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.
Two years ago, Wall Street banks were on their way out of a long-term relationship with the
oil industry. Now, with oil prices over $70 for the first time in three years, big bond buyers
are snapping up oil bonds once again.
Only there is a condition this time.
The Wall Street Journal's Joe Wallace and Collin Eaton
wrote this week that Wall Street was buying bonds from non-investment-grade U.S. energy
companies, which took advantage of record low interest rates to raise some $34 billion in fresh
debt in the first half of the year.
That's twice as much as the industry raised over the same period last year. But investors
don't want borrowers to use the cash to drill new wells. They want them to use it to pay off
older debt and shore up balance sheets.
It makes sense, really, although it is a marked departure from how banks normally react to
oil industry crises. The 2014 oil price collapse, in hindsight, may have been the last "normal"
crisis. Oil prices fell, funding dried up, supply tightened, prices went up, banks were willing
to lend again, and producers poured the money into boosting production.
Since then, however, the energy transition push has really gathered pace and banks have more
than one reason to not be so willing to lend to the oil industry. With the world's biggest
asset managers setting up net-zero groups to effectively force their institutional clients to
reduce their carbon footprint and with the Biden administration throwing its weight behind the
push for lower emissions, banks really have little choice but to follow the current. Their own
shareholders are increasingly concerned about the environment, too.
https://www.youtube.com/embed/aQXqMVeoOPs
Yet business is business, and nowhere is this clearer than in banks' dealings with the oil
industry. Bank shareholders may be concerned about the environment, but they certainly would be
more concerned about their dividend""and part of that comes from income made from lending to
oil. And the higher oil prices go, the more willing banks will be to lend to those that produce
it.
When they were unwilling to lend to the oil industry, other lenders
stepped in . Last year, alternative investment firms scooped up hundreds of millions in oil
industry debt from banks that were cutting their exposure to the politically incorrect
industry. Hedge funds and other so-called shadow lenders don't seem to have banks' misgivings
about profiting from oil and gas.
Now banks have mellowed towards oil somewhat, but it is an interesting twist that the
current loans come with the condition of not boosting output. Again, it makes sense. For years,
the shareholders of U.S. shale oil companies have been complaining about poor returns as the
companies put everything into output growth. Now it's payback time, and shareholders want their
returns.
So do lenders, apparently.
Per the WSJ article, this year, bond buyers "want to see companies repairing their
balance sheets and delivering to creditors and shareholders rather than plowing money into new
wells."
We have owned rigs. We could never keep an operator around long enough to make it
worthwhile. We had a double drum and a single drum. Mud pump. Power swivel. Power tongs on
both. Testing truck. The whole enchilada.
We sold them all to a man who had worked for someone else and then went out on his own. We
gave him a good deal, and he did a lot of work for us. He still does work for us, but he can't
find help that will stay.
We also owned a tank truck. Sold it also. It is currently parked, the man we sold it to
cannot find a driver. He is a one horse tank truck driver. He turns down work all the time. We
had to shut down a lease we haul water on for a few days when he got COVID. Thankfully he
recovered.
All of us around here just cannot quite believe what is going on with the oilfield labor
force. It is a perfect storm.
Meanwhile, most recently we paid $5.63 per foot for 2 3/8" steel tubing, which was under $3
a year ago. We priced a 115 fiberglass tank for $6,800, would have been $3,900 a year ago.
We had a couple wells down for a few weeks because we could neither get new nor rewound
motors for them.
The man who owns the backhoes, trackhoes and cranes that does contract work for us is in his
70's and has great grandkids. He works in the field daily beside his son and grandson.
One of the last rig hands we had broke into our shop last winter. He got out of jail after a
few weeks and immediately got a job in a local factory. Hope he stays clean. He was a good hand
when he was, and had learned to operate a single drum also.
The prosecutor in our county announced the first six months of 2021 that 162 felony cases
had been filed in our small county, that in 2019 the total for the year was 204 felonies, and
that 33 of the 34 jail inmates were addicted to meth.
We do have one pumper now under 50. The rest are from 51 to 63. REPLYINGRAHAMMARK7 IGNORED07/20/2021 at 1:34
am
How much land do you have left? At one well per section how many can you drill and how long
it takes? That's when your business wraps up. REPLYRASPUTIN IGNORED07/20/2021 at 2:40
am
Holy Moly SS
I guess the days of vertical doing things in house are gone. That labor mess is unreal.
However, here in nowhere USA it is hard to find good help but you can usually find help. I was
so surprised at some of the job turnover even during peak covid when some businesses were
restricted and some essential. How are people living that have no jobs? Over the years I hired
relatives that never got it, didn't stay sober and didn't see the long term upside. Maybe it's
all about today for the younger generation.
Over the past year and a half I've been following your posts including labor issues. Were
they so dreadful before covid and helicopter money? It might appear to the uninformed that
training rig help. pumpers and the like is easy, but it's not. One small oops for man is one
huge oops for you.
Perhaps, as we move away from the false narrative that you must have a college degree to get
a good or high paying job, things will improve in the trades and the oilfield.
About 20 years ago I was visiting with a substantial independent stimulation company that
was having labor issues. The head honcho lamented that they had already poached all of the
young guys that grew up on farms and knew machinery, getting up early and how to work. Having
known a few guys and what they earned they most likely didn't point their kids at basket
weaving degrees.
Sure wish I had an answer for you. Personally, I'm shrinking down to a few wells close to
the house/shop/yard, one of which I could walk to for daily exercise. However, I'll run my
equipment myself as long as possible.
The number of basically "homeless" people living here in my part of very rural USA is
startling. People aren't generally sleeping in the parks. They have duffle bags and backpacks
and crash place to place.
We have the tremendous labor shortage, yet the public defender and conflicts public defender
have over 400 clients combined. This in a county of a little less than 20K people. That right
there is the labor force for a decent sized factory around here.
To qualify for the PD you must have income below 125% of federal poverty guidelines, which
is very low. During the height of COVID, nothing got done with their cases because the PD's
couldn't get ahold of them. Few have cell phones that are permanent (track phones) and few have
permanent addresses. The jail is full so there aren't a lot of warrants being issued for the
lower level crimes. So people haven't been showing up for their court cases for months/ over a
year. Our county is going to send close to 100 people to prison this year, almost all for meth
delivery. This is the situation all over rural USA. People who live here and aren't in the
court system are oblivious to it until they get broken into or robbed (or have an addicted
relative, which many do).
The primary reason for the labor shortage here is a combination of young people moving to
larger towns/cities, a very large percentage of the working age population being addicted to
meth (which is now being cut with heroin, fentanyl, etc) and the significant benefits that have
been paid to not work. I hate to think of how many billions of borrowed money stimulus our
future generations are now indebted with that went directly into the pockets of the foreign
drug cartels.
As for the oilfield, add to that the hard work, not the greatest pay in the world at the
bottom end (rig hands) the need to find people who can work unsupervised outdoors, and the
young people being told the industry is dead and a job in that field will soon be gone.
Finally, a ton of "old timers" simply retired during COVID.
Our country has no idea how dependent we are on labor from Mexico and Central America that
keeps us alive. The only farm workers are Hispanic. However, most don't want to work in the
oilfield either, it seems. We just harvested green beans, and all the crew were Hispanic. The
same will be the case here shortly as we harvest watermelons and cabbage. If Trump were
successful and closed the borders and sent everyone back, we would starve.
The largest oil company here shut in everything it owned when oil went negative.
Unfortunately for them they laid off a lot of people. Many of their wells are still idle.
Maybe we are an outlier. But I doubt it. A decent amount people at the lower end of the
labor force seem to have decided they aren't going to work, and offering a lot more $$ won't
bring them back. Maybe they will come back when the government benefits end.
Even the prisons can't find employees. They pay $70K+ plus great benefits. Mentally
difficult work though. Also, can't have a criminal record and cannot use drugs, even pot.
Keep in mind a large percentage of the USA population now smokes or ingests pot. That
doesn't work well in a lot of industries where sobriety is mandatory.
The gas station I fill up at is offering a $300 signing bonus which is paid after 30 days of
no unexcused absences. $13 and hour to start at the cash register. They can't find people to
take that.
I'm rambling now, and I'll stop.
Surely there are some shale basin people reading this. Could any of you comment about
whether there is a labor shortage in your shale basin? If there isn't, maybe we could persuade
a few of them to come to our neck of the woods and work on the simple, shallow wells. Not a lot
of traveling, no weekends unless you pump, and work is daytime only. KANSAS OIL IGNORED07/20/2021 at 9:10
am
Shallow Sand –
I echo all of your sentiments. We are a small operator in Kansas, producing about 300
bbl/day in 13 various counties. We have approximately 50-60 bbl/day offline pushing 3 weeks.
We're talking 8/8ths approximately $75,000 in revenue. Pre-Covid you could count on getting a
pulling unit sometimes next day if you had a mechanical failure. Now it's 3-4 weeks. $20/hour
for green rig hands evidently isn't enough to move the needle, whether it's because the work is
too difficult, or it's easier to keep cashing the government checks. And by my count we are in
a similar situation with oil field pumpers. We have 13 of them. 2 are 50s, and the rest are all
over 60. I'm in my early 40s and my field superintendent is 56. He loves to work and will
probably do so until he's 70-75. When he checks out will probably be when I check out.
REPLYSHALLOW SAND IGNORED07/20/2021 at 9:55
am
Kansas Oil.
Great to hear from you.
Thanks for confirming what we are experiencing.
The big question is whether this is also going on in the shale basins, primarily Permian. If
it is, don't see how USA production grows much.
I drive across Kansas on both I 70 and the South Route through Wichita to the OK panhandle
quite a bit. Always keep my eyes open for whether pumping units are moving or not.
I worry about whether the huge feed lots, hog facilities and packing plants out there can
find enough help. People have no clue how much of the USA is fed from the TX, OK panhandles on
up through Western KS and NE.
Two years ago, Wall Street banks were on their way out of a long-term relationship with the
oil industry. Now, with oil prices over $70 for the first time in three years, big bond buyers
are snapping up oil bonds once again.
Only there is a condition this time.
The Wall Street Journal's Joe Wallace and Collin Eaton
wrote this week that Wall Street was buying bonds from non-investment-grade U.S. energy
companies, which took advantage of record low interest rates to raise some $34 billion in fresh
debt in the first half of the year.
That's twice as much as the industry raised over the same period last year. But investors
don't want borrowers to use the cash to drill new wells. They want them to use it to pay off
older debt and shore up balance sheets.
It makes sense, really, although it is a marked departure from how banks normally react to
oil industry crises. The 2014 oil price collapse, in hindsight, may have been the last "normal"
crisis. Oil prices fell, funding dried up, supply tightened, prices went up, banks were willing
to lend again, and producers poured the money into boosting production.
Since then, however, the energy transition push has really gathered pace and banks have more
than one reason to not be so willing to lend to the oil industry. With the world's biggest
asset managers setting up net-zero groups to effectively force their institutional clients to
reduce their carbon footprint and with the Biden administration throwing its weight behind the
push for lower emissions, banks really have little choice but to follow the current. Their own
shareholders are increasingly concerned about the environment, too.
https://www.youtube.com/embed/aQXqMVeoOPs
Yet business is business, and nowhere is this clearer than in banks' dealings with the oil
industry. Bank shareholders may be concerned about the environment, but they certainly would be
more concerned about their dividend""and part of that comes from income made from lending to
oil. And the higher oil prices go, the more willing banks will be to lend to those that produce
it.
When they were unwilling to lend to the oil industry, other lenders
stepped in . Last year, alternative investment firms scooped up hundreds of millions in oil
industry debt from banks that were cutting their exposure to the politically incorrect
industry. Hedge funds and other so-called shadow lenders don't seem to have banks' misgivings
about profiting from oil and gas.
Now banks have mellowed towards oil somewhat, but it is an interesting twist that the
current loans come with the condition of not boosting output. Again, it makes sense. For years,
the shareholders of U.S. shale oil companies have been complaining about poor returns as the
companies put everything into output growth. Now it's payback time, and shareholders want their
returns.
So do lenders, apparently.
Per the WSJ article, this year, bond buyers "want to see companies repairing their
balance sheets and delivering to creditors and shareholders rather than plowing money into new
wells."
No. Not true and badly misleading. Remaining EIA PDP from the Permian will not generate sufficient net cash flow to self fund
123,000 wells (your estimate) costing nearly $1T, much less do that AND pay down over $100 B of existing debt in the Permian. That's
using EIA PDP estimates; whack those by 30%. It is not possible to drill $9MM wells for a 135% ROI over 15 years and be financially
self-sufficient, service and pay down debt, provide returns to investors and maintain a 100% RRR. The US shale oil model does not
work without credit. $70 "assumptions" do NOT solve the issue of where the money is going to come from for your miracle of abundance
to actually occur. ANCIENTARCHER IGNORED07/05/2021 at 6:01 am
EIA is expecting excess supply in 2022.
Are they smoking some really good stuff to come up with this? I'd like to smoke that too
As I see it, demand will slowly go back up to previous level of 100mmbpd and then resume its slow march upwards. Where is it that
EIA are seeing that extra production from that will lead to oversupply 6-7 months down the line? All I see is that various regions
of the world are slowly declining in production due to a combination of worsening asset quality and a paucity of capex over the last
several years, especially in 2020/21. US Shale, Russia, Offshore, conventional onshore, small members of OPEC and even Saudi"¦ all
are experiencing pressure on production.
OPEC seems to be concerned about the possibility of excess supply next year, probably due to this report by EIA. The Saudis are
especially concerned and therefore are pushing to extend the supply cut to the end of 2022 which UAE is opposing.
So, am I missing a crucial element or are the EIA on to something here?
The U.S. is producing roughly 2 million barrels a day less than it was before the pandemic.
In the USA shale patch many "sweet spots" are now gone and what remains is less proficableto drill and thus requres higher prices.
In this sense the currentoil price might be not enough to spur additional activity.
Frackers have been forced to rein in spending and
live
within their means
after many investors lost faith in the companies following years of poor returns, lenders reduced their
credit lines and capital markets showed little interest in funding expansive new drilling campaigns.
The result is that shale drillers, which in the past have played the role of the oil world's swing producer by quickly increasing
output to meet demand, are largely standing pat for now, as the reopening of Western economies leads to a resurgence of global
oil
and
gas prices
.
The companies are raking in more cash than ever. Public shale companies that drill primarily for oil collectively generated a
record $4.1 billion in free cash flow in the first quarter of 2021 and are poised to take in almost $15 billion for the year if
prices remain higher, according to consulting firm Rystad Energy.
U.S. shale producers generated more free cash
flow in the first quarter than any time
in the
industry's history, analysts said.
Free
cash flow
Source:
Rystad Energy
billion
2014
'15
'16
'17
'18
'19
'20
'21
-12.5
-10.0
-7.5
-5.0
-2.5
0
.0
2.5
$5.0
But instead of pumping that money back into drilling as they have historically done, large producers such as
Occidental
Petroleum
Corp.
OXY
+2.09%
and
Ovintiv
Inc.,
the
company formerly known as Encana Corp., have said they plan to
focus
on reducing debt
, keeping U.S. output flat. Other sizable shale drillers such as
Pioneer
Natural Resources
Co.
PXD
+0.66%
and
Devon
Energy
Corp.
DVN
+3.40%
are
socking away money to return to investors in the form of variable dividends, one of the enticements they want to use to lure more
investors back.
"We're producing all this free cash flow, but it's not going out to investors yet," said Scott Sheffield, chief executive of
Pioneer, noting that many companies are focusing on debt before they return cash to investors. "There's no reason for them to buy
into this sector at this point in time."
... ... ...
In the heyday of the shale boom, publicly traded oil producers typically reinvested more than 100% of the cash flow they made
from operations back into drilling campaigns. Now they are using about half of the income they generate on new drilling and are
only growing output slightly, if at all.
... ... ...
Shale companies had about $148.6 billion in debt coming into the year, according to energy consulting firm Wood Mackenzie, and
much of the cash they are collecting is going toward that debt pile. Securing new capital is increasingly difficult for many.
Many large U.S. banks have cut their energy lending, and some European ones such as
Deutsche
Bank
AG
and
Société
Générale
SA
SCGLY
5.48%
have
exited fossil fuel financing altogether...
Callon said it would cut its 2021 capital expenditures to $430 million, a 12% reduction from its 2020 budget. In 2019, it spent
$515 million. As a result, the company said it would produce about 90,000 barrels of oil and gas a day in 2021, down from more
than 101,000 barrels a day in 2020. Callon said it is focused on reducing its roughly $3 billion in debt. The company declined to
comment.
Many frackers made bad bets early this year, hedging their production with oil in the forties and low fifties -
especially Pioneer and Devon. This article, for some reason, fails to mention that fact and it's impact on their
current production.
PAUL HUNT
After 38years in O&G E&P I filtered out of the industry due to changing industry. The loss of expertise and technology
in the energy industry over the last 5 years has been huge. USA has given the energy industry to China. Look for
overall energy prices to triple in less than 10 years.
DAVID LAWRENCE
What is left out in this article are the returns of the 600lb gorilla of frackers in the room.
XOM alone generated almost $7 billion in free cash flow last quarter. With oil prices where they are that figure is
likely to rise to $10 billion next quarter. The company has only $53 billion in debt outstanding having already pared
down $6 billion during the pandemic.
They are going to gobble up even more weaker little guys shortly.
Peter Sullivan
I don't see XOM significantly increasing production in US shale anytime soon. They are focusing CAPEX on deepwater
assets that present a better ROI than shale. Who would of thought we have reached a time where it is less risky for a
US based company to drill in a small South American country than within our own borders?
DAVID LAWRENCE
XOM CAPEX is greatly reduced (1/2) in 2021 across the board. This is because they spent nearly $20 billion in 2020 using
piles of borrowed money that so many junior analysts obsessed over.. The plan is to pay that pile down with the
windfall those investments are generating.
XOM is far from a pure play fracker and have always developed the largest offshore assets of any company and Guyana is a
hot prospect!
Edward Cotterell
The oil market has always been boom and bust. When the pandemic hit people stopped driving and the oil market went
bust. Prices fell and drillers went bankrupt. Now the economy is reviving, people are driving again and oil is
booming. To those who think otherwise, get a grip. The price of gasoline today is about where it was in 2018 and 2019
pre-pandemic. You know, when Trump was president.
This article points out a longer term change in the market. The hype over fracking is over. The lenders want their
principal back plus interest and they are not taking exaggerations from drillers any more. So oil prices may have to go
a bit higher until the lenders are satisfied that they will get their money. Then they will lend to drillers and
fracking will crank up.
Trash that 12 mpg pickup. Get a vehicle that gets better mileage. Some hybrids get over 50 miles a gallon. Electrics
get the energy equivalent of 100 miles a gallon.
Ben Griffith
How is the electricity produced ? Coal, oil, natural gas produced by fracking, nuclear, hydroelectric dam, harnessing
the hot air of Climate Change speech ?
ROBERT STUPP
Many don't realize how many older, experienced energy professionals took retirement over the last few years. Similar to
the 1980's energy bloodbath, it will take a while to establish teams able to stabilize the companies, let alone grow
them from survival mode. You can't turn on production like your kitchen faucet.
Jerome Abernathy
Fracking wells deplete so fast that the capex expenditures needed to maintain and grow production result in a low ROI
for the industry. Worse yet, given the volatility of oil prices and the precarious state of their balance sheets,
frackers are unattractive borrowers. The industry needs a new, creative financing model.
Matthew Oatway
An interesting article, but the authors should have acknowledged (a) the impact of consolidation in the sector on
production discipline and (b) the fact that many shale producers have a large portion of their production hedged at
lower crude prices. Both factors point to a more restrained return to production growth that we have seen in the past.
Banks have started to cut their exposure to the U.S. shale patch, seeing more than 100
producers and oilfield services firms go bust last year and feeling the environmental, social,
and governance (ESG) pressure to reduce credits to fossil fuels. While traditional lenders are
cutting their losses and de-risking energy loan portfolios, alternative capital providers are
stepping up to scoop up U.S. energy debt at a discount and take part in debt or equity
transactions that could give them returns sooner than a loan would for a bank.
Since the oil price crash in 2020 and the downturn in the U.S. shale industry, banks have
been wary of their exposure to the sector. The commodity price slump last year dramatically cut
the value of the assets of oil and gas firms, against which they have traditionally obtained
loans from banks.
Running for the Exit
Lenders slashed the amounts of reserve-based loans to the U.S. shale firms in the middle
of last year.
But it is not only purely financial considerations that are driving reduced bank exposure
to the oil and gas industry. ESG lending and aligning loan portfolios to the Paris Agreement
goals are now more prominent than ever.
For example, asset manager Schroders, which holds many bonds in the banking sector, is
engaging with banks to understand their fossil fuel exposure.
"Banks that are highly exposed to the fossil fuel industry face significant financial,
regulatory and reputational risks as a result of the transition to a low-carbon economy,"
Schroders said, explaining its rationale to identify the exposure of the banks to oil, gas, and
coal.
Increased pressure from the ESG universe, coupled with years of poor returns of U.S.
shale firms, have prompted several major transactions in which banks have sold energy debt to
hedge funds and private equity firms.
Hancock Whitney, for example, agreed last year to sell $497 million worth of energy loans
to certain funds and accounts managed by alternative investment provider Oaktree Capital
Management. Hancock Whitney expected to receive $257.5 million from the sale of the
reserve-based loans (RBL), midstream, and non-drilling service credits.
Hancock Whitney's main reason to sell the energy loans was to minimize the risks to its
loan portfolio.
"The primary objective of this sale is to continue de-risking our loan portfolio by
accelerating the disposition of assets that have been impacted by ongoing issues within the
energy industry, and have now been further complicated by COVID-19," Hancock Whitney's
President and CEO John M. Hairston said.
At the end of 2020, Bank of Montreal decided it would wind down its non-Canadian
investment and corporate banking energy business.
Most recently, ABN AMRO announced last week it would sell a $1.5 billion portfolio of
energy loans to funds managed by Oaktree Capital Management and affiliates of Sixth Street
Partners. The portfolio consists of loans to around 75 companies active in the North American
energy markets.
With this sale, ABN AMRO is withdrawing from oil and gas related lending in North America
as part of a process to wind down its non-core activities and significantly reducing the
non-core loan book.
"On a daily basis, loadings will decline by 22% in July compared to the current month,
Reuters calculations showed."
REPLYPOLLUX IGNORED06/28/2021
at 1:37 pm
"Russian oil production has declined so far in June from average levels in May despite a
price rally in oil market and OPEC+ output cuts easing, two sources familiar with the data told
Reuters on Monday.
Russia's compliance with the OPEC+ oil output deal was at close to 100% in May, which
means the state is about to exceed its target in June.
Two industry sources said that lower output levels may be due to technical issues some
Russian oil producers are experiencing with output at older oilfields."RON PATTERSON IGNORED
06/28/2021 at 2:38 pm
Yes, they are definitely experiencing issues with their older oilfields, it's called
depletion. But that decline is only 33,000 bpd or .3%. But your post above that one says
exports in the third quarter will decline by 22%. What gives there?
I just checked the Russia site and they have revised up their original May estimate. It is
one week later than the original. Production is now down 9,000 b/d. RON PATTERSON IGNORED06/28/2021
at 4:50 pm
Yeah, they revised it up by 14,000 pbd. A pittance. Now they are down only 9,000 bpd instead
of 23,000. Nothing to get excited about. Basically, they were flat in May.
JEAN-FRANÇOIS FLEURY IGNORED06/28/2021
at 4:09 pm
"Russia plans to decrease oil loadings from its Western ports to 6.22 million tonnes for
July compared to 7.75 million tonnes planned for loading in June, the preliminary schedule
showed." 7,75 x 10^6 – 6,62 x 10^6 = 1130000 t. 1130000×7,3/30 = 274966 b/d.
Therefore, these decrease of oil export suggests a decrease of production of 274966 b/d.
Precedently, it was announced that oil exports of Russia would decrease of 7,2 % for the period
July-September or a decrease of 308222 b/d. Therefore, it's coherent.
https://www.zawya.com/mena/en/markets/story/Russias_quarterly_crude_oil_exports_to_drop_72_schedule-TR20210617nL5N2NY2IQX8/?fbclid=IwAR0ZjvwzjVS427CbUAzTL1vJfqog7R8CDwaJAvI3uUdaw_0z5S5l_57SGFY
I notice that it concerns the "Western ports", therefore the exports toward EU and USA. Well,
EU is also the main customer of Russia with 59% of the oil exports of Russia. RON PATTERSON IGNORED
06/28/2021 at 4:59 pm
Western Syberia is where all the very old supergiant fields are. They produce 60% of Russian
crude oil. Or at least they used to. LIGHTSOUT IGNORED06/29/2021
at 2:11 am
Ron
If one of the West Siberian giants is rolling over in the same way as Daquing did, things could
get very interesting very quickly. RON
PATTERSON IGNORED06/29/2021
at 7:24 am
Four of Russia's five giant fields are in Western Siberia. The fifth is in the Urals, on the
European side. All five have been creamed with infill horizontal drilling for almost 20 years.
All five are on the verge of a steep decline. Obviously, one and possibly more have already hit
that point.
This linked article below is 18 months old but there is a chart here that shows where
Russia's oil is coming from. Notice only a tiny part is coming from Eastern Siberia, the hope
for Russia's oil future. Those hopes are fading fast.
As I have written a few months ago: When you reduce output voluntarily for a longer time,
all the nickel nursers from accounting and controlling will cut you any investing in over
capacity you can't use at the moment. That works like this in any industry.
So you have to drill these additional infills and extensions after the cut is liftet. And
this will take time, while fighting against the ever lasting decline.
"Abu Dhabi's state-owned Adnoc has informed customers that it will implement cuts of
around 15pc to client nominations of all its crude exports loading in September, even as the
Opec+ coalition considers further relaxing production quotas.
It was unclear why Adnoc is deepening reductions for its September-loading term crude
exports, with the decision coming ahead of the next meeting of Opec+ ministers scheduled for 1
July when the group is expected to decide on its production strategy for at least one
month"
As oil price stays above $70/barrel, most shale will come back. However the max reached by
USA was 13,100 million b/d. So whether World will hit 75 million b/d is doubtful. But NGL keeps
increasing because of increase in natgas output. Besides nearly 6 million b/d that comes from
CTL, GTL and bio-fuels will keep overall oil consumption above 100 million b/d.
Despite rapid increase in electric vehicles, oil will hold above 100 minion b/d mark.
REPLYHOLE IN HEAD IGNORED06/20/2021
at 1:34 pm
Ted , demand is governed by price and availability . Demand of 100 mbpd is immaterial if the
supply is only 80mbpd . Shale is not coming back . USA has peaked . Period . The peak in shale
was (is) the peak of oil production in USA . I have commented earlier that " all liquids " is
BS . The 6mbpd of NGPL ,CTL , GTL etc. are just " fill in the blanks " . These are not
transportation fuels and have 65% of the BTU of crude . HICKORY IGNORED 06/20/2021
at 2:30 pm
Hole- Hydrocarbon Gas Liquids are nothing to belittle. It is a lot of energy-
"HGLs accounted for over a quarter of total U.S. petroleum products output in 2018"
NGL has about 70% of the energy content of a barrel of crude. In addition most uses for HGLs
are not for transportation which is the the main use for crude plus condensate.
As Ron has said we don't count bottled gas. I would say NGL should be put in a basket with
natural gas.
Or we could define liquid petroleum as that which is a liquid at 1 atmosphere pressure and
25C aka STP.
By that standard only pentanes plus would qualify, which makes sense as it is essentially
condensate, the proportion of pentanes plus in the US NGL mix is less than 12% by volume, 2020
data (582
kbpd). RON PATTERSON IGNORED06/21/2021
at 4:01 pm
I am expecting prices a lot higher in 2022. An average of $85 would not shock me at all.
They will be higher because oil production will not fully recover to the 2019 level as everyone
expects it to.
The EIA Short Term Outlook has production fully recovered by the end of 2022 and total
liquids about one million barrels per day higher for non-OPEC.
OPEC officials heard from industry experts that US oil output growth will likely remain
limited in 2021 despite rising prices,
While there was general agreement on limited US supply growth this year, an industry source
said for 2022 forecasts ranged from growth of 500,000 bpd to 1.3 million bpd
The forecasts for 2021 were for average output to be close to 200 kb/d. The 1.3 Mb/d
prediction for 2022 is out to lunch. The 500 kb/d has a chance but I think the average will be
closer to 350 kb/d.
I think WTI will be $85 plus/minus $5 in mid 2022. This will push the average price of
gasoline slightly above $3/gal. As for output, the US will add somewhere close to 300 kb/d
average in 2022 over 2021. I am betting on some restraint on the part of the drillers. The
Permian is the pivotal basin and I see that the early results for 2021 wells are not as good as
2020.
The big unknown for me is: What is a sustainable price for WTI, $100? At what point does
gasoline suck too much money out of the economy. Once the economy starts to slow, oil demand
will slow. We can all remember 2008.
If WTI crosses $90, OPEC might start to worry. However will they have the spare capacity to
try to control it? Six months from now we can revise our estimates.
What do you mean by confirmation? Do you mean they will confirm that the peak was 2018-2019?
If so, I cannot agree. No, there will be deniers all the way down. There is something about the
human psyche that just cannot accept reality... MATT MUSHALIK IGNORED06/19/2021
at 8:57 pm
Thanks for continuing to monitor crude oil production. As of now, we are back to 2005
levels!
Frac Sand Baroness @sand_frac · Jun 16 There is
currently a @chevron well
uncontrollably blowing out on my land that I live and raise cattle on in West Texas. It is
injecting super concentrated brine and benzene into my water supply. The casing (metal pipe) is
so corroded that Chevron literally cannot re plug it. 5.7K views 0:01 / 0:06 3 60 117
Frac Sand Baroness @sand_frac
· Jun 16 More concerningly, this
well was plugged and abandoned (P&A) in 1995. For those not in the oil industry, a P&A
blowout is extremely rare. A plugged well is exactly that: plugged. It is filled with concrete
plugs, and considered to be permanently deactivated and safe. 2 7 67 Frac Sand Baroness @sand_frac · Jun 16 We've had
issues with Chevron before. In 2002, we flushed a toilet at the ranch house (approximately 1.5
miles south of the blowout) and crude oil bubbled up. The leak source was never fully
identified, and we shut in that water well. 2 6 66 Frac Sand Baroness @sand_frac · Jun 16 Chevron had
operations nearby, so drilled water monitoring wells. These monitoring wells identified a crude
oil plume in the groundwater, and also found a large salt water plume. See Texas Railroad
Commission OCP #08-2423. Again, we never found the source. 1 5 57 Frac Sand Baroness @sand_frac · Jun 16 This
required Chevron to provide an annual water test result to the landowners (me). Of course, they
didn't comply from 2007 through 2013. We never heard about this, and thought our water was safe
again.
One of the biggest pieces of news for Royal Dutch Shell recently has been the Dutch court
ruling that forces them to make a larger 45% emissions reduction by 2030.
Despite this sounding very transformation, considering the geological and economic
reality of their current situation, it actually does not significantly change their underlying
future.
Their reserve life is only sitting at just above seven years and thus even if they wished
to maintain their fossil fuel production, they already required significant investments before
2030.
SNIP You Cannot Fight Geology
Upon reviewing their reserves, it may initially sound very impressive to hear that their
oil and gas reserves currently stand at slightly over nine billion barrels of oil equivalent.
Although in reality this actually sits rather low when compared to their annual production
during 2020 of 1.239b barrels of oil equivalent. This effectively only leaves their reserve
life at just above seven years, which is not particularly long and thus means that their fossil
fuel production would already begin shrinking dramatically by the latter half of this decade.
Admittedly they would likely continue replacing a portion of their oil and gas reserves in the
future but their current production rate would still see them running very low by 2030 if
approximately half were replaced per annum, as the graph included below displays.
There are two charts in this article. The second on titled: Oil Discoveries Lowest Since
1847 is alarming. STEPHEN HREN IGNORED06/17/2021 at 8:25 am
Hi Ron, any thoughts on why Shell would bag their operations in the Permian while they are
also running low on reserves everywhere else? Seems like they would be holding on to every
scrap of producing land they could. Unless one of two things: 1) they are making a serious
attempt to transition to a low carbon energy company; and/or 2) their holdings in the Permian
are worth squat REPLYRON PATTERSON IGNORED06/17/2021 at
9:22 am
NEW YORK/HOUSTON, June 15 (Reuters) – A cadre of oil companies, seeing continued
profits in shale, are mulling Royal Dutch Shell's (RDSa.L) holdings in the largest U.S. oil
field as the European giant considers an exit from the Permian Basin, according to market
experts.
The potential sale of Shell's Permian holdings, located in Texas, would be a litmus test
of whether rivals are willing to bet on shale's profitability through the energy transition to
reduce carbon emissions.
Shell would follow in the footsteps of other producers, including Equinor (EQNR.OL)
and Occidental Petroleum (OXY.N) that have shed shale assets this year, looking to cut debt and
reduce carbon output in the face of investor pressure.
Shell, like a lot of other companies, sees shale assets as a very low profit, or even a
losing proposition. They can take the money from the sale, reduce their debt, and reduce carbon
emissions of their company in one fell swoop. More from the article:
Against this backdrop, estimates for Shell's acreage run from $7 billion to over $10
billion, the latter implying a valuation of almost $40,000 an acre.
That would be in line with the per-acre price Pioneer Natural Resources (PXD.N) paid for
DoublePoint Energy in April, the most costly deal since a 2014-2016 rush by producers to grab
positions in the Permian.
Most Permian deals this year have closed between $7,000 and $12,000 per acre, said
Andrew Dittmar, senior mergers and acquisitions analyst at data provider Enverus.
If they can get $40,000 per acre they have found a greater fool to offload their acreage on.
HICKORY IGNORED06/17/2021 at 9:44 am
Something about that doesn't make sense. The need or desire to downsize is likely due to an
inability to project making profit on the shale assets rather than any concern over a carbon
footprint- I don't believe they are in business to win any kind of beauty contest. REPLYROGER
IGNORED06/17/2021 at 8:17 pm
"Shell's position as a major European enterprise has become untenable. The Spar had gained a
symbolic significance out of all proportion to its environmental effect. In consequence, Shell
companies were faced with increasingly intense public criticism, mostly in Continental northern
Europe. Many politicians and ministers were openly hostile and several called for consumer
boycotts. There was violence against Shell service stations, accompanied by threats to Shell
staff."
Things are a little different for European companies I recall "Greenpeace sympathizers"
fire-bombed a gas station back then; in light of what has transpired in the US recently who is
to say it couldn't happen again?
Shell is well aware of peak oil, and can't solve the problem. So, what would you have them
do? REPLYKOLBEINIH IGNORED06/17/2021 at 1:26 pm
"Shell would follow in the footsteps of other producers, including Equinor (EQNR.OL) and
Occidental Petroleum (OXY.N) that have shed shale assets this year, looking to cut debt and
reduce carbon output in the face of investor pressure."
