when
oil consumption begins to zero in on oil production, and exports decrease..
ELM.
Dennis Coyne x
Ignored says:
07/26/2018 at 10:58 am Another consideration is discoveries and reserve appreciation.
Consider estimates of conventional C+C using Hubbert Linearization by Jean Laherrere which
have gradually increased from 1998 (1800 Gb) to 2016 (2500 Gb.) In addition, there is not
any particular reason that output would tend to follow a "Hubbert" type logistical
function.
Generally estimates based on Hubbert Linearization would be a minimum estimate in my
view.
In addition conventional oil Extraction rates (output divided by producing reserves) in
the World (5.6% in 2016) are far lower than the United States (14.8% in 2016, all C+C), so
there is the potential that with higher oil prices the average extraction rate for the
World may increase. The World conventional extraction rate was about 11.6% in 1979. A
gradually increasing rate of extraction might allow a plateau in output to be extended for
many years (to 2030 at least). Impossible to predict of course, the number of scenarios
that can be created is large.
One such scenario is presented below (peak in 2025 at 85.5 Mb/d of C+C or 4275
Mt/year).
The analysis using the logistic function does not account for this potential.
Dennis Coyne x
Ignored says:
07/26/2018 at 6:49 pm I disagree. Oil prices are more likely to increase than
to fall to $30/b and more of these companies are likely to be profitable as oil
prices rise, also 3 of the top companies are profitable, so a "well run" oil
company can indeed be profitable, those that are less well run will either change
the way they operate or they will go out of business. The better companies buy the
worthwhile assets on the cheap and life goes on.
It's called capitalism folks.
Also the DPR is not very good, I ignore that report and use EIA's tight oil
estimates (link below) and shaleprofile.com for good information.
GuyM
x Ignored says:
07/27/2018 at 9:12 am "Also the DPR is not very good", is an understatement.
I have never seen an analysis use so many different fruits to come up with
bananas expected.
Reply
Minqi Li x
Ignored says:
07/26/2018 at 3:55 pm I suppose by "decline rate" they are talking about the
"legacy decline"
Reply
Guym x
Ignored says:
07/26/2018 at 5:48 pm As an example, I will use approximate data from a fairly
good tier 2 well in the Eagle Ford. It starts off production at 33k the first
month, and drops rapidly after that to reach 8k by the final month. Let's say it
produces 175k the first year, which would be profitable at today's prices. The next
year it produces 55k, and the next year 36k. By the fourth year it is producing
less than 100 barrels a day, and by the sixth year it is questionable to keep up.
Little better than stripper status. Tier three stuff is much worse, it may reach
stripper status by the third year. Eventually, all will be tier two and three
status wells. That's the majority of reserves estimated. Estimating future
production from current production doesn't touch on reality. Eventually, to keep up
on initial production, you would have to drill twice as many wells. But, you won't
keep up with twice as many, because the decline rates will be higher. There is a
lot of difference between a 600k EUR well, and a 300k EUR, or a 150k EUR. 2042 for
US peak? Not hardly.
Reply
I agree, probably 2023 to 2025 will be the US peak, after that decline is
likely to be rapid because mostly tier 2 and tier 3 wells will be left, high
oil prices may make them profitable, but it will be impossible to keep up with
the decline rate of legacy wells after 2025 and US output will decline rapidly
(4 or 5% per year) after 2030.
Reply
TechGuy
x Ignored says:
07/26/2018 at 7:48 pm One snag: The Shale Debt starts coming due in
2019 and continues through to 2024. Shale drillers were successful since
the borrowed at rock bottom interest rates and investors practically fought
each other begging Shale drillers to take their money. Not so sure it will
work if interest rates are higher, and The Shale sweet spots aren't
endless.
Reply
Guym
x Ignored says:
07/26/2018 at 8:49 pm That might slow the start up, for sure. If
the price of oil gets high enough, that will barrier will be short
lived.
Reply
TechGuy
x Ignored says:
07/27/2018 at 2:43 pm As oil prices increase so does the costs.
It takes a lot of diesel to haul Water, Sand, and oil. Shale
drillers never really made a real profit, even when Oil was over
$100/bbl. One must consider the EROEI for Shale & rising
CapEx\OpEx as the cost of Oil rises.
Second, its likely that consumers cannot afford high oil prices.
As prices rise, Consumers will cut back and it will plunge the
global economy back into recession. Perhaps the Worlds Central
banks can coach something back into the global economy, but it
won't work over the long term.
FWIW: Some of the recent data is showing weakness in the global
economy: Housing sales are falling and prices in the hot regions
are flatlining. Trumps tariffs are also taking a toll as global
trade is falling. And there are cracks in the developing world
credit markets. We might see a stock market correction this fall,
which would likely see commodity prices fall (including Oil).
Reply
Hickory
x Ignored says:
07/27/2018 at 10:37 pm " consumers cannot afford high oil
prices. As prices rise, Consumers will cut back and it will
plunge the global economy back into recession."
Well, that likely depends on how fast and far the prices go.
Slow steady rise can be well tolerated pretty far. Energy is so
cheap for what you get, after all.
Many other countries have a much better GDP/unit energy
consumed than the USA, and with price pressure the USA could
get there too. I suspect we could shed 10-20% of our oil
consumption without big effect, particularly if we did it
slowly. For example, it wouldn't affect the GDP at all if we
slowed down to max 60 mph. Painless saving of energy, if you
choose good music.
It is the fast changes in price that really tend to hurt.
Reply
TechGuy
x Ignored says:
07/27/2018 at 11:45 pm "I suspect we could shed 10-20%
of our oil consumption without big effect, particularly if
we did it slowly."
It doesn't work that way. Consumers cut back on
spending, from eating out, going on vacations. They loss
confidence and delay major purchases like new cars, homes,
etc.
Most of the population commute to work well below 60
mph. Traffic usually limits speeds to 40 mph or less during
commuting hours.
To understand how high oil prices affect the economy
just research the events around 2007/2008. Schools &
business were planning to reduce work & school days to
3 or 4 days a week. Thieves were draining fuel from parked
trucks and cars. The higher oil prices caused food prices
to soar, which lead to the arab spring in Africa & the
middle east. Europe had frequent riots. Airlines &
shipping companies impose fuel surcharges. People homes had
utilities shutoff. since they could afford their energy
bills.
Funny how quickly people forget the aftermath of high
energy prices. Doesn't anyone read or study economics?
GoneFishing x
Ignored says:
07/26/2018 at 5:28 pm Nice report. Production decline is a short time away if we
don't keep drilling.
Speaking of legacy wells, the huge number of abandoned wells from the past is
leaving us a legacy of leakage. The even bigger number of recent wells will continue
that legacy.
Fernando Leanmex
Ignored says:
07/27/2018 at 4:33 am 150 year old wells in the eastern USA could indeed leak
methane. But I would not rely much on Arstechnica, it's a blog run by a guy with a
liberal arts degree very well crafted to be a cheering section for renewables. It
may even be subsidized by Yingli Green, a Chinese solar panel maker.
Reply
Fred Magyar
x Ignored says:
07/27/2018 at 6:57 am Are you seriously claiming that a peer reviewed
scientific paper, in the 'Proceedings of The National Academy of Sciences of
The United States of America' is somehow untrustworthy because it's conclusions
were mentioned by Ars Technica?!
Identification and characterization of high methane-emitting abandoned oil
and gas wells
Abstract Recent measurements of methane emissions from abandoned oil/gas wells show
that these wells can be a substantial source of methane to the atmosphere,
particularly from a small proportion of high-emitting wells. However,
identifying high emitters remains a challenge. We couple 163 well measurements
of methane flow rates; ethane, propane, and n-butane concentrations; isotopes
of methane; and noble gas concentrations from 88 wells in Pennsylvania with
synthesized data from historical documents, field investigations, and state
databases. Using our databases, we (i) improve estimates of the number of
abandoned wells in Pennsylvania; (ii) characterize key attributes that
accompany high emitters, including depth, type, plugging status, and coal area
designation; and (iii) estimate attribute-specific and overall methane
emissions from abandoned wells. High emitters are best predicted as unplugged
gas wells and plugged/vented gas wells in coal areas and appear to be unrelated
to the presence of underground natural gas storage areas or unconventional
oil/gas production. Repeat measurements over 2 years show that flow rates of
high emitters are sustained through time. Our attribute-based methane emission
data and our comprehensive estimate of 470,000–750,000 abandoned wells in
Pennsylvania result in estimated state-wide emissions of 0.04–0.07 Mt
(1012 g) CH4 per year. This estimate represents 5–8% of annual
anthropogenic methane emissions in Pennsylvania. Our methodology combining new
field measurements with data mining of previously unavailable well attributes
and numbers of wells can be used to improve methane emission estimates and
prioritize cost-effective mitigation strategies for Pennsylvania and
beyond.
Reply
Fernando Leanme
x Ignored says:
07/27/2018 at 8:33 am I am an academy member. I also know how to search
for methane leaks. And I'm aware the academy publishes papers which lack
the quality one would like to see. But if you want credibility, I would
skip Arstechnica and link directly to the paper.
The Arstechnica editor has an axe to grind, publishes a bunch of
garbage, therefore I never pay attention to it. Regarding the paper itself,
it's not representative of what goes on in say Texas. There are areas in
Texas (say Spindletop) where gas leaks should be present from the wells
drilled with cable tools in the old days. But a better sense for what goes
on now is gained from looking at wells drilled and abandoned in Texas and
Louisiana in the last 40 years.
Regarding Pennsylvania methane leaks, in the overall picture they are
meaningless. There are coal mining regions in India and China which can be
seen as very large hot spots from satellites.
Fred Magyar
x Ignored says:
07/27/2018 at 3:11 pm Hippity hoppity! Off to a tea party
with the Mad Hatter and Alice! As in A Large Ion Collider
Experiment at the LHC. Much more fun than dealing with the
crippled egos of idealogues.