I don't think it has anything to do with shale oil specifically. For Equinor it has to do
with that it can draw on competence in Norway in the harsh offshore environment in the North
Sea. Floating offshore wind power is where Equinor is world leading with technology and know
how; now about to be utilised in the North Sea, Japan, US East coast and California. It is not
more economical than ground based offshore wind mills, but has some advantages when it comes to
lifecycle costs. For one, the wind mills can be placed in optimal wind condition areas not in
the way of fishing resources. The big size of wind mills will not cause problems (the height
and diameter of the blades are necessary to capture enough wind energy). And also the wind
mills can be more easily moved to land and recycled, e.g. the steel. Wear and tear offshore is
on the minus side.
Usually the blades are made of carbon fiber to make it lighter, but it can also be made of
aluminum in the future with lower efficiency.
Shell is just now investing in North Sea South II in Norway for ground based offshore mill
farms together with BP. To make the North Sea work with the enormous amount of wind power
coming online and connection cables everywhere is very serious business and just a priority.
Shale oil is too much of a distraction for Shell and Equinor, not even within their core
competence area. REPLYJAY
WOODS IGNORED06/18/2021 at 7:50 am
Shell was ordered by a Dutch court to cut by 45%. Of course, they will cut their "losers"
first.
The chart is old and was published in 2016 by Wood Mackenzie and there is no data for 2016.
It also leaves out the discovery of Ghawar in 1948, first bar/spike. I have not seen any
updates since then. Not sure if Guyana had been discovered in 2016. The original is
attached.
Ironically, the wave of ESG investing in global energy markets may lead to much higher
oil prices as a serious lack of capital expenditure on new fossil fuels dries up just as demand
for crude continues to grow
Pressure from investors, tighter emissions regulation from governments, and public
protests against their business have become more or less the new normal for oil companies. What
the world -- or at least the most affluent parts of it -- seem to want from the oil industry is
to stop being the oil industry.
Many investors are buying into this pressure. ESG investing is all the rage, and
sustainable ETFs are popping up like mushrooms after a rain. But some investors are taking a
different approach. They are betting on oil. Because what many in the pressure camp seem to
underestimate is the fact that the supply of oil is not the only element of the oil
equation.
"Imagine Shell decided to stop selling petrol and diesel today," the supermajor's CEO Ben
van Beurden wrote in a LinkedIn post earlier this month. "This would certainly cut Shell's
carbon emissions. But it would not help the world one bit. Demand for fuel would not change.
People would fill up their cars and delivery trucks at other service stations."
Van Beurden was commenting on a Dutch court's ruling that environmentalists hailed as a
landmark decision, ordering Shell to reduce its emissions footprint by 45 percent from 2019
levels by 2030.
Total DUCs in shale basins are falling at the rate of about 250 per month. I don't know how long this can continue. I have been
told by some experts in the field that there are some DUCs that will never be completed because they would not produce enough oil
to pay the completion cost. So we just cannot count the DUCs and divide by 250. The decline in DUCs will have to stop sooner or
later.
Frugal, I am not an oilman, and an oilman could obviously give a better answer than I. But I will give it a shot, and hopefully,
I will be corrected for any mistakes I make.
Drillers are not frackers and frackers are not drillers. That is an entirely different operation requiring different crews, different
equipment, and different CAPEX. But the driller leaves behind samples from the well, indicating just how productive the well should
be. The best wells will obviously be fracked first. The less promising wells will be left for times when the price is high enough
to justify the fracking cost.
But"¦. the total cost of the well is the drilling cost plus the fracking cost. And in a DUC, the drilling cost has already been
spent. So when times get hard, and you can get a well, though it might not be the best well, you have already paid the drilling
cost, so you can get it for only the fracking cost now. So you pay the fracking cost and recover what you can. And this would
be the case especially if the new wells that are coming in are less promising than the poor wells already drilled.
But then, that's just my opinion, for what it's worth.
Exxon Mobil Corporation XOM has been generating fewer barrels of oil from the prolific
shale fields of the United States since 2019, per Reuters.
According to a latest report, the company's oil wells, which are involved in some of the
most promising shale fields, produced fewer barrels of oil per well despite an increase in
overall expenditure and production.
In 2017, Exxon, which is one of the largest shale oil producers, acquired $6.6 billion of
net acres in New Mexico, which doubled the company's assets in the Permian basin that spans
west Texas and New Mexico. Notably, the company intends to boost shale output in the New Mexico
portion of the Permian basin to 700,000 barrels per day (bpd) by 2025.
Per data released by the Institute for Energy Economics and Financial Analysis ("IEEFA"),
Exxon's average liquid output for the first 12 months of a well dropped to 521 bpd in 2019
from an average of 635 bpd in 2018 in its Delaware basin assets of New Mexico.
That's an 18% drop in production per well. And this was before the pandemic
Another scenario is that some exporting nations realize they will need this oil as the world
stares into a scarcity of oil. They might say: "Shit, why are we selling this stuff when we
will desperately need it for ourselves in a few years?" And as they cut back, or stop exporting
altogether, the problem gets a lot worse, and prices spike even higher. REPLYDOUG LEIGHTON IGNORED06/13/2021 at 3:34 pm
L.O.L. The decision concerning the proportion of a domestic resource that should be
preserved for domestic needs, and how much to export, is interesting. China's REE deposits come
to mind. Also, the impact of the immediate use of a resource versus a lower level of
exploitation over time might come into play in some (perhaps unrealistic) scenarios as well.
Not many examples of countries that have exhaustible natural resources saving some for future
generations I'm aware of; probably would result in an unwelcome war or another ugly result!
John Kilduff of Again Capital has predicted Brent to hit $80 a barrel and WTI to trade
between $75 and $80 in the summer, thanks to robust gasoline demand. Brent is currently trading
at $71.63 per barrel, while WTI is changing hands at $69.13.
On 05/07/21 the US 10year chart formed a hammer candlestick on daily chart within a consolidation pattern. Which suggested higher
yields coming. Well little over a month later price broke below the bottom of that candlestick which suggest that the bond market
doesn't believe the inflation we have seen is here to stay. Yield headed lower.
The inflation we have had seems to be supply side due to covid. If inflation is at peak which bond market is suggesting. Oil price
might not have much more room to run higher. And I'd take it a step further and say price inflation due to a weaker dollar is starting
to real hurt places like China and they are going to act by tightening monetary policy. You think this would be positive for the
yuan and push the dollar even lower. But when you tightening monetary policy credit contracts and economic activity contracts.
I do expect oil price to rollover and head back to $50-$55 might happen from a slightly higher price from here because of lag
time between when bond market signals rollover in inflation back into deflation and when prices start reacting to this.
REPLYEULENSPIEGEL IGNORED06/11/2021
at 10:07 am
This isn't your history bond market.
Inflation doesn't really matters, what only matters is the one big question: "How much bonds does the one market member with unlimited
funds buy?".
And the time the FED was able to rise more than .25% is in the rear mirror "" when they hike now, inflation or not, all these
zombie companies and zombie banks will fail and no lawyer in the world will be able to clean up the chaos after all these insolvency
filings.
They have to talk the way out of this inflation. They have to talk until it stops, or longer. They can't hike. They can perhaps
hike again when most of the debt is inflated away "" a period with 10+% inflation and 1% bond interrest.
And yes, they can buy litterally any bond dumped onto the market "" shown this in March last year when they stopped the corona
crash in an action of one week.
I think most non-investment-banks are zombies at the moment, and more than 20% of all companies. They all will fail in less than
1 year when we would have realistic interrest rates. On the dirty end, this would mean 10%+ for all this junk out there "" even mighty
EXXON will be downgraded to B fast.
In old times the FED rates would be more than 5% now with these inflation numbers. Nobody can pay this these days.
And now in the USA "" look for how much social justice and social security laws you'll get. The FED has to provide cover for all
of them.
We in Europe will do this, too. New green deal, new CO2 taxes, better social security "" the ECB already has said they will swallow
everything dumped on the market.
So, oil 100$ the next years "" but some kind of strange dollars buying less then they used to.
This is nonsense. They have Brent crude oil prices peaking, so far, in March 2025 at $164.11. And they have WTI peaking the same
month at $132.55, $32.56 lower. There is no way the spread could be that large. Also, they have natural gas prices dropping over
the same period. Just who the hell are these "Longforcast.com" people?
Disregard anything with "forecast" in the title. They don't have a time machine, and extrapolation is a horrible metric with dynamic
markets as complex as the energy ones.
Might as well show me the tea leaves or goat entrails and tell me the price on 11 June 2027.
REPLYSHALLOW SAND IGNORED06/11/2021
at 3:58 pm
Dennis Gartman is still considered a commodities expert.
He infamously said in 2016 that WTI would never be above $44 again in his lifetime. He is still alive last I knew.
Since I have owned working interests in oil wells (1997) I have sold oil for a low of $8 and a high of $140 per barrel. 6/14 oil
sold for $99.25 per barrel. 4/20 oil sold for $15.40 per barrel.
Predicting oil prices is impossible.
About the only oil price prediction I have had right so far is that if Biden won, oil prices would rebound. Of course, we can
argue about why that is, and if there is even any connection.
There are still no drilling rigs running in the field we operate in. There are still hundreds of production wells shut in. There
are still less than 10 workover rigs running in our field. The largest operator still has a help wanted sign up in front of its office.
We finally found one summer worker, he is still in high school, but thankfully covered by our workers comp. He cannot drive our trucks,
and is limited to painting, mowing, weed control, digging with a shovel, cleaning the shops and pump houses and other tasks like
those. That's ok, because we need that, but not being able to drive is a pain. But auto ins won't allow anyone under 21 to be covered.
REPLYIRON MIKE IGNORED06/11/2021
at 11:53 am
Yea Ron i agree with Kleiber, I wouldn't take anything on that site too seriously.
REPLYOVI IGNORED06/11/2021
at 1:34 pm
The IEA is now starting to sound warnings about supply. Last week they were telling the oil companies to stop exploring and to
move toward a renewable energy future.
IEA: OPEC needs to increase supply to keep global oil markets adequately supplied
In its monthly oil report, the International Energy Agency (IEA) has said that global oil demand is set to return to pre-pandemic
levels by the end of 2022, rising by 5.4 million bpd in 2021 and by a further 3.1 million bpd next year. The OECD accounts for 1.3
million bpd of 2022 growth while non-OECD countries contribute 1.8 million bpd. Jet and kerosene demand will see the largest increase
( 1.5 million bpd year-on-year), followed by gasoline ( 660 000 bpd year-on-year) and gasoil/diesel ( 520 000 bpd year-on-year).
World oil supply is expected to grow at a faster rate in 2022, with the US driving gains of 1.6 million bpd from producers outside
the OPEC alliance. That leaves room for OPEC to boost crude oil production by 1.4 million bpd above its July 2021-March 2022 target
to meet demand growth. In 2021, oil output from non-OPEC is set to rise 710 000 bpd, while total oil supply from OPEC could increase
by 800 000 bpd if the bloc sticks with its existing policy.
(IEA) has said that global oil demand is set to return to pre-pandemic levels by the end of 2022, rising by 5.4 million bpd
in 2021 and by a further 3.1 million bpd next year.
That comes to about 500,000 barrels per day monthly increase, every month until the end of 2022. I really don't believe that is
going to happen. No doubt most nations can increase production somewhat, but returning to pre-pandemic levels will be a herculean
task for most of them.
WTI Punched a $70 ticket sometime after 6:00 PM EST, June 6, 2021. The last time this
happened was Oct 16, 2018, $71.92 before falling below $70 the next day.
"Igor Sechin, the head of Russian oil major Rosneft (ROSN.MM), said on Saturday the world
was facing an acute oil shortage in the long-term due to underinvestment amid a drive for
alternative energy, while demand for oil continued to rise."
Exxon Mobil Corp. is
pulling out of a deep-water oil prospect in Ghana just two years after the west African nation
ratified an
exploration and production agreement with the U.S. oil titan.
The company relinquished the entirety of its stake in the Deepwater Cape Three Points block
and resigned as its operator after fulfilling its contractual obligations during the initial
exploration period, according to a letter to Ghana's government seen by Bloomberg and people
familiar with the matter, who asked not to be named because the information isn't
public.
Energy giant BP Plc
sees a strong recovery in global crude demand and expects it to last for some time, with U.S.
shale production being kept in check, according to Chief Executive Officer Bernard Looney.
"There is a lot of evidence that suggests that demand will be strong, and the
shale seems to be remaining disciplined," Looney told Bloomberg News in St. Petersburg,
Russia. "I think that the situation we're in at the moment could last like this for a
while."
Defeats in the courtroom and boardroom mean Royal Dutch Shell (RDSa.L) , ExxonMobil (XOM.N) and Chevron (CVX.N) are all under pressure to cut carbon
emissions faster. That's good news for the likes of Saudi Arabia's national oil company Saudi
Aramco (2222.SE) , Abu
Dhabi National Oil Co, and Russia's Gazprom (GAZP.MM) and Rosneft (ROSN.MM) .
It means more business for them and the Saudi-led Organization of the Petroleum Exporting
Countries (OPEC).
"Oil and gas demand is far from peaking and supplies will be needed, but
international oil companies will not be allowed to invest in this environment, meaning
national oil companies have to step in," said Amrita Sen from consultancy Energy Aspects.
... ... ...
Climate activists scored a major victory with a Dutch court ruling requiring Shell to drastically cut emissions, which in
effect means cutting oil and gas output. The company will appeal.
The same day, the top two U.S. oil companies, Exxon Mobil and Chevron, both lost battles with shareholders who accused them
of dragging their feet on climate change.
...Western oil majors control around 15% of global output, while OPEC and Russia have a share of around 40 percent. That
share has been relatively stable in recent decades as rising demand was met with new producers like smaller private U.S. shale
firms, which face similar climate-related pressures.
...Despite pressure from activists, investors and banks to cut emissions, Western oil majors are also tasked with maintaining
high dividends amid heavy debts. Dividends from oil companies represent significant contributions to pension funds.
"This time is different" may be the most dangerous words in business: billions of dollars
have been lost betting that history won't repeat itself. And yet now, in the oil world, it
looks like this time really will be.
For the first time in decades, oil companies aren't rushing to increase production to
chase rising oil prices as Brent crude approaches $70. Even in the Permian, the prolific shale
basin at the center of the U.S. energy boom, drillers are resisting their traditional
boom-and-bust cycle of spending.
The oil industry is on the ropes, constrained by Wall Street investors demanding that
companies spend less on drilling and instead return more money to shareholders, and climate
change activists pushing against fossil fuels. Exxon Mobil Corp. is paradigmatic of the
trend, after its humiliating defeat at the hands of a tiny activist elbowing itself onto the
board.
And what they don't realize is that the two largest producers in OPEC+, Russia and Saudi
Arabia, are on the ropes also. Russia has admitted it but Saudi is still trying to deny the
fact.
"This time is different" may be the most dangerous words in business: billions of dollars
have been lost betting that history won't repeat itself. And yet now, in the oil world, it
looks like this time really will be.
For the first time in decades, oil companies aren't rushing to increase production to chase
rising oil prices as Brent crude approaches $70. Even in the Permian, the prolific shale basin
at the center of the U.S. energy boom, drillers are resisting their traditional boom-and-bust
cycle of spending.
The oil industry is on the ropes, constrained by Wall Street investors demanding that
companies spend less on drilling and instead return more money to shareholders, and climate
change activists pushing against fossil fuels. Exxon Mobil Corp. is paradigmatic of the trend,
after its humiliating defeat at the hands of a tiny activist elbowing itself onto the
board.
The dramatic events in the industry last week only add to what is emerging as an opportunity
for the producers of OPEC+, giving the coalition led by Saudi Arabia and Russia more room for
maneuver to bring back their own production. As non-OPEC output fails to rebound as fast as
many expected -- or feared based on past experience -- the cartel is likely to continue adding
more supply when it meets on June 1.
'Criminalization'
Shareholders are asking Exxon to drill less and focus on returning money to investors. "They
have been throwing money down the drill hole like crazy," Christopher Ailman, chief investment
officer for CalSTRS. "We really saw that company just heading down the hole, not surviving into
the future, unless they change and adapt. And now they have to."
Exxon is unlikely to be alone. Royal Dutch Shell Plc lost a landmark legal battle last week
when a Dutch court told it to cut emissions significantly by 2030 -- something that would
require less oil production. Many in the industry fear a wave of lawsuits elsewhere, with
western oil majors more immediate targets than the state-owned oil companies that make up much
of OPEC production.
"We see a shift from stigmatization toward criminalization of investing in higher oil
production," said Bob McNally, president of consultant Rapidan Energy Group and a former White
House official.
While it's true that non-OPEC+ output is creeping back from the crash of 2020 -- and the
ultra-depressed levels of April and May last year -- it's far from a full recovery. Overall,
non-OPEC+ output will grow this year by 620,000 barrels a day, less than half the 1.3 million
barrels a day it fell in 2020. The supply growth forecast through the rest of this year
"comes nowhere close to matching" the expected increase in demand, according to the
International Energy Agency.
Beyond 2021, oil output is likely to rise in a handful of nations, including the U.S.,
Brazil, Canada and new oil-producer Guyana. But production will decline elsewhere, from the
U.K. to Colombia, Malaysia and Argentina.
As non-OPEC+ production increases less than global oil demand, the cartel will be in control
of the market, executives and traders said. It's a major break with the past, when oil
companies responded to higher prices by rushing to invest again, boosting non-OPEC output and
leaving the ministers led by Saudi Arabia's Abdulaziz bin Salman with a much more difficult
balancing act.
Drilling Down
So far, the lack of non-OPEC+ oil production growth isn't registering much in the market.
After all, the coronavirus pandemic continues to constrain global oil demand. It may be more
noticeable later this year and into 2022 . By then, vaccination campaigns against Covid-19
are likely to be bearing fruit, and the world will need more oil. The expected return of Iran
into the market will provide some of that, but there will likely be a need for more.
When that happens, it will be largely up to OPEC to plug the gap. One signal of how the
recovery will be different this time is the U.S. drilling count: It is gradually increasing,
but the recovery is slower than it was after the last big oil price crash in 2008-09. Shale
companies are sticking to their commitment to return more money to shareholders via dividends.
While before the pandemic shale companies re-used 70-90% of their cash flow into further
drilling, they are now keeping that metric at around 50%.
The result is that U.S. crude production has flat-lined at around 11 million barrels a day
since July 2020. Outside the U.S. and Canada, the outlook is even more somber: at the end of
April, the ex-North America oil rig count stood at 523, lower than it was a year ago, and
nearly 40% below the same month two years earlier, according to data from Baker Hughes Co.
When Saudi Energy Minister Prince Abdulaziz predicted earlier this year that "'drill, baby,
drill' is gone for ever," it sounded like a bold call. As ministers meet this week, they may
dare to hope he's right.
More stories like this are available on bloomberg.com
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now to stay ahead with the most trusted business news source.
The OPEC Monthly Oil Market Report said the
world oil supply fell by 150,000 barrels per day in April.
World oil supply
Preliminary data indicates that global liquids production in April decreased by 0.15 mb/d to
average
93.06 mb/d compared with the previous month, and was lower by 6.45 mb/d y-o-y.
World oil supply rose 330 kb/d to 93.4 mb/d in April and will increase further in May as
the OPEC+ alliance continues to ease output cuts. Based on the current agreement, global oil
production is set to grow by 3.8 mb/d from April to December. For 2021 as a whole, world oil
production expands by 1.4 mb/d year-on-year versus a collapse of 6.6 mb/d in 2020. Canada leads
non-OPEC+ with growth of 340 kb/d while the US is set to contract by a further 160
kb/d.
That's a difference of just under half a million barrels per day, (480,000 bpd). That's a
huge difference. Which one should we believe? Which organization has the most credibility?
We live in a world of half-truth where words are very carefully chosen. Companies hire
public relations firms to give just the right "spin" to what they are saying. CEO make
statements that suggest that everything is going well. Newspapers would like their advertisers
to be happy. Still is at the limit of Moore's law and fither shriking of dier is
impossible due to physical limits. One of the key challenges of CPU engineering is the design
of transistors gates. As device dimension shrinks, controlling the current flow in the thin
channel becomes more difficult. So callled 8mn process (not that this is a marketing not
technological term) is possible and now used in production, 5mn is problematic but used for
example by Apple in A14 CPU ( iPhone 12) / According to some sources, the A14 processor has the
transistor density of 134 million transistors per mm2. 3mn is probably the current
technological limit (TSMC is on track for production first 3 nm chips at the end of 2022
Anton Shilov, Anandtech April 26, 2021 ). It is unclear, if 2mn process will be
technologically viable or not. So the only way for CPU manufactures to increase the processing
power of CPUs is to increase the number of cores.
I We live in a finite world; we are rapidly approaching limits of many kinds. Which creates
problem, in some ways, somewhat similar to the world of the 1920s.
Yields on the US 10 year formed a bullish hammer within consolidation on Friday. Suggests
that yields are headed to 2% or above. It suggests that the move higher is now. Higher yields
will lead to stronger dollar. Might be the beginning of where price inflation becomes a drag on
economy as yields rise on debt. And as long as price inflation continues yields will rise.
Might put a cap on oil price in near future. Maybe we get another $5-$15 rise in oil price
before credit blows up due to rise in yields.
As the cost of credit rises due to price inflation. If you borrowed money at rock bottom
interest rates and you now have to rollover debt at a higher interest rate that is a problem
for corporate USA.
Anyone that doesn't believe that there will be a huge price to pay for the policy response
of Covid-19 is kidding themselves.
Even just on a relative basis. When you expand monetary and fiscal policy by that much in
one year. Things tighten on a relative basis as what comes next in the years after is less
support.
He is right that it doesn't work at $55/b, at $61 (today's price for WTI) it works in the
Permian basin. Note that I also use the data from shaleprofile as the basis for my models.
Though I clearly don't know the oil business as well as an old pro like Mike, not even
close.
The average price of oil in 2020 was about $36/b, in 2021 it will be about $60/b and in 2022
about $70/b (WTI prices). Decline will stop at $70/b for sure and probably at $60/b.
Note that in 2017 the average WTI price was about $52/b, and in 2018 it was $67/b, and in 2019
it was $60/b. 2018 saw a very large increase in tight oil output and the increase in 2019 was
pretty big as well.
My Permian model assumes new wells are financed from cash flow rather than new debt, debt
paid back in full by 2026. REPLYSCHINZY
IGNORED04/27/2021 at 4:21
am
Dennis,
Your observations are correct with the implicit assumption that extraction costs do not rise
at the same rate as the price of oil. Shallow Sand has remarked that in the 1990s $20/barrel
was considered a good price but today most wells, either onshore or off, are not profitable at
$50/barrel. Shallow is our invaluable guide to the evolution of costs in the oil patch.
My prediction is that oil prices will stay in the current range ~$55-$65/ barrel until
decreased investment (see
http://peakoilbarrel.com/december-non-opec-oil-output-continues-rebound-from-may-low/#comment-715646
) results in a shortage. I believe the shortage will cause oil prices to kick on the order of
50% in a year. The price kick will then provoke a financial crisis similar to that of 2008, but
central banks will have far fewer options to alleviate the crisis. REPLYHOLE IN HEAD IGNORED04/27/2021 at 6:24
am
Schinzy , I agree with you . Dennis is underestimating a few critical issues ;
1. End of OPM finance .
2. Underestimating the GOR and WOR rise .
3. Underestimating decline rates in shale .
4. Underestimating the rise in costs now ( steel above by 50% in 2021) which makes $ 75 non
viable .
5 . His contention that the big corporations will buy out the bankrupt corporations . The flaw
is that the big corporations themselves want to exit . Further as Mike S has pointed out " who
wants to buy wells which are at the tail end of their production and are going to have a
shutdown expense of $ 100000 to bear " .
All three agree that there is going to be shortage in 2022 sometime in the second or third half
and your scenario that the resultant high price will provoke an even deeper financial crisis
than that exists now will play out . Let me add that Covid damage cannot be assessed at this
stage as the virus is mutating at a rapid pace . It has moved from India to Pakistan. https://www.rt.com/news/522199-pakistan-military-coronavirus-khan/
P.S : He always give's EOG as an example of a well run shale play but " one swallow does not
the summer make " . For every one EOG there are 10/15 waiting in line for bankruptcy .
SHALLOW SAND IGNORED04/26/2021 at 6:48
am
I don't see how these wells can be profitably operated by a company with a lot of overhead,
which I assume these publicly traded companies have. DENNIS COYNE IGNORED04/26/2021 at 7:31
pm
I have discussed before the uselessness of GAAP accounting in US shale.
Raw Energy, who writes articles on Seeking Alpha, has addressed this much better than I
can.
Over 3,000 of the approximately 19,000 oil wells in ND produced 0 barrels of oil in the last
reported month, 2/21. Some of this could be weather related. I suspect more of the problem is
economic, even at improved oil prices.
I suspect the numbers are similar in the other shale basins. Mike says there are many
inactive shale wells in EFS, where he operates his conventional production.
US shale oil producers shut in production because it became hugely. A large part of US
production even saw negative prices. But even as prices recovered quickly to $40/bbl, hardly
any producer could cover their operating costs, let alone being profitable. This lead to a
continuous decline in output and only very recently we saw a modest recovery in production. At
this point, production is down around 2.5mb/d from peak.
One might argue that we have seen the same dynamics before. Back in 2014, US shale oil
production was also growing at breakneck pace. This eventually led to a much oversupplied
global market and a price crash from $110/bbl to $30/bbl over 18 months. As a consequence, US
shale oil production also sharply declined, which eventually rebalanced the market. Prices
recovered and stabilized at around $60-70/bbl. Subsequently US shale producers slowly adapted
to the new price environment and by 2019, production again grew at over 2mb/d. But in 2019, the
market had not much trouble absorbing that kind of production. In fact, it depended on it.
However, the recent price crash and ensuing production decline doesn't seem to follow the
same path. Oil prices have fully recovered by now, but production has not. In fact, US
production is near the lowest it has been since the outbreak of the pandemic. Moreover,
drilling activity is also greatly lagging. Arguably the US oil rig count has recovered from 172
in August 2020 to currently 344, but this seems not enough to keep production even
constant.
Exhibit 11: US production has yet to show any meaningful recovery despite the full price
recovery (Kb/d year-over-year)
Source: EIA. Goldmoney Research
In fact, the reason why US shale output is not lower despite this very low rig count is
because producers reverted to high grading. High grading means the producers are producing from
their most prolific acreage. This also means that any production increase would require a
massive redeployment of rigs as new wells would be less prolific than the current ones. But US
producers vowed to their investors as well as to their banks that – unlike the last time
prices recovered – they would refrain from growing output and focus on profitability
instead.
Exhibit 12: As the rig count fell, average production per rig increased due to high grading
(B/d and rig count (Permian Basin))
Source: EIA, Goldmoney Research
A further issue is the size of US shale output and the steep decline rates. Unlike shale gas
producers which somehow managed to flatten their decline curves, shale oil producers still
struggling with decline rates around 70% in the first year. The larger total US shale oil
output gets, the more new production has to be brought online to simply offset the decline
rates in existing output. This is not a new problem, but the recent reluctance of US producers
to grow output at all costs means this issue is now real.
Exhibit 13: Steep decline rates remain a problem as US shale oil output remains high even
after the crash (B/d all basins)
Source: EIA, Goldmoney Research
The pandemic and the price crash have also accelerated phenomenon that was already known
from the shale gas market, but is new to the shale oil market. In the US, there used to be
multiple shale oil basins which all showed production growth, albeit at different speeds. The
Permian basin became sort of the king of shale oil, but other basins such as the Bakken (the
first), Eagle Ford, Mississippi Lime and Niobrara all grew as well. But in this price recovery,
and despite the rebound in the rig count, all those basins show a continuous decline. The
Permian Basin is the only shale oil Basin that shows a recovery in supply (albeit a small one).
This is not unlike what we have seen in US gas, where shale gas production started in the
Barnett shale, then Haynesville Basin outgrew everything else, but now the Marcellus shale is
dominating US gas markets.
Exhibit 14: Only the Permian Basin shows some output recovery (b/d)
Source: EIA, Goldmoney Research
If this fully repeats in the shale oil space, then production is limited to how much
pipeline space can grow out of the Permian. Arguably that was an issue before, but if
production continues to decline in other basins, then the Permian has to offset those declines
as well. This would further restrict how fast production can growth in the future.
We believe that the necessary focus on profitability, combined with the issue of high
decline rates which become more dominate as base production grows, limit US shale oil
production growth long term. We don't think we see production again growing at the record rates
of the past, certainly not at these prices. Much higher prices would likely ignite another rush
in the sector, but eventually the decline rates will dominate and effetely limit production
growth.
The future of global supply growth:
On net, this means that supply will struggle to return to pre-COVID-19 levels quickly as
non-OPEC ex US shale will be permanently lower and continue to decline while it will take time
for US to reach old highs. US shale oil production is unlikely to grow again at past rates,
particularly with current prices. And once US shale production has reached the previous peaks,
it will be increasingly difficult to grow much further as high decline rates simply limit to
how high production can go. Even before the pandemic, most OPEC countries were already more
concerned about maintaining their production rather than growing it over the long run. Low
prices and high spare capacity also prompted core OPEC members to lower their CAPEX, at least
temporarily.
The duration mismatch between supply and demand peaks
The problem is, while oil producers are preparing for a low carbon future with potentially
declining oil demand, oil demand itself will still grow for many years to come. The oil space
is facing a duration mismatch.
Oil demand is primarily driven by the transportation sector and to a lower extent by the
petrochemical industry and industrial sector as a whole. Together they account for 84% of
global oil demand, 87% if demand from the agricultural, forestry and fishing sectors are added
(as it is likely also mostly transportation related oil demand). The transportation sector
accounts for about 2/3 of global oil demand and it is still growing. The petrochemical sector
accounts for 11% and is the fastest growing sector for oil demand. Industrial demand comes in
third at 7% and it has been declining for decades.
The future of oil demand
Industrial demand will likely continue to decline slowly. Wherever possible it's substituted
as oil tends to be one of the most expensive energy sources compared to power or gas. But this
is an ongoing process and the low hanging fruits have been harvested decades ago. Hence this
future decline is irrelevant in the grand scheme of things.
In contrast, demand from the petrochemical sector will continue to grow in the foreseeable
future as plastics demand will continue to rise with population growth and global economic
expansion. We expect Petchem demand growth to offset declines from all sectors other than the
transportation sector.
The big question therefore is what will happen to transportation demand. Transportation fuel
demand has been declining for many years in most Western economies even as Western economies
continued to expand and both the population as whole and mobility continued to rise. This is
mainly due to much better fuel economies in transportation vehicles driven mostly by
regulations. Importantly, the regulatory frameworks that drive these efficiency gains are not
new. In the US, the Corporate Average Fuel Economy (CAFE) standards were introduced already in
1975 as a reaction to the 1973-1974 oil embargo. The regulatory frameworks aims at fuel
consumptions directly. The CAFE standards have been continuously tightened over the past 45
years.
Exhibit 17: Fuel efficiencies have been increasing for decades without electrification
Source: Wikipedia
The European Union adopted a regulatory framework with a dual mandate that not just targets
fuel economy, but also emissions. European manufacturers have a binding emission target of CO2
95g/km for the average mass of their vehicles from 2021 onwards. It was CO2 130g/km from
2015-2019. Other OECD nations have similar standards that have tightened over the past
decades.
The result is that fuel consumption in most OECD countries has actually peaked a while ago.
Countries with high population growth such as the US have seen their overall fuel consumption
rising, but not at the same speed as their population and economy was growing.
The main contributor to fuel demand growth over the past 20+ years this were the emerging
markets. In Emerging Markets, the fuel economy of newly sold cars is already quite high as the
cars sold tend to be smaller, lighter and equipped with smaller engines. According to the SIPA
center on global energy policy, the fuel economy of average car sold in China in 2018 was
roughly 5.8 liters per 100km, equivalent to 40.5Mpg. In contrast, the average vehicle sold in
the US had a fuel economy of around 33.8Mpg. However, given the rapid expansion of the car
fleets in these countries, fuel demand has been strongly rising over the past decades.
Importantly, the rise in popularity of hybrid cars and EVs over the past years has not yet
lead to a complete change in trend in fuel consumption. The efficiency gains over the past
years were still primarily driven by more fuel efficient cars with combustion units. The reason
is that despite their popularity, hybrid and full EVs are still only a small fraction of all
transportation vehicles sold in the world and even a smaller share of the global car fleet.
According to the international Energy Agency (IEA) roughly 90 million of cars are sold
worldwide, up from around 60 million units by 2005. According the IEA, only 2.1 of the vehicles
sold in 2019 were electric in some form, which includes hybrid cars.
According to Bloomberg, there are currently 1.2 billion vehicles in the world. According to
the IEA, the total electric car flight is just 7 million. Again, this includes hybrid cars.
The important part for future production is that we make a clear distinction between those
three supply sources (counting OPEC and the + states as one source). There are very different
reasons for why production is down from each source and more importantly, what the long term
prospects are.
In the second part of this report, we will discuss the prospects of each source in detail
and show that the pandemic, and the ensuing price crash, have accelerate a process where global
production will hardly be able to grow. At the same time, demand will not peak as quickly as
people believe. This has the potential for a massive supply shortfall in the medium term.
smellmyfingers 2 hours ago
The only real shortage we have is truth.
We're all being fed a huge steaming pile of BS on everything. Oil build/draw. Crypto
currencies based upon what? Fiat money, paper.
All these lying politicians and banksters just jockeying for positions to steal as much as
they can as they push the human family to genocide.
wick7 38 minutes ago
Either way oil is going over the Seneca cliff and then Mad max here we come.
wick7 35 minutes ago
Every oil well that has ever existed has followed a bell curve. Pretending oil is infinite
is like believing in a flat earth.
Galtmandu 1 hour ago (Edited)
This is some weak sauce analysis on the relationship between gold and energy prices. Here
is a summary:
Energy prices and gold prices tend to correlate.
I have simplified,
Galtmandu
PS, your model is basically, interest rate policy, fed reserves of gold supply, and
inflation - not groundbreaking stuff. You have created an algorithm that uses these three
inputs to overlay on gold prices. Simple stuff. In fact, a basic polynomial exercise gets you
your best fit.
Now, predict the movements of fed gold reserves, inflation, and interest rate policy. You
can't. Therefore, your model has no predictive capability beyond your opinion. Otherwise, you
would be spending your days sipping umbrella drinks.
If I seem aggressive about this stuff its because I hate this kind of faux-analytical
b@llsh&t that is just sales propaganda.
Thrashed10 2 hours ago
I'm sitting mostly in cash right now. I do have a little exposure to oil. And food.