Cheers!
Reply
If the wells are plugged, the concrete eventually fails (30 years) so we
have an ongoing source of methane that could last for centuries. Millions
of wells across the US, much more across the world.
And guess what, those ideas of storing CO2 underground, well now we have
millions of pathways for the CO2 to escape, so actual sites would be few
and far between.
The original Canadian study I read a few years ago has disappeared from
the internet. It showed the long term potential leakage of well systems.
Reply
Dave Kimblex
Ignored says:
07/26/2018 at 6:11 pm All this Hubbertian analysis is useful to set a ceiling on
production, but the world's economy runs on making a profit and so producers have a minimum
price they must receive, while the end consumers have a maximum price they can afford to
pay.
In mid-2008 the effect of a 72% price rise in 18 months caused a $1.75 trillion extra
cost on OECD oil imports and the world economy crashed. Recovery required the USG to
guarantee loans to frackers to get the production numbers up. I am not saying that they
won't try that again, but this can only go so far. Surely next time this happens, no one
will be able to avoid the obvious conclusion that there is no future profit in oil
production, and the oil industry will have its share prices downgraded, reducing the
collateral for loans, whereupon they will go out of business in a puff of smoke.
This will happen long before any URR impacts, so I wonder at how much this analysis is
worth.
Reply
Guym x
Ignored says:
07/26/2018 at 8:25 pm USG guaranteed loans to frackers???? Interest rates for
everyone was low then, but I don't remember reading about any guarantees. Drilling
horizontals is a little past SBA stuff.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 1:56 am If the "oil industry" means the IOCs then they are a minor
player now. The NOCs dominate the reserves and production, of course they all seem to
be having money issues as well but maybe they manifest in a slightly different way
– i.e riots, uprisings and infrastructure collapse.
It's already noticeable that many of the big companies are switching to share buy
backs (Total, Shell, Anadarko) and less development spending even as the price has been
rising. The one which has switched the other way is ExxonMobil, and not
uncoincidentally it is the only one with really good recent discoveries. That straight
line H/L for the rest of the world is just the tail run out on existing discoveries,
most of which are also already developed and wouldn't be taken off line even with
bankruptcies for the operators. If only as chemical feedstock oil is way better in
almost every way than anything that could be made from water/CO2/renewable energy so if
civilisation lasts long enough most of it will be used.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 1:44 am Forcing a logistic curve on some of those production histories
might give some big errors, though maybe they cancel out overall. Hubbert said himself that
H/L wouldn't work well on production that had been artificially constrained by a cartel
(e.g. OPEC for Saudi, Kuwait, UAE, Iran and Iraq) or environmental moratoria (e.g. some US
and Canada oil). For oil sands they tend to be built on 50 year project lives, with steady
production and a fast fall off rather than a traditional decline curve. About 50 mmbbls of
reserve is already tied into operating, steady production. Future developments will be
similarly constrained with the additional limit from environmental objectives to both the
extraction and pipelines. Logistics curves might still come close if the reserve estimates
are good, but that is also the biggest unknown as other comments have said.
Reply
Minqi Li x
Ignored says:
07/27/2018 at 2:54 pm Projections are not meant to be predictions. Even EIA or IEA
say that. But they are always useful to illustrate given certain assumptions, what will
or what are likely to happen.
That has been said, given our understanding of the inherent limitations of
projections/data, a careful and cautious application of these projections does provide
us some idea regarding the likely range of future development. For example, the
projection for the US oil used in this report is likely to be too optimistic especially
for years after 2025, as many have pointed out. That will reinforce the case for a
global peak oil before 2025
In addition to production, I think the consumption data in the report also provides
some interesting information. I wonder if someone cares to comment about that.
Reply
Guym x
Ignored says:
07/27/2018 at 7:37 pm Well, obviously consumption can't be over production for
any great amount, or we won't have inventory. Peak production precedes any mythical
peak demand. Consumption mostly follows production is my guess. At probably a much
higher price than today.
Reply
"Pioneer spent $818 million on capital expenditures (CapEx) for additions to oil and gas
properties (drilling and completion costs) during Q1 2018, brought on 63 horizontal wells
in the Permian, and only added 9,000 barrels per day of oil equivalent over the previous
quarter"
So it's round about 13 million $ per well, not 7 million.
Reply
Fernando Leanmex
Ignored says:
07/27/2018 at 8:38 am The number of wells brought on isn't proportional to wells
drilled. And the CAPEX isn't proportional to wells drilled. Therefore it's hard to
derive a per well cost from such figures.
Reply
GuyM x
Ignored says:
07/27/2018 at 9:06 am Yeah, there a lot of DUCs, and you have to consider that
Pioneer lays out some bucks for its gathering system and gas processing plant in the
Permian. Hard to isolate per well from total capex figures.
Reply
(Sale of oil) – well cost – variable cost per barrel = profit
does not work that good – there are lots of hidden costs even under CAPEX,
that are almost as high as completion costs when these 7 million$ / well are
right.
And I think these cost are not one time cost just only in this quarter –
there is alway a pipeline to build, a convertert to install, a gravel road to the
site to build and so on.
Reply
George Kaplan x
Ignored says:
07/27/2018 at 3:42 pm Rystad has first half figures for discoveries a bit better than
last year, though more on the gas side than oil, but there was a billion barrel Equinor
discovery in Brazil this week that will make things look better. I thought things were
worse, partly because I assumed the Guyana discoveries would count as appraisals and be
back dated against 2016 and 2017, but it looks like they are new fields. Overall though it
still shows a big drop over the past few years.
With over 3000 platforms, 25,000 miles of pipeline, all unsecure in the Gulf of Mexico,
they provide a lucrative target in any conflict with the US. Energy disruptions and
environmental calamities would reek havoc. Surely there is a plan to quickly secure the Gulf
from under/over/on the water threats? If not get at it.
More Oilprice.com industry pimping. The world uses 36 billion barrels (Gb) of crude per
year. Plus they are quoting boe, or barrels equivalent. Gas is not crude. The article should
read: "The world is still pumping 9 barrels for every 1 it finds". D day is not something the
industry doesn't wants advertised.
Look at the graph again. Draw a trend line from left to right across the peaks from 2014
til now. Is the line pointing up or down? That's peak oil.
So there's been an up tick this year. How much has been discovered. Ooooh, 4.5 billion
barrels. Sounds like a lot to you? What's the world consumption rate expressed in millions of
barrels per DAY? Don't know? It's around 90 million barrels per DAY. Look it up if you doubt
me. If you divide 4.5 billion by 90 million, you'll calculate how many DAYS it takes to
consume 4.5 billion barrels. To make it easier for you, just reduce the fraction by stroking
6 zeros off each number. That's 4,500/90. Not too hard. That's 50 DAYS of supply!!! OK, maybe
another 4.5 billion will be found in 2H2018. Oooooh, another 50 DAYS worth. We're
saved!!!
In the last paragraph, what's the Reserve Replacement Rate? 10% . That's not so good.
Also, a large portion of the newly discovered oil is offshore, in ultra deep reservoirs.
Do you think that might be more expensive to produce?
As for abiotic oil, as Laws of Physics pointed out, even if that desperate theory were
true -- which it isn't -- it's the rate of replacement that matters, and it's nowhere near 90
million barrels per day.
So, fore-warned is fore-armed, but if you'd rather bury your head in the sand that's your
prerogative.
"... Crude price manipulation is important to maintain the (fraudulent) petrodollar system because the sheeple subconsciously measure inflation through the price of gasoline. The Oligarchy that owns The Fed will not give up the petrodollar system because it is their main weapon for global domination and control. Unprofitable shale companies will continue to be lent money ;) ..."
"... That's not what the article is saying. If we stopped drilling and fracking today, in one month's time, the production would decline by 500k bbl/day. To offset that, 500k bbl/day production from new wells needs to be brought online in a month, which is what they're doing. The problem is, the more production, the more they have to drill just to keep production flat. ..."
"... it really was by the end of aug the production will drop by 1/2 mbpd making 10.5 mbpd unless somewhere else they made up for that loss, and thats prolly not counting your ability to bring that new production to mkt, via VW bus? ..."
"... Shale production is used primarily as a diluent, and as a petro chemical feed stock. The majority of it is used by Canada and Mexico. ..."
"... The Eagle Ford shale play here at home went bust two years ago. It has never recovered and does not look like it ever will. Most of my family have to drive to Odessa for oil work. Now the greed over there is raping the workers with exorbitant rental rates. Those poor slobs can't get a break. Well most working folks just can't get a break period. ..."
While the U.S. reached a new record of 11 million barrels of oil production per day last week,
the top five shale oil fields also suffered the highest monthly decline rate ever. This is bad
news for the U.S. shale industry as it must produce more and more oil each month, to keep oil
production from falling.
According to the newest EIA Drilling Productivity Report, the top five U.S. Shale Oil
fields monthly oil decline rate is set to surpass a half million barrels per day in August.
Thus, the companies will have to produce at last 500,000 barrels of new oil next month just to keep
production flat.
Here are the individual shale oil field charts from the EIA's July Drilling Productivity Report:
The figures that are shown above the UP arrow denote the forecasted new production added next
month while the figures above the DOWN arrow provide the monthly legacy decline rate. For example,
the chart on the bottom right-hand side is for the Permian Region. The EIA forecasts that the
Permian will add 296,000 barrels per day (bpd) of new shale oil production in August, while the
existing wells in the field will decline by 223,000 bpd.
If we add up these top five shale oil fields monthly decline rate for August will be 503,000
bpd. Thus, the shale oil companies must produce at least 503,000 bpd of new oil supply next month
just to keep production from falling. And, we must remember, this decline rate will continue to
increase as shale oil production rises.
We can see this in the following chart below. Again, according to the EIA's figures,
the top five U.S. shale oil fields monthly legacy decline rate increased from 398,000 bpd in
January to 503,000 bpd for August
:
In just the first seven months of 2018, the total monthly decline rate from these top shale
fields increased by 26%. These massive decline rates are the very reason the shale oil and gas
companies are struggling to make money. A perfect example of this is PXD, Pioneer Resources.