The oil market is so manipulated. Probably a smart move long term. But I have to trade so
my kids get ice cream. I already know my trade for Monday if I feel motivated. I trade
commodities and industrials. The boring stuff that is not sexy.
hanekhw 1 hour ago
Oil prices linked to the worthless dollar won't continue and this Administration is
working hard to make our dollars even more worthless.
...Raymond James analyst John Freeman, who claimed this year in a note to clients that the
United States' true DUC count is much lower, given that many of the wells included in the EIA's
DUC count are dead in the water and many years old, likely never to be completed. According to
Freeman, this figure is as much as 22% too high.
A 2019 Federal Reserve of Dallas survey of oil and gas company executives suggests that half
of the respondents agree that the EIA is overestimating the number of DUCs.
Related: Investors Rush To Oil Stocks Despite ESG Push
In a low oil price environment, oil and gas companies may spend money on finishing off an
already drilled well, rather than on drilling a new well. But companies will continue to strive
to keep that DUC inventory in their back pocket should the market call for it. But when oil
prices have been low for a long time -- and demand for crude or gas remains low, those low oil
prices may never justify completing a well, resulting in another dead DUC.
The essence of shale operation is generation of the stream of junk bonds along with the
stream of oil and gas. In other words profitability is low or nagative. Junk bond need buyers do
this is a confidence gate -- as sson as confidence drops buyers will evaporate. At this point
there will be writing on the wall. We do not need necessary a stock crash for that. But as just
bond moves in parallel with stock that will also be the Minsky moment for shale oil
production.
Nice charts and summary of U.S. Oil & Gas Reserves.
However, it seems to me that a large percentage of these "supposed" unconventional reserves
will never be extracted. Thus, the U.S. Shale Industry will have permanent DUCs that will never
be completed and proved undeveloped reserves that will evaporate into thin air.
Why? Well, if we look at some of the top shale players, total long-term debt from just
five companies increased from $17 billion in 2006 to $133 billion in 2020 (XOM, CVX, EOG, OXY
& CLR).
With Equinor selling its Bakken assets (liabilities), writing down $11.5 billion from the
company's original price-tag, and saying it was a big mistake to get into shale . why would it
be any different for ExxonMobil or OXY?
Indeed, the U.S. Shale Ponzi Scheme will continue a bit longer until the day the
highly-leveraged over-inflated broader stock markets finally crash. At that point there will
not be a SHALE 3.0. I see U.S. shale oil production falling 75% by 2030.WATCHER
IGNORED04/09/2021
at 11:05 pm
Feb this year Exxon erased oil sands from its reserves.
Article talked pandemic so doubt they sold anything. Probably just a price determinant.
JEAN-FRANÇOIS FLEURY IGNORED04/11/2021
at 2:51 pm
This one is also laughable : "That gives plenty of incentive for giants like Total or Royal
Dutch Shell Plc, plus the hundreds of smaller explorers that remain in business, to keep
searching the world's frontiers for the next place to sink their drill bits." Royal Dutch Shell
stated that their production did peak in 2019 and that their production will decrease by 1 or 2
% per year. That means that they decided to cease exploration and implementation of new
oilfields or gasfields, if I am not wrong.Therefore, why there are still people who decide that
oil companies should look for new oilfields ? They want to make real their dreams despite the
crude reality ?
Consolidation continues in the Permian. Pioneer CEO Sheffield has stated repeatedly recently
that the goal is free cash flow now and not growth at all costs. As smaller producers continue
to get marginalized, rapid production increases in tight oil are likely a thing of the past.
Most likely a good thing for everyone.
(Reuters) – Exxon Mobil and Chevron Corp have scaled back activity dramatically in
the top U.S. shale oil field, where just a year ago the two companies were dominating in the
high-desert landscape.
The cautious approach of the two largest U.S. oil companies is a major reason domestic
oil production has been slow to rebound since prices crashed during pandemic lockdowns in 2020.
Production now is about 11 million barrels per day (bpd), down sharply from the record of
nearly 13 million bpd hit in late 2019.
The share of drilling activity by Exxon and Chevron in the Permian Basin oil field in
Texas and New Mexico dropped to less than 5% this month from 28% last spring, according to data
from Rystad Energy.
"We essentially hit a pause button," said Chevron Chief Financial Officer Pierre
Breber. "When the world was oversupplied we didn't see the virtue in putting more capital to
add barrels." (Graphic: Exxon and Chevron slash Permian drilling, here)
Neither company is likely to boost spending until next year, according to the
companies and analysts. Chevron expects to produce around 1 million barrels daily by 2025 and
Exxon 700,000 bpd by 2025, the companies said at investor days this month.
Chevron will increase Permian spending from $2 billion now to pre-Covid levels of $4
billion annually "over the course of the next several years," Breber said, but the
company will not increase drilling in the Permian this year. It is currently running about five
rigs in the Permian with two completion crews, down from just under 20 a year ago.
SNIP However, output is unlikely to increase dramatically, due to the swift decline rates for
shale wells.
"We would need three months of oil prices sustained at current levels followed by six
months of drilling activity before production begins to climb higher on a sustained basis,"
said Peter McNally at Third Bridge.
Exxon and Chevron are not the only producers keeping spending down. Many shale companies
have hedged a majority of expected 2021 oil production at an average price below $45 a barrel,
well below current market prices, Enverus' Andy McConn said. The hedges reduce exposure to the
recent increase in oil prices, discouraging near-term growth. (Graphic: Permian oil production
stalls, )
It looks like they hope to return to normal production by 2025.
Biden's plan will end tax preferences for fossil fuel companies. I am not sure if there are
more specifics than that.
However, if expensing intangible drilling costs is eliminated, the shale boom will
officially be dead.
As percentage depletion applies only to the first 1,000 BOEPD per company, elimination of
that would primarily hurt marginal wells.
Also, Biden has proposed $16 billion to plug abandoned wells and reclaim abandoned
mines.
Of course, at this point, the infrastructure bill is not entirely specific. There will be a
lot of negotiation in Congress.
To me, it would seem short to medium term positive for oil prices. Shale companies will
finally have to pay income taxes, and assuming the corporate rate goes to 28%, I don't see how
there would be another drilling boom in shale, absent a super spike in oil and/or natural gas
prices.
Further, the bill would cause a spike in US oil demand. Lots of heavy equipment and
materials that will consume petroleum, even that needed for more clean energy.
Future will be more clear once the plan is signed into law.
I would note grain spiked on the USDA estimates for corn and soybean acres. This could
affect oil prices short term.
The 12 nation group might not see annual C plus C output increases of 1400 kbo/d in the
future, but it will take time for the rate of increase to fall to 455 kbo/d (where a
plateau in World output would occur) especially if oil prices rise to $80/bo or more.
No, it will not take time. Why would you think production would graduallly fall off?
Yes, decline slops are usually gradual as well as increasing slopes. But the change from
increase to plateau or increase to decline is seldom, if ever gradual. USA+Saudi+Russia has
already plateaued. Their decline is very likely to be sudden, well, it has actually already
happened.
However, in the two charts below, I have used your method of stopping the chart just before
the Covid induced decline. The charts speak for themselves.
I think it instructive to recall oil and gas investment history. Unregulated oil and gas
markets have always yielded boom bust cycles. There was a bust cycle from 1986 to 2000. A boom
cycle started in 2001 with investment in oil and gas rising on average 11% per year to $780
billion in 2014 (this was from a Kopits talk in 2014, but the link I have no longer works).
There is a lag between increased or decreased investment and the response in extraction
rates. The lag is longer offshore than onshore. For example, in spite of the investment boom
from 2001 to 2014, extraction rates were stagnant between 2005 and 2010.
A bust began in 2015 with investment dropping 25% in 2015 and a further 20% in 2016. The
drop was more pronounced offshore than onshore. Investment stayed essentially flat through
2019. Extraction rates continued to climb through 2018 but were flat in 2019.
The IEA began warning in 2016 that investment was not sufficient to meet demand in the early
2020s. In their 2019 WEO they stated that $650 to $750 billion was needed annually to attain
106 mb/d in 2030. I am assuming this sum referred to oil AND gas investment. In 2019 oil and
gas investment was $483 billion. In 2020 it was $313 billion (close to 2009 levels).
As Dennis noted in response to my comment above, the relationship between a drop in
investment and the corresponding drop in supply is not linear. But unless investment increases,
I don't expect extraction rates to achieve 2018 levels soon.
REPLYSHALLOW SAND IGNORED
03/28/2021 at 6:08 am
Ovi. I appreciate your posts. Thanks.
Schinzy. Look at what the integrated oil companies are forecasting. BP, RDS and TOT are
shrinking production. CVX and XOM are greatly reducing CAPEX. So is COP, the largest
independent. So is PXD, one of the largest shale players. Of course, these companies can change
strategy quickly, likely next year if any do.
For the first time I can recall, the government of the United States is not supportive of it
increasing production. Contrary to popular belief, this matters.
To keep a lid on oil prices, on the supply side, either the USA needs to keep adding barrels
or some other country that does not benefit as a whole from high oil prices will need to step
up. The CAPEX currently isn't budgeted to do that.
Of course, decreased demand due to the continued spikes in COVID cases will continue to put
a lid on demand. Hopefully by fall this won't be much of an issue, not for oils sake, but for
public health sake.
The other demand side lids I see could be Western EV adoption offsetting developing world
oil demand growth. Worried here about both the needed upgrades to the grids, plus the lack of
rare earth metals. The other could be another big economic issue. Don't want that, but seems
economy issues are also going to be with us given the high debt levels. The stimulus in
response to COVID isn't cheap.
REPLYSCHINZY
IGNORED
03/28/2021 at 7:41 am
All very true Shallow. I suspect these companies are reducing CAPEX because of increasing
debt. The more conservative CAPEX spending seems to be helping their share prices. SHALLOW
SAND IGNORED
03/28/2021 at 7:55 am
Schinzy.
IHS Markit doesn't see US CAPEX spending at the 2018-19 levels returning until 2024-25.
Probably too far out in the future to be accurate. However, it's 2021 forecast is for lower
CAPEX in all years since 2010 except for 2020.
I will add another big player to my list above, EOG also lowered CAPEX guidance for 2021
from where it had been pre-pandemic. Will seek to hold production flat in 2021.
Here is the C Plus C chart to to December 2022. In the original chart in the post above, I
only took it out to March 2021.
The March STEO report along with the International Energy Statistics are used to make the
projection. It projects that world crude production December 2022 will be 81,759 kb/d, 2,735
kb/d lower than November 2018
Ovi, thanks for a great chart. And even this, 2,735 kb/d below the previous peak, I think is
overly optimistic.
I think, at least two of the world's three greatest oil producers have peaked, (The USA,
Saudi Arabia, and Russia), have peaked, and the rest of the world has clearly peaked, there is
no way we can possibly surpass that 2018 peak. Actually, I think all three have peaked. I was
just being conservative.
World less USA, Saudi Arabia, and Russia peaked in 2017. All three peaked, yearly average,
in 2019. Of course you can argue that this is just the peak "so far". But I do not believe any
of the three will ever surpass their 2019 yearly average peak.
Dennis, you wrote: Below I use the trend in the ratio of World C plus C to World
petroleum liquids from Jan 2017 to Dec 2019 to estimate World C+C from Jan 2021 to Dec
2022.
Okay, you use past trend lines to estimate future production. Well, I guess there is
also how the EIA does it and the IEA does it. I just don't have confidence in that type of
analysis.
Above I have charted past World oil production less the USA, Russia, and Saudi Arabia. There
is clearly a trend there. Do you think this trend will continue?
World C+C production in 2018 averaged 82,897,000 barrels per day. In 2019 that average was
82,306,000 barrels per day. I have little doubt that future world oil production can come close
to those averages. But I would bet my SS check that the 2018 peak will never be surpassed. (I
like annual averages but if you like centered 12-month averages, then go with that.)
At any rate here are four possible sources for a surge in World oil production:
1. THE USA
2. Russia
3. Saudi Arabia
4. The World less USA, Russia, and Saudi Arabia
If World oil production is yet to peak, which one, or ones, of these four sources, will it
come from? RON PATTERSON IGNORED
03/26/2021 at 12:00 pm
I believe I have seen reports that suggest a plateau near the recent 12 month peak output
can be maintained for 5 to 10 years.
No Dennis, you have not seen that. I posted that myself some time ago. Russia stated that
they hoped to hold production at about 11.2 million barrels per day for the next four years,
2021 through 2024. I have since lost the link but it was posted right here on this list.
However, I think that was wishful thinking on Russia's part. I don't think they will hold that
level, ever again.
The drop in World minus KSA, US, and Russia C plus C output since 2018 has mostly been
due to a combination of lower oil prices and OPEC reducing output to try to bring oil prices
back up,
I am not talking about the drop since 2018, I am talking about the peak and decline
before 2018. The peak month in my chart above was November of 2016 at 52,206,000. The
peak 12-month average was September of 2017 at 51,161,000 barrels per day. At that point, in
September of 2017, the World less USA, Russia, and Saudi produced 63% of all World production.
63% of World oil production peaked in September of 2017.
While World oil production was peaking in 2018, due to increased production by the USA,
Saudi, and Russia, the World less these big three was declining to 50,737,000 barrels per day,
the average for 2018. A decline of almost half a million barrels per day.
Dennis, regardless of what happens in Canada, Brazil, and Norway over the next 5 to 10
years, the World less the big three peaked in 2016 monthly and 2017 annually. Any increase in
World production must come from one or more of the big three. HOLE IN HEAD IGNORED
03/26/2021 at 1:22 pm
Dennis , your post on the last thread .
"I stand by my estimate, in 2020 World C plus C output dropped by 5.5 Mbo/d due to a lack of
oil demand and the resulting drop in oil prices from the 2019 annual average, so a 10 Mbo/d
increase from the 2020 level (annual average) of C plus C output requires a return to the 2019
average level (roughly 82.3 Mb/d) requiring a 5.6 Mbo/d increase and then a further 4.4 Mbo/d
increase in output to reach 87 Mbo/d.
If World demand for C plus C warrants such an increase by 2028, I believe it can be
produced, and yes the model accounts for depletion, which has been ongoing since the first
barrel of oil was produced. The basis for the estimate is likely World resources of 3400 Gb of
C plus C (this includes the 1428 Gb of crude plus condensate that was produced from 1860 to
2020), remaining resources (this includes conventional and unconventional C plus C) are about
1972 Gb (this includes future discoveries and reserve growth).
It is possible less will be produced due to lack of demand, if a rapid transition to
non-fossil fuel energy sources occurs, I hope that is the case, but I am skeptical"
Well, 2020 production came in at an average of 75.93 mbpd . Decline rate was 7.5% compared to
2019. How will you achieve additional 10 mbpd by 2028 ? Ron is correct . Igor Sechin boss at
Rosneft confirms what Ron has stated , shale party is over , KSA is going to cut domestic
consumption by 1mbpd so that it can export that oil . Sorry, Brazil , Norway ,Tom Dick and
Harry are in no position to cover this lag in production .In the future decline rates will
increase as horizontal wells reach their limits of extraction . You must rethink your models
with the new facts . Your statement "If World demand for C plus C warrants such an increase by
2028, I believe it can be produced " does not hold water . Your belief or mine is irrelevant .
Geology prevails . RON PATTERSON
IGNORED
03/27/2021 at 8:55 am
OPEC has been holding back production since 2017 in order to get oil prices up, how much
different nations produce depends on their cost of production relative to price,
I don't see any evidence to support that statement. Average OPEC production in 2018 was only
170,000 barrels per day below the average for 2017. If they were holding back, they weren't
doing a very good job of it. I think they were producing flat out all three years, 2016 through
2018.
I remembered incorrectly, OPEC likely started cutting back on output in the middle of
2016 to get oil prices higher,
You remember very incorrectly. OPEC, in the last months of 2016 was emptying their storage
tanks in order to produce as much oil as they could. They would set their quotas on the amount
produced in November and December of 2016, so they were making heroic attempts to produce every
barrel possible in order to get a higher quota. (November 2016 was the OPEC all-time peak. And
in my opinion, will remain so forever.)
They started cutting in January of 2017. But by June everyone was cheating and they were
all, by July 2017, producing flat out.
Why does OPEC exist?
OPEC was formally constituted in January 1961 by five countries: Saudi Arabia, Iran, Iraq,
Kuwait, and Venezuela. They existed then for the sole reason of trying to drive oil prices
higher. They would like to do that today but squabbling among members has made them somewhat of
a joke. They are a disorganized bunch of buffoons. Yes, they have dramatically cut production
during the pandemic. But so has everyone else in the world. The bottom dropped out of
demand so everyone cut production trying to save money.
A decline in output for the World has occurred since 2018 because oil prices dropped due
to oversupply of oil relative to demand.
Okay, but what about 2017 and 2018? OPEC could not keep their members in line and by June of
2017 everyone was again producing flat out, causing that oversupply. And their cut was a
pittance anyway, not enough to make much difference. For most of 2017 and all of 2018, every
OPEC member was producing every barrel they could. (With the exception of Iran and Venezuela of
course, but that is another story for another thread.)
Just look at the chart Dennis, that is just so damn obvious it cannot be denied.
For OPEC minus Iran, Libya, and Venezuela the centered 12 month average peak was 26759
kbo/d in January 2019.
Okay, you need to update your nations here. Libya is already back, producing at maximum
possible capacity for the last 4 months. Venezuela will never be back, not in the next decade
anyway, long after peak oil is history. That leaves only Iran. Iran, if sanctions were lifted
today, could possibly increase production by approximately 1.6 million barrels per day in the
next six months or so. That would not be nearly enough to make up for the natural decline in
OPEC, especially Saudi Arabia, since the peak in 2016.
Iran is the only nation on earth that can possibly increase production in any significant
amount. So you should only deal with Iran when talking about possible OPEC production
increases.
Dennis, OPEC has done nothing but basically tread water since 2005. Why do you think they
will now save the world?
(In the chart below 2021 is only two months, January and February.
OPEC does not produce at maximum output, except when fighting for quotas.
Dennis, OPEC is not an oil company, they are a cartel. The only ones that increased when
battling for quota were Saudi, the UAE, and Kuwait. The rest just produced flat out all the
time. Check the charts.
Yes, they were all producing flat out most of the time. Only in a few instances did they
actually cut production. Of course, the pandemic hit everyone. But as you can see by the yearly
chart I posted their total share of the market has shrunk dramatically since 2005.
Dennis, OPEC peaked in 2016. Saudi Arabia is in decline. End of story. ALIMBIQUATED
IGNORED
03/27/2021 at 7:47 am
Ron,
Good point about past trends lines being a dubious predictor of future trends. This is testable
too. In this case three years of past data was used to predict the future.
If there is 40 years of data, you could run the algorithm on 35 three-year data sets and
check the accuracy of the prediction. That would give you some idea of how likely the latest
prediction is to be accurate.
My guess is that the accuracy is fairly low, but checking would reveal the truth. POLLUX
IGNORED
03/26/2021 at 3:30 am
In November, Saudi Arabia's domestic crude stockpiles fell to 17-year low: "Saudi Arabia's domestic crude stockpiles fell by 1.2 million barrels in November to 143.43
million barrels, the lowest since November 2003." (
source )
This trend continues and in January, stockpiles fell to 137.207 million barrels: "The country's domestic refinery crude throughput rose to 2.343 million bpd while crude
stocks fell to 137.207 million barrels in January." (
source ) HOLE IN HEAD IGNORED
03/26/2021 at 11:19 am
In an article Steven Kopits wrote "In its February Short Term Energy Outlook (STEO), the EIA
forecasts this month's world oil consumption at 96.7 million barrels per day (mbpd). The oil
supply, however, is much lower, only 93.6 mbpd, with the difference of 3.1 mbpd of necessity
being drawn from crude oil and refined product inventories. This is a shortfall of 3.5% "
Is he correct ? if yes ,then are we in trouble ?
One more observation from my seat in the gallery: FOSSIL ENERGY is the basis of industrial
civilization, and our complete dependence on it portends our extinction as a species. We
might as well accept the fact that we are done.
On the technical side, drillers have vastly lengthened the horizontal leg of the typical
shale well, from slightly over a mile in
2014 to an average of 8,500 feet in early 2019. The ability to do this has come in part
from improvements in drilling fluids design to permit entry into longer sections, and better
rotary steerable MWD/LWD assemblies that enable more reliable real time drilling data from the
bit to ensure they are staying in the sweet spot of the reservoir. Improvements in perforating,
frac stage design with 4-D fracking that takes into account the frac's progress over time have
also contributed to this increase in productivity.
The amount of sand or proppant pumped per foot of interval has also increased hugely from
around a
1,000 pounds per foot-PPF, to between 2,000 and 2,500 PPF. Increasing the amount of
proppant ads to the well's cost, but it also hugely increases the permeability of the
completion. Permeability is a measure of the flow capacity of the rock. More permeability
results in more production for longer periods of time.
High grading of drilling opportunities has been a prime contributor to being able to
maintain a lower decline rate that originally supposed in my calculations. What this means is
that operators have been focusing on their Tier I acreage and bypassing lower tier
opportunities.
When you take this performance and multiply it across the top twenty or so drillers, you can
begin to see how shale production manages to hover around the 7.5 mm BOEPD level.
... ... ...
One of the questions that often comes up is what will happen when Tier I acreage is
drilled up. Some estimates have been put forward that this might occur within the next
decade.
Rystad has challenged those estimates showing an estimate of the longevity of Tier I shale
in years at present rates of drilling.
It comes as no surprise the Delaware sub-basin of the larger Permian basin is the king of
shale, and operators there will retain a low cost drilling advantage for a number years beyond
other plays.
Most analysts believe that most public companies will stick to discipline. OPEC+ also seems
to have gambled on expectations that U.S. shale will look at higher profits instead of
production this time - unlike in any of the previous oil price spikes in recent years - when it
decided not to raise production from April, except for small increases for Russia and
Kazakhstan.
In view of the recent high prices, JP Morgan now expects U.S. oil production to average
11.36 million bpd in 2021, slightly up from 11.32 million bpd last year.
Sweet spots depletion might be a problem for them. U.S. shale production as a whole is
unlikely to return to the levels before the pandemic. The high decline rates of shale well are
more acure outside of sweet spot. Larger firms which still have sweet spots feel the pressure
from investors to produce level of dividends expected in the industry. That excude "all-in"
drilling as happned inthe past when Wall Stertt money were abundant and discipline was
lacking.
Currently, OPEC itself sees U.S. crude oil production for 2021 at 11.2 million bpd, slightly
down from an estimated 11.28 million bpd output for 2020. In its latest Monthly Oil Market Report
(MOMR) for February, the cartel actually revised down its 2021 forecast for U.S. oil production
by 210,000 bpd and now expects a 70,000-bpd annual decline from 2020, as continued capital
expenditure discipline is "expected to weigh on production prospects in 2021."
Larger listed U.S. producers are concerned
that some drillers would break promises of output restraint.
"There are going to be bad actors [who pursue] growth for growth's sake," Matthew Gallagher,
an executive at Pioneer Natural Resources, told the Financial Times in
January.
Pioneer Natural Resources itself will look to limit production growth to an average 5
percent over the long term, CEO Scott Sheffield
said on the Q4 earnings call last week. Moreover, Pioneer expects to return up to 75
percent of its annual free cash flow to shareholders after the base dividend is paid, Sheffield
noted. This will be returned in the form of variable dividends paid out quarterly the following
year, the executive said. Related:
Is This The World's Next Big Offshore Oil Region?
While Pioneer and other major listed shale players seem to be heeding investors' calls for
higher returns to shareholders, the smaller closely held operators are not promising anything
other than chasing higher returns on their investment, which is being generated by more oil
production.
Dennis, I must disagree with your assessment. OPEC peaked in 2016. Yes, Iran can come back
and increase production by about 1.5 million barrels per day. But that still will not make up
for the decline in the rest of OPEC. No need to mention Venezuela, they may come back around
2030 or so, long after the peak has passed.
Russia said they had peaked in early 2020. I see no reason to think they were lying.
That leaves Brazil, Norway, and Canada. They all three may increase production but nothing
spectacular. Not nearly enough to make up for the rest of the world in decline. REPLYSTEPHEN HREN IGNORED02/27/2021 at
5:58 pm
I'm inclined to agree with Ron. So much investment deferred because of 2014 and 2020 price
crashes. LTO can come back quickly if the price stays consistently high (a big if) but it
won't be enough to save the day. Investors are expecting cash from LTO these days, not
production increases. I imagine most other countries are just coasting after the turmoil of
the last year. Also still plenty of wildcards in the collapse department over the next 5-10
years: Iraq, Nigeria, Libya, etc. WATCHER IGNORED02/28/2021 at
1:12 am
Factions in the administration are on record as wanting sharply higher oil prices. Seems
difficult to see how this would get through the Senate, but it is a green priority.
RON PATTERSON IGNORED02/28/2021 at
8:48 am
Does Occidental know what they are talking about? They are saying that the investors are
just not there for a massive increase in production. And they are one of the two largest
producers in the Permian Basin.
America's oil production will never again reach the record 13 million barrels a day set
earlier this year, just before the pandemic devastated global demand, according to Occidental
Petroleum Corp.
"It's just going to be too difficult to replace the 2 million barrels a day of
production that we've lost, and then to further grow beyond that," Chief Executive Officer
Vicki Hollub said Wednesday at the Energy Intelligence Forum. "Over the next three to four
years there's going to be moderate restoration of production, but not at high
growth."
Occidental is one of the biggest producers in the U.S. shale industry, which added
wells at such a rate prior to the spread of Covid-19 that the country became the world's top
crude producer, overtaking Saudi Arabia and Russia, ushering in an era that President Donald
Trump called "American energy dominance."
U.S. oil production is stuck below it's pre-pandemic high
Shale's debt-fueled expansion came to a juddering halt due to lower gasoline demand and oil
prices, but also because of Wall Street's increasing reluctance to fund growth at any
cost. Shale operators are increasingly prioritizing cash flow and returns to investors over
production growth.
Occidental, which vies with Chevron Corp. to be the biggest producer in the Permian
Basin, has been forced to throttle back capital spending, lower growth targets and cut its
dividend in a bid to save cash during the downturn. Its finances were already severely
challenged by the debt taken on through its $37 billion purchase of rival Anadarko Petroleum
Corp. last year.
Hollub said global consumption stands at about 94 billion barrels a day, and it will
take a Covid-19 vaccine before it returns to 100 million barrels. Due to cutbacks around the
world, supply and demand for oil will likely balance again by the end of 2021, she
said.
Unlike some of her European peers, Hollub sees strong long-term demand for oil. "I
expect we'll get to peak supply before we get to peak demand," she said.HICKORY
IGNORED02/28/2021 at
11:31 am
"Unlike some of her European peers, Hollub sees strong long-term demand for oil. "I expect
we'll get to peak supply before we get to peak demand," she said."
Thanks Ron.
I wonder if she is referring to the balance in the USA, or the world.
It will be a horse-race finish for the whole decade- "and here comes Demand up the
backstretch " RON PATTERSON
IGNORED02/28/2021 at
11:26 am
Figure this one out. The EIA's AEO2021 In
the past they have always given scenarios based on "Low Price" and "High Price". But now it
is "Low Supply" and "High Supply".
They are not making a prediction, they are just saying: "Here is what low supply looks
like", and "Here is what high supply looks like". Hell, we already knew that.
Anyway, it is all about tight oil. Everything depends on tight oil. Occidental says tight
oil has peaked. But the EIA is taking no chances. They are saying in effect: "Here is what it
looks like if tight oil has peaked and here is what it looks like if it has not."
One factor is a change in one of the three large producer's policies. This large producer is
also the only producer that consumes more than it produces and therefore the only one of the
three that favors lower prices. I'm referring to USA, of course.
USA shale (and to a much lesser extent GOM) growth kept a lid on prices. Where would prices
have been 2010-19 without USA adding 7 million BOPD?
USA growth doesn't appear to be headed toward adding 1 million BOPD or more per year in the
future. USA companies are all being pressured to pay dividends. To cover dividends, USA
companies need much higher prices. USA companies aren't forecasting growth like past years.
For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority. I am not making a "political" statement here trying to rile up
the left on the board. Just look at oil prices since the USA election on 11/3. Not a
coincidence. Not likely USA will be intervening anytime soon in the ME to protect oil supplies.
At least not in a big way.
I have no idea how high oil prices will go. I wonder what happens politically in USA with $3
gasoline? $4 ? Are high gasoline prices no longer a political liability? They weren't for Obama
in 2012. But USA was drilling like crazy in 2012. Not sure what happens this time if that
occurs, given clear desire of Biden Administration to discourage USA oil production growth.
Another factor is the Western European producers have told the market recently in a very
straightforward manner that their oil production is past peak. The CEO's of both BP and RDS
have stated this. Total is also transitioning away from oil. Equinor also, it changed its name
to remove the word oil.
Next, even though total worldwide demand will still be below a record, demand growth from
2020 to 2021 worldwide will be big, much bigger than from 2009 to 2010 after GFC. What did
prices do from the depths of GFC to 2011? Compare GFC stimulus to COVID stimulus.
Last, how many paper barrels are traded per physical barrel? With the increase in paper
barrels (I would call them more accurately day trader barrels) volatility in the oil market has
grown. The price went negative big time one day last April. It was purely a day trader
phenomenon.
Everyday you can find headlines that point to a huge transition underway in the world energy
scene.
For example today-
-Exclusive: Equinor considers more US asset sales in global strategy revamp, and
-Ford bets $29B on leading the 'electric vehicle revolution'
There is a huge scramble underway to adapt to the conditions these big companies now see
coming to be over this decade.
In the meantime, I think that oil demand growth will be very strong over the next 18-24
months.
And as the price of gas in the USA goes up in this rebound phase, the great difference in
travel cost/mile between plug-in vehicles (like a Ford mustang) and ICE vehicles will become a
widely known fact. Ford (and the other manufacturers) all know that now, even if they were slow
on the uptake.
This world is going to change rapidly this decade in so many ways. REPLYALIMBIQUATED IGNORED02/15/2021 at 11:34
am
I think a general feeling of optimism that there is light at the end of the Covid 19 tunnel
is helping as well. REPLYSURVIVALIST IGNORED02/15/2021 at 12:23
pm
" For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority."
Great observation. I recall when GWB2 went to KSA to 'kiss the ring' and ask for more oil
production. I wonder how it will play out next time. REPLYHICKORY IGNORED02/15/2021 at 12:33
pm
"" For the first time ever, the USA government is not making oil production growth, either
domestic or foreign, a priority."
Of much greater impact- For the first time ever, the major oil companies are not making oil
production growth, either domestic or foreign, a priority. REPLYSHALLOW SAND IGNORED02/15/2021 at 1:11
pm
The Biden administration is under pressure to see oil prices rise. The green agenda of wind,
solar and EV's is only cost competitive with fossil fuels in two ways: 1) green subsidies; or
2) higher oil prices. Until high oil prices threaten the economy, the Biden administration will
enact policies that gladly see oil prices rise. And with the oil price experience of 2009 to
2014 still relatively fresh in people's minds, the Biden administration is not afraid of $60,
$70, or even $90 oil. They are hoping for it. REPLYHICKORY IGNORED02/15/2021 at 2:13
pm
"$60, $70, or even $90 oil. They are hoping for it."
As are the people working in the oil industry. REPLYSTEPHEN HREN IGNORED02/15/2021 at 4:59
pm
As far as anyone on this board is considered, the higher the price of oil the better. Let's
phase out oil production in the US over the next three decades and keep the price high the
entire time so the producers make money and people are incentivized to switch to less polluting
EVs. It'll be like the TRC for the whole country but heading towards a bottleneck. Auction
drilling rights so only the best wells get drilled. Keep restricting drilling in a phased
manner, enact a gradually lower cap on the number of wells that can be drilled until it goes to
zero in twenty years and then maintain these stripper wells until they are empty. REPLYPAULO IGNORED02/15/2021 at 6:33
pm
Can you imagine any US party that would actually dare to promote a higher cost for gasoline?
Personally, I think there should be a big carbon tax and fuel tax surcharge imposed to fix
infrastructure, but whatever.
Confession: I am not anti oil. My son works in the Cdn industry. I just think people drive
more than they should and that energy should be priced higher. Win win. LLOYD IGNORED02/16/2021 at 3:55
pm
So $90 oil is good for:
-Saudi
-Democrats
-Shallow
-Tesla
-Renewables
PAOIL-
I disagree that high oil prices are needed to make green energy competitive, because oil is
already very expensive energy, which is why it is rarely used to generate electricity. Wind and
solar compete against coal, nuclear and gas, not oil.
Oil shines as a way to store energy in a moving vehicle and power internal combustion
engines. As such, it really competes with batteries, not with the rest of the energy market at
all. And batteries still have a tiny impact on oil markets.
So higher oil prices might be useful for the EVs, but not particularly useful for wind and
solar. But in reality, the EV market is suffering from chronic battery shortages as
manufacturers struggle to build factories fast enough to meet 20% or more annual demand growth.
The oil price really isn't an issue, and raising oil prices wouldn't help.
If Biden's goal was to make EVs more competitive, the government has an easy way to raise
oil prices, which is to raise taxes at the pump. This would be more or less neutral to the oil
price from the producer point of view. It would just encourage exports and discourage imports,
improving America's balance of payments. But it hasn't worked in Europe, where taxes are over
60% of the price at the pump. The most effective way to promote EVs is subsidizing the purchase
price of the vehicle. That has been very effective.
Hoping that the American consumer will keep oil demand up internationally no longer makes
sense, as America's relative economic importance has been falling since 1945. I'm not sure what
the previous administration was trying to accomplish by talking down the price. REPLYJEFF IGNORED02/16/2021 at 5:13
am
"But it hasn't worked in Europe, where taxes are over 60% of the price at the pump. "
I have driven a Toyota Corolla on an 4 week US trip.
With an engine for the US market – you can't buy this modell in Europe. It was very
steady going – and thirsty. At least for european thinking, we used 7-8 litres / 100 km
by mostly driving country roads in cruise control at the given speed (didn't wanted to deal
with US police). Slow for my feeling, I'm driving faster in Germany.
And use only round about 6 litres with a car of similar size, which is a bit faster than
this Corolla – with this lazy slow driving I would use below 5 litres with my car (and
get a lot of flashing).
Jeff –
That was a little unclear on my part. I meant high gasoline prices haven't gotten people to
buy, EVs, but direct subsidies seem to work.
It's also worth mentioning that $120 oil didn't really dent consumption much, and certainly
didn't inspire many to buy EVs.