Pioneer is the largest shale oil producer in the Permian. According to Pioneer's Q1 2018 Report:
Producing 260 thousand barrels oil equivalent per day (MBOEPD) in the Permian Basin,
an increase of 9 MBOEPD, or 3%, compared to the fourth quarter of 2017;
first quarter
Permian Basin production was at the top end of Pioneer's production guidance range of 252 MBOEPD
to 260 MBOEPD; as previously announced, freezing temperatures in early January resulted in
production losses of approximately 6 MBOEPD; Permian Basin oil production increased to 170
thousand barrels of oil per day (MBOPD);
63 horizontal wells were placed on production
.
Pioneer spent $818 million on capital expenditures (CapEx) for additions to oil and gas
properties (drilling and completion costs) during Q1 2018, brought on 63 horizontal wells in the
Permian, and only added 9,000 barrels per day of oil equivalent over the previous quarter.
So, how much Free Cash Flow did Pioneer make with oil prices at the highest level in almost four
years?? Well, you're not going to believe me... so here is Pioneer's Cash Flow Statement below:
Pioneer reported $554 million in cash from operations and spent $818 million drilling and
completing oil wells in the Permian and a few other locations. Thus, Pioneer's Free Cash Flow was
a negative $264 million. However, Pioneer spent an additional $51 million for additions to other
assets and other property and equipment shown right below the RED highlighted line for a total of
$869 million in total CapEx spending. Total net free cash flow for Pioneer is -$315 million if we
include the additional $51 million.
Therefore, the largest shale oil producer in the Permian spent $264 million more than they made
from operations drilling 63 new wells in the Permian and only added a net 9,000 barrels per day of
oil equivalent. Now, how economical is that???
How long can this insanity go on??
If we look at the Free Cash Flow for some of the top shale energy companies in Q1 2018, here is
the result:
Of the ten shale companies in the chart above (in order: Continental, EOG, Whiting, Concho,
Marathon, Oasis, Occidental, Hess, Apache & Pioneer), only three enjoyed positive free cash flow,
while seven suffered negative free cash flow losses.
The net result of the group was a
negative $455 million in free cash flow.
Even with higher oil prices, the U.S. shale energy companies are still struggling to make money.
So, the question remains. What happens to these shale oil companies when the oil price falls
back towards $30 when the stock market drops by 50+% over the next few years?? And how is the U.S.
Shale Energy Industry going to pay back the $250+ billion in debt??
Lastly, here is my recent video on the Shale Oil Ponzi Scheme if you haven't seen it yet:
Crude price manipulation is important to maintain the (fraudulent)
petrodollar system because the sheeple subconsciously measure inflation
through the price of gasoline. The Oligarchy that owns The Fed will not
give up the petrodollar system because it is their main weapon for global
domination and control. Unprofitable shale companies will continue to be
lent
money
;)
Let's do the math: US produced 11 million bbls a day recently, but
production is declining at a rate of 1/2 million bbls/day according to
the article. So that means US oil production will be zero bbl/day in
about 3 weeks.
That's not what the article is saying. If we stopped drilling and
fracking today, in one month's time, the production would decline by
500k bbl/day. To offset that, 500k bbl/day production from new wells
needs to be brought online in a month, which is what they're doing.
The problem is, the more production, the more they have to drill just
to keep production flat.
This is a well know item, horizontal fracking produces very well
for a couple years and then not so much. Also known that the US uses
17 to 19 (depending on who is telling) million barrels per day so the
US still imports a lot of crude per day. We use it like there is no
tomorrow and one day there won't be but I'm 85 so the three words
to tranquility applies. "Not my problem".
it really was by the end of aug the production will drop by 1/2 mbpd
making 10.5 mbpd unless somewhere else they made up for that loss,
and thats prolly not counting your ability to bring that new
production to mkt, via VW bus?
the yearly chart is very telling. we stayed in a $20-$40 range from the
70's to mid 2000's then bush drove the price up but we fell exactly when
obama won the election BUT UNDER OBAMA WE SETTLED INTO A RANGE OF
$40-$100....fucking double the old range.
The US has 1.7 million operating shale wells. Over the next five years 1.4
million of those wells will have to be replaced to keep production
constant. The decline rate for the average shale well is 89% over its first
five years. At an average replacement cost of $4.4 million per well the
total cost of replacing 1.4 million wells will be $6.2 trillion. The total
cost of all the petroleum products consumed by the US over the next five
years will approximately $2.5 trillion.
To keep the shale industry alive over the next five years it will cost
the US economy 2.5 times as much as it will spend on all the petroleum
products it will consume. Expect a massive dislocation in the petroleum
industry in the very near future!
http://www.thehillsgroup.org/
First... I don't trust Continental
Resources figures, but I can't get into that yet... long story.