In my opinion liquid fuel is cheap. I mean I think that consumers aren't willing to make
significant changes in behavior even if prices increase significantly. S IGNORED02/17/2021 at 3:05
am
Alimbiquated, as an European in a well-to-do country, the matter of car buying is somewhat
more complicated than just gasoline price. E.g. fully electric car availibily, their price,
distances that need to be travelled (range anxiety in other words) are still important. Hybrid
cars are also rather expensive. Here it seems that these two car groups are selling better and
better, public charging points are increasing etc so we will see what happens. As I have a full
electric car I got relatively cheaply (still a bit of ouch ) I think I will not get a petroleum
or diesel car ever J HOUSMAN IGNORED02/18/2021 at 4:08
pm
"The green agenda of wind, solar and EV's is only cost competitive with fossil fuels in two
way" Three ways, actually. The third is when we finally start to realize the actual cost of
destroying the environment by burning fossil fuels REPLYMATT MUSHALIK IGNORED02/15/2021 at 10:01
pm
Global crude oil may have peaked 2018-19 before Covid
A dozen workers that are members of the Safe union are threatening to down tools at the
Mongstad terminal from midnight on Monday if talks with the industry body aimed at breaking an
impasse over a 2020 wage settlement with Equinor fail.
Other fields that could be impacted include Kvitebjorn, Visund, Byrding, Fram and
Valemon, with gas output exports from the Troll area also in danger of being hit.REPLYMATT MUSHALIK IGNORED02/15/2021 at 8:05
am
An interesting scenario showing what happens when demand outstrips supply due to lack of
investment is playing out right now in Oklahoma and Texas. There has been a lack of investment
in the region last year due to the drop in prices, and in Oklahoma, the slowing of investment
has been happening for a few years. The massive cold snap that descended on the region made
spot prices (not the futures price you can look up on Bloomberg etc) rise from $2 an MMBTU, to
$5, to $9, to $300, to $600, all in the course of a week. It is currently higher. The cold
weather has caused shut ins of wells, and processing plants. You have a situation where demand
is increasing but supply cannot keep up. I know this is a micro problem that will resolve
itself as temperatures increase, in the coming weeks, but this could be an example of what oil
prices might see in the near future. There has been a lack of investment for years in large
projects, if demand rebounds quickly as vaccine roll out continues, we will not be able to turn
back on new production fast enough to keep prices from running higher, resulting in some
temporary ridiculous price spikes. REPLYSHALLOW SAND IGNORED02/15/2021 at 10:31
am
I saw this resulted in a lot of wells that have been shut in for 5-10 years being
reactivated. REPLYGREENBUB IGNORED02/15/2021 at 8:25
pm
Shallow, are you affected by the cold snap or power outages? REPLYSHALLOW SAND IGNORED02/16/2021 at 12:41
am
Yes. We have about 10% frozen off. Our pumpers decided what to drain and shut in, and what
to keep on. They are real pros. You can't find better.
Our people are the key. We owe them bigtime. They have been out there in this stuff keeping
the rest from freezing.
We will be good soon, temps will come up.
Keep in mind, with one exception, our pumpers are 50+ years old.
Are there millennials that are going to keep the strippers going 24/7/365?
No. I work in construction biz. 90% of twenty somethings can't work five minutes without
looking at their phones. They are useless. All my buddies have the same complaint. REPLYOVI IGNORED02/15/2021 at 9:49
pm
An interesting clip from this article:
"This isn't a consensus view yet but it's quickly coming. Two heavyweights in the past week
have stepped up and called out the problem.
The first was Goldman Sach's Jeff Currie, who called the bull market in the early 2000s.
"I want to be long oil and hang on for the ride," Currie said in an interview with S&P
Global Platts on Feb. 5, warning "there is a lot of upside here."
"Is it back to $150/b? I don't know as it is a macro repricing we are talking about and
everything needs to reprice."
The other is JPMorgan and Marko Kolanovic, who said Friday that oil and commodities appear
to be entering a supercycle.
"We believe that the new commodity upswing, and in particular oil up cycle, has started,"
the JPMorgan analysts said in their note. "The tide on yields and inflation is turning."
"We believe that the last supercycle peaked in 2008 (after 12 years of expansion), bottomed
in 2020 (after a 12-year contraction) and that we likely entered an upswing phase of a new
commodity supercycle."
Shale driller bases rig lease costs on well performance
Rigs are typically rented out at a daily rate for a period of a few months, which has meant
less money for oilfield service providers as drilling becomes quicker and more efficient. So
Helmerich & Payne Inc. is touting a new pricing model based on overall well performance,
and almost a third of its U.S. rigs are now being leased on that basis, CEO John Lindsay said
Wednesday on an earnings call.
In the Permian Basin of West Texas and New Mexico, home to the busiest shale patch in North
America, operators are now drilling the same number of wells with 180 rigs as they were with
300 rigs a year ago, according to industry data provider Lium.
Yeah okay. That's all great. But what I was looking at was oil production. It's going down,
not up. With these prices oil production should be increasing, not decling. Why is that? After
all, that's really all that matters.
In ShaleProfile published today, the Permian is showing a slight bump up in production. It
may have hit bottom. The latest STEO is showing US production dropping till June and July
before beginning to increase. Looks like many more LTO wells have to be put on line before the
decline from all of the current wells can be offset. OVI IGNORED02/16/2021 at 6:36
pm
U.S. oil output plunges as Arctic air freezes Permian shale fields
(Bloomberg) –U.S. oil production has plunged by more than 2 million barrels a day as
the coldest weather in 30 years brings havoc to key producing states that rarely have to deal
with frigid Arctic blasts.
Oil traders and company executives, who asked not to be identified, lifted their forecasts
for supply losses from an earlier estimate on Monday of 1.5 million to 1.7 million barrels.
They said the losses were particularly large in the Permian Basin, the most prolific U.S. oil
region, which straddles West Texas and southeast New Mexico. Output cuts were also significant
in the Eagle Ford, in southern Texas, and the Anadarko basin in Oklahoma.
Two million barrels would be the equivalent of about 18% of overall U.S. crude production,
based on the most recent government data.
Wonder if this drop will show up as a drop in US inventories on Feb 24. While production is
down, so is driving.
Reminder back in the day in the Bakken they had to equip their onsite huge storage of
fracking water with heaters, because NoDak is cold. One suspects the Permian is not equipped
with that and widespread frozen pipe damage can be expected. HOLE IN HEAD IGNORED02/18/2021 at 8:31
am
There is a lot of reasons to be bullish on oil at the moment. There is one problem lurking
over next 4-5 months though. Treasury will shrink the TGA by about 1 trillion USD. Most assume
this will be bullish for most things other than the dollar. But as this cash gets pushed into
the economy/markets. Banks are forced to hold more collateral, mainly T bills. Short end of
treasury yield curve is without a doubt going negative as banks have to have collateral to
except all this cash. Likely another collateral shortage in the making (repo blowup) Fed would
likely have to cut QE purchases to get yields back into positive territory. Which is no
different than hiking interest rates on an economy with a massive debt load that can't handle
higher rates.
Most of the US government debt is on short end of the curve. Therefore most of the debt will
have a negative yield. This would likely end the reflation narrative/ inflation narrative we
currently have. It's likely dollar bullish because the collateral underpinning everything just
went negative yield. And if it turns out to be highly dollar bearish. Well lookout oil prices
would be well beyond the moon.
"... U.S. oil production has fallen more than 2 million barrels per day since March 2020. It will fall much lower. ..."
"... EIA's forecast is impossible. It does not account for the low level of drilling and for the high decline rates of U.S. wells. It seems more likely that production will drop by at least another million barrels per day below October's level later in 2021. ..."
U.S. oil production has fallen more than 2 million barrels per day since March 2020. It will
fall much lower.
Output has fallen from almost 13 mmb/d in late 2019 to below 10.5 mmb/d in October 2020
(Figure 1). EIA forecasts an increase in November to 11.0 mmb/d and then an average level of
about 11.1 mmb/d for the rest of 2021.
... ... ...
EIA Forecast is Impossible
EIA's forecast is impossible. It does not account for the low level of drilling and for the
high decline rates of U.S. wells. It seems more likely that production will drop by at least
another million barrels per day below October's level later in 2021.
... ... ...
What About DUCs?
Many reasonably expect that DUCs (drilled uncompleted wells) provide a solution to the lag
between drilling and production. There are, after all, about 5,800 DUCs in the main U.S. tight oil plays.
These are already drilled and could be converted into producing wells for the cost of
completion which is about half the total well cost.
Most DUCs, however, are uncompleted for a reason namely, that their owners don't believe
that their performance will be as good as wells that they chose to complete instead.
... It doesn't matter whether wells are newly drilled and completed or DUCs -- there are
simply too few wells being added to maintain present levels of production.
... ... ...
It is unlikely that the tight oil business will recover from the effect of Covid-19 and
lower oil prices. Markets will continue to send higher price signals until rig counts recover
to the 800 or so rigs needed to support EIA's 11 mmb/d forecast.
The public and many investors have the peculiar belief that the world will be just fine
without oil. The world will be fine. It has survived meteor impacts and mass extinctions
but humans are more fragile. Higher oil prices are the last thing the global economy
needs right now.
Art, I couldn't agree more. Commodities are rising and oil price is set to rise, in the
midst of a global economic crisis. A perfect storm is brewing and no amount of money printing
can fix that. If things take a turn for the worst the economic crisis could be followed by a
monetary crisis. Energy per capita and standard of living are going down for the majority no
matter what.
That could easily add a social crisis whose first signs we are all seeing. Peter Turchin predicted the increase in social instability 10 years ago in Nature Vol 46, 4 February
2010, pg 608.
The pandemic was just a catalyst for what was already brewing. We are living in
interesting times.
How will the USA regain its advantage in this world?
It will not.....
USA domestic petroleum liquids production is scheduled to drop to 5 million bbl / day by
july. Shale is loss making at prices less than $80 / bbl. Investors/banks have wised up. $$$
has dried up. There are no greater fools with $$ to burn... Drop in production ~ 45% / annum
exponential declining function.
US corporate governance favors quick returns via share buybacks stock kiting schemes
instead of product development. Boeing / GE / Lockheed / and other Fortune 500 firms not
hiring engineers, not developing new products. Experienced engineers going to China for work
or retiring. Shortly, US will not have enough petroleum geologists, mining engineers,
software engineers, hardware engineers, electrical engineers, civil engineers, chemical
engineers, etc to run it's industries.
Lawyers, political scientists, historians, economists... can't do the math.... are
useless....
Trump said "I like being energy independent, don't you? I'm sure that most of you noticed
when you go to fill up your tank in your car, oftentimes it's below two dollars "
But energy "independence" has got little to do with price at the pump. The marginal barrel
sets the price. If the world price for crude goes to $100/barrel, West Texas Intermediate is
going to the same level and gasoline will rise to $4.00.
Oil is at $40/barrel because the Gulf producers and Saudi Arabia want to insure a long
term market for their one export product while making a lot of high cost production
unsustainable and alternate energy sources less attractive.
Below are a number of oil (C + C ) production charts for Non-OPEC countries created from
data provided by the EIA's
International Energy Statistics and updated to May 2020. Information from other sources
such as the OPEC and country specific sites is used to provide a short term outlook for future
output and direction.
Non-OPEC production dropped slowly from a high of 52,638 kb/d in December 2019 to 52,396
kb/d in March 2020. In April that changed when we saw the first big drop in output from the
Non-OPEC countries associated with Covid and with the drop in world oil prices. May output
collapsed to 45,340 kb/d, which is close to the production level in September 2013.
The projection to September (red square) was made using the September STEO report. It
projects that after the low of 45,350 kb/d in May, production will increase by close to 3,500
kb/d to just under 49,000 kb/d in September.
Above are listed the worldʼs 15th largest Non-OPEC producers. They produced 83.6% of
the Non-OPEC output in May. On a YoY basis, Non-OPEC production was down by 5,011 kb/d. On a
MoM basis, production was down by 5,282 kb/d. World oil production was down by 11,418 kb/d, MoM
and 10,318 kb/d YoY.
May saw a drop in output to 2,765 kb/d but rebounded in June to 3,013 kb/d according to this
source . Maintenance and extensive turnarounds planned between September and November could
shave around 200,000 b/d from Brazil's output.
The EIA shows Canadian production was down in May by 658 kb/d by 248 kb/d to 3,694 kb/d. The
CER data is higher because it includes NGPLs in their estimates and is close to 6% of total
output.
Canadian oil exports by rail to the US fell from a high of 411,991 b/d in February to a new
low of 48,820 kb/d in June.
April 156,242 kb/d May 58,048 kb/d June 48,820 kb/d
At the same time, according to this
source , "The Trans Mountain pipeline carried a record-breaking amount of oil to British
Columbia from Alberta in August, despite persistent price and demand woes gripping the energy
sector as the COVID-19 pandemic drags on".
"We have been full every day during the COVID period. Demand for the pipeline has not
softened at all," he told The Globe and Mail in an interview Tuesday.
Chinaʼs production peaked in June-15 at 4,408 kb/d and has been in a steady decline up
to September 2018 where it reached an output low of 3,694 kb/d. According to this
source, Chinaʼs August production increased by 2.6% over last August. Output increased
by 59 kb/d to 3,899 kb/d (Red square). However August's output is still slightly lower than the
June 2019 output of 3,918 kb/d even though Chinese oil companies have increased their spending
to reduce the decline rate.
Kazakhstan production hit a new output high in February, 1,976 kb/d. For May, production
dropped by 203 kb/d to 1,738 kb/d. OPEC expects their output to drop by an average 15 kb/d this
year.
Mexicoʼs production decreased in May by 85 kb/d to 1,686 kb/d, according to the EIA.
Data from Pemex shows that production dropped to 1,647 kb/d in July (red square). Under the
OPEC + Declaration of Cooperation, Mexico committed to reduce output by 100 kb/d in May. Their
target was almost met.
The EIA reported that Norway's May production was 1,775 kb/d, a decrease of 14 kb/d from
April.
According to the Norwegian Petroleum Directorate, "average daily liquids production in July
was: 1 739 000 barrels of oil, 296 000 barrels of NGL and 27 000 barrels of condensate. (Red
lines)
On 29 April 2020, the Government decided to implement a cut in Norwegian oil production. The
production figures for oil in July include this cut of 134 000 barrels per day in the second
half of 2020."
In other words, if Norway hadn't made their commitment to reduce production, May's oil
output would have been (1,739 + 134) 1,873 kb/d. This output level would have been very close
to some earlier highs.
According to the Russian Ministry of energy, Russian production increased by 479 kb/d in
August to 9,860 kb/d. July was revised up by 11 kb/d from 9,371 kb/d to 9,382 kb/d.
UKʼs production decreased by 63 kb/d in May to 1,004 kb/d. According to OPEC, crude
production is expected to increase to 1,010 kb/d in June (Red square).
June's production rebounded from May's low by adding 420 kb/d according to the the EIA's
August report. May's output was revised up by 15 kb/d in the EIA's September report.
US and Permian oil rigs decreased by 1 to 179 and 121 respectively in the week of September
18. As a percentage, Permian oil rigs represented 67.5% of the total for the week of Aug
21.
According to the September DPR, the 121 rigs operating in the Permian in September will be
sufficient to raise production in September by 42 kb/d to 4,150 kb/d.
While WTI has remained close to $40/bbbl, there has been essentially no change in drilling
activity since the week of July 17 in the US. There were 180 oil rigs in operation that week vs
179 for the week of September 18.
These five countries complete the list of Non-OPEC countries with annual production between
500 kb/d and 1,000 kb/d. All five are in overall decline. Their combined May production was
3,263 kb/d down 232 kb/d from April's output of 3,495 kb/d. Azerbaijan, Indonesia and India
appear to be in a slow steady decline phase. Columbia's production began to drop in March as
Brent prices began to drop.
According to Colombia's minister of energy, Maria Fernanda Suarez, ANH president Armando
Zamora said if Brent oil prices hit around $35 a
barrel national oil output could average around 850,000 barrels a day, down from a previous
forecast of 900,000 barrels.
Guyana is a new oil producing country that started production in December 2019. According to
this s ource
, production was supposed to reach 120 kb/d by June. However gas re-injection issues have
delayed its planned production rise. Output in June is expected to be close to 80 kb/d (red
square). This new source for oil will offset some of the decline in other countries, which
currently is close to 400 kb/d/yr.
NON OPEC W/O US PRODUCTION
This chart shows that oil production in Non-OPEC countries has only increased by 541 kb/d
from December 2014 t0 December 2019. It is an indication that these countries as a whole are
approaching an output plateau. April is the first month in which the large production drop
associated with CV-19 and the plunge in oil prices shows up in this chart. In May 0utput from
these countries dropped by 3,293 kb/d to 35,348 kb/d.
Using information from the September STEO, output from the Non OPEC countries W/O the US, is
expected to rebound to 37,054 kb/d in September (red square). Looking further out to October
2021, output is predicted to reach 39,692 kb/d. (Blue graph). Note that the October 2021 high
is currently expected to be 143 kb/d lower than the December 2019 peak. The 143 kb/d difference
is probably well within the margin of error in making these projections.
World Oil
Production
World oil production in May decreased by 11,417 kb/d to 71,374 kb/d. This chart also
projects world production out to October 2020. It uses the September STEO along with the
International Energy Statistics to make the projection. It projects that world production will
recover by close to 5,000 kb/d in October 20202 to 76,019 kb/d.
This chart presents world oil production without the US. Note that the November 2016 peak is
two years prior to all the worldʼs peak shown in the previous chart. May production was
61,372 kb/d, a decrease of 9,429 kb/d from April.
Using the STEO and the EIA international Energy Statistics, output for September is
projected to be 63,768 kb/d, an increase of 2,396 kb/d higher than May.
1. Shale bust is here
- Shale wells decline somewhere between 70 and 90 percent from their initial peak within 3
years, with the bulk of that decline coming within the first 12 months.
- As a result, the pause in drilling quickly translates into U.S. oil production declines.
- "We just have no new drilling and these decline curves are going to catch up," Mark Rossano,
founder and chief executive officer of private-equity firm C6 Capital Holdings LLC, told
Bloomberg. "That hits really fast when you're not looking at new production."
- With no drilling at all, U.S. shale oil production would theoretically fall by more than a
third to less than 5 mb/d by the end of the year.
2. Bankruptcies to spike
- Between 2015 and 2019, there were roughly 200 bankruptcies in the North American oil and gas
sector.
- Through April of this year, there have been another 7 bankruptcies, according to Haynes and
Boone, although the value of the debt involved is 2.8 times larger compared to the first
quarter bankruptcies in 2019.
- Around 70 companies are on track for bankruptcy by the end of the year with WTI averaging $30
per barrel, according to Rystad Energy. If WTI remains stuck at $30, that total would rise to
150 to 200 by the end of 2021.
- "In our view, we will need WTI prices of $40 to $45 per barrel to eliminate the upcoming
explosion in the number of financially distressed US E&Ps, https://oilprice.com/Energy/Energy-General/The-Shale-Bust-Has-Arrived.html
It's now canonized in American public opinion, as the NYT has published an authorial
article (in the pedantic upper middle class I-wanna-win-a-Pulitzer style) about it:
For
most any nation, let alone a superpower, energy independence is considered the geopolitical
holy grail. So when fracking lured in American investors, everyone had high hopes the country
would finally break free of OPEC. But oil is a complex game, and 2020 saw sharp declines in
demand caused by the cartel's maneuvering, shale oil's oversupply, and now the devastating
effects of the coronavirus. What's worse, the startup mentality of the U.S. fracking industry
promised investors mythical growth and nonexistent returns. In the end, it burned a $340
billion hole in Wall Street's pocket. (Source: Bloomberg)
"... "Well, I think it's automatic. Because they're already cutting. I mean, if you look, they're cutting back. Because it's it's market. It's demand. It's supply and demand. They're already cutting back, and they're cutting back very seriously," ..."
The United States is on track to cut 1.7 million barrels of oil production per day,
according to Reuters calculations of state and company data shared on Thursday. It was US
President Donald Trump that suggested
at the beginning of April, prior to the most recent OPEC deal signing that the United
States would cut its oil output as a natural response to the worsening market conditions. The
statement was not initially good enough for OPEC, who wanted more of a commitment from the
world's largest producer and consumer of crude oil.
"Well, I think it's automatic. Because they're already cutting. I mean, if you look,
they're cutting back. Because it's it's market. It's demand. It's supply and demand. They're
already cutting back, and they're cutting back very seriously," US President Trump said at
a press briefing early last month.
US Energy Secretary said last month that the DoE expected that production in the United
States would fall by between two and three million bpd by the end of the year -- it appears the
cuts have come even quicker than the department expected.
The need for the production cuts grew more evident as the United States shut down nearly all
activity in an attempt to flatten that curve of infections that sought to overwhelm the
country's healthcare system. Doing so, however, has idled much of the economy and crippled
demand -- and as such, its oil and gas industry that fuels that economy.
The cuts from US producers may seek to quiet the disgruntlement of OPEC and Russia, in
particular, who expressed their displeasure that the US would not require its producers to curb
production. After all, the US shale industry has benefited greatly from previous rounds of OPEC
cuts.
On Monday, the price of West Texas Intermediate petroleum fell below
$30 a barrel for the first time in four years.
Elliot Smith at CNBC reports that BP CFO Brian Gilvary is braced for petroleum demand
actually to contract in 2020.
This prediction is very bad news for US fracking firms, most of which need a price point of
from $40 to $60 a barrel to make their hydraulic fracturing method of oil production
profitable.
In the Democratic primary debate on Sunday, Bernie Sanders pledged to ban fracking entirely,
and even Joe Biden said no
new fracking would be allowed. Fracking may be moribund anyway by November, and if a
Democrat wins the presidency, the industry may never recover.
Not only is petroleum likely headed way below that profitability floor, but many energy
firms involved with fracking are deeply in debt, and had taken out the debts with their
petroleum fields as collateral. Since their collateral is worth only half what it used to be,
the banks will call in their loans. Other energy firms involved in fracking have held
significant assets in their own stocks, the price of which just zoomed to earth like a crashing
meteor.
Fracking has been banned by countries such as France, and by states such as New York because
it is highly polluting, leaving behind ponds of toxic water. Moreover, research has
demonstrated that the process of fracking, which involves pumping water under high pressure
underground to break up rocks and release oil or natural gas, causes gargantuan
methane emissions that had earlier been underestimated as much as 45% . The
methane in the atmosphere is burgeoning, and scientists had puzzled over why. But scientists
have fingered the culprit: fracking. Methane is 80 times as potent a heat-trapping gas as
carbon dioxide over two decades, and carbon dioxide is no slouch. A quarter of the global
heating effect of greenhouse gas emissions put out by humans burning fossil fuels is owing to
methane emissions. Rapid heating is melting the North and South Poles, causing sea level rise
that will soon be calamitous.
Given that the world population is increasing and that developing countries such as China
and India and Indonesia are seeing more and more people abandoning their bicycles or bus rides
for mopeds or automobile ownership, for the world to want less petroleum this year than it did
last is extremely unusual.
We are getting a preview courtesy COVID-19 of what will happen through the next decade and a
half as electric vehicles take off, significantly reducing demand.
The world produces about $100 million barrels of petroleum a day, and given the Saudi
determination to expand production starting on April 1, it could be producing 102 million
barrels a day later this spring. The world may only want
90 mn. barrels a day this spring. What with the novel coronavirus pandemic, fewer trucks
and cars will be on the road. Petroleum is largely used for transportation fuel.
Do you know what happens if demand falls and production increases? The price falls. In fact,
it doesn't just fall. It collapses. It takes a deep dive. It falls off a cliff. It craters deep
beneath the earth's crust.
How steep the fall is depends in part on whether Saudi Arabia and Russia keep playing
chicken. Saudi Arabia wants to discipline Moscow, which rejected OPEC + production quotas aimed
at reducing supply and supporting a $60 per barrel price. So Riyadh is opening the spigots,
upping its production by two million barrels a day. Saudi Aramco says it is comfortable with a
price point of $30 a barrel. But unfortunately for Aramco, the price may not have stopped
falling.
Andreas de Vries at
Oilspot.com believes the price could fall to as little as $10 a barrel later this spring.
In 2019 the price tended to be around $60 a barrel.
The fossil fuel companies that lack deep pockets could well just fail this year.
Brenda Sapino Jeffreys quotes Jason Cohen, an attorney at Bracewell in Houston, as saying
of the oil industry, "There is, I'd say, a sellers market for bankruptcy talent." His
observation gave me my title.
This steep decline in stock prices and oil prices comes on top of a 5-year run in which the
market has destroyed 90% of the value of US investor stocks in oil services. That is, we could
this year be entering an oil market crisis as severe as the
Asian banking crash of 1997-1998 .
The difference is that by the time fossil fuels come out of their economic doldrums,
renewables will have stolen a further march on them. From here on in, hydrocarbons are
beginning their death spiral. Friends don't let friends invest in petroleum companies, and
nobody should have those stocks in their retirement accounts– if they want ever to
retire.
Colonel, you are NOT wrong. The oil business in America is going to take a very long time to
recover. There are complete shutterings of businesses, bankruptcies and more - all while we
were in the middle of a downturn. Personally, I just folded up my tent because my my active
client list went from 21 to zero over this last month (and that includes intl clients).
As the number one buyer of US steel, the oilpatch represents much more than people
realize. We have also been the number one buyer of many other items - where sales have
disappeared as company quietly and reluctantly face the reality of the current induced
glut.
I'm being forced to change livelihoods - interesting for me, as I am short of the age to
get my SS check and too old to employ by most corporate masters....
div
This (oil + the virus) is looking like an economic Pearl Harbor for shale oil industry
This (oil + the virus) is looking like an economic Pearl Harbor. I think BRICS is playing a
far better game of chess so far and will win if we don't replace The Swamp with dedicated
people with vision and smarts and who put country above cronyism and self-enrichment.
What has the fluctuating price of oil got to do with peak oil? One is reflection of demand,
plus manipulation of the price by producers, and the other has to do with the long term rates
of extraction relative to the creation of new reserves by deposition of marine micro-organism
and there decay under pressure and temperature conditions only geological time scales. the
two are as similar as the price of fish and oranges.
You were spot on about Peak Oil. US shale will not die. While shareholders and bond
holders will take a haircut today, the extraction technology will continue to improve and
their costs of production will decline. As oil prices improve shale production will return.
The US is in a strong position as it doesn't have to be concerned about oil at least for the
next several decades.
From a supply/demand perspective, oil density in the west will continue to decline as our
economies become more efficient and as solar and nuclear becomes more cost competitive for
electricity generation.
An investment maxim is to buy when there's blood in the streets. We will continue to use
oil for at least another couple generations IMO.
The big issue in the short term is going to be the drastic impacts for those economies
entirely dependent on crude revenues. The last time crude prices were lower for a sustained
period the Soviet Union collapsed. MbS is running massive budget deficits as he keeps his
population from revolting against the monarchy. One possible good outcome is there's going to
be less funding for the jihadists in the short term.
There is oil out there and there will be for a long, long, time. The only determining factor
is the price to get it out of the ground. Here in North America fracking has opened the
spigot but the price is $40+ a barrel to get it out of the ground.
What I can't fathom is why Canada is pushing through with the Keystone XL pipeline taking
tar sands oil from Alberta to Nebraska and eventually to the gulf coast.
Obama put the stop to it but the Trumpster reversed his executive order and they started
building again this month, although a federal judge just stopped it due to environmental
review.
Several years ago I read that tar sands oil costs $70+/barrel and that doesn't include
shipping cost. Does Canada know something about the future price of oil or are they just
subsiding their oil companies/workers? I sure wouldn't invest in it.
"... JPMorgan Chase & Co, Wells Fargo & Co, Bank of America Corp and Citigroup Inc are each in the process of setting up independent companies to own oil and gas assets, said three people who were not authorized to discuss the matter publicly. The banks are also looking to hire executives with relevant expertise to manage them, the sources said. ..."
"... U.S. oil and gas producers have increasingly relied on banks for cash over the past year, as debt or equity options dried up. Lenders have been conservative in valuing hydrocarbons used as collateral, but recent restructurings have left them spooked. ..."
NEW YORK (Reuters) - Major U.S. lenders are preparing to become operators of oil and gas
fields across the country for the first time in a generation to avoid losses on loans to energy
companies that may go bankrupt, sources aware of the plans told Reuters.
JPMorgan Chase & Co, Wells Fargo & Co, Bank of America Corp and Citigroup Inc
are each in the process of setting up independent companies to own oil and gas assets, said
three people who were not authorized to discuss the matter publicly. The banks are also looking
to hire executives with relevant expertise to manage them, the sources said.
The banks did not provide comment in time for publication.
Energy companies are suffering through a plunge in oil prices caused by the coronavirus
pandemic and a supply glut, with crude prices down more than 60% this year.
Although oil prices may gain support from a potential agreement Thursday between Saudi
Arabia and Russia to cut production, few believe the curtailment can offset a 30% drop in
global fuel demand, as the coronavirus has grounded aircraft, reduced vehicle use and curbed
economic activity more broadly.
Oil and gas companies working in shale basins from Texas to Wyoming are saddled with
debt.
The industry is estimated to owe more than $200 billion to lenders through loans backed by
oil and gas reserves. As revenue has plummeted and assets have declined in value, some
companies are saying they may be unable to repay.
Whiting Petroleum Corp became the first producer to file for Chapter 11 bankruptcy on April
1. Others, including Chesapeake Energy Corp, Denbury Resources Inc and Callon Petroleum Co,
have also hired debt advisers.
If banks do not retain bankrupt assets, they might be forced to sell them for pennies on the
dollar at current prices. The companies they are setting up could manage oil and gas assets
until conditions improve enough to sell at a meaningful value.
Big banks will need to get regulatory waivers to execute their plans, because of limitations
on their involvement with physical commodities, sources said.
Banks are hoping their planned ownership time frame of a year or so will pass a Federal
Reserve requirement that they do not plan to hold assets for a long time. Because lenders would
be stepping in to support part of the economy that is important to any potential rebound, and
which has not gotten direct bailouts from the federal government, that might help applications,
too.
For now, the banks are establishing holding companies that can sit above limited liability
companies (LLCs) containing seized assets. The LLCs would be owned proportionally by banks
participating in the original secured loan.
To run the oil-and-gas operations, banks might hire former industry executives or specialty
firms that have done so for private equity, sources said. Houston-based EnerVest Operating LLC
would be among the most likely operators, sources said.
"We regularly look for opportunities to operate on behalf of other entities, that is no
different in this market," said EnerVest Operating's chief executive, Alex Zazzi.
GETTING ASSERTIVE
U.S. banks have not done anything like this since the late-1980s, when another oil-price
rout bankrupted a bunch of energy companies. More recently, they have relied on restructuring
processes that prioritize them as secured creditors and leave bondholders to seek control in
lieu of payment.
But banks are becoming more assertive because of the coronavirus recession and balance sheet
vulnerabilities that have developed in recent years.
U.S. oil and gas producers have increasingly relied on banks for cash over the past
year, as debt or equity options dried up. Lenders have been conservative in valuing
hydrocarbons used as collateral, but recent restructurings have left them spooked.
Alta Mesa Resources' bankruptcy will likely provide banks with less than two-thirds of their
money, while Sanchez Energy's could leave them with nothing.
The structures banks are setting up will take a few months to establish, sources said. That
gives producers until the fall - the next time banks will evaluate the collateral behind energy
loans - to get their houses in order.
After several years of on-and-off issues with energy borrowers, lenders have little choice
but to take more dramatic steps, said Buddy Clark, a restructuring partner at law firm Haynes
and Boone.
"Banks can now believably wield the threat that they will foreclose on the company and its
properties if they don't pay their loan back," he said.
(Reporting by David French and Imani Moise in New York; Additional Reporting by Elizabeth
Dilts Marshall; Editing by Leslie Adler; Editing by Lauren Tara LaCapra)
Trump announced that he would use the cheap prices to fill the U.S. strategic oil reserve.
But the spare room in the reserve storage at that time was only some 150 million barrels.
As it can only be filled at a rate of 2 million barrels per day the topping off of the
reserve is insignificant in the current market.
The oil producers at first pumped their oil into storage tanks to be sold later. When
those filled up they rented supertankers to store the oil at sea. But empty supertankers
are now also getting rare and the price for them
is increasing :
The CEO of the world's largest tanker owner, Frontline Ltd., said on Friday that he'd
never known such demand to hire ships for long-term storage. Traders could book ships to
put 100 million barrels at sea this week alone, he estimated, but even that could
accounts for less than a week's oversupply.
The only solution will be a shut down of the more expensive oil fields. Canada and
Brazil are already doing it. U.S. shale producers who are bleeding cash will now have to
follow.
As soon as U.S. shale leaves the market, prices will rebound and could reach $60 a
barrel, Rosneft's Igor Sechin said recently. As fate would have it, in what many would
have until recently considered an impossible scenario, a lot of U.S. shale might do just
that.
Breakeven prices for U.S. shale basins range between $39 and $48 a barrel, according
to data compiled by Reuters. Meanwhile, West Texas Intermediate (WTI) is trading below
$25 a barrel and has been for over a week now.
The Trump administration has asked the Saudis to
produce less oil but as the Saudi tourist industry is currently also dead the Saudi clown
prince needs every dollar he can get. The Saudis will continue to pump and they will sell
their oil at any price.
The White House is now concerned that it will completely lose its beloved shale oil
industry and all the jobs connected to it.
A new OPEC+ deal to balance oil markets might be possible if other countries join in,
Kirill Dmitriev, head of Russia's sovereign wealth fund said, adding that countries
should also cooperate to cushion the economic fallout from coronavirus.
...
"Joint actions by countries are needed to restore the(global) economy... They (joint
actions) are also possible in OPEC+ deal's framework," Dmitriev, head of the Russian
Direct Investment Fund (RDIF), told Reuters in a phone interview.
...
"We are in contact with Saudi Arabia and a number of other countries. Based on these
contacts we see that if the number of OPEC+ members will increase and other countries
will join there is a possibility of a joint agreement to balance oil markets."
Dmitriev declined to say who the new deal's members should or could be. U.S. President
Donald Trump said last week he would get involved in the oil price war between Saudi
Arabia and Russia at the appropriate time.
A logical new member of an expanded crude oil cartel would be one of the biggest global
producer that so far was not a member of that club - the U.S. of A.
We now learn that Trump is ready to talk about
that or other concepts:
As Ria reports (in Russian) the
topics of upcoming phone call [between Putin and Trump] will be Covid-19, trade (???)
and, you guessed it, oil prices.
Trump, who sanctioned the Russian-German Nord-Stream II pipeline while telling Germany
to buy U.S. shale gas, is now in a quite bad negotiation position. Russia does not need a
new OPEC deal right now. It has many financial reserves and can live with low oil prices
for much longer than the
Saudis and other oil producing countries. Trump would have to make a strategic offer
that Russia could not resist to get some cooperation on oil prices.
But what strategic offer could Trump make that would move Putin to agree to some
new deal?
Ukraine? Russia is not interested in that
unrulable , bankrupt and fascist infested entity.
Syria? The Zionist billionaires would stop their donations to Trump if he were to give
up on destroying it.
Joining an OPEC++ deal and limit U.S. oil production? That would be an anti-American
intervention in free markets and Congress would never agree to it.
And what reason has Russia to believe that Trump or his successor would stick to any
deal? As the U.S. is non-agreement-capable it has none.
The outcome of the phone call will therefore likely be nothing.
The carnage in the oil markets will continue and will ravage those producer countries
that need every penny while the corona virus is ravaging their people. Meanwhile the U.S.
shale market
will go bust . US financial companies had a big exposure to the Shale Oil frackers.
Good thing trillions of dollars of 'liquidity' has been shoveled their way.
FWIW:
One aspect of the crude complete collapse is to keep an eye on futures and the serious
contango at the moment: contango=prices on future contracts are higher than current
contract.
e.g. May 2020 CL contract=~$20, May 2021 =~$35.50.
Someone or someones are betting that the crude market will improve, i.e. they are
storing crude in very large crude carriers (VLCC) @>$200k per day lease cost. That is a
serious commitment/bet on future price/mkt improvement.
Unmentioned is the connection between Fracking Fraud and the Bond Market Bubble with
Congress actively intervening/abetting the Fraud by providing more money to the Ponzi
Scheme.
It was time. The shale industry already was a huge bubble even when oil prices were at USD
60.00 (because it had to borrow a lot to invest, and the more wells drilled, the lower was
the oil output per USD invested), which insiders in Wall Street were already discussing how
to burst it.
And this is a 100% intentional by the Russians. If American shale really go down, then
it would be ironic, since it was the oil crisis of 1975 that effectively ended the Soviet
Union.
Another factor going against the shale fracking pipe dream is that the Strategic Petroleum
Reserve (SPR) is filled with real oil. Fracking produces light condensate (not oil) that
does not meet this criteria, and thus the frackers will not benefit from filling the SPR
(unless Trump changes the rules)
A study by the Wall Street Journal concluded that in one ten year period, the shale oil
companies' total costs had exceeded their revenues by two hundred and eighty billion
dollars. They have stayed in business by issuing new stock and more debt to cover their
losses. Their prime fields are seeing production declines. Their costs are rising as the
price of is oil tanking. Collapse is imminent. It's going to have far-reaching
consequences.
Yet another example of the utter intellectual bankruptcy of the US ruling class. They've
been playing a rigged game for so long, they've forgotten how to think.
As others here have pointed out, not to worry, the US fracking industry will get bailed
out.
The real thing the US might do, is not to join an expanded OPEC+, but to limit imports
of foreign oil and protect the domestic industry. Contrary to current 'free trade' dogma,
protectionism does work (example A: the United States from 1776 to 1970. Any questions?),
but classically you want to limit imports of MANUFACTURED goods and keep the cost of raw
materials low. Increasing the relative costs of raw materials in the US while still
allowing mass importation of manufactured goods from low-wage nations is anti-Hamiltonian
and will crush what remains of US domestic manufacturing..)
Not sure the US shale market can "go bust" as such. The owners can go bankrupt, but that
just means banks and bondholders become the new owners, and their debt investment suddenly
turns into equity investment with zero gearing. Once that happens the US shale producers
become solid companies financed with zero debt and no incentive to hold back on production.
They pump and pump and pump until the pumps no longer work.
Sure, no new developments, but the existing infrastructure will last a few years yet.
I don't see a way out for the US fracking industry. Their product is too expensive in the
current times, and those setting the rules in these times (Russia and Saud Arabia) have no
good reason to help.
The social damage from a collapse in the US will be papered over with printed money. I
don't know how that will play out.
One scenario is time being called on the US's forever-wars in the Middle East, but would
they be replaced by an invasion of Venezuela? There is good stuff down there, as well as
the heavy stuff they've been pulling out. And just across the border into Brazil there is
some high ground that looks like a good spot to build a command post.
The US could cut its losses in the wider world, something that seems to be happening
anyway, and return to America, north and south. I don't see it just quietly going down the
gurgler, but the European Union might.
Of course it is already a war. The question I ask is, who is fighting and against whom?
The tactical aim at the moment is the end of the petro-dollar. A secondary aim is finding a
limit to US militarism. Which in turn depends on the pork.... soorry.... the grifting of
large sums of unlimited largess. Third, is trade and domination of markets including
sanctions and "treaties". Fourth, is the "domination" of population dissent and overriding
Judicial systems.
So the US, China and Russia are at it "hammer and tongs" (old saying but apt). Covid is
just one means to an end, regime change another. Who else is in the fight? I would suggest
that the Oligarchy and the Termites, the Fed and the deep parallel financial pool, the
uncontrolled but unified intelligence "agencies", all have their own agendas.
"The slow collapse of the US position in Iraq means that the US is not going to hold
those oil-fields for too long."
Remember where this oil is going to. During the previous presidential term, it was
discovered that the oil was going into Turkey, aided and abetted by the profiteers Erdogan
and his son, and then onto oil tankers that shipped it to Occupied Palestine. Current
production is also going into Jordan, where it is being shipped by pipeline into the
refinery in Eliat(?). I can only surmise the price to be extremely cheap.
So the inhabitants of Occupied Palestine will expect the US to maintain this flow as
long as they can, come hell or dead GIs.
The problem with shale became clear right after the first wells were drilled.
If I understood the reports from the "shale bubble" website correctly, originally the
magic over shale gas and oil came from the fact that Wall Street was involved since the
beginning (so it was a "coastal elites/heartland rednecks alliance" from birth) and the
expectation was that a horizontal well would perform the same way as the traditional
vertical well.
A traditional vertical well follows are normal curve graphic, imitating a hill. It
starts low, but keeps growing until reaching a peak, maintains this peak for a while (some
decades) and then begin a suave fall, which also takes decades.
No wonder, then, the huge euphoria that started in Wall Street when those horizontal
wells begun pumping out oil at absurd quantities - they imagine that was the output floor
of such wells, and that productivity would only rise after the decades. Indeed, it was
predicted at the time that the USA not only was firmly walking towards self-sufficiency -
many also predicted it would become the world's greatest oil exporter (yes, above Saudi
Arabia, Venezuela, Russia etc.).
But this euphoria was short-lived, as, some years later, productivity of the horizontal
wells begun to suddenly fall. It was then realized, after further research, that those
wells performed differently than the vertical wells: they begun directly with peak
production, then immediately started to fall. Their output graphic looks like an
upside-down, slightly inclined letter L.
Even after this discovery, the investors didn't immediately give up. They thought: let's
just drill longer wells. And they did. It was then that another problem came out: it seems
that, after 3-5 miles, those horizontal wells suddenly lose a lot of pressure necessary to
pump the oil out of it. To make things worse, after this length, they begin to suck out
pressure from the neighboring wells as well. Therefore, it is a self-defeating enterprise
to extend the horizontal wells beyond 3 miles length. And the situation is even direr
because shale reserves are usually concentrated in one specific area - it's not like you
can drill one horizontal well in Ohio and another one in Florida and so on: the rule of
thumb that the oil and gas "must be there" to be extracted in economically viable
quantities still do apply to horizontal wells.
After that, all that kept the American shale industry alive was Wall Street and its
rotten papers recycling machine.
A friendly reminder to all barflies that fracking within the Outlaw US Empire also takes
more energy to operate than the energy extracted. The business was bankrupt before it
began, and nothing can change that fundamental fact.
"I believe that yuan pricing of oil is coming and as soon as the Saudis move to accept it
-- as the Chinese will compel them to do -- then the rest of the oil market will move
along with them," Carl Weinberg, chief economist and managing director at High Frequency
Economics, told CNBC
Also, recall the recent ARAMCO IPO, reportedly China took a 5 % stake. Hmmm. Was it with
USTs?
The minute the Al Saud family begins accepting yuan for oil their days are numbered.
The US put them there, put the Saudi in Saudi Arabia. Any move to accept yuan will be seen
as betrayal, and the Al Sauds will be removed, either replaced or simply obliterated.
Posted by: Realist | Mar 30 2020 23:21 utc | 86
+++
If Saudi Arabia shifts to the Yuan, it would have to diversify away from buying US arms.
They might be the undisclosed buyer of high-end Chinese missiles, said to have an "urgent
need" for them, as per Chinese media on 2020/3/29. This news might be functioning as
diplomatic signalling.
It was the first time a third-generation anti-tank weapon system developed by the Chinese
company has been exported, according to the statement.
As the client was in urgent need of the missiles, the successful delivery had
significant meaning for establishing Norinco's (China North Industries Group Corporation)
market position and further opening up the market, the company said.
Norinco did not disclose more details on the deal in the statement, including the name
of the buyer, the quantity purchased and the value of the deal.
The US put them there, put the Saudi in Saudi Arabia. Any move to accept yuan will be
seen as betrayal, and the Al Sauds will be removed, either replaced or simply
obliterated.
You hug that thought. Newsflash: The horses camels have already bolted. China is
expanding its presence/influence in ME.
These 35 agreements with KSA,'centered around ways to align the Saudi Vision 2030 with
the Chinese Belt and Road Initiative' will not be in USD - unless China is unloading USTs.
There is nothing US can do except sell more arms to the kingdom. Reuters, WSJ reported the
big signing and likely, CNN, Fox, ABC buried it.
The meeting took place in the grand surroundings of the Great Hall of the People in
the Chinese capital Beijing. After their talks, the crown prince headed the Saudi
delegation at the third session of the China-Saudi Arabia High-Level Joint Committee
which he co-chaired with Zheng.
Delegates at the meeting discussed moves to strengthen cooperation between the two
countries on trade, investment, energy, culture and technology, as well as the
coordination of political and security matters. The committee also reviewed plans for
greater integration between China's Belt and Road development strategy and the Saudi
Vision 2030 reform program.
After agreeing on the minutes of the meeting, the Saudi royal and Zheng took part in
the signing of a range of agreements, memorandums of understanding (MoU), investment
projects and bilateral cooperation accords between the Kingdom and China:[.]
MoU between the Kingdom's Ministry of Energy, Industry and Mineral Resources and the
National Development and Reform Commission in China, signed by Saudi Energy Minister
Khalid Al-Falih and Ning Jizhe, vice chairman of the National Development and Reform
Commission.
MoU between the Chinese Ministry of Commerce and Saudi Ministry of Commerce and
Investment to form a working group to facilitate trade, signed by Abdul Rahman Al-Harbi,
the Kingdom's deputy minister of commerce and investment, and Qian Keming, Chinese vice
minister of commerce.[.]
Deciphering the mental processes of MBS is always speculative, but it is very hard for KSA
to deliver on the threat to increase the deliveries by 2.5 mln bbl/day. As we can see,
planes fly only a fraction of pre-virus level, people on quarantine drive much less, you
can offer fuel for free and it will not sell more. Now, if you could offer some hand
sanitizer and facial tissues with each "full tank", perhaps it could work... But stopping
oil production is troublesome for some reasons, to the ignorant me it seems that if you
interrupt flow dynamic of oil, it is troublesome to restart it, shale oil may suffer from
something similar. Thus tanker ships are being filled up and used for storage as
destination ports refuse to take cargoes invoking "higher power". Hapless KSA cannot find
enough tankers, and when they find them, hard to find a port to accept them. So KSA
combative threat could impact psychology of the traders, but the virus made a dent in
demand of several times larger magnitude.
Nobody knows how long the demand will stay low, but as it does, storage will be
bursting, renting tanker ships became expensive. so the glut it will take time to dissipate
(folks renting the tanker ships will be pressed to get rid of the cargoes at the first
opportunity), and with no coordination to cut the production, low prices may stay for a
year or more. This seems necessary to cut shale oil and other high cost oil project down to
size. Periodic down period of pricing does not change long term calculations, but long
periods will drive a lot of small players out of business. This means so-called
consolidation, creditors become owners and sell it to vultures (regular folks cannot own
something that costs more to maintain than it brings revenue). And what do the vultures do?
"Paring excess capacity". Happened to many industries in the past. And even brainless
bankers will give it two thoughts before lending money for projects in high cost oil
production.
BTW, Putin is doing a gently MBS-like manouver, with the assist from Trump. To wit,
Russia started to tax repatriated profits -- no need to imprison the account holders in
Ritz Carton. But why would they be motivated to repatriate the profits back to Mother
Russia? A patriotic virus? Or pestering with account freezes that Trumpian robbers are so
fond of doing?
One mystery for me is why Canadians bother to produce oil with single-digit prices.
Stopping tar oil production should be simple, just mothball the equipment.
One rumour in the oil patch is that USG will give them bail out. That could be a boon
for green thinking idealists who are hostile to carbon energy production, because many
deplorables do not like bailout (unless they are the beneficiaries). This could allow Trump
to be defeated by a brain dead opponent.
"Bloomberg reports that Plains All American Pipeline asked its suppliers to scale back
production,
and Plains and Enterprise Products Partners is requiring customers to prove they have a
buyer or place to offload the crude they are shipping
The companies made the requests during the past week.
This is a clear sign that a growing glut of crude is overwhelming storage capacity.
Pipeline companies are running out of storage space for oil. Coronavirus related lockdowns
are resulting in plunging demand."
It is payback time for Russia no doubt, but Russia plays always the long game, any decision
or concession will always be related to the long game. for Russia, which is the global
leader in energy supplier (oil, gas & nuclear).
Russia got really mad with the Nordstream II delay, this is something Russia will not
forget that easy, besides costing them a lot, it was some sort of global humiliation, that
combination is pure fire. Even if the sanction are lifted now, Nordstream would start late
2020 and not late 2019....1 year delay anyway, so lifting sanctions won't matter here.
My first reaction is that Russia will not agree with the USA in anything, it will drive the
shale market dry for a little longer, it must if it wants to cause long term problems for
the players in the US, so no short term relieve for the shale players here, and if Russia
does agree in the OPEC++ with the US and other export players then this will take time, and
then US Gov can not intervene in the local production, more time...and no results, at the
end the US will have to give up something, and I do not think lifting sanctions will be it,
they may try it, bit it has no real value for Russia....only a global military retreat,
something that will cost dearly, politically and in image will. serve Russia and its key
strategic ally...China, mind you that cheap oil and gas helps China's recovery...March nbrs
came in from China and it has already shown a better recovery than expected.
This is the only way I can see Russia playing the long game, together with China and a
major strategic geopolitical defeat for the US.
They're going to have to bail out/nationalize the shale oil industry.
Or "They" could just ignore it.
It has achieved these outcomes – despite steep decline rates and a constant need
for huge numbers of new wells – through massive levels of junk debt forced into
existence by almost zero interest rates and by having little to no profits since 2008.
Sounds like a really rotten business model. "steep decline rates and a constant need for
huge numbers of new wells" describes an industry in eclipse, to put it kindly.
The break-even for shale oils wells varies, but $70 a barrel is a good average
figure.
Even worse. This 'business' is essentially fake and should be shuttered. Every dollar
thrown at it will be wasted. If everything in the world somehow reverses itself one day and
shale oil is once again needed, we can restart it. Won't happen, though. Obsolete.
@Kim One part of the New Deal, that seemed to work very well for all parties concerned,
was the Department of Agriculture's willingness to buy up excess grain/dairy production in
order to encourage an ample supply of grain/dairy and a sustainable price, so that farmers
could get out of the boom/bust cycle. These excess stores were intended to provide supplies
when weather or disasters disrupted the harvests. The AG Dept. also established guidelines
for farmers on how much acreage should be allocated to which type of food product, based upon
its own estimates of aggregate demand and needs for strategic reserves. It even paid farmers
to keep acreage fallow at times.
The Department of Energy could do something similar (provided the Congress should
legislate it). For this to work, the government must limit foreign sources from supplying the
US markets to serve only as augmentation to US energy production whenever/wherever the US
energy producers can't meet the demand at the price level that the Energy Department sets. If
the price is determined on an average COST+ ROI basis, our energy producers would effectively
become utilities.
They're going to have to bail out/nationalize the shale oil industry.
Why? These were private failed investment decisions, so let the industry go bankrupt along
with their shareholders and junk bond investors.
The world doesn't need oil supplied at $70 – And what has this got to do with the US
public? They didn't make these shale oil investment decisions.
TBTF (Too Big To Fail) is another fake argument. If the investment banks had been allowed
to fail in 2008, we would now have a smaller and more prudent banking sector. There are
always some serious banks out there to pick up the pieces.
"The U.S. shale sector is getting completely killed. A complete bloodbath. Billions of
dollars in equity wiped out.
"Occidental Petroleum is down 44%. EOG is down 35%. Continental Resources down 40%.
Smaller players like Parsley down more than 50%."
I suggest this bird look at one of those corp's balance sheets since they had very little
equity but lots of liabilities (Assets=Liabilities+Equity) as Assets and Liabilities where
allowed to grow with the use of interest-free money to keep the Ponzi Scheme afloat. Also
recall that CEOs often get paid in shares which get dividends. Often those dividends are paid
using the zero interest loan money leaving the corp with a bigger, unstable pile of debt and
the CEO with a purse fattened by the loan instead of actual company performance, ie,
profits.
Soon people won't have to worry much about damage from new wells. Instead they will have
to worry about existing-and-soon-to-be-abandoned wells. This is already a huge problem in
Alberta, where "it's estimated that more than 155,000 Alberta energy wells have no
economic potential and will eventually require reclamation".
But not to worry. It will only cost $47 Billion for Alberta to clean up
the mess .
No surprise that it is worse in the US. I couldn't quickly find a cost estimate.
Nobody knows how many orphan and abandoned drilling sites litter farms, forests and
backyards nationwide. The U.S. Environmental Protection Agency estimates there are more
than a million of them. Unplugged wells can leak methane, an explosive gas, into
neighborhoods and leach toxins into groundwater.
"... As Fastow explained, in finance, the difference between a loophole and fraud isn't always easy to identify. And that may be something the U.S. fracking industry is working to its advantage. ..."
Posted on March 6,
2020 by Yves
Smith Yves here. It really is remarkable how super low interest rates have led investors on
a widespread basis to pour money down ratholes. Unicorns is one. Another has been fracking,
which despite being another widespread cash sink, remarkably has kept sucking in funding.
As we pointed out in 2014 :
John Dizard at the
Financial Times (hat tip Scott) gives a more intriguing piece of the puzzle: the degree
to which production is still chugging along despite it being uneconomical. The oil majors
have been criticized for levering up to continue developing when it is cash-flow negative;
they are presumably betting that prices will be much higher in short order.
But the same thing is happening further down the food chain, among players that don't
begin to have the deep pockets of the industry behemoths: many of them are still in "drill
baby, drill" mode. Per Dizard:
Even long-time energy industry people cannot remember an overinvestment cycle lasting as
long as the one in unconventional US resources. It is not just the hydrocarbon engineers
who have created this bubble; there are the financial engineers who came up with new ways
to pay for it.
Justin Mikulka argues that one reason these persistently unprofitable fracking companies
keep going is via fraud.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg,
NY. Originally published at DeSmogBlog
In a 2016 interview with Fraud Magazine , former Enron
CFO Andrew Fastow explained what he thought made him so successful while at the former energy
corporation that's now infamous for financial scandal.
"I think my ability to do structured financing, to finance things off-balance sheet and to
find ways to manipulate financial statements -- there's no nice way to say it. Like I said at
the conference, I was good at finding loopholes."
As Fastow explained, in finance, the difference between a loophole and fraud isn't always
easy to identify. And that may be something the U.S. fracking industry is working to its
advantage.
Fastow, the convicted fraudster, does admit that what they did at Enron misled investors.
"We created something that was monstrously misleading, but any one of those deals alone wasn't
necessarily considered fraudulent," he said.
Fast-forward to today and a different part of the energy industry: The U.S. shale oil and
gas industry has lost more than a quarter trillion dollars since 2007, while being sold to
investors as an economic boom, even at oil prices much lower than those of recent years. Does
that financial mismatch seem misleading? Or perhaps, familiar?
In an unexpected twist, Fastow now gives talks to the energy industry on ethical leadership.
Sounding the Alarm
Bethany McLean was the first reporter to question whether Enron was a financially sound
company in a 2001 article
for Fortune magazine. McLean went on to co-author the book The Smartest Guys in the
Room , which documented the fall of Enron due to its fraudulent practices, including the
ones Fastow engineered.
In 2018, McLean also published the book Saudi America , which highlighted many of the
financial challenges the fracking industry has faced. In a recent interview for Texas Monthly's
podcast Boomtown , McLean
explained one of the very accepted and blatantly misleading practices of the fracking
industry:
I'd raise a couple of points. One is that companies have long hyped these break-even
numbers. They say we can break even at $25 a barrel, we can break even at $20 a barrel. And
then you look at their consolidated financial statements and they are losing money. And so
something is going wrong the people called it to me [sic] corporate math or investor
economics. So they were trying to put together these investor pitch decks that would show
investors a set of economics that weren't real. So they would show you that they could break
even on a well at $25 barrel of oil but then yet you'd go to the corporate financial
statements and they were losing money.
Is that a loophole? Where you can openly misrepresent to investors the financial reality of
your business? Or is it fraud?
As more and more players in the fracking industry run out of options and file for
bankruptcy, investors are beginning to ask questions about why all the money is gone.
"This is an industry that has always been filled with promoters and stock scams and
swindlers and people have made billions when investors have lost their shirts."
Much like with the housing crisis that caused the financial crisis of 2008, the fracking
boom has led to Wall Street bankers finding innovative ways to finance a money-losing endeavor.
Some companies are now even
selling bonds based on future well performance , a concept similar to the
mortgage-backed securities that led to the 2008 housing crisis.
Another Wall Street invention is what is called a "special purpose acquisition company" (
SPAC ), or, as they are also known,
blank check companies. The way these investments work is a big bank or private equity firm
backs a management team to raise money for the SPAC with the agreement that the leaders of the
SPAC will then at some point make a "special purpose acquisition" -- which means they will find
an existing company and buy it.
They are called blank check companies because the management is given a blank check to buy
whatever they choose. In the 1980s, the
Wall Street Journal ( WSJ ) noted that "blank-check companies were often associated with
penny-stock frauds." In a 2017 article on the oil industry, the
WSJ reported that " SPAC s were a hallmark of the frothy days before the financial crisis
[of 2008]."
Understandably, SPAC s were often seen as a risky investment, but much like with the housing
crisis, the biggest names on Wall Street are getting involved and giving the concept
legitimacy, with Goldman Sachs starting to back SPAC s in 2016. And new fracking companies have
come about as a result.
Ben Dell, a managing partner at investment firm Kimmeridge Energy, explained one of the
risks of SPAC investments to the Wall Street Journal. " SPAC management teams have an incentive
to spend the money they have raised no matter what, so they can collect fees and pay themselves
a salary and stock options at the company they purchase," Dell said.
" SPAC s are the most egregious example in the industry of executive misalignment with
investors," Dell
told the WSJ .
As I
have previously reported , one of the problems with the fracking industry is that CEO s are
paid very well even when the companies lose money. According to Dell, SPAC s take this problem
to a new "egregious" level.
Alta Mesa: A Star Is Born
To successfully raise money for a blank check company, having some star power in the
management helps. As the Wall Street Journal has noted, investments in SPAC s "
are largely bets on their executives ."
Jim Hackett would seem to be the ideal candidate to lead a SPAC in the fracking industry.
Hackett has an impressive resume: the former CEO of fracking company Anadarko, former
chairman
of the Federal Reserve Bank of Dallas , an executive committee member of the industry
lobbying group American Petroleum Institute ,
and
partner at the major private equity firm Riverstone Holdings.
In 2013 Hackett retired from Anadarko to attend Harvard Divinity School to get a degree in
theology. However, he was still a partner at Riverstone and in 2017 was lured back to the
fracking business to run a SPAC backed by Riverstone.
The SPAC raised a billion dollars while being advised by the biggest names in the business,
including Goldman Sachs and CitiGroup. The initial blank check company was called Silver Run
Acquisition Corp. II .
Hackett used the money to buy two companies in Oklahoma -- an oil producer and a pipeline --
and the new combined company Alta Mesa was valued at $3.8 billion.
The Future Was Bright for Alta Mesa
Hackett and Alta Mesa had big plans for making money fracking wells in Oklahoma, which
included forecasts for big increases in oil and gas production from the newly acquired assets
with very low break-even numbers.
When the Wall Street Journal reported the creation of Alta Mesa,
it noted , "Alta Mesa's core acreage in Northeast Kingfisher County has among the lowest
breakevens in the U.S. at around $25 per barrel, the company said." Because oil was well over
that price at the time, the future looked good, according to Hackett and Alta Mesa. Forbes
reported that Hackett said Alta Mesa's holdings were "oil that will be economic even at $40
WTI [West Texas Intermediate]" and oil has been well over that mark since Hackett made that
statement in 2017.
Like break-even numbers, another area where misleading investors in the oil industry might
be particularly easy is making overly optimistic forecasts about how much oil will be produced
by future wells. The Wall Street Journal
has documented this as a significant problem for the U.S. shale industry.
Description of Alta Mesa assets in investor proxy statement. Credit: Screen capture from
proxy
statement.
In early 2018 when touting the potential of the proposed new company Alta Mesa, Hackett said
that "its average well would produce nearly 250,000 barrels of oil over its life." A year
later, Alta Mesa said it expected those wells would produce less than half that, only 120,000
barrels of oil over the life of the well.
Later in 2019, Alta Mesa filed for bankruptcy after writing down its assets by $3.1 billion.
The billion-dollar blank check had been spent, and it took less than two years to lose it
all.
SEC Investigation and Multiple Investor Lawsuits
Alta Mesa's assets were sold off earlier this year. The SEC declined to comment on the
status of the investigation.
In May 2019,
the Houston Chronicle reported , "Alta Mesa also is facing a series of lawsuits. Some
shareholders are suing claiming they were defrauded and lied to about the value of the company
and its assets when the company was formed."
One lawsuit filed by the Plumbers and Pipefitters National Pension Fund claims that the
proxy statement for Alta Mesa contained materially false and misleading information. That
filing lays out a lot of facts to support that claim.
Yet another lawsuit has been filed against Riverstone for " misleading
statements ."
Investors are saying they were misled by Hackett and Riverstone. The allegations are based
on the claims that were made about how much oil the company could produce. In hindsight, those
claims appeared wildly inaccurate and misleading. But is that fraud? Or just taking advantage
of a loophole?
In January, the Houston Chronicle summed up the situation as it described Alta Mesa's downfall : "It was a dramatic fall from grace after
significantly overestimating its potential in Oklahoma's STACK shale play "
While Alta Mesa is a spectacular example of how fast the fracking business can make large
sums of money disappear after "significantly overestimating its potential," it also likely
marks the beginning of investor lawsuits against many other failing fracking companies with
similar histories.
Learning From Enron
When Jim Hackett decided to go to Harvard Divinity School, several favorable profiles about
his choice were written, including one on the Harvard website.
That article noted that one of the reasons Hackett decided to go to school was because of "the
collapse of Enron, a disaster that he attributed to 'a failure in leadership' among people he
knew well."
The speed with which Hackett and Alta Mesa went bankrupt is remarkable, indicating a likely
failure in leadership.
However, Hackett seems to have learned something from former Enron executive Andrew Fastow:
that there is work for former executives like them to teach the energy industry about ethics
and morality.
Fraud? Or Just a Laughing Matter?
Good reporting is hard work but sometimes involves a bit of luck. Like when a
Wall Street Journal reporter , in a room full of people hired to make forecasts of fracked
oil and gas production, learned about the existence of much more accurate methods for
predicting that oil production. And also learned that with accuracy comes much lower estimates
of shale oil reserves.
The WSJ article that followed quoted Texas A&M professor and expert on calculating oil
and gas reserves John Lee. "There are a number of practices that are almost inevitably going to
lead to overestimates," said Lee. Those are the practices used by the industry, with Alta Mesa
serving as just one example.
Overestimates are why Alta Mesa received funding but now no longer exists.
The Wall Street Journal reported that during a presentation given by Lee, an audience member
"stood up and challenged the engineers in attendance," asking why the forecasters weren't using
accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
" Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal.
Is it misleading to laugh at your company's investors if you know the estimates you are
giving them are inflated, but because you own the stock that benefits from those estimates, you
do it anyway? Is that fraud? Perhaps that depends on if you get you get ethics lessons from
Andrew Fastow and Jim Hackett.
Will the biggest innovation of the fracking revolution be making financial fraud a laughing
matter?
A lot of people on EFT like to talk about how shale is fraudulent. That's simply not
true:
You can't commit fraud when the rules are so lax you can just make shit up and it's still
allowed.
While I've little doubt there is a lot of fraud, so much of the stupidity around fracking
comes down to the old saying that its hard to make a man undrestand something when his job is
to not understand it.
The financing of the oil and gas industry is almost entirely dependent on projections
– projections of flow per well, and projections of future prices. All you need to do is
make a few optimistic projections of one or both, and you've suddenly turned a dud into a
highly valuable asset. Anyone can look at the pricing and question it, but with oil/gas, that
is much harder with 'novel' types of well as there are few if any precedents. So if someone
says 'the well is producing X per day, we can continue this flow for 3 years and when thats
finished, we can drill down another 200 metres and replicate the same flow', there is nobody
to contradict it. The drilling guys aren't going to argue, they want to keep their jobs. The
geologist isn't going to argue, he has his mortgage to pay. The senior manager won't argue,
he wants a promotion. The drilling company owners won't argue, they want to cash out. And the
Wall Street financier won't argue, because he can pass on the risk to the equivelent of the
last booms 'German bankers'.
So when someone like Arthur Berman – a geologist who has continuously being
questioning the underlying geological assumptions – raises concerns – he's
listened to politely, even invited to some conferences, but is otherwise ignored. Because its
not in anyones interest to listen. There is literally nobody who's job it is to shout 'stop'.
So much for self regulating markets.
While there may well be very severe economic consequences if and when this blows up in
everyones face (and I suspect that Covid-19 will be the catalyst for this, oil demand is
collapsing day by day), the big loser is the planet we depend on for our survival.
I live in NY on the PA border. Fracking is still happening south in PA but is only a
fraction of what it once was. If you drive into PA you will see lots full of fracking
materials that have sat there for a long time. At first for about two years it was a boom.
The activity from fracking was amazing. Then as fast as it started it slowed down to a crawl.
There are a few reasons in my opinion. The so called sweet sports were quickly fracked
leaving less attractive sights. It was concealed that a fracked well produced most of it's
gas in the first two years. After that the production from a well dropped off drastically.
Locals soon lost their enthusiasm for fracking.There is still some fracking but it is hardly
noticeable. Local people thought this would be great but attitudes soon soured. A few made
big bucks at the expense of the rest. The fracking was in former coal country. The difference
is coal lasted a lot longer. Now the majority of people in the area oppose fracking. I'm
thankful that NY state banned fracking because of the negatives associated with fracking. I
own 50 acres near the PA border. Before fracking was banned I was constantly hounded by
leasing companies. I refuse to lease because to me my land was more important than a few
bucks. I hope in my life time NY doesn't reverse the fracking ban. On another note there are
wind farms where I live. I would leas to a wind company because there are fewer negatives and
it's less intrusive.
The good news is that if the companies were chasing you, you own the minerals. You can
donate them to a conservation land trust and assure that no mineral extraction takes place,
and get a tax benefit for the foregone production.
It can be argued that the money invested in many fracking companies with such inflated
pay-back periods, ROIs or breakeven estimates, apart from fraud, could be considered as a
private subsidy, just like Uber investors subsidize Uber taxi services. If we can blame it to
low interest rates resulting in such subsidies, for fracking oil, unicorns, education,
housing etc. to my knowledge this has only been argued in very few sites like here at NC or
Wolf Street but merits a close examination. If pension and mutual funds are pouring a lot of
money in such business with low to negative returns what consequences are to be expected in
the future?
Eight to Ten years ago you would have seen giant trucks moving water and dirt from
fracking sites when you got off the turnpike around Donegal PA. Since about 2015 or 2016 i'd
say that completely died. Pittsburgh actually had one year of population gain due to the
fracking boom but thats done. Yves mentioned investors and low interest rates chasing bad
investments and fraud. I'd say the same thing is going on in healthcare based on my exp. of
it and the amount of money floating around. We need higher interest rates to nip this stuff
in the bud and re-balance the economy.
This pretty much says it all regarding the health of our eCONomy, but hey, after it all
falls apart we should have plenty of reformed criminals to teach ethics classes
"The Wall Street Journal reported that during a presentation given by Lee, an audience
member "stood up and challenged the engineers in attendance," asking why the forecasters
weren't using accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
"Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal."
In a 2016 interview with Fraud Magazine,
==============================================
I have to say, I was shocked, SHOCKED to find that there is a magazine actually, only devoted
to fraud – that is published bi-monthly.
AND than I was shocked to find out that the magaine actually, only devoted to fraud is ONLY
published bi-monthly
Is the U.S. Fracking Boom Based on Fraud? Is the Pope Catholic? There are going to have to
be major structural changes in the world's economy in the next few years and with the demand
for oil dropping, prices have gotten cheaper which is turning fracking into a non-profit
industry. In any case, how are you suppose to frack with sick crews? This is one industry
that needs to go away before it causes any more damage. You'd find more honesty in a boiler
room brokerage firm than in this industry.
There's a recent documentary called The Price of Everything that is about the enormous
sums being paid for every latest fad in modern art. The show says that all the great masters,
old and new, have been locked up by museums or the super rich and so a recent flood of new
investors are looking for any excuse to spend lots of money on paintings. Apparently there is
so much money sloshing around at the top of our unequal economy that that these plutocrats
don't even care if they lose their shirts on bad investments. The main thing is to keep it
out of the hands of the poor.
Clearly we as a society are suffering from affluenza, at least among the elites who should
all be virus quarantined and then maybe we will forget to check back.The show tries to
pretend that this money driven art world is a cool thing. It had this viewer thinking of
guillotines.
Yes, like all the people who cannot see the art. It's mostly buried in storage. What is
the point of having over two thousand years of art from multiple civilizations, if most of it
is hidden away and often only known from catalog descriptions or cramped tiny pictures.
You must mean the insiders who suckered the rubes into taking shares off their hands at
the IPO. IIRC the IPO price was over $70/share. Right now it's just under $32 with no signs
of every being a profitable enterprise.
Grifters, charlatans and mountebanks everywhere you look.
Charging mineral resource rent, which everyone has an equal claim to, would help to reduce
the tendency of financial shenanigans. The profit motive is crack to rent seekers.
Speaking of Enron, it is perhaps appropriate that my employer's head of non core assets,
toxic waste for fire sale, came from Enron. Standard Chartered has some, too.
I think the big issue goes back to the investors and bond rating agencies, similar to the
subprime mortgage crisis. If bondholders aren't willing to do the homework, then they don't
get paid for the risk that they are undertaking. with the multiple prediction tools for well
production, you can make up an optimistic and pessimistic case. If the bond yield doesn't
cover that risk to your satisfaction, then you don't buy the bond or you demand a higher
interest yield and lower bond price.
Instead, it seems like the industry is raising money from people who don't want to think
more than a few months ahead on a multi-year investment. The challenges faced by the fracking
industry have been well publicized for several years now. If an investor doesn't understand
those challenges now and isn't looking at specific methods of calculating production yield
etc., then they have only themselves to blame if their investment loses money.