Second, EOG is spending twice as much as most shale players on
CapEx per quarter and are making some free cash flow. However,
EOG also paid $97 million in dividends Q1 2018. So, if we
subtract out their dividend payouts, EOG only netted $14 million
after spending $1.4 billion in Capex during Q1 2018.
Lastly, Whiting's oil production is still less than what it was
in 2016. By cutting CapEx spending drastically, from $600 million
a quarter two years ago to only $178 million in Q1 2018, they can
make some free cash flow. But, by drastically cutting CapEx
spending, Whiting won't be able to increase production to pay back
the $2.8 billion in long-term debt that they owe.
And this is the same pattern for our govts.... spend more and
get less..... the result is inevitable, same with our pumped up
markets.... not if, but when.... and it looks to be soon...
Now, Trump wants the EU to buy this gas? It's obviously a very
short term deal, or he hasn't looked at the numbers at all...
which makes him perfect for his role in the 'out with the OWO,
in with the NWO'.
Ponzi scheme is the correct word for this shale industry,
same with all of our industries ,as empires all operate this
way... pushing off paying the bills till tomorrow, always a new
tomorrow... kick that can down the road... the states do it,
the fed govt does it... all those not making money do it... and
these are the opposite of startups.
Buying time. Short and sweet. The mere fact that they are so
actively "buying time" with these short-term policies is
proof that they are aware time is running out, which leaves
one to ponder just exactly "how much" time are they trying
to buy, and toward what end. Big plans are in the works I
suspect, and the end of "buying time" is rapidly
approaching.
For as long as there are enough natural resources left in the
world to be able to strip-mine at about exponentially increasing
rates, as enabled by making "money" out of nothing as debts in order
to "pay" for doing so, which is a debt slavery system based on the
public powers of governments used to back up legalized counterfeiting
by private banks, and the big corporations that grew up around those
big banks. The oil extraction corporations operate inside of that
overall context where everything they are able to do is based on the
degree to which the sources of their funding ultimately depend upon
being able to continue enforcing frauds.
It is too good a phrase to use to refer to those aspects of that
process as being "Ponzi Schemes," since deceived people voluntarily
participated in Ponzi's Scheme. The dominant Pyramid Schemes of
Globalized Neolithic Civilization are systems that offered people a
deal they could not refuse.
The history of oil can not be separated from the history of war.
Within the overall context that money is measurement backed by
murder, the funding of the oil industry developed as vicious feedback
loops due to be able to
enforce frauds
, despite that
about exponentially advancing technologies were enabling about
exponentially increasing fraudulence, with respect to the related
about exponentially increasing strip-mining.
"How long can this insanity go on?"
Probably for a relatively long time for those who are old and
rich, and positioned near the center, toward the top, of the Pyramid
Scheme of enforced frauds which achieve
symbolic robberies
for those people.
Shale oil extraction exemplifies DIMINISHING RETURNS, which
applies across everything else that Civilization is doing.
"It's amazing the amount of money that needs to be invested
just to replace production."
It is more
"amazing"
when one goes through the labyrinth of Money
As Debt, which is the MADNESS of
negative capital
,
which is able to be publicly presented as if that is still positive
capital. While it is abstractly obvious that murder systems are
manifestations of general energy systems, there is relatively little
public appreciation of those murder systems backing up the money
systems.
Around about the 15 minute mark in the video embedded in the
article above, some of the reasons for calling shale oil extraction a
"Ponzi Scheme" are outlined, including "Ponzi Stock Finance," which
are secondary mechanisms where the MAD Money As Debt travels from its
original source
ex nihilo
through other
investors, before going into the shale oil industry. The underlying
issues related to DIMINISHING RETURNS will manifest first and
foremost through the fundamentally fraudulent financial accounting
systems which almost totally dominant Globalized Neolithic
Civilization.
"How long can this insanity go on?"
Until those runaway debt insanities provoke sufficient runaway
death insanities to cause series of crazy collapses which result in
whatever systems of organized crime could continue to operate after
the consequences of DIMINISHING RETURNS have worked their way
through. Since it is barely possible to exaggerate the degree to
which
negative extraction
was presented as
if that was positive production, it is also barely possible to
exaggerate the degree of psychotic breakdowns that will manifest when
runaway enforced frauds finally have their about exponentially
increasing fraudulence go past their tipping points.
The USA became the most important component in Globalized
Neolithic Civilization. The USA has led the way into the development
of globalized monkey money frauds, backed by the threat of force from
apes with atomic bombs, whose lives still mostly became dependent
upon the chemical energy in petroleum resources. The USA, therefore,
also led the way to the development of shale oil extraction, while
that continued to be publicly presented as if that was production.
At the present time, and for the foreseeable finite future, it is
politically impossible for human beings living inside of the dominant
Civilization to better understand themselves as manifestations of
general energy systems. Instead, almost everyone who is adapted to
living inside that Civilization has developed ways to present what
they are actually doing in the most dishonest and absurdly backward
ways possible.
Extracting more and more expensive petroleum resources is merely
one of the leading symbols of what is happening everywhere else one
looks. That Civilization is almost totally based on being able to
back up legalized lies with legalized violence continues to be
socially successful to the degree that most people do not understand
that, because they have been conditioned to not want to understand
that being able to back up lies with violence never stops those lies
from still being fundamentally
false.
THAT
was the source of the
"insanity."
It is too optimistic to expect that will
not continue, despite series of collapses into crazy chaos, and the
related series of psychotic breakdowns. Whatever civilization
survives will continue to operate according to the principles and
methods of organized crime, which will continue to have the related
corollaries that the apparent successfulness of those organized
crimes will depend upon most people not wanting to understand what is
actually happening.
Theoretically, enough people "should" better understand themselves
as manifestations of energy systems, which would then include their
perceptions of the ways that they lived as
nested toroidal
vortices engaged in entropic pumping of environmental energy sources.
That is made even more theoretically imperative to the degree that
some people have better understood some energy systems.
However, throughout everything that operates through Pyramid
Schemes, for those continue requires that the pyramidion people do
everything they can to make sure that those lower down in those
Pyramid Schemes do not understand that those Pyramids are actually
NESTED TOROIDAL VORTICES. At the present time, and in the foreseeable
finite future, the dominant Civilization will continue intensifying
its paradoxical Grand Canyon Contradictions that physical science
makes prodigious progress in understanding some energy systems, while
political science makes no similar progress in understanding human
energy systems, except to the degree that human systems are thereby
enabled to become about exponentially more dishonest.
Fracking symbolizes advancing physical technologies, channeled
through financial systems which only "advance" by becoming about
exponentially more fraudulent. Since almost everything Civilization
is doing has become based on that exponentially increasing
fraudulence, which in turn is based on exponentially increasing
strip-mining, it is politically impossible for that Civilization to
stop that
"insanity"
other than by driving
itself some series of psychotic breakdowns.
That
"lousy shale oil economics will pull down the U.S
economy"
is only one of the more and more painfully
obviously tips of the immense icebergs of enforced frauds, whose own
exponentially increasing fraudulences are melting themselves. (In
that context it is old-fashioned nonsense that possessing precious
metals is a somewhat saner "solution" to the runaway criminal
"insanity"
of Civilization.)
"At an average replacement cost of $4.4 million per well the total cost
of replacing 1.4 million wells will be $6.2 trillion. "
I think your
math is way off, To To date, Shale spent about $500B to $750B drilling &
operating those 1.7M wells. That said, Shale drillers borrowed about
$400B, Its unlikely they'll find more Suckers^H^H^H^H investors to
borrow another $400B. Plus they are running out of sweet spots to drill
in Bakken & Eagle Ford. I believe currently the only remaining sweet
spot they can develop is the Permian Basin. Plus the debt coupon on the
borrowed money start coming due between 2019-2023 (They need to roll
that debt over).
Frackers are really dumb. They can't refracture the wells. As soon as their
wells run dry, it's game over. Financial guys are really smart. They make
pronouncements from their desk. They are never wrong.
I'm going back under my bed and work on my Zombie apocalypse cookbook. On
sale soon.
"Frackers are really dumb. They can't refracture the wells."
They can
re-frack their wells, but the yield is abysmally low; so it is rarely
attempted. Re-fracking produces very little additional oil. Most of what is
produced from refracking is gas, which is a low revenue product. It is, by
far, more cost effective to just drill a new well.
By our calculations the US is selling the oil it produces at 46% below its
full life cycle cost of production. The shale industry is apparently using
a business plan that was developed by an Ivy League business school MBA.
They got their degree in Advance Ponzi Schemes.
http://www.thehillsgroup.org/
My family owned some mineral interest in Blaine County, Oklahoma. It's one of
the hottest shale plays out there right now. A well was drilled and it came in
just gang busters. Within 3 months, the production had fallen by 86%. The well
results out of the gate were so good that the well was mentioned in an investor
presentation for a major oil company. I doubt anyone went back to inform the
investors of the results 90 days later.
That's Shale. If you're lucky you get initial high rates BUT IT WILL drop
in production like hell with time. It's all in the geology. Just look at
the perms and you will understand.
Any idiot can sell goods at half the price it costs them to produce. That
is shale.
Peak oil theory was proved to be correct. It referred to conventional oil.
At the time sour oil wasn't even used, now a majority of the world's oil
is sour. No enhanced oil recovery techniques were available, now every barrel is
geeked out. Water flooding failing Ghawar super giant oilfield, shows the
desperation to keep up oil production.
As far as I know, every Giant in the world (the less than 1% of total
fields that produce 60% of world production) is using some form of
tertiary extraction method to keep producing. Tertiary extraction
methods retrieve anywhere from 2 to 20% of OOIP (original oil in place).
6 to 7% is probably the average. Ghawar is using CO2 injection, in
junction with horizontal wells to extract the last 30 feet of its
original 350 foot oil seam. In other words Ghawar is over 90% depleted.
That was the main reason that the Saudi's $2 trillion IPO for Aramco
fell apart.