This is a very different issue than if somebody flat out lies about whether or not wells
exist etc.
A single well can make financial sense even if there will never be a net profit from it.
Fracking is pretty similar to the Hollywood film industry where nobody ever has any net
profits despite living high on the hog. "Don't ever settle for net profits. It's called
'creative accounting'." – Lynda Carter: https://en.wikipedia.org/wiki/Hollywood_accounting
I dunno. There may be a sucker born every minute, but I can't picture enough of them
getting born with a million (or billion) Dollars to blow on rackets like this to keep it
going this long.
Sad to see that the Plumbers' Union Pension Fund was a victim; I hope that's not a
pattern, but it would make sense. If it's a pattern, then it's no wonder the Fed tried so
hard to postpone the next Crash until after the elections. How much junk paper has Wall
Street sold to other Pension Funds? States & Municipalities are already squeezed by
"unfunded liabilities"; how much repackaged funky Fracking paper are held by public
(governmental) agencies? Damn, this is gonna be a mess.
I'd advise investing in popcorn, except that my 401k will probably evaporate soon, so
maybe it's pitchforks.
CFO Fastow of Enron. How nice to see him land on his feet. The company made listening to
the rolling blackout reports for California while driving to work a requirement.
Posted on March 6,
2020 by Yves
Smith Yves here. It really is remarkable how super low interest rates have led investors on
a widespread basis to pour money down ratholes. Unicorns is one. Another has been fracking,
which despite being another widespread cash sink, remarkably has kept sucking in funding.
As we pointed out in 2014 :
John Dizard at the
Financial Times (hat tip Scott) gives a more intriguing piece of the puzzle: the degree
to which production is still chugging along despite it being uneconomical. The oil majors
have been criticized for levering up to continue developing when it is cash-flow negative;
they are presumably betting that prices will be much higher in short order.
But the same thing is happening further down the food chain, among players that don't
begin to have the deep pockets of the industry behemoths: many of them are still in "drill
baby, drill" mode. Per Dizard:
Even long-time energy industry people cannot remember an overinvestment cycle lasting as
long as the one in unconventional US resources. It is not just the hydrocarbon engineers
who have created this bubble; there are the financial engineers who came up with new ways
to pay for it.
Justin Mikulka argues that one reason these persistently unprofitable fracking companies
keep going is via fraud.
By Justin Mikulka, a freelance writer, audio and video producer living in Trumansburg,
NY. Originally published at DeSmogBlog
In a 2016 interview with Fraud Magazine , former Enron
CFO Andrew Fastow explained what he thought made him so successful while at the former energy
corporation that's now infamous for financial scandal.
"I think my ability to do structured financing, to finance things off-balance sheet and to
find ways to manipulate financial statements -- there's no nice way to say it. Like I said at
the conference, I was good at finding loopholes."
As Fastow explained, in finance, the difference between a loophole and fraud isn't always
easy to identify. And that may be something the U.S. fracking industry is working to its
advantage.
Fastow, the convicted fraudster, does admit that what they did at Enron misled investors.
"We created something that was monstrously misleading, but any one of those deals alone wasn't
necessarily considered fraudulent," he said.
Fast-forward to today and a different part of the energy industry: The U.S. shale oil and
gas industry has lost more than a quarter trillion dollars since 2007, while being sold to
investors as an economic boom, even at oil prices much lower than those of recent years. Does
that financial mismatch seem misleading? Or perhaps, familiar?
In an unexpected twist, Fastow now gives talks to the energy industry on ethical leadership.
Sounding the Alarm
Bethany McLean was the first reporter to question whether Enron was a financially sound
company in a 2001 article
for Fortune magazine. McLean went on to co-author the book The Smartest Guys in the
Room , which documented the fall of Enron due to its fraudulent practices, including the
ones Fastow engineered.
In 2018, McLean also published the book Saudi America , which highlighted many of the
financial challenges the fracking industry has faced. In a recent interview for Texas Monthly's
podcast Boomtown , McLean
explained one of the very accepted and blatantly misleading practices of the fracking
industry:
I'd raise a couple of points. One is that companies have long hyped these break-even
numbers. They say we can break even at $25 a barrel, we can break even at $20 a barrel. And
then you look at their consolidated financial statements and they are losing money. And so
something is going wrong the people called it to me [sic] corporate math or investor
economics. So they were trying to put together these investor pitch decks that would show
investors a set of economics that weren't real. So they would show you that they could break
even on a well at $25 barrel of oil but then yet you'd go to the corporate financial
statements and they were losing money.
Is that a loophole? Where you can openly misrepresent to investors the financial reality of
your business? Or is it fraud?
As more and more players in the fracking industry run out of options and file for
bankruptcy, investors are beginning to ask questions about why all the money is gone.
"This is an industry that has always been filled with promoters and stock scams and
swindlers and people have made billions when investors have lost their shirts."
Much like with the housing crisis that caused the financial crisis of 2008, the fracking
boom has led to Wall Street bankers finding innovative ways to finance a money-losing endeavor.
Some companies are now even
selling bonds based on future well performance , a concept similar to the
mortgage-backed securities that led to the 2008 housing crisis.
Another Wall Street invention is what is called a "special purpose acquisition company" (
SPAC ), or, as they are also known,
blank check companies. The way these investments work is a big bank or private equity firm
backs a management team to raise money for the SPAC with the agreement that the leaders of the
SPAC will then at some point make a "special purpose acquisition" -- which means they will find
an existing company and buy it.
They are called blank check companies because the management is given a blank check to buy
whatever they choose. In the 1980s, the
Wall Street Journal ( WSJ ) noted that "blank-check companies were often associated with
penny-stock frauds." In a 2017 article on the oil industry, the
WSJ reported that " SPAC s were a hallmark of the frothy days before the financial crisis
[of 2008]."
Understandably, SPAC s were often seen as a risky investment, but much like with the housing
crisis, the biggest names on Wall Street are getting involved and giving the concept
legitimacy, with Goldman Sachs starting to back SPAC s in 2016. And new fracking companies have
come about as a result.
Ben Dell, a managing partner at investment firm Kimmeridge Energy, explained one of the
risks of SPAC investments to the Wall Street Journal. " SPAC management teams have an incentive
to spend the money they have raised no matter what, so they can collect fees and pay themselves
a salary and stock options at the company they purchase," Dell said.
" SPAC s are the most egregious example in the industry of executive misalignment with
investors," Dell
told the WSJ .
As I
have previously reported , one of the problems with the fracking industry is that CEO s are
paid very well even when the companies lose money. According to Dell, SPAC s take this problem
to a new "egregious" level.
Alta Mesa: A Star Is Born
To successfully raise money for a blank check company, having some star power in the
management helps. As the Wall Street Journal has noted, investments in SPAC s "
are largely bets on their executives ."
Jim Hackett would seem to be the ideal candidate to lead a SPAC in the fracking industry.
Hackett has an impressive resume: the former CEO of fracking company Anadarko, former
chairman
of the Federal Reserve Bank of Dallas , an executive committee member of the industry
lobbying group American Petroleum Institute ,
and
partner at the major private equity firm Riverstone Holdings.
In 2013 Hackett retired from Anadarko to attend Harvard Divinity School to get a degree in
theology. However, he was still a partner at Riverstone and in 2017 was lured back to the
fracking business to run a SPAC backed by Riverstone.
The SPAC raised a billion dollars while being advised by the biggest names in the business,
including Goldman Sachs and CitiGroup. The initial blank check company was called Silver Run
Acquisition Corp. II .
Hackett used the money to buy two companies in Oklahoma -- an oil producer and a pipeline --
and the new combined company Alta Mesa was valued at $3.8 billion.
The Future Was Bright for Alta Mesa
Hackett and Alta Mesa had big plans for making money fracking wells in Oklahoma, which
included forecasts for big increases in oil and gas production from the newly acquired assets
with very low break-even numbers.
When the Wall Street Journal reported the creation of Alta Mesa,
it noted , "Alta Mesa's core acreage in Northeast Kingfisher County has among the lowest
breakevens in the U.S. at around $25 per barrel, the company said." Because oil was well over
that price at the time, the future looked good, according to Hackett and Alta Mesa. Forbes
reported that Hackett said Alta Mesa's holdings were "oil that will be economic even at $40
WTI [West Texas Intermediate]" and oil has been well over that mark since Hackett made that
statement in 2017.
Like break-even numbers, another area where misleading investors in the oil industry might
be particularly easy is making overly optimistic forecasts about how much oil will be produced
by future wells. The Wall Street Journal
has documented this as a significant problem for the U.S. shale industry.
Description of Alta Mesa assets in investor proxy statement. Credit: Screen capture from
proxy
statement.
In early 2018 when touting the potential of the proposed new company Alta Mesa, Hackett said
that "its average well would produce nearly 250,000 barrels of oil over its life." A year
later, Alta Mesa said it expected those wells would produce less than half that, only 120,000
barrels of oil over the life of the well.
Later in 2019, Alta Mesa filed for bankruptcy after writing down its assets by $3.1 billion.
The billion-dollar blank check had been spent, and it took less than two years to lose it
all.
SEC Investigation and Multiple Investor Lawsuits
Alta Mesa's assets were sold off earlier this year. The SEC declined to comment on the
status of the investigation.
In May 2019,
the Houston Chronicle reported , "Alta Mesa also is facing a series of lawsuits. Some
shareholders are suing claiming they were defrauded and lied to about the value of the company
and its assets when the company was formed."
One lawsuit filed by the Plumbers and Pipefitters National Pension Fund claims that the
proxy statement for Alta Mesa contained materially false and misleading information. That
filing lays out a lot of facts to support that claim.
Yet another lawsuit has been filed against Riverstone for " misleading
statements ."
Investors are saying they were misled by Hackett and Riverstone. The allegations are based
on the claims that were made about how much oil the company could produce. In hindsight, those
claims appeared wildly inaccurate and misleading. But is that fraud? Or just taking advantage
of a loophole?
In January, the Houston Chronicle summed up the situation as it described Alta Mesa's downfall : "It was a dramatic fall from grace after
significantly overestimating its potential in Oklahoma's STACK shale play "
While Alta Mesa is a spectacular example of how fast the fracking business can make large
sums of money disappear after "significantly overestimating its potential," it also likely
marks the beginning of investor lawsuits against many other failing fracking companies with
similar histories.
Learning From Enron
When Jim Hackett decided to go to Harvard Divinity School, several favorable profiles about
his choice were written, including one on the Harvard website.
That article noted that one of the reasons Hackett decided to go to school was because of "the
collapse of Enron, a disaster that he attributed to 'a failure in leadership' among people he
knew well."
The speed with which Hackett and Alta Mesa went bankrupt is remarkable, indicating a likely
failure in leadership.
However, Hackett seems to have learned something from former Enron executive Andrew Fastow:
that there is work for former executives like them to teach the energy industry about ethics
and morality.
Fraud? Or Just a Laughing Matter?
Good reporting is hard work but sometimes involves a bit of luck. Like when a
Wall Street Journal reporter , in a room full of people hired to make forecasts of fracked
oil and gas production, learned about the existence of much more accurate methods for
predicting that oil production. And also learned that with accuracy comes much lower estimates
of shale oil reserves.
The WSJ article that followed quoted Texas A&M professor and expert on calculating oil
and gas reserves John Lee. "There are a number of practices that are almost inevitably going to
lead to overestimates," said Lee. Those are the practices used by the industry, with Alta Mesa
serving as just one example.
Overestimates are why Alta Mesa received funding but now no longer exists.
The Wall Street Journal reported that during a presentation given by Lee, an audience member
"stood up and challenged the engineers in attendance," asking why the forecasters weren't using
accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
" Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal.
Is it misleading to laugh at your company's investors if you know the estimates you are
giving them are inflated, but because you own the stock that benefits from those estimates, you
do it anyway? Is that fraud? Perhaps that depends on if you get you get ethics lessons from
Andrew Fastow and Jim Hackett.
Will the biggest innovation of the fracking revolution be making financial fraud a laughing
matter?
A lot of people on EFT like to talk about how shale is fraudulent. That's simply not
true:
You can't commit fraud when the rules are so lax you can just make shit up and it's still
allowed.
While I've little doubt there is a lot of fraud, so much of the stupidity around fracking
comes down to the old saying that its hard to make a man undrestand something when his job is
to not understand it.
The financing of the oil and gas industry is almost entirely dependent on projections
– projections of flow per well, and projections of future prices. All you need to do is
make a few optimistic projections of one or both, and you've suddenly turned a dud into a
highly valuable asset. Anyone can look at the pricing and question it, but with oil/gas, that
is much harder with 'novel' types of well as there are few if any precedents. So if someone
says 'the well is producing X per day, we can continue this flow for 3 years and when thats
finished, we can drill down another 200 metres and replicate the same flow', there is nobody
to contradict it. The drilling guys aren't going to argue, they want to keep their jobs. The
geologist isn't going to argue, he has his mortgage to pay. The senior manager won't argue,
he wants a promotion. The drilling company owners won't argue, they want to cash out. And the
Wall Street financier won't argue, because he can pass on the risk to the equivelent of the
last booms 'German bankers'.
So when someone like Arthur Berman – a geologist who has continuously being
questioning the underlying geological assumptions – raises concerns – he's
listened to politely, even invited to some conferences, but is otherwise ignored. Because its
not in anyones interest to listen. There is literally nobody who's job it is to shout 'stop'.
So much for self regulating markets.
While there may well be very severe economic consequences if and when this blows up in
everyones face (and I suspect that Covid-19 will be the catalyst for this, oil demand is
collapsing day by day), the big loser is the planet we depend on for our survival.
I live in NY on the PA border. Fracking is still happening south in PA but is only a
fraction of what it once was. If you drive into PA you will see lots full of fracking
materials that have sat there for a long time. At first for about two years it was a boom.
The activity from fracking was amazing. Then as fast as it started it slowed down to a crawl.
There are a few reasons in my opinion. The so called sweet sports were quickly fracked
leaving less attractive sights. It was concealed that a fracked well produced most of it's
gas in the first two years. After that the production from a well dropped off drastically.
Locals soon lost their enthusiasm for fracking.There is still some fracking but it is hardly
noticeable. Local people thought this would be great but attitudes soon soured. A few made
big bucks at the expense of the rest. The fracking was in former coal country. The difference
is coal lasted a lot longer. Now the majority of people in the area oppose fracking. I'm
thankful that NY state banned fracking because of the negatives associated with fracking. I
own 50 acres near the PA border. Before fracking was banned I was constantly hounded by
leasing companies. I refuse to lease because to me my land was more important than a few
bucks. I hope in my life time NY doesn't reverse the fracking ban. On another note there are
wind farms where I live. I would leas to a wind company because there are fewer negatives and
it's less intrusive.
The good news is that if the companies were chasing you, you own the minerals. You can
donate them to a conservation land trust and assure that no mineral extraction takes place,
and get a tax benefit for the foregone production.
It can be argued that the money invested in many fracking companies with such inflated
pay-back periods, ROIs or breakeven estimates, apart from fraud, could be considered as a
private subsidy, just like Uber investors subsidize Uber taxi services. If we can blame it to
low interest rates resulting in such subsidies, for fracking oil, unicorns, education,
housing etc. to my knowledge this has only been argued in very few sites like here at NC or
Wolf Street but merits a close examination. If pension and mutual funds are pouring a lot of
money in such business with low to negative returns what consequences are to be expected in
the future?
Eight to Ten years ago you would have seen giant trucks moving water and dirt from
fracking sites when you got off the turnpike around Donegal PA. Since about 2015 or 2016 i'd
say that completely died. Pittsburgh actually had one year of population gain due to the
fracking boom but thats done. Yves mentioned investors and low interest rates chasing bad
investments and fraud. I'd say the same thing is going on in healthcare based on my exp. of
it and the amount of money floating around. We need higher interest rates to nip this stuff
in the bud and re-balance the economy.
This pretty much says it all regarding the health of our eCONomy, but hey, after it all
falls apart we should have plenty of reformed criminals to teach ethics classes
"The Wall Street Journal reported that during a presentation given by Lee, an audience
member "stood up and challenged the engineers in attendance," asking why the forecasters
weren't using accurate models like the ones that were available -- as Lee had described.
Another audience member explained the reason.
"Because we own stock," replied another engineer, "sparking laughter," according to the
Wall Street Journal."
In a 2016 interview with Fraud Magazine,
==============================================
I have to say, I was shocked, SHOCKED to find that there is a magazine actually, only devoted
to fraud – that is published bi-monthly.
AND than I was shocked to find out that the magaine actually, only devoted to fraud is ONLY
published bi-monthly
Is the U.S. Fracking Boom Based on Fraud? Is the Pope Catholic? There are going to have to
be major structural changes in the world's economy in the next few years and with the demand
for oil dropping, prices have gotten cheaper which is turning fracking into a non-profit
industry. In any case, how are you suppose to frack with sick crews? This is one industry
that needs to go away before it causes any more damage. You'd find more honesty in a boiler
room brokerage firm than in this industry.
There's a recent documentary called The Price of Everything that is about the enormous
sums being paid for every latest fad in modern art. The show says that all the great masters,
old and new, have been locked up by museums or the super rich and so a recent flood of new
investors are looking for any excuse to spend lots of money on paintings. Apparently there is
so much money sloshing around at the top of our unequal economy that that these plutocrats
don't even care if they lose their shirts on bad investments. The main thing is to keep it
out of the hands of the poor.
Clearly we as a society are suffering from affluenza, at least among the elites who should
all be virus quarantined and then maybe we will forget to check back.The show tries to
pretend that this money driven art world is a cool thing. It had this viewer thinking of
guillotines.
Yes, like all the people who cannot see the art. It's mostly buried in storage. What is
the point of having over two thousand years of art from multiple civilizations, if most of it
is hidden away and often only known from catalog descriptions or cramped tiny pictures.
You must mean the insiders who suckered the rubes into taking shares off their hands at
the IPO. IIRC the IPO price was over $70/share. Right now it's just under $32 with no signs
of every being a profitable enterprise.
Grifters, charlatans and mountebanks everywhere you look.
Charging mineral resource rent, which everyone has an equal claim to, would help to reduce
the tendency of financial shenanigans. The profit motive is crack to rent seekers.
Speaking of Enron, it is perhaps appropriate that my employer's head of non core assets,
toxic waste for fire sale, came from Enron. Standard Chartered has some, too.
I think the big issue goes back to the investors and bond rating agencies, similar to the
subprime mortgage crisis. If bondholders aren't willing to do the homework, then they don't
get paid for the risk that they are undertaking. with the multiple prediction tools for well
production, you can make up an optimistic and pessimistic case. If the bond yield doesn't
cover that risk to your satisfaction, then you don't buy the bond or you demand a higher
interest yield and lower bond price.
Instead, it seems like the industry is raising money from people who don't want to think
more than a few months ahead on a multi-year investment. The challenges faced by the fracking
industry have been well publicized for several years now. If an investor doesn't understand
those challenges now and isn't looking at specific methods of calculating production yield
etc., then they have only themselves to blame if their investment loses money.
This is a very different issue than if somebody flat out lies about whether or not wells
exist etc.
A single well can make financial sense even if there will never be a net profit from it.
Fracking is pretty similar to the Hollywood film industry where nobody ever has any net
profits despite living high on the hog. "Don't ever settle for net profits. It's called
'creative accounting'." – Lynda Carter: https://en.wikipedia.org/wiki/Hollywood_accounting
I dunno. There may be a sucker born every minute, but I can't picture enough of them
getting born with a million (or billion) Dollars to blow on rackets like this to keep it
going this long.
Sad to see that the Plumbers' Union Pension Fund was a victim; I hope that's not a
pattern, but it would make sense. If it's a pattern, then it's no wonder the Fed tried so
hard to postpone the next Crash until after the elections. How much junk paper has Wall
Street sold to other Pension Funds? States & Municipalities are already squeezed by
"unfunded liabilities"; how much repackaged funky Fracking paper are held by public
(governmental) agencies? Damn, this is gonna be a mess.
I'd advise investing in popcorn, except that my 401k will probably evaporate soon, so
maybe it's pitchforks.
CFO Fastow of Enron. How nice to see him land on his feet. The company made listening to
the rolling blackout reports for California while driving to work a requirement.
Africa's largest oil producer could see oil production fall by 35 percent as low oil prices
and regulatory uncertainty threaten to prompt oil majors to postpone final investment
decisions. OPEC member Nigeria is the largest oil producer in Africa and it pumped 1.776
million barrels of oil per day (bpd) in January 2020, according to OPEC's secondary sources in
its monthly report published this week. Adding condensate production, Nigeria's total oil
output exceeds 2 million bpd.
However, three deepwater projects offshore Nigeria, operated by oil majors Exxon, Shell, and
Total, could see their start-up dates delayed by two to four years to the late 2020s, according
to the research WoodMac shared with Reuters ahead of publishing it on Friday.
The regulatory changes in Nigeria's oil industry and the still pending final approval of a
petroleum bill - after two decades of delays and wrangling - act as deterrents to the oil
majors' investment decisions, according to Wood Mackenzie.
Moreover, the three deepwater projects - which could add a combined 300,000 bpd to Nigeria's
production - are not profitable at current oil prices with Brent Crude below $60 a barrel, the
consultancy noted.
Just this week, Nigeria assured foreign oil investors that the country is open to business
and can guarantee high returns on investment, the country's President Muhammadu Buhari told an
energy conference on Monday.
Nigeria is set to finally pass a new bill regulating the petroleum industry by the middle of
this year, after nearly two decades of delays, the country's Minister of Petroleum Timipre
Sylva said at the same event.
Mele Kyari, Group Managing Director at the Nigerian National Petroleum Corporation (NNPC),
said at the conference that "We are, more than ever before, committed to working with
stakeholders to increase our crude oil production from 2.3 million bbl per day to 3 million bbl
per day."
The recent amendment to the Deep Offshore Act will improve financial stability and investor
confidence, NNPC's head said.
"... that every nation produces what oil they can produce. Production must have some relation to reserves. ..."
"... The normal R/P ratio is around 20. That doesn't mean a nation with an R/P ratio of 20 will run out of oil in 20 years. Because as their production declines, their R/P ratio will still hold at about 20 because they are producing less oil therefore their reserves will go further. So an R/P ratio of about 20 is the norm for normal size conventional fields. ..."
"... For giant and supergiant fields the R/P ratio would be greater and for smaller fields, as well as shale fields, the R/P ratio would be smaller. ..."
"... Using OPEC's reserves data for both OPEC and Non-OPEC, OPEC has an R/P of 109 while Non-OPEC has an R/P ratio of about 12. That OPEC number is absurd beyond belief. ..."
"... If we exclude the heavy oil then OPEC's share is close to the 70% I suggested. How does this square its share of the production numbers for the world. This was my original question. I would like to read what the thoughts of other posters are on this as well. ..."
What is the explanation that Non-OPEC produces more than OPEC, but OPEC has 70% of world
reserves?
Although this might have been the case in the early history of oil production, I
would think that this should not be the case near the peak. If I recall correctly, Campbell
thought that OPEC's stated reserves are actually the estimated values produced by the government for each OPEC country?
Well, 79.4% to be exact Some people really believe that unbelievable crap. Well hell,
there are still people who believe the earth is flat and that the sun revolves around the
earth. So why should we be surprised? Some people will believe anything.
I would like to think that most people on this list know that OPEC quoted reserves is
pure bullshit.
Hey, we have a president who lies every time he tweets. And sometimes he tweets 200 times
a day. And perhaps 45% of the nation believes him. The capacity of humans to believe the
absurd is unbounded.
Anyway if IEA and EIA projections are made on the basis of OPEC claimed reserves, we
have a serious problem.
Well, I have always stated, on this blog as well as The Oil Drum, that every nation produces
what oil they can produce. Production must have some relation to reserves.
The normal R/P ratio is around 20. That doesn't mean a nation with an R/P ratio of 20 will
run out of oil in 20 years. Because as their production declines, their R/P ratio will still
hold at about 20 because they are producing less oil therefore their reserves will go
further. So an R/P ratio of about 20 is the norm for normal size conventional fields.
For giant and supergiant fields the R/P ratio would be greater and for smaller fields, as
well as shale fields, the R/P ratio would be smaller.
If a giant or supergiant field is nearing the end of its life, but infill drilling,
creaming the top of the reservoir, this will throw a monkey wrench into their R/P ratio.
While in its prime, the field may have had an R/P ration of 40 or even greater, its R/P ratio
while being creamed will be much smaller, less than 20.
Using OPEC's reserves data for both OPEC and Non-OPEC, OPEC has an R/P of 109 while
Non-OPEC has an R/P ratio of about 12. That OPEC number is absurd beyond belief.
According to Hubbert methodology, at the peak production the number of years to exhaust
the reserve is N = 2/a in which "a" is the intrinsic growth rate
dQ/dt=a Q (1-Q/Q_0)
From Laherrere's reports for world peak, this is between 0.04 and 0.05. This means that
the R/P ratio is between 40 and 50 at the peak. Thus if we say that 1/2 of the reserves are
left at the peak and we take Laherre's URR = 2500, this gives R/P=1250/35=36 years. These are
ball park figures, but suggest that R/P ~ 20 is low. These numbers are for the entire world
and for example for North Sea at its peak Hubbert's analysis gave a = 0.12, so
R/P=2/0.12=16.6, and this illustrates the fact that smaller fields are closer to your number
R/P=20.
If we exclude the heavy oil then OPEC's share is close to the 70% I suggested. How does
this square its share of the production numbers for the world. This was my original question.
I would like to read what the thoughts of other posters are on this as well.
Following the sharp re-drop in oil and natural gas prices in late 2018, bankruptcy filings
in the US by already weakened exploration and production companies , oilfield services
companies, and "midstream" companies (they gather, transport, process, or store oil and natural
gas) jumped by 51% in 2019, to 65 filings, according to data compiled by law firm Haynes and
Boone . This brought the total of the Great American Shale Oil & Gas Bust since 2015 in
these three sectors to 402 bankruptcy filings.
The debt involved in these bankruptcies in 2019 doubled from 2018 to $35 billion. This
pushed the total debt listed in these bankruptcy filings since 2015 to $207 billion. The chart
below shows the cumulative total debt involved in these bankruptcies since 2015.
But this does not include the much larger losses suffered by shareholders that get mostly
wiped out in the years before the bankruptcy as the shares descend into worthlessness,
and that then may get finished off in bankruptcy court.
The banks, which generally had the best collateral, took the smallest losses; bondholders
took bigger losses, with unsecured bondholders taking the biggest losses. Some of them lost
most of their investment; others got high-and-tight haircuts; others held debt that was
converted to equity in the restructured companies, some of which soon became worthless again
when the company filed for bankruptcy a second time. The old shareholders took the biggest
losses.
The Great American Fracking Bust started in mid-2014, when the price of WTI dropped from
over $100 a barrel to below $30 a barrel by early 2016. Then the price began to recover, going
over $70 a barrel in September and October 2018. But then it began to re-plunge. By the end of
2018, WTI had dropped to $47 a barrel.
Two major geopolitical events in the Middle East – the attack on Saudi Aramco's oil
facilities last September and the US assassination of Iranian Major General Qasem Soleimani
– that would have shaken up oil markets before, only caused brief ripples, quickly
squashed by the onslaught of surging US production. At the moment, WTI trades at $56.08 per
barrel, which is still below where the shale oil industry can survive long-term:
And 2020 is starting out terrible for natural gas producers. The price of natural gas has
plunged to $1.90 per million Btu at the moment, a dreadfully low price where no one can make
any money. Producers in shale fields that produce mostly gas, such as the Marcellus, are in
deeper trouble still, because oil, even at these prices, would be a lot better than just
natural gas.
Producing areas with constrained takeaway capacity (it takes a lot longer to build pipelines
than to ramp up production) are subject to local prices, which can be lower still. In some
areas, such as the Permian in Texas and New Mexico, the most prolific oil field in the US,
where natural gas is a byproduct of oil production, limited takeaway capacity has caused local
prices to collapse, and flaring to surge.
The chart shows the spot price for delivery at the Henry Hub:
Texas at the Epicenter.
The most affected state, in terms of the number of bankruptcy filings, is Texas, the largest
oil producer in the US. Since 2015, the state had 207 oil-and-gas bankruptcy filings, of the
402 total US filings. In 2019, Texas had 30 of the 65 US filings.
Delaware, obviously, is not into oil and gas production, but into coddling corporations, and
many companies are incorporated in Delaware, including some oil-and-gas companies in Texas.
When they file for bankruptcy, they do so in Delaware. These are the eight states with the most
oil-and-gas bankruptcy filings since 2015:
Bankruptcy filings are triggered when the E&P companies no longer get funding from Wall
Street or from their banks to continue with their perennially cash-flow negative operations and
service their debts. And this is what is happening now. Wall Street and the banks have started
to demand that these companies stick to an entirely new mantra in the fracking business: "live
within cash flow."
When E&P companies run short on funding, they cut back on drilling activity which puts
the squeeze on oilfield services companies that provide products and services to the oilfield,
including drilling and completing wells. And then these OFS companies go bankrupt.
This is what happened to oilfield-services giant Weatherford
which filed for a prepackaged bankruptcy last July . Back in 2014, before the oil bust, it
had 67,000 employees; by July, it was down to about 26,000. The reorganization plan allowed
Weatherford to shed $5.8 billion of its $7.6 billion in long-term debt. Old shareholders got
wiped out. The creditors got 99% of the restructured company's new shares.
In its report on the OFS bankruptcies, Haynes and Boone cited this pressure from Wall Street
and its cascading effect, which Weatherford had pointed out in its bankruptcy filing:
We note that Weatherford, in its July 2019 filing, attributed its insolvency in part to
reduced drilling activity by producers who have also been dramatically affected by the
commodity price slump since 2015. Investors' pressure on producers to "live within cash flow"
is further reducing demand for OFS services and supplies leaving the OFS sector with little
near term hope for a turnaround in prospects.
What this sector needs are much higher prices for oil and natural gas. But that cannot
happen while production continues to surge. A large-scale culling in the sector – a lot
more bankruptcies – could reduce production, and support higher prices.
But as soon as prices rise above certain levels, with investors still chasing yield at every
twist and turn, the flood of new money will wash over the sector again, with investors having
already forgotten by then that shale oil and gas was where money went to die every time. And
this new money will cause a new surge in production, which will collapse prices once again.
It's a cycle that the shale industry has a hard time getting out of, under the current
loosey-goosey monetary conditions.
The cratering of natural gas prices is bad news for any attempt to encourage
renewables.
From my own situation, I made a substantial capital investment in moving my domestic space
heating from gas to ultra-high efficiency air source heat pumps.
The economics worked out as broadly favourable (this wasn't my motivation, but it helped
justify the investment). My heat pumps have a raw (non-seasonally adjusted) coefficient of
performance of a little over 5. So I get 5kW of heat for every 1kW of electrical input). Here
in the UK I was paying 14 pence per kW/hr for electricity compared with 3.5 pence for natural
gas. With a AFUE efficiency on the gas heat of 90% my heat pumps generated heat at just under
3 pence per kilowatt, the gas heat would work out, net, at around 3.8 pence. So I saved about
10% to 15% in energy costs doing space heating via renewables. Again, here in the UK market,
electicity is about one-third to 40 percent from zero-carbon sources, wind, hydro and
nucelar. So my carbon footprint for space heating using heat pumps was hugely lower (maybe up
to half).
I've just got my utility's latest quote on energy prices. Electricity charges are about
the same. But I'm being quoted 2.5 pence per kilowatt hour for natural gas.
There's no way my air source heat pumps can compete with that. I might as well just burn
the gas and say screw the carbon dioxide emissions. I won't, of course. I'll grin and bear
it. But the shale glut and the uneconomic (wasted) investment in overproduction is massively
distorting the energy market.
Yes. Those are the calculations to be done. I am in the same situation though in Spain the
"spread" between gas and electricity prices in energy terms is smaller compared with the UK
and will probably get even smaller in the future despite the natl gas glut (because tariff
policies and investment in renewables). I am paying about 0,14€/kWh on electricity
consumed (fixed power contract apart but I needn't change it) and gas is at 0,06€/kWh.
The seasonal coefficient of performance of my reversible air/water heat exchanger is 4.5 by
Eurovent (third party certification of performance) so current expenses relative to natural
gas are 0.14/(0.06 x 4.5) = 0,52 that means I save 48% relative to the gas boiler. In fact a
bit less because the seasonal COP of the condensation boiler was about 1.05. But then, there
are other advantages about getting freed of natural gas: not needed periodical inspections.
Also my boiler was ageing and requiring more frequent revisions and repairs. In Spain the
electrical mix is now about 60% renewable + nuclear (approx). Gas prices are also more
volatile.
I among other things was designing, sourcing and installing high efficient NG powered
floor heating system in the North West of British Columbia. I once participated in 2012 in a
symposium by a supplier of heat pump systems.
The maximum savings one could expect because of the demand of the system (basically a reverse
refrigerator with a compressor demanding the most power) was actually 30% of the cost of
gas.
However – and that is the big one – a gas powered system at the time using high
efficiency boilers cost about 5 – 7$/ square foot, depending how much electronic
controls you threw into the system.
This way a new house install at an average 2500 square foot house would set you back an
average of 15 grand. Installing a heatpump system with either 8 -10′ buried PEX loops
or wells to 100′ deep would add between 25 – 30 000$ on top minus the cost for
the boilers at an average of 4500$.
And the typical heat-pump unit would cost between 8-10 000$ with a lifetime of about 10
years, double the cost of a boiler who usually have a somewhat longer lifespan.
The reason: air heat extraction systems in Canada do not work, when the heat is needed the
air temp. is at about – 5 to – 35C ..so only subsoil extraction works with
attending cost of machinery and labour.
The conclusion by all 25 contractors attending was quite unanimous – heat pump
systems in Canada except maybe in the most southern portions – are a waste of resources
and money.
Even here in mild England, despite having a heat pump installation which has capacity for
the space heating load even on a design condition day for winter extremes (let's say minus
5C) I have done a lot of data logging which has shown that in some not exactly challenging or
unusual climatic situations, the heat pump performance doesn't meet anything like submittal
sheet claims.
A few weeks ago, I'd forgotten to run the systems overnight at a low setpoint (but enough
to keep the space at a reasonable temperature -- I usually pick 16C or the low 60s F). When I
went into the kitchen / breakfast nook at seven o'clock-ish it was freezing cold (okay, maybe
not freezing, about 14C) with an outside temperature of 1 or 2C (low 30s F).
I turned the heat pump on, set it to a high output as I needed the space to warm through
relatively quickly before I had coffee then had to leave.
After less than five minutes, the outdoor unit went straight into a defrost cycle. Why?
Because it was one of those typically English damp, foggy mornings (where there was almost
100% RH outside). Even though the outdoor coil would have been, say, 2 or 3C, as soon as the
system started, the coil surface temperature would have crashed to minus 3 or 4C -- whereupon
the saturated outside air promptly froze the coil solid. Coefficient of performance would
have been less than one for the twenty minutes or so I needed to heat the space. I'd have
been better off firing up the gas heat.
Only an isolated and probably unusual use case. But a good illustration that green
technology has limits. For US climate zone 3 or 4 inhabitants, I suspect heat pumps will only
ever be viable in the shoulder months. For the severe winters you guys get, I can't see how
you can avoid combustion heat sources. Not to say that renewables such as air source (or
ground source) heat pumps aren't a partial solution, but the capital costs will be high,
probably prohibitively so for a monovalent system and overall carbon emissions savings won't
be especially spectacular.
Coastal temperate US regions might the best. Many inhabitants there. But I guess it works
in Texas, New México, Arizona (may be not so well in high plains north to the Canyon)
and others. May be Arkansas for instance and north up to Iowa?. It has to be noted that when
temperatures go close to 0ºC or below, and for long hours, performance is much worse.
So, in Madrid (a urban heat island itself) this occurs in winter for about 3-10 hours during
the night (I set thermostats at 19ºC during the night) in an average January day and it
is not big deal.
But, again, the climate is very important indeed. It has to be carefully analysed.
IMO Air heatpump is good for Oz, NZ and the likes, with the south UK being marginal now,
but not-applicable once Gulf Stream goes :)
ground-water, or water-water HP are needed for anything that gets freezing 3-4 months a
year, but that, as you say, has nontrivial capital costs, unless costs of carbon goes up by a
lot.
And, TBH, there are problems even with that. Say if ground-water is using subsurface loop,
it actually has a measurable impact on the soil temperature over few years, which is bad for
a number of reasons. Water-water can be ok if the water source is running water and not
over-used, but I've seen water-water sources that were using ponds freeze large ponds that
under normal circumstances would never fully freeze.
That said, ground-water well driven HPs are IMO very good for large office or apartment
buildings, especially if they work both ways (i.e. cooling into ground in the summer,
avoiding city heat islands).
I think the broadest lesson to be drawn from Clive's experience is that investment capital
is actively making it difficult to transition away from fossil fuels because investment
managers and underwriters absolutely insist on continuing to invest in fossil fuel projects,
even if it loses tons of money!!!
How can we compete with rich, powerful people who insist on wasting money!?!?!!
I have long wanted to use geothermal heat pump. In my case it simply won't happen, sadly.
For one, I would never be able to get the permit to drill the well in city limits. Two, the
equipment would cost more than my older, poorly insulated house itself. Three, our state
government has allowed and caused some of the highest electric prices in the nation, despite
having a huge hydro electric plant in town. We don't get that electricity, it gets sold to
NYC at greatly inflated prices. We don't get the money either. Instead we are forced to
import our electricity with full taxes and tariffs on it.
Last week, the temperatures were down to -15C at night And of course the snow.
Yes, the condition of the building is such a crucial aspect. I used to have beautiful
hardwood window frames, but there were an unmitigated disaster for energy efficiency and
creating a good building envelope. They were an almost complete thermal bridge. And they
could only accommodate the thinnest of double glazing. In a really cold winter's day, I'd
have to set the leaving air discharge temperature fairly high on the heat pump indoor coil to
get warm, which hampered efficiency. I was able to change to triple glazing (which fixed the
problem and significantly reduced heat loss but, again, at a cost ) because the property is
modern. If I'd had an older property, the windows would only have been part of the problem
(solid or poorly insulated walls and an un-insulated slab, for example, would be worse). And
the chances of getting permission to replace windows in a historic house would be slim,
certainly with the UK's tight building control.
And as you say, if you're in zone 5 or 6, you're a bit stuffed with regular drops to -15C
(5F). My heat pumps guarentee operation down to -15C, but capacity takes a nosedive. Luckily,
design conditions here in southern England are -5C, which reduces capital cost massively. And
if design conditions demand operation is guaranteed down to -20C (c. 0F), there is not much
choice of air source equipment available at any price. The only unit I know which is rated
down to below -30C is a Panasonic mini split, which here in the UK costs nearly £2,000
(c. $2,600) for a 3/4 ton unit. Out of reach for most. So you're left with ground source, but
-- as you say about NYC -- forget that idea in, say, London where tunnels and utility
wayleaves can't be interfered with. And ground conditions are difficult too, with a heavy
clay.
Green tech is not a panacea. I don't want to be discouraging, just the opposite. But some
of the talk about how practical it is is fanciful.
I do believe that much good is possible by greatly revising and liberalizing the building
codes, but practally trying to accomplish this is like pulling teeth. For some reason there
is large political resistance to change in this area. Older buildings can easily be made
quite efficient with current tech, but then the problem becomes an economic one. How to
overcome the first costs when the cost of upgrading is more than the structure itself?
FWIW many homes in my area were built in the 70s and 1980s with the assumption that
electric power would be free, or nearly free once the original bond issue for the power plant
was paid off. LOL the bastards managed a 30% rate hike the same year they paid it off, using
every little excuse possible.
Reading your reply, I was struck with just how underdeveloped the building insulation
field is. I have seen blow in and spray in foam retrofit insulation systems used in
commercial construction. (I particularly remember a system for inserting expanding cellular
foam into the void spaces in concrete block walls. [Yes! It can be done!])
Saying the above, I have read about the building insulation codes in the Nordic countries
being very 'tight.' Anyone from there care to enlighten us?
All the above is referencing winter heating. Where we live, summer time air conditioning is
the main energy sink.
Excellent points. Of course there is one plus. In the US we also need cooling in the
summer. My impression was that the heat pump systems could provide this as well, and very
economically.
Yes, we had a hot summer (hot by north European standards at any rate, we had about 10-15
days in the low 90s F and only a single day over 100F, maybe another few weeks in the 80s)
and my A/C cost was well under $100 for the whole cooling season, just because the heat pumps
with variable speed compressors and larger coil surface areas are so efficient when in A/C
mode.
As ambrit says above, even with low US electricity costs (in some areas, anyway), I don't
know how feul-poor folks manage in the south and so-cal with 10 SEER equipment and poorly
insulated homes when you have day after day at 95-100F.
It's dry in SoCal. One can easily survive by opening the windows, avoid direct sun on
windows, and dress accordingly.
I lived in the tropics under the same conditions, no direct sun on windows, behind insect
screen. That, one bed sheet to cover oneself, and a ceiling fan worked well.
Yes, the avoidance of service costs for gas-fired equipment plus the utility connection
fee for the gas service does make me consider the idea of moving away from gas as a fuel
source entirety. I must run the numbers on that to see how it might work out. It's a good
point to consider for anyone looking at the long-term costs for air source water or space
heating.
And you UKers are not precisely big spenders of electricity in per capita terms. About
half than French with all that nuclear power in place. Guess that how the power is delivered
to the grid has an important effect in consumption patterns.
If natural gas prices stayed cratered just long enough to exterminate thermal coal beyond
hope of revival in many countries before the natural gas prices went back up . . . would that
be a good thing?
Can someone at NC explain why the government allows burning flared gas? If it was outlawed
production would drop for oil as well until some way to store and use the gas was developed.
It seems burning natural gas at the wellhead must increase CO2 since gas is a
hydrocarbon.
I think you've answered your own question. The US govt has long had a policy to INCREASE
oil/gas production, side effects be damned.
There's a collective action problem among producers where they'd all benefit if they all
agreed to drop production 20%, say. But, each individual player benefits if they get to cheat
on those production cuts.
Plus, they've all floated a ton of high interest debt, which requires that they put
capital to work to generate cash flow to service that debt. It's clear that we're in the
'ponzi finance' stage of the cycle where new debt has to be issued to keep up payments on the
interest of the older debt. That's why the bankruptcies are perking up.
Bond underwiters, investment mgrs, oil services execs, and other players are all very
incentivized to keep getting new deals done.
First of all, it seems to be up to the states (?). There actually are regulations in Texas
(the Permian basin is the marginal-cost producing location in the US, where most of these
stories are centered). But the state is a friend of the industry and these regs are loosely
enforced. Secondly, emitting unburned natgas (mostly methane) is even worse than CO2 as a
greenhouse gas. Thirdly, they are drilling for oil, not gas, and are hoping to maximize the
oil-to-gas ratio. With low natgas prices and smaller amounts per well than elsewhere in the
US, putting in pipe for natgas is not economical. In fact the oil-gas-ratio varies in simple
geographic pattern that was known for years. The best, i.e. oil-rich land was claimed early,
subsequent waves of development that came on line during the oil price spike in mid 2000s,
are now getting killed. Fourthly, the ones losing money can't afford the extra ongoing
capital investment anyway – recall the very short life cycle of wells in fracking. They
are certainly cutting corners in other environment related tasks, like wastewater
disposal.
So will it stop? Not at the moment no. On the legal front, not until the next Ralph Nader
comes along and we get another wave of federal public interest legislation like we had in the
70s (which neither major party wanted at the time, just like now, and always). Economically,
also no. The marginal producers who were late to the gold rush will exit, but there is no
shortage of oil at even $50. The wildcard is in international developments. We are
suppressing production and export of conventional oil from Iraq, Iran, Libya, and Venezuela.
We are suppressing transport of natural gas from Russia to the EU. There is also
unconventional oil in Canada. I.e. US policy is supporting prices. Net effect on global oil
and gas use? None, since we just produce the difference ourselves, with a bunch of extra
natgas the world doesn't want, and can't be stored, so we burn it. Sucks.
Flaring is usually classed as solution gas flaring, emergency flaring and just unwanted
gas flaring.
These days flaring unwanted gas is rare because of the huge waste. But not long ago
producers could just flare stuff they didn't feel like getting to market, so entire
reservoirs of gas were burned just to get to the oil. This mostly doesn't happen anymore.
Emergency flaring happens in production or refining when a sudden unwanted flow of gas
manifests and for safety reasons, it must be disposed of rapidly. This appears a sudden very
large luminous flares over short timescales. Again, this is rare and essentially can't be
avoided. Flaring is much safer than just releasing.
Solution gas flaring is the bubbles of gas dissolved in liquid that come out of solution
during production as liquid pressure drops close to the wellhead. These need to be collected
or they would fill up liquid storage tanks. The volume and composition of the gas flows
determines the cost of collection. Companies have to balance the cost of collection vs. the
damage to the environment if flared. They usually try to make a case that the containment
cost (the cost to produce it to market, since the market value is usually minimal) is
prohibitive and request a permit to flare. This is the usual minimum compliance approach of
most resource development.
Basically, the conditions to obtain flaring permits vary with jurisdiction and are based
on a balance of revenue vs. environmental damage. These days most places encourage developers
to collect solution gas, but for remote locations in sour plays, that is costly to the
viability of the play.
If no one will build the gas-flaring oil fielders a free pipeline from oilfield to
gas-market, and building their own pipeline would cost more than what the oilfielders could
sell the gas for; they will just burn it in place. The other alternative would be for them to
release the methane UNburned into the air, which would be even worse than burning it
first.
But as soon as prices rise above certain levels, with investors still chasing yield at
every twist and turn, the flood of new money will wash over the sector again, with
investors having already forgotten by then that shale oil and gas was where money went to
die every time
This among the agricultural folk is called the "Schweinezyklus" or "pig cycle". Typical
for larger scale farming when from a previous oversupply the market has tried up, raising
prices and everyone increasing again their pig production till – again – the
market collapses.
I studied agricultural economy and production in the early 1970's when this type of cycle
became typical when farmers moved from mixed production providing risk compensation to dual
or even single products.
Indeed, the situation you refer to looks suspiciously like a process of financialization
of agriculture. Not to wax nostalgic for the "good old days" of backbreaking labour and
crummy living standards, but agriculture used to be a form of 'calling.' Now it's just a job.
Of course, the serfs and other 'forced' agricultural labourers of yesteryear disproved the
ethos of Goldsmith's "The Deserted Villiage."
There was a Golden Age, but it was not evenly distributed.
Frankly it is hard from Wolf's figures to know if he is even right. $207bn of defaulted
debt sounds like a lot of money, but is that from a total of $250bn or $2.5tn? I have no idea
if this is a lot of the industry or a little. And 2019 may be worse than 2018 for defaults,
but both 2016 and 2017 were way higher than that. Are things really getting worse or not? I
am deeply sceptical about the financial viability of fracking, but the case being made here
doesn't justify the sensation rhetoric.
In 1993 I built a house guaranteed to use 6,192 Kwh per year for heating and cooling here
in central PA, near Harrisburg. That includes resistance electric heat for backup. At that
time the cost was less than $40 a month.
Following the specifications to achieve this added about $2,500 to the cost of this 1288
sq.ft. house. It was a result of government requirements but no subsidies except for
administrative cost by the utility. Those requirements were subsequently dropped and the
program disappeared.
My question would be, was this program dropped because of complaints from the general
public, the homeowners as a group, or the builders and developers? $2 USD a square foot added
to construction expense wasn't chicken feed back in the 1970s.
Great article! It causes me to wonder, are the neocons trying to start a shooting war in
the Middle East to drive up US petroleum prices? Make America Great at least Texas. ;-)
I feel like supply control over there is more about petrodollars and perhaps efforts to
hurt Russia and Iran. Meanwhile the US seems to essentially be dumping oil with QE and repo
money funding money losing small fracking plays. I figured ages ago the plan was always to
have the supermajors mop up the wreckage at pennies on the dollar when the party ends.
Paper bankruptcies seem like a small price to pay for the gain in geopolitical influence
of all that extra production. Not being at the mercy of someone turning down the crude tap
can foster much more unilateral, terrible decision making in the middle east.
The invisible hand of the market did well to coddle a massive infrastructure buildup I saw
first hand in the Eagle Ford in Texas. Long term well production may have dropped off
significantly faster than the sales pitch but all of those wells will still be in place to
re-fracture when the market demands it.
"... Such is the extent of the shakeout in the U.S. shale industry that Permian Basin oil production is closer to peaking than many forecasts suggest, according to one energy investor. ..."
"... Adam Waterous, who runs Waterous Energy Fund, regards the sector's financial position as unsustainable after years of disappointing returns for investors and negative free cash flow. With capital markets now largely shunning shale producers, the impact will begin to show in oil and natural gas output from the largest U.S. oil patch, he said. ..."
Production from these selected top 9 US shale oil companies might be about to fall as shown
by decreasing quarterly crude oil production changes in chart. ExxonMobil (XOM) shale oil is
growing fast about 11% per quarter but probably not enough to offset declines from other
operators.
XOM data is taken from shaleprofile.com, averaging three months into a quarter, then
multiplying by 75% to get crude oil. 75% is used because Pioneer Natural Resources crude to
total shale oil is 75% and Pioneer operates in the Permian which is also XOM main basin.
Pretty sure shale profile reports crude plus condensate, for "oil" production. As the data
matches pretty closely with the EIA's tight oil estimates by play when Oklahoma output is
excluded (shaleprofile only reports Oklahoma output on the subscription service.)
In short, one should not assume 75% of what is reported at shale profile is the "crude"
portion of output. In fact all US output is reported as crude plus condensate, all the way
back to 1860.
There is also Chevron, BP, and Shell operating in US tight oil, all have deep pockets and
will be unaffected by the tightening up of the credit markets. In the past 2 years these 5
have doubled their tight oil output, though most of the increase occurred in 2018 when oil
prices were higher.
Output may drop, that in turn will lead to higher oil prices and higher tight oil output,
also the majors will be able to pick up cheap assets as smaller oil companies that have not
been financially prudent go bankrupt, that may accelerate the growth of tight oil output from
the majors as oil prices rise.
Liquids produced at natural-gas processing plants are excluded. Those are the NGPLs if
memory serves and are not NGLs which I think of as coming from NG at the well head.
In other words liquid from NG is listed two ways: The stuff obtained at the well head
(NGL) and the stuff obtained farther down the line at NG processing plants (NGPL), and the
latter is not included as oil. This is from my failing memory but so is my ability to find my
way home most of the time.
What some do not realize is that the natural gasoline (which condenses from the natural gas
stream at standard temperature and pressure of 1 ATM, 25 C) has always been included in the
crude plus condensate data in the US since 1860. The lower carbon chain products (C2, C3, C4)
are not liquids at STP, they are gases and remain in the natural gas stream until they are
separated at the natural gas processing plant. The definition given by the EIA is quite clear
on this point.
In the Permian basin, the ratio of crude to total oil (incl NGL) produced by Pioneer has
fallen from 81% at beginning of 2016 to 75% at the end of 2019. If this fall is similar for
other Permian producers then it may be harder to continue increasing Permian crude
production.
The comparison between oil production from shaleprofile.com and from Pioneer is very close,
as shown by the two green lines. For 2019Q3, shaleprofile production was 286 kbd compared to
290 kbd from Pioneer quarterly report. Note that both these numbers include crude, lease
condensate and NGLs. http://www.pxd.com/
I read an very interested report here on this forum where US geological Institute had
estimated break even prices for Thiere 6 to 1. Thiere 6 was categorizized as sweet spots with
more than 800 kbpd. As I remember this had break even cost 18 usd each barrel and to next
class you could aproximately multiplay it with 3. I believe this is much of the core
knowledge the Pioneer Mark Papa is estimated US future shale production at wich again is
related to change in rock quality. What we know is in 2014 -2015 I believe US could earn
money at least with some borrowings at 30 usd WTI , 5 years after tjey cant earn money at 60
usd WTI even with huge improvement in drilling efficiency that it is a reason to believe will
go much slower in future. Labour cost and all other will continue to increase. It might be
break even price in 2025 will be above 120 usd WTI iff Thiere 5 runs out as same as Tiere 6
the sweet spots. This mean we will be back to the situation before 2014 when the main source
off oil was offshore, and investment was there. It simply means US need to cut more cost in
shale oil, develop more oil from wells drilled in less quality rock but this challange might
be very hard to solve even for Exxon that is ramping up, the question will be if their
barrels are profittable at 42 usd WTI as they predict. Perhaps Mr. President could give tax
release, or simply start buy up the 1500 billion in depth that need to be payed next 4 years.
Some people may consider natural gasoline (which condenses from Natural gas in the lease
separators) as "NGL", I consider this this to be lease condensate and generally is is mixed
with the crude and sold with the crude. Perhaps Pioneer keeps a separate account of "crude"
and "condensate", in the US these are usually lumped together as C+C, most of the NGPL
produced in the US is Ethane (C2), Propane (C3), and Butane (C4), about 12% of the NGPL is
natural gasoline (C5), roughly 600 kb/d of a 5000 kb/d total output of NGPL. Note that the US
does not count the pentanes plus from NGPL plants as part of C+C output even though it is
chemically very similar to lease condensate. In Canada, for example the pentanes plus from
NGPL is added to C+C from the field, not sure why the US does things this way, Canada's
approach seems more sensible.
Such is the extent of the shakeout in the U.S. shale industry that Permian Basin oil
production is closer to peaking than many forecasts suggest, according to one energy
investor.
Adam Waterous, who runs Waterous Energy Fund, regards the sector's financial position as
unsustainable after years of disappointing returns for investors and negative free cash flow.
With capital markets now largely shunning shale producers, the impact will begin to show in
oil and natural gas output from the largest U.S. oil patch, he said.
"We think we are at or near peak Permian" production, Waterous said last week in an
interview. "The North American oil market has been grossly overcapitalized, which is not
sustainable."
Predicting peak Permian output for 2020 isn't a mainstream view. There's plenty of debate
about how much production growth in the West Texas and New Mexico patch may slow this year as
shale drillers slash capital spending, but the consensus is that supplies will rise, albeit
at a slower pace. Tai Liu, an analyst at BloombergNEF, said in a report Tuesday that the
pessimism may be overdone.
Just because there are newcomers I will re offer up a consideration.
If you have to have it, and you do have to have it, you are not going to let a substance
created from nothingness on a whim by the local Central Bank get in the way.
This is a peak oil blog, and that means scarcity. When something that you have to have is
scarce, then you are going to go get it. The concept of price is a parameter of value --
value that exists only in the imagination of counterparties. Oil moves food and your stomach
doesn't care about the imagination of counterparties. So don't be so sure that price
determines production. Or consumption.
Anybody notice that the price is rather a lot less than it was five or six years ago? How
does production compare to then?
"'There are known knowns. There are things we know that we know. There are known unknowns.
That is to say, there are things that we now know we don't know. But there are also unknown
unknowns. There are things we do not know we don't know."
Economics is the study of how people allocate scarce resources for production,
distribution, and consumption, both individually and collectively.
Supply and demand is the amount of a commodity, product, or service available and the
desire of buyers for it, considered as factors regulating its price.
Watcher, we don't live in a perfect world of instant information and production.
" Over the past five years, the industry and its investors "mistook a massive structural
change for a simple cyclical event," he said. "It's impossible to continue to have uneconomic
production and capex.""
It is basic stuff. I can show you many time periods of increasing price that aligned with
increasing consumption.
And again, worst of all, you know I can show those time periods.
The theory fails. If you find even one instance where it is wrong, it fails. That's the
scientific method. The hypothesis is proposed. Experiments are observed. If even one fails to
support it, that's failure. That's how it's always worked.
There is no oh, but. Price is lower than 6 years ago and production is higher. 2010 to
2014 price rose from $95/b to $112/b. Consumption 2010 89 bpd to 2014 93 mbpd. I found that
without breaking a sweat.
The theory fails. Embrace a new one. And why be surprised? It's a substance whose value
derives from whimsy and counterparty imagination
So rigs and frac spreads continue to fall yet almost all experts predict continued LTO growth
. it would appear the day of reckoning is coming and the majors in the Permian will not save
the day .. wasn't everyone hoping for a pick up in rigs and spreads as budgets were meant to
be renewed in the new year
I think independents are finally getting it that they can't simply look to increase
production as soon as the POO goes up.
I think the change has solely been bought about by investors requiring a return on
investment, I'm not sure we can surmise that LTO producers will act as they have in the past,
I suspect it will take a sustained period of high POO before LTO producers open the spigots
it will create even more of a boom/bust scenario going forward ..
I agree with you Jack, a large increase in oil prices seems unlikely to have much boost in
LTO production for several years because banks will want significant loan payback before
increasing drilling budgets. Dennis' model is an excellent BAU projection, but we live in
more dynamic times than that imho. Banks will need a consistent high oil price to lend like
they did in the past. That seems unlikely given possibility for recession, war, EV adoption,
increased regulation from Democratic prez, etc.
Wall Street is obsessed with the shiny new thing and that is not FF production. Tesla's
share price now more than GM and Ford combined.
Debt mountain for shale producers 2020-2023. Maybe once they get past this mountain banks
will be ready to loan again and rig counts and frac spreads will increase. But only if
there's a consistently high oil price during this period so banks have confidence to lend and
debt is substantially reduced.
It's all about the Permian and has been for quite some time.
None of the other shale basins have enough rigs running to grow production
significantly.
The Bakken is probably the most economic besides the Permian, and it seems the operators
there are in maintenance mode with regard to production.
There are still 397 rigs running in the PB. That is still a large number. I suspect there
are more locations left there than in the remaining shale basins combined (not counting the
ones which produce mostly natural gas).
It takes rigs to drill wells and frak spreads to complete them. No, rigs and frak spreads
have not improved their efficiency that much in such a short time. And drillers and frakers
are not working that much faster.
What you are seeing, or are about to see, is a slowdown in completions. The frak
spreads that are being retired have obviously just finished completing a well. But they
will not be completing another one. That's why you see a lag between falling rig and frak
spread count and completions.
Hell, that's all we need Dennis. If the total number of national frac spreads fall then the
total completions, nationwide, will fall. If production falls everywhere except the Permian,
then that decline will offset any increase in the Permian.
Okay, we know that the lions share of frac spreads are for oil therefore???
I think you are way overplaying your hand with this efficiency stuff. Last time when rigs
and frac spreads declined, then production declined. Why should it be any different this
time?
The simple fact of the matter is: "The total number of frac spreads are falling".
Therefore completions will fall because retired frac spreads frac no new wells. Yes, it is as
simple as that. Saying the remaining frac spreads will be more efficient therefore
completions will not fall, is just wishful thinking at best, and total nonsense at worst.
Well said Ron losing frac spreads means that the maximum number of completions able to be
completed has decreased – the concept of increased efficiency is a red herring when
spreads have fallen 40%!in the past 6 months – spreads efficiency sure hasn't risen 65%
in the same time ..
I think we all agree once the worm turns in the Permian LTO production will decrease, I am
not sure producers will increase production as the POO rises they do have to pay back a lot
of debt and have shareholders to answer to who want a return ..
From what I have read there is always improvement of efficiency in operation regarding new
Buisinesses such as shale. This improvement is normaly linked to exsperiance, increased
volumes i.e. but typical it will slow down during time as much of the easy potential will be
taken out. I see this as drilling padds, skidding systems as same rig could drill more wells
without be dismantled and mounting again. Dere have also been improvements in latheral
lenghts, propant, and fluid . But as Slumberger wrote in 2019, they believed max latheral
lenght already is reach as if increased cost off equipment will be much higher and also risk
increase when operating atbthe limit, more tear i.e. There might still be improvements but
more slow than it have been. According to reports the break even price increase 4-5 times
each Tiere class, and I believe rock quality will be a main challange in years to come as
shale will need higher oil price to earn money, pay back ballons and dividends.
Let's see the next quarterlies from LTO producers noting the continued comments about being
profitable under $50. If Permian centric producers cannot profit on maintaining production
output we know Houston we have a problem going forward .. will the companies be able to stick
to using cash flows from continued operations only or will we see more excuses carted out
again .
Gail makes the case for an oil peak for 2018, predicting production down 1% in 2020 in a
low-price environment. Her take is worth a read even though she likes to go far out on a limb
with little support sometimes
Production from these selected top 8 US shale oil companies might be about to fall as shown
by decreasing quarterly crude oil production changes as in chart below.
very interesting graph it shows what is evident that independents are being forced into
financial discipline at last. I cannot see the majors picking up the slack regardless of what
the MSM say, why would they continue with the growth at all costs strategy which has caused
noting but carnage for the above 8 producers.
Can XOM do all the heavy lifting itself once the independent growth plateaus then falls is
the million $ question. My bet XOM will grow but in a sustainable way, the impact of the
Permian increase will be interesting to note in their quarterly how much has that growth cost
them is the question ..
If we look at Exxon/Mobil, Chevron, Conoco-Philips, Shell, and Total combined, they have
increased combined tight oil output from 400 kb/d to 840 kb/d in the past 2 years (Sept 2017
to Sept 2019). Most of this increase occurred from Sept 2017 to Sept 2018 when oil prices
were a bit higher, in the past 12 months output grew by only 155 kb/d. Oil prices matter, low
oil prices may kill tight oil output growth, if so, oil prices are likely to rise.
For my "medium oil price scenario" (maximum WTI price of $83/b in 2018$ reached in 2027),
we get about 195,000 total wells drilled, about 110,000 total horizontal tight oil wells get
completed from 2010 to 2030 (about 26,000 have been completed through November 2019) so
roughly 80k wells completed from Sept 2019 to Sept 2029 in scenario below.
Also link below has spreadsheet you can play with.
Changing row 4 changes completion rate to any rate that seems reasonable. Scenario ends in
2030 for this particular spreadsheet, you can use excel, google sheets, or some other
spreadsheet program, it is saved in microsoft excel format.
On prices remaining range bound, that depends in part of how quickly oil consumption
grows. From 1982 to 2018 the average rate of growth in annual oil consumption has been about
800 kb/d. My $83/bo model has US tight oil growing by about 385 kb/d over the next 7 years,
it is not clear that the rest of the World will be able to fill the 415 kb/d gap each year
(assuming the 800 kb/d C+C consumption growth continues for the next 7 years). That is why I
expect oil prices to rise.
There has been relatively low offshore oil investment over the past 5 years and this is
likely to start affecting World oil output soon, the bumps in output from Brazil and Norway
are likely to be offset by declines in other producing nations (Mexico, China, and UK) and it
is far from clear that we will see higher output from Iran, Venezuela, Libya, or Nigeria.
As always the future is difficult to predict and I am often wrong, so perhaps oil prices
will remain "range bound" in your preferred $55 to $65/bo range. If that is correct Permian
output will grow far more slowly, perhaps growing from 4 Mb/d to about 6 Mb/d. The low oil
price scenario has about 72,000 wells completed from Sept 2019 to May 2030 in the Permian,
about 52,000 wells in all other US tight oil basins for a total of about 124,000 wells for
the low oil price scenario over that period. The completion rate falls from 850 in 2030 to
zero in 2035 for the low oil price scenario and output falls from 8200 kb/d at the start of
2030 to 2600 kb/d at the end of 2035.
I think it unlikely oil prices will remain range bound when World oil output peaks in
2026, that is only 6 years away, growth in oil output will slow significantly starting in
2024 and oil prices are likely to rise (at the latest) by June 2023.
That is a lot of locations. Of course, not all locations are the same productivity
wise.
Incredible how much oil the Permian Basin has produced and will produce in the next
decade.
Interesting how many companies sold out most of their acreage in the PB in the late 1980s
and 1990s, thinking it was past its prime.
I know of a small operator that bought leases in the PB and drilled some good vertical
wells. Martin Co. I don't know what they paid, but I am sure it was a tiny fraction of the
$600 million they sold out for a three years ago.
QEP bought about 9,500 acres from them for $600 million. There was 1,400 BOPD of
production from vertical wells at the time of the sale.
I have been looking at the wells QEP has drilled on this acreage. I don't think $600
million for 450 hz locations was a good deal for QEP. There are some good wells, but not
enough of them.
Yes I agree, all locations will not have the same productivity, I use the average for all
wells drilled for any given month as I am interested in the entire industry, some operators
will have better wells than others, some of this is skill and some of it is luck, I simply
assume generic company X will have a well productivity distribution that will be similar to
the industry average, in practice this is not likely to be true, but if we think of the
entire Permian basin as being run by a single large oil producer (Big Permian Oil Company) it
would be approximately correct, if my economic assumptions are correct.
I also find it amazing how much tight oil has been produced (5.6 Gb so for for Permian
since Jan 2000) and will be produced ( a total of 29 Gb for my model from Jan 2000 to May
2030, and for longer scenarios out to Dec 2079, about 60 Gb URR for Permian basin alone.)
Mike Shellman thinks that is completely wrong, but if the USGS mean estimate is roughly
correct and my medium oil price scenario and other economic assumptions are correct, that is
what the model suggests might happen. Mike is not a fan of the USGS TRR estimates, their F95
estimate is 43 Gb for Permian Basin URR, my low oil price scenario is in line with that F95
TRR estimate, with a URR of about 37 Gb.
If the TRR is low, oil prices are likely to be higher and a higher percentage of the TRR
is likely to be profitable to produce. (For a low TRR scenario the EUR would decrease more
rapidly than my "medium" TRR assumption (the basis for my best guess estimates).
I assume new well EUR starts to decrease starting in Jan 2019. In Dec 2018, my model has
the average Permian well with an EUR of 378 kbo. Chart below shows how the model assumes the
EUR will change from Sept 2019 to May 2030 (end of model scenario) for the Permian scenario I
presented above.
Again this is a guess for how future EUR will change based on a TRR scenario (no
economics) with 255,000 wells and a TRR matching the USGS mean estimate of 75 Gb for the
Permian basin. The rate that the EUR decreases depends on the number of wells completed each
month. Chart is small, click on chart for larger chart.
So they paid 1.33 million per well, I agree the wells do not look very good, for a 2017
average well, QEP has cumulative output of 145 kbo, my basin wide average well has about 190
kbo at 24 months, so the QEP wells about 24% lower than average, yikes.
This month, the energy consulting firm Wood MacKenzie gave an
online presentation that basically debunked the whole business model of the shale industry.
In this webinar, which explored the declining
production rates of oil wells in the Permian region , research director Ben Shattuck noted
how it was impossible to accurately forecast how much oil a shale play held based on estimates
from existing wells.
" Over the years of us doing this, as analysts, we've learned that you really have to do it
well by well," Shattuck explained of analyzing well performance. "You cannot take anything for
granted."
For an industry that has raised hundreds of billions of dollars promising future performance
based on the production of a few wells, this is not good news. And particularly for the
Permian, the nation's most
productive shale play , located in Texas and New Mexico.
Up until now, the basic premise of the fracking business model has been for a company to
lease some land, drill until finding a high-volume well, hype to the press this well and the
many others it plans to drill on the rest of its acreage, and promise a bright future, all
while borrowing huge sums of money to drill and frack the wells.
Throughout the seminar, Wood MacKenzie analysts emphasized that companies can't reliably
predict future oil production by "clustering" wells, that is, estimating volumes of many future
wells based on the performance of a small number of nearby existing wells, and described the
practice as potentially "misleading."
Shattuck called out how the old business model of firms borrowing money from investors while
hoping for future payouts on record-breaking wells no longer works. He summed up the
situation:
" We're transitioning to a point in time, where the investment community was enamored of
the next well and how big it might be. That has changed for a variety of reasons. One very
important reason is the next well might not be bigger. It might be smaller."
The fracking industry is now being asked to produce positive financial results -- not just
promises of new
super wells, or cube development, or artificial intelligence. And yet the industry couldn't
deliver profits while drilling all the best acreage over the last decade. Now, shale companies
need to do that with oil wells that may not produce as much.
Seven years ago, Rolling Stone referred to the fracking industry as a "
scam " while profiling the "Shale King" Aubrey McClendon, the man generally credited with
inventing the business model the shale industry has used the past decade. Today, McClendon's
old company Chesapeake Energy is
in danger of going bankrupt .
Perhaps investors are finally catching on.
Are Child Wells the New Normal?
Last year I covered the issue of
child wells , or secondary wells drilled close to an existing "parent" well, and the risk
they posed to the fracking industry. Child wells often cannibalize or damage parent wells,
leading to an overall drop in oil production.
At the time, I cited a warning about this situation from Wood MacKenzie, which said,
"Closely spaced child well performance presents not only a risk to the viability of the ongoing
drilling recovery but also to the industry's long-term prospects."
Over a year later, has the shale oil industry abandoned this approach or are child wells
still an issue?
During this month's webinar, Ben Shattuck answered that question, making a statement that
should strike fear in the heart of shale investors and the owners of all this shale
acreage:
" We know we're on the cusp of a child-well world."
One of the biggest problems with fracked oil well production is child wells, and according
to Shattuck, that looks like the new normal. When the bug in an unprofitable business becomes
the main feature of the business model, its future is definitely at "risk."
In the Eagle Ford shale, average production per foot of well length and per pound of
"proppant" has been falling steadily. Mr Kibsgaard blamed the decline on a rising proportion
of child wells, which are now up to about 70 per cent of all new wells drilled https://t.co/uG58KcNNJp
As long as shale firms could keep borrowing and losing money to drill new wells, producing
more oil was simple. When profits weren't a concern, the debt-heavy business model worked. But
similar to the dot com boom and bust, the fracking industry is learning that if you want to
stay in business, you need to make a profit.