With the huge amount of capital outflow now leaving the EM
it seems likely that world demand will begin to decline at about the
same time production begins to decline. The EM constitutes 38% of world
GDP, and 47% of world trade. They also use a greater amount of oil per
GDP $ produced than does the DE. As they continue to fail, as we have
seen recently from Turkey to Venezuela, their petroleum usage will fall.
As Shale has a very limited shelf life (now needing $6.2 trillion over
the next five years to keep production even) the US will find itself in
the situation of having to deal with whipsawing oil markets. Its
precarious debt situation means that it is going to be a rough ride down
from here.
As far as I know no one has called a peak in shale production. As long as
the FED is giving them a $65/ barrel subsidy with ZIRP it is hard to do.
What we can say is that they are planning on taking the $6.2 trillion they
will need for new wells over the next 5 years out of your hide. Invest in
Neosporin, there is gong to be some chapped asses coming down the pike.
I for one want to thank you SOO. Your analysis is also spot on, and
along with your real world experience it reminds me of that ole
detective show Dragnet, "Just the facts Ma'm, just the facts".
Now if
there was an answer that we could all live with....
About what I'd expect. We are 2 years out from the bottom. Exploration and
drilling came to halt. Now that's starting to show up in the declines. It will
start to pick up now with higher prices. Pendulum swings both ways.
"What happens to these shale oil companies when the oil price falls back towards
$30..."
This is the part I don't get, unless you are making two separate
arguments.
Oil is a strategic resource
and as so is an issue of
national security.
They will produce at a loss until they're all dry, if
they have to. The financing will not stop. Same reasoning: Since Musk is
advancing the whole globalist agenda, I hesitate to short the hell out of Tesla.
The financing may just not ever stop. Can the same be said of the broader market?
They've been wiping out EM debt with jubilees; is that how they plan on printing
forever and fueling GDP with debt?
I would protest. They will produce at a fiat loss until dry (assuming fiat
is still accepted of course). The will not produce at an energy loss
though, less than 3 to 4 EROEI.
A Shale well, with an IP (initial production) of 450 b/d, reaches its
energy breakeven point at about 70,000 barrels, or about 10 months. After
that point they must be energy subsidized to keep producing; they go from
being an energy source to become an energy sink. A conventional well
remains an energy source until the WOR (water oil ratio) reaches 45:1, or a
97.8% water cut. At which point they become uneconomical to operate and are
shut in. Shale wells are only operational past their energy source/sink
point because energy is being input from other sources. Much of that comes
from conventional crude - but - the ERoEI of conventional is also falling.
The average conventional well will reach its energy breakeven point by
2030. In thermodynamics that is referred to as the "dead state".
Shale production is used primarily as a diluent, and as a petro chemical
feed stock. The majority of it is used by Canada and Mexico. The Canadians
need it to produce their tar sands oil, and Mexico uses it for their Mayan
Heavy. Both are important raw material sources for US oil refineries.
Even
though Shale is net energy neutral, or negative, and will never be
economical to produce, if the US wants to keep its primary suppliers of
crude in business it has to supply them with diluent. The FED has already
been subsidizing Shale through its ZIRP policy.
Over its full production
life cycle that has contributed about $65 a barrel. In the event that the
FED can no longer keep interest rates suppressed subsidizes will have to
come from some other source. Those may come through the refineries, or like
farmers they may be paid by the bushel. In any event those costs are going
to become extremely burdensome as these high decline rate wells need to be
replaced frequently. Shale will remain a massive, and growing expensive
until the economy has chugged to a halt, and it is no longer needed.
I'm telling you they're lying thru their teeth about oil. We are sucking the
planet dry faster than you can say, "Dry as a popcorn fart."
The powers that
be dont want you to know this because they dont want you to slow down because
they need your tax money to hold up the sick wobbling over weight monster they
created.
It's common knowledge, at least to anyone glancing at the industry, that shale
oil has a two-year boom/bust cycle.
But that oil was not supposed to
exist. Nor any of the last half century's production.
A year ago, there were articles predicting the shale-induced peak would be
2019. (But shale gas was going to be increasing for another couple of
decades.)
You expect profit margins to fall as you squeeze the last of the juice.
Not really sure what the news is, or at least why it is so remarkable.
Calling it a Ponzi scheme, come now.
The Eagle Ford shale play here at home went bust two years ago.
It has never
recovered and does not look like it ever will. Most of my family have to drive
to Odessa for oil work. Now the greed over there is raping the workers with
exorbitant rental rates.
Those poor slobs can't get a break.
Well most working folks just can't get a break period.
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 t
More likely is a gradual increase in oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price (today's future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61 (Dec 2026). By Contrast the EIA's AEO 2018 reference oil price scenario for Brent crude has the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too low.)
"The Saudi government said it would take another month to complete a full investigation, which would be overseen by Mohammed.Watcher x Ignored says: 10/21/2018 at 2:51 amUS sanctions against Iran could give oil a boost to $100 amid dramatic shortfall in supplies
Oil surges to 4-year high as investors see no sign of production rise amid Iran sanctions
"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