Without a doubt, drilling and fracking shale can produce a lot of oil and gas in the right
geological regions. It just usually costs more to get the oil and gas out of the rock than the
fossil fuels are worth on the free market. Now, however, the much-lauded "shale revolution" is
facing two big issues -- the best rock has been
drilled and few are eager to
loan money to drill the remaining acreage.
E&E News recently highlighted
what this reality means for Texas's Eagle Ford shale play, where production is now 20 percent
lower than at its peak in early 2015. For an oil basin that's only been producing oil via
fracking for
just over a decade , that is a pretty grim number. However, an analyst quoted by E&E
News highlights the secret to making money while fracking for oil: Simply stop fracking.
"Generating free cash is easy: Stop spending on new wells," said Raoul LeBlanc, vice
president for North American unconventionals at IHS Markit. "The catch is that production will
immediately move into steep decline in many cases."
# IHSM arkit
forecasts capital spending for shale drilling & completions to fall by 10% to $102
billion this year. By 2021, we'll see a near $20 billion decline in annual spending. What's
causing this? Raoul LeBlanc comments- https://t.co/7q1QTiWZVs @HoustonChron
Ah, the catch. To generate cash while fracking requires companies to stop fracking and sell
whatever oil they have left from rapidly declining wells. Because fracked wells decline quickly
even when everything goes perfectly, if a producer isn't constantly drilling new wells, then
the oil production of a field drops off very quickly -- the "steep decline" noted by
LeBlanc.
That's exactly what happened in the Eagle Ford shale, an early darling of the fracking
industry, and most of the top acreage
in the Bakken shale play in North Dakota and Montana has already been drilled, and will
likely see similar declines.
LeBlanc emphasizes this point again in the Journal of Petroleum Technology
, where he is recently quoted saying that the decline rates in the Permian region have
"increased dramatically" for new fracked wells.
A year and a half ago, DeSmog launched a special series exploring the finances
of the fracking industry , putting a spotlight on its financial failings. At the time,
optimism about the future of fracking was still filling the pages of the financial press.
Hughes told DeSmog that with the finances of fracking, "Ultimately, you hit the wall. It's
just a question of time."
With the industry on the cusp of a "child-well world," that wall appears to be approaching
quickly -- unless you still believe the industry promises that fracking's big money is right
around the corner.
As the article says, the key scary thing for investors and the industry about fracking is
that fracked wells don't tail off over years like conventional ones – they stop
producing quite abruptly. Once the sweet spots are sucked dry, the drop off in production
will be calamitous with all sorts of potential impacts through both the oil/gas and the
finance world. It will probably happen far too quickly for most investors to jump off the
carousel in time. It will be a game changer when it happens (and probably, sadly, quite good
news for the Gulf States).
In past years, whenever I've expressed scepticism about the finances of fracking, the
usual response is 'but those guys wouldn't be putting in billions unless they knew there was
lots of oil and gas there'. What they don't seem to grasp is that making money from oil and
gas exploration is not the same as making money from oil production. Its not about selling on
the fuel. Its about first of all extracting money from investors for the exploration (and
getting your cut), then its about developing a prospect and selling it on for a big profit.
They don't really care if the well is profitable in the long term or not. I know of at least
one oil company (not in fracking, mostly off-shore), which has made millions for its owners
over the 40 years of its existence, despite the fact that it has never sold one barrel of
oil, nor ever found a field which could be brought to full production. All their profits have
come from their cut in selling on prospective fields, not one of which has ever come to
production.
===Its about first of all extracting money from investors for the exploration (and getting
your cut)==
==All their profits have come from their cut in selling on prospective fields, not one of
which has ever come to production===
What that tells me is there are a lot of investors that have soo much idle money floating
around the world and can literally throw huge sums of money at some venture and if the
venture fails oh well.
Many authors (Susan Strange, etc.) have used the term Casino Capitalism and this seems to
fit that.
It's like taking millions of dollars and making an idle bet at the roulette wheel and if
you lose oh well it was just pocket change or I'll just make up the losses on some other
scam. Meanwhile millions of people are homeless, without healthcare, hungry, etc. It's is
long past time to storm the castles! Pitchforks Up!!
I predict a nightmare of numerous abandoned wells as the many unprofitable fracking
companies go belly up, leaving the public with an expensive environmental mess to clean
up.
Just another example of western cronie capitalism where you privatise all profit, and
socialise all losses including both monetary and environmental.
The only way to stop this is to make shareholders personally responsible for such losses
including environmental clean up, even after a company goes belly up. Only then will
shareholders demand long term viability and more sustainable environmental practices, instead
of only short term profits.
A much simpler way is to simply insist that any license to drill can only be granted if it
is tied to a certified insurance bond for correct capping and abandonment. It would be
interesting to see just how many insurance companies would be willing to take on that
risk.
This should be the norm for all resource extraction permits: mining, logging, drilling,
whatever. A "restoration bond" has to be in place to finance the restoration of the site
after the valuable resources have been carted away.
This would be cheap in some cases, and very expensive in others (e.g., uranium mining). It
would be a way of factoring the externalities (as economists like to call them) into the
overall cost of the project, as well as decreasing the odds that fly by night operators will
trash the planet.
"You wouldn't know you were near an uranium mine any more ."
Alas, the residents of Red Shirt, South Dakota, a tiny Lakota community on the fringes of
the Pine Ridge Reservation, know about uranium mining. Past uranium mining
activity has resulted in the leaching of radioactive materials into their ground water
and wells. Even the nearby Cheyenne River has been contaminated. They can't drink the water.
Or use it for irrigation or fishing. The entire region is an official National Sacrifice
Area. Just a bunch of poor Indians.
The Defenders of the Black Hills are now fighting efforts to mine uranium using in-situ
leach mining. In this process, holes are dug, water and solvents injected to dissolve the
uranium, then the waste water is brought to the surface and temporarily stored in mud waste
ponds. Sounds like 'fracking?' Concerns are for the spread of contaminants in ground water
and aquifers. Where you can't see it.
Granted, no type of mining is without its problems.
But you could live in an area like mine where well water has to be tested routinely for
the high levels of uranium that occurs naturally in our water. No uranium mines around
here.
I'm going to be polite and ignore the tone of your comment. I was merely pointing out that
uranium mining is not the only reason for high uranium levels in ground water. There is a lot
of uranium in the earth's crust and it is dissolvable in water. All well water should be
checked for uranium levels but it is rarely done.
I'd favor forcing the investors and executives that want to erect these horrors to
personally (along with their family members) do the on-site labor of closing and cleanup,
while breathing the air and drinking the water that locals do. Still, of course, possible to
game even that by capturing the regulatory process of setting cleanup standards and
requirements, a la the federal and state Superfund programs.
Malum prohibitum vs. malum in se
" Latin referring to an act that is "wrong in itself," in its very nature being illegal
because it violates the natural, moral or public principles of a civilized society. In
criminal law it is one of the collection of crimes which are traditional and not just created
by statute, which are "malum prohibitum." Example: murder, rape, burglary and robbery are
malum in se, while violations of the Securities and Exchange Act or most "white collar
crimes" are malum prohibitum." https://dictionary.law.com/Default.aspx?selected=1201
The public won't be asked to fund the cleanup because there will be no cleanup. The
responsible parties aren't interested, and our government is no longer interested either.
It's another one of those issues in which communities without power will insist on government
action, and they will be ignored.
I wonder if could it be the case that some government considers strategically important to
keep production from free-falling, no matter if the economics are not sound, and shifting the
cost to the Treasury. MMT to the rescue of shale plays and financiers.
If the article is correct, calling for a plateau as soon as in 2021, the shale boom will
prove more transient than expected.
I can't keep up with all the interlocks and back-scratches. But Banksters are getting
rich, the intermediators in exploration and production are getting rich, the petroleum Bigs
are getting rich and using the notional global competition and Market to damage one
"nation's" comparative advantage to their own ends. And as with all the behaviors leading to
the conclusion that humanity is a failed, and maybe more honestly a plague species, all the
incentives and flows of power are in the direction of what I believe it was a Reagan
appointee offered as the moral underpinning of globalization and ruination: "God gave us
dominion over the planet, and Jesus is coming back real soon and if we have not used up the
whole place in accordance with His Holy Word as i read it, He is going to be really pissed
"
As with all the stuff we NCers read here, everything seems to drive the truly awake soul
in the direction of despair and that sense of vast futility, and that mindset of "Eat, drink
and be merry, for tomorrow we shall die " And screw future generations – past
generations said that to us, so why should we, or some small elite among us, who now are in a
position to have all our pleasure centers fully engaged and satiated to the max, behave
"Responsibly?" "Responsible people maximize shareholder value (and executive looting)!"
5 million EV takes inevitably back to nuclear energy. Without nukes you can anticipate
losing your residential AC for several hours/day. PG&E is the future.
The Forbes article is crap. Any analysis of electricity costs coming from renewable power
that does not include the costs of the energy storage systems required at high
penetration levels will underestimate the costs. Badly. The solar panels and wind turbines
are the easy part. The energy storage systems will easily cost 10X as much (and take 10X as
much time). Because of this, we've seen renewable energy deployment efforts stall out in
Germany, Spain, China, Denmark, and elsewhere, as they bumped into grid stability issues that
require storage to mitigate. And the storage costs too much.
Using "batteries" also produces a 10%* net loss to charge the batteries right off the bat.
You need 110% of the electricity to get to same 100% you were getting before the battery.
Rather than batteries helping, they actually end up using more electricity. That's also
before counting the electricity to make the battery.
* that's best case, theoretical, scenario.
Batteries are net users of electricity. The do not make it.
The Forbes article talks about balancing the grid so that variable energy sources can be
incorporated reliably. To whit:
Actually, battery storage, though often cost-effective today, is rarely needed to "firm"
the output of variable renewables (photovoltaics and windpower), because there are eight
ample cheaper methods.
I believe the author's thesis is for the electricity from renewables to be fed into the
grid when it is available, not to store it.
Do you think nuclear power plants run continuously and are never taken off the grid? Do
you think we use huge storage batteries when they are down?
Both your quote, and the pdf 'talk about' that. That's all they do. The forbes author
really is a treat. "There are 8 ample, cheaper methods" What are those eight methods? why
only 8? No further details.
"I believe the author's thesis is for the electricity from renewables to be fed into the
grid when it is available, not to store it."
It seems you noticed it too. No details, just numbers spelled out as words and asserted as
evidence.
Well, unfortunately the link that explains his 8 methods is behind a paywall.
But I think we are talking apples and oranges here.
The author of the Forbes article is talking about how a grid works. When a power plant is
taken off the grid, energy is moved in from some other area to take up the slack as long as
that power plant is offline. He expects that should be done with renewable energy also.
If you are depending on only one form of renewable energy, then of course you would need
batteries when that form of energy is not available. But batteries are an added cost and not
as efficient as moving energy via the grid. A better method would be to have many types of
renewable energies available so that you can switch between them as necessary. It is what he
means when he is talking about needing to firm the output of variable renewables.
So for example, in my area, the winds kick up when the sun goes down so it makes sense to
switch from solar to wind power at dusk.
I'm don't buy Amory Lovins' thesis. Bob's criticism is correct. The other 8 methods aren't
listed. The required sizes and associated costs aren't listed. It is impossible to judge the
viability of the scheme he envisions when the relevant information is missing.
A real plan would list nameplate GW for all types of generation assets and GW and
GWh for all energy storage assets. In other words, full details.
The only "plan" I've seen for supplying US energy needs with 100% renewable power that
actually contained full details came from Mark Jacobson of Stanford University: https://web.stanford.edu/group/efmh/jacobson/Articles/I/USStatesWWS.pdf
. To his credit, he did the time-domain analysis necessary to determine the amount of
load-sharing and energy storage necessary to keep the lights on through even extended periods
of unfavorable weather.
Unfortunately, his "solution" required two things: (1) expanding US hydro capacity by a
factor of 10, and (2) deploying a stupendous 541 TWh of energy storage. Neither is feasible.
The first would cause massive flooding and ruin river ecosystems if ever run at full power,
and the second would cost over $100 trillion at today's energy storage costs of $200/kWh. His
plan was so wildly unrealistic (and yet popular with Democrats) that a team of scientists and
engineers issued a formal rebuttal: https://www.pnas.org/content/114/26/6722 .
Jacobson's plan has been debunked .
The South Koreans deployed their nuclear fleet for approximately $3000/kW. At this cost,
we could completely de-carbonize the US electrical system for less than $2.5 trillion. It
would be quite the bargain in comparison.
The South Koreans do have one of the lowest costs for nuclear energy production – a
LCOE of about $2021/kWe compared to the US of $4100/kWe and the world average of $4702/kWe
– but the way they do that is by having much looser regulations and by severely
underestimating the decommissioning, waste management, and accident compensation costs. Is
that what you want for nuclear energy in the US?
I think it's kind of dangerous to just throw numbers around unless you understand what
they actually mean.
Ah, the wonderful "Heaters". They are situated outside EBR-1, just south of ID-20, west of
Idaho Falls, and east of Arco.
The whole of the area around there is a fascinating place to visit for a nuclear nerd like
me, plus you have the wonderful Craters of the Moon NM there too.
Other interesting places to visit are Atomic City, which has a population of around 25,
and is a weird time capsule from the '60s, plus Big Southern Butte, which is a, er, big
butte.
You can also find a gate leading off ID-20 to the north, into INL (Idaho National
Laboratory), which used to be the access road to the army's SL-1 reactor, which underwent a
steam explosion due to a core excursion in 1961, and is (as far as is admitted) the only
nuclear accident that led to immediate deaths in the US.
For a really interesting review of nuclear history read the three books by James Mahaffey.
He was a nuclear plant operator for a while, and describes the little pastime of "reactor
racing", which was seeing who could get a reactor up to nominal operating capacity in the
shortest time.
I guess that this means that Trump and his crew will make another run at Venezuela –
before the fracking industry goes down the gurgler. All of Venezuela's oil fields are like a
big box of chocolates in America's backyard. But if they try to take it, like life, you never
know what you are going to get.
Am I right in guessing that this will significantly impact forecasts of aggregate US
domestic oil production? Do we remain the global "swing" producer?
As PlutoniumKun says above, the collapse of the shale field production will be great news
for the Gulf Coast's petroleum industry. Not only is the Gulf a proven reserve, but with the
inevitable higher prices for crude oil, many more of the offshore wells will become
profitable.
The American shale collapse will also be good news for other world producers of petroleum.
OPEC will regain some of it's lost political influence.
On the down side; all forms of shipping and transportation will have a spike in per unit
costs. A canny politician could use this factor to push an onshoring of lost industrial and
manufacturing capacity. Put Americans back to work in America. That will be a winning
strategy.
Yes, well, I generally assume that the definition of "profitable" in use in the board
rooms of the giant conglomerates 'rules the day.' Until some method of 'regulating' the
actions of the board rooms of industry are brought into play, I'm afraid we are stuck with
some version of the status quo.
Just as the German usual suspects moved nations into 'Realpolitik' after the War, so too have
the modern Austrian usual suspects moved the world into 'Realeconomik.' Both have led our
best of all possible worlds into a Neoliberal Paradise.
Didn't Chesapeake Energy declare bankruptcy a good ten years ago? And then restructured
itself into a shale fracking company with the extreme help of the Obama administration? When
Obama "pivoted" away from KSA he went straight to US drillers. Allowing any hype necessary to
get the needed investments. Obama was clearly panicked. I wonder if it is possible that that
is when he learned that Aramco's reserves were only a fraction of the Saudi hype? Bin
Sawbones was subsequently allowed to provide the estimate of the worth of KSA's oil reserves
at 2 Trillion. The IPO went forward at that estimate and just today there is an article in ZH
about Aramco's actual value being much less. It looks to me like we just up and left KSA. Why
on earth would we do that unless they were running dry? And why would they have fought that
obscene war with Yemen unless they (the Saudis) were getting desperate? Secure people
generally don't do things that stupid. And the next logical question might be, How long will
Russian reserves hold up as they supply both China and the EU? The simple answer is it is all
just a question of time. We need to envision a lifestyle that is far more compatible with the
planet. Fracking was just a distraction. A farce. It would be better to own warm sox than oil
shares. And electricity is not going to help us out if we do not aggressively restrict our
use. I'd just like to know why we can't all come together and admit this one elemental
fact.
Drainage! Draaaainage, Eli, you boy! Drained dry. I'm so sorry.
Here, if you have a milkshake, and I have a milkshake, and I have a straw. There it is,
that's a straw, you see? You watching? And my straw reaches acroooooooss the room, and starts
to drink your milkshake.
I drink your milkshake! slurp I drink it up! Every day I drink the Blood of Lamb from
Bandy's tract.
The last man standing might be profitable.
Not so long ago gas was much higher I think the peak during a pre fracking cold winter was
$15 now under $3. Plus we're exporting the stuff bc us price is so far below Eu price. But us
price is clearly unstable Bc it's too low for frackers to break even, much less make
money.
It's the large fracking production that's driven price down to sub $3. Maybe foolish
investors and banks will soon stop burning $, after which price will rise towards $10 as this
happens utilities will really jump on solar bc gas will be increasingly non competitive.
Ca should refuse all utility requests to build more gas-fired generating plants existing ones
will be shut over the next decade as solar plus storage price continues falling and gas price
rises.
From graphs 2 and 3, you can see that half or more of the national oil production comes
from about 50,000 high producing wells (out of roughly 1mm total). These are of course on the
treadmill of decline and need continuous investment to be renewed.
Anyway after 2014 the national production responded to the price collapse within about a
year. This is what is somewhat different about fracking -- the short time horizon and the
outsize contribution of the "top" wells -- constant depletion and investment -- results in a
fairly fast response to the price environment.
Factor in pipeline capacity shortages come and go, affecting the share of $$ taken by the
midstream. In any case, they're losing money when the WTI price is in the $50-$60 range. What
does that mean? Great question.
So, the shale/fracking industry has ~$200bn in debt, god only knows how much market cap is
at risk on Shale and fracking alone, and it's COMPLETELY UN PREDICTABLE. And people buy
shares in this snake oil on the market? SEC sleeping? what a crock.
I suspect that shale plays like OXY, with marketwatch assigning a "beta" of (get this!)
0.99 to this stock, are fundamental misallocations of capital. In a political sense, it's a
red state SOE type play that doesn't pass snuff. I saw the entire Wood MacKenzie webinar
linked in Lambert's article, and even THEY themselves are amazed at the range of valuations
in the shale sector. No two wells can be compared truly. The webinar references when Ben
Shattuck asked a wall street analyst for their comps on some company, and Wood MacKenzie's
analysis using on the ground depletion knowledge, was 40% lower, versus a higher paid wall
street "comps" analysis!
This entire sector is SNAKE OIL, imho, not to mention the environmental degradation not on
the balance sheets. But it is politically privileged, so we must zip it.
HB. I have used leases developed in our field in the past ten years to demonstrate that shale
is high cost. Again, rule of thumb the cost of a conventional well in our field is
approximately 1/100 of a shale oil well ($70K range v $7 million range).
Here are some examples with production through 10/31/19:
8 producers 4 injection wells. Cumulative BO 83,466. YTD BO 2,085. First production
4/2003.
10 producers 4 injection wells. Cumulative BO 116,065. YTD BO 2089. First production
9/2005.
10 producers 4 injection wells. Cumulative Bo 55,595. YTD BO 3,023. First production
3/2006.
4 producers 1 injection well. Cumulative BO 37,418. YTD BO 1,289. First production
8/2008.
8 producers 3 injection wells. Cumulative BO 42,494. YTD BO 2,328. First production
10/2008.
4 producers 1 injection well. Cumulative BO 19,216. YTD BO 1,220. First production
12/2010.
8 producers 3 injection wells. Cumulative BO 46,463. YTD BO 1,877. First production
8/2011.
4 producers 2 injection wells. Cumulative BO 10,700. YTD BO 634. First production
10/2011.
8 producers 3 injection wells. Cumulative 59,592 BO. YTD 4,956 BO. First production
11/2011.
1 producer. Water disposed of in adjoining lease. Cumulative BO 7,872. YTD BO 444 BO.
First production 5/2012.
8 producers 3 injection wells. Cumulative 56,500 BO. YTD 3,858 BO. First production
6/2012.
4 producers 1 injection well. Cumulative BO 11,758. YTD BO 1,457. First production
6/2013.
2 producers. Water disposed of on adjoining lease. Cumulative 3,524 BO. YTD BO 393. First
production 11/2013.
6 producers Two injection wells. Cumulative 25,988 BO. YTD 3,233 BO. First production
9/2014.
Figure in anywhere from $60K-80K to drill, complete and equip each well including
electric, flow and/or injection lines. Figure another $20-30K for a tank battery.
Assume anywhere from 12.5 to 20 percent royalty.
Of course, some projects do better than others. But compare this to shaleprofile.com
wells.
There was very little drilling in our field from 1987 to 2003. There has been very little
since 2015. Century plus year old stripper field.
There have also been many reclamation projects in our field during 2005-2014 of abandoned
wells wherein the producers went bust in the 1990s, with 1998 being a knockout blow.
We took over 2 wells drilled in the 1950s they were abandoned in 1998. We just had to
equip them and build a new tank battery. We also took over three wells also drilled in the
1950s where we had to do the same, plus plug the injection well and convert one producer to
an injector. These work well at $55-65 WTI also.
I can also point to many projects developed in our field in the 1980s where cumulative per
well has topped 40K BO to date.
Conventional oil is a much better deal than shale usually when you can find it. And also
when you aren't trying to pay for 8 figure CEO pay, skyscrapers and jets out of it.
Shale just has the scale. Huge scale. Worldwide game changing size.
Shallow, I can't thank you enough. Alot to digest here. My first glance gave me the feeling
shale drilling dollars are about half as productive. Maybe you have a better number.
When a new field is drilled, is it always under pressure without the cost of lifting it
from the hole? Then once the pressure is exhausted it becomes a stripper?
A lot of the Huntington Beach field lays under the ocean. There is over a mile long row of
wells along the shoreline. I'm assuming they go horizontal under the ocean. Only a few wells
have lift Jacks. Can strippers wells go horizontal?
There isn't enough down hole pressure here for natural flow. Everything goes on pumping unit
immediately and injection wells are also drilled at the same time as production wells.
To put into perspective, the field was originally drilled over 100 years ago. Waterflood
was initiated on a large scale right after WW2. Many wells were plugged in the late
1960s-early 1970s when oil prices were low. The field was redrilled in the late 1970s –
early 1980s. Little activity after 1986, until prices took off during the Iraq War.
For example, we operate a lease that was originally drilled in the 1950s. It was plugged
out in 1972. In 1979-81, all of the plugged wells were drilled out (casing had not been
pulled). New injection wells were drilled.
Cumulative from 9 producing wells since 1979 is over 140K BO with production currently at
5.5 BOPD. It is difficult to tell what these wells produced from 1953-1972, because they were
part of a larger unitized waterflood project. Our guess is around 200-250K BO during that
time frame.
Only a small company would be interested in 9 wells making 5.5 BOPD, but they have been
economic even during the worst part of 2016 (barely during Q1 – 2016).
There haven't been HZ wells drilled in the shallow zones (1,500' and below). However,
there has been some success with 1,800'-5,000' TVD hz wells. Not sure of the economics.
There has been success with slick water fracks in deeper vertical wells also.
No way. It's already here, and there will be no rebound. BTW I did carefully read your
comments above Dennis and thank you for your time to respond. As always, your responses are
significantly better than what my caustic remarks deserve.
As has been said many times, money does not equal geology. Even if a new tranche of
'investment' could be begged, borrowed, or stolen (likely stolen) it would be spent to build
new drilling equipment, pay for new leases/roads/infrastructure, with all of it into new
wells that will produce less than any before them. If inflation is a factor (and it is), the
borrowed & eventually defaulted upon money will buy less than before.
Shale started bad, and it will stay bad. No shale well was a gusher instead, they all
needed huge horsepower, millions of gallons of water, hundreds of tons of sand, and lots of
investment dollars just to get started. None of these were ever a Texas gusher. To me, this
is no business model to follow, it is a debacle.
We have seen hundreds of shale companies go bankrupt over the last couple of years. Going
forward, there won't be hundreds of bankruptcies because there won't be hundreds of shalies
to go bankrupt. Like the motorcar companies of old, it'll go from dozens of market
participants to a handful through M&A and bankruptcies. There is still plenty of surface
carnage to come and it is far from over. Bear in mind, this is largely the same crowd that
kept exclaiming a dropping 'breakeven' price from 2010 forward, to the point where $20 was
wildly shouted from the rooftops (particularly from John Mauldin) as the point of
profitability. Of course, none of it was true. Now we see at long last that $60 (and probably
$75) was the true breakeven point. Lots of C-suite executives should be in jail for their
malfeasance, but of course none are and with the exception of Aubrey McClendon, all of them
are still 'at large'.
So with all this in mind and to round off a long screech, I summarize by saying that 2019
is peak shale.
The small companies, which have gotten only B class land will have to reduce, leading the
decline.
The bigger ones can continue to grow to a certain amount – but using up their A
class land. Especially all non-Permian will see this very soon and start declining. So
Permian growth soon will not be enough to keep up all shale decline – and this at the
cost of the Permian Tier A claims.
Oil production from shale will have a long future if prices settle at 100$ – but
with worse land it will just not be a bit boom.
A boom means high drilling everything costs, in a long calm era everything has more normal
prices (why should a truck driver carrying fertiliser to farm tows earn much less than a
truck driver delivering sand to a hole). And so finally some money can be earned in the oil
spot.
If the Democrats take over and get more green, taxes on oil production will be increased
anyway, and tax credits cut – so more calm drilling anyway. This is a big "if", I don't
know how the D – R battle stands now.
" The golden age of U.S. shale is far from over, with an expected slowdown in the Permian
Basin likely to be temporary, according to the new U.S. Energy Secretary.
The shale boom helped transform the U.S. into a net exporter of crude and petroleum
products in September from a major importer a decade ago. Even as growth is set to slow next
year in the Permian and elsewhere as drillers respond to investor demands for capital
restraint, Dan Brouillette said the shale boom has further to run."
Permian Drillers Are Struggling To Keep Output Flat
Newer wells in the Permian see their oil and gas production declining much faster than
older wells, and operators will need to drill a large number of wells just to keep current
production levels, an IHS Markit analysis showed on Thursday.
IHS Markit has analyzed what it calls the "base decline" rate, calculating the actual or
expected production of all the operating wells at the start of the year and tracking their
cumulative decline by the end of the year. Over the past decade, the base decline rate of
the more than 150,000 producing oil and gas wells in the Permian has "increased
dramatically," according to the analysis.
Your article goes into a lot of depth. I noticed these statements:
"The main driver of Legacy Loss is Total Production, which is logical.
In Permian, higher Initial Production (IPt) increased legacy loss, probably because new wells
deplete faster than old wells"
New wells depleting fasting than old wells partly explains why the monthly legacy loss
keeps increasing from month to month. It's now close to 600kbd/month, according to EIA
DPR.
The chart below from the article shows Jan 2015 as Peak Shale No 1 as legacy loss was
above new monthly shale production. The author says when "red line gets above new monthly
initial production then that's Peak Shale No 2", which might happen as soon as early 2020.
This is shown by the dashed line "IPt minus Legacy Loss" reaching zero, which means Peak
Shale No 2. The author says that this could happen if WTI stays at $55.
The basic premise is that productivity per completion has stalled, and there is no longer
a huge overhang of cheap frac spreads keeping the frac market oversupplied.
And what, Dennis? How, pray tell, will 17 million horsepower -and other infrastructure
including manpower – magically re-appear in 2020 and inflate another peak? With
existing shale finances in the tank, $300 billion of already accumulated and un-repayable
debt, and Wall Street financiers demanding repayment on their investments, your
prognostication for a rebound has a tinge of 'wildly unrealistic' about it.
ExxonMoble boe per day is 2.25 millon and has a market value of $300 billion. The tight oil
shale play over the last decade has increased production 7 million bpd. Is $300 billion of
debt really out of line? Do you have CFO experience with a multi-billion dollar company?
In the trucking industry the major freight companies running 24/7 turn their tractor fleet
over on a 5 year rotation receiving 20 cents on the dollar at retirement. Ready mix trucks
are turned over after 10 years rotation at 20 cents or less on the dollar running 12/5. When
the business environment is good. It's easy to delay retirement a little to meet demand. When
times are difficult, the old trucks sit in the yard and can be stripped for parts.
I have to question your hair on fire comment. Do you know the life expectancy of a
drilling rig for a large corporation ? The related article is talking about retiring 10
percent. That's a 10 year rotation. Maybe replacement is just cost efficient verses down
time. The big boys don't work on the same time frame as the little guy.
HB. $300 billion divided by 7 million comes to over $42,000 per barrel of debt. IMO that
is a high level of debt unless oil prices recover to 2011-14 levels.
Only the best oil production is selling for that in our part of the world and that is
production with a decline rate of 3% per year or less.
Regarding XOM, keep in mind that includes not just the upstream, but the midstream and
down stream, both of which are substantial.
XOM also has substantial international upstream assets which are generating substantial
cash flow at $60s Brent.
The only reason there is any production of shale oil at all is that there is a combination of
cheap money and a plethora of desperate investors starved for yield. Well guess what, the
investors want a return on their investment and the cheap money is drying up. So, artificial
life support is being withdrawn and the patient is now expected to get off the emergency room
gurney and start working for his keep. We shall see how that turns out.
This whole exercise in perfidy is much like Uber, that has never made a profit to date,
and yet was supported by billions of investor dollars. The whole ignominious affair put
hundreds of thousands of cabbies into destitution and bankruptcy, i.e those who didn't enjoy
the largess of investors willing to put up with loss-making operations for years on end.
Uber and Shale; the twin shitstorms of inequity, capital misalocation, and widespread
collateral damage to their respective proximal markets.
I agree with your concerns Mike. It seems to me that debt will be accumulated in the system
until it needs to be defaulted on. The governments of the world have become expert on kicking
the can down the road.
But that path will end one day, perhaps suddenly. Default will come via one of several
mechanisms- currency devaluation and debt write-off, for example. Whatever method, it will
severely hurt those who were expecting pensions or government payments (Medicare/SS), or to
live on savings or investment yield. These things will be massively de-valuated. Negative
interest rates you have been hearing about are just the early symptom of this process. A
president who cannot release his tax returns because he has a long pattern of committing
severe financial crimes, is another. The extreme accumulation of wealth among the super
wealthy is yet another.
I have given up expecting a 'fair' or rational game.
The EIA has December 2019 C+C production at 12.99 million bpd. They have December 2020 at
13.28 million bpd. That is an increase, December to December of .29 million bpd. Quite a
comedown from the over 2 million bpd increase in 2018.
The financial struggles of the U.S. shale industry are
becoming increasingly hard to
ignore,
but drillers in Appalachia are in particularly bad shape.
The Permian has recently seen
job
losses
, and for the first time since 2016, the hottest shale basin in the world has seen job
growth lag the broader Texas economy.
The industry is cutting back amid heightened
financial scrutiny from investors, as debt-fueled drilling has become increasingly hard to justify.
But E&P companies focused almost exclusively on gas, such as those in the Marcellus and Utica
shales, are in even worse shape. An IEEFA
analysis
found
that seven of the largest producers in Appalachia burned through about a half billion dollars in
the third quarter.
Gas production continues to rise, but profits remain elusive.
"Despite booming
gas output, Appalachian oil and gas companies consistently failed to produce positive cash flow
over the past five quarters," the authors of the IEEFA report said.
Of the seven companies analyzed, five had negative cash flow, including Antero Resources,
Chesapeake Energy, EQT, Range Resources, and Southwestern Energy. Only Cabot Oil & Gas and Gulfport
Energy had positive cash flow in the third quarter.
The sector was weighed down but a sharp drop in natural gas prices, with
Henry
Hub
off by 18 percent compared to a year earlier. But the losses are highly problematic. After
all, we are more than a decade into the shale revolution and the industry is still not really able
to post positive cash flow. Worse, these are not the laggards; these are the largest producers in
the region.
The outlook is not encouraging.
The gas glut is expected to stick around for a
few years. Bank of America Merrill Lynch has repeatedly warned that unless there is an unusually
frigid winter, which could lead to higher-than-expected demand, the gas market is headed for
trouble. "A mild winter across the northern hemisphere or a worsening macro backdrop could be
catastrophic for gas prices in all regions," Bank of America
said
in
a note in October.
The problem for Appalachian drillers is that Permian producers are not really interested in all
of the gas they are producing. That makes them unresponsive to price signals. Gas prices in the
Permian have plunged close to zero, and have at times turned negative, but gas production in Texas
really hinges on the industry's interest in oil. This dynamic means that the gas glut becomes
entrenched longer than it otherwise might. It's a grim reality plaguing the gas-focused producers
in Appalachia.
With capital markets growing less friendly, the only response for drillers is to cut back. IEEFA
notes that drilling permits in Pennsylvania in October fell by half from the same month a year
earlier. The number of rigs sidelined and the number of workers cut from payrolls also continues to
pile up.
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The negative cash flow in the third quarter was led by Chesapeake Energy (-$264 million)
and EQT (-$173 million), but the red ink is only the latest in a string of losses for the sector
over the last few years. As a result, the sector has completely fallen out of favor with investors.
But gas drillers have fared worse, with share prices lagging not just the broader S&P 500, but
also the fracking-focused XOP ETF, which has fallen sharply this year. In other words, oil
companies have seen their share prices hit hard, but gas drillers have completely fallen off of a
cliff. Chesapeake Energy even
warned
last
month that it there was "substantial doubt about our ability to continue as a going concern." Its
stock is trading below $1 per share.
Even Cabot Oil & Gas, which posted positive cash flow in the third quarter, has seen its share
price fall by roughly 30 percent year-to-date.
"Even though Appalachian gas companies
have proven that they can produce abundant supplies of gas, their financial struggles show that the
business case for fracking remains unproven,"
IEEFA concluded.
Tags
Business Finance
"... StateImpact Pennsylvania noted that costs to reclaim a well could add up to $20,000, and DEPspokesperson Fraley said they could be "much, much higher." The GAO report noted that "low-cost wells typically cost about $20,000 to reclaim, and high-cost wells typically cost about $145,000 to reclaim." ..."
"... The Western Organization of Resource Councils summarized bonding requirements by state, and none of them came even close to being adequate to cover estimated costs to deal with old wells. In North Dakota, a $50,000 bond is required for a well. But a $100,000 bond can cover up to 6 wells, which comes out to $16,667 per well -- or approximately one tenth of the estimated cost to reclaim a well in that state. ..."
"... By any measure, the amount of private money currently allocated in the U.S. to plug and reclaim oil and gas wells is a small fraction of the real costs. That means oil and gas wells -- and the U.S. had one million active wells in 2017 , and even more abandoned -- will either be left to fail and potentially contaminate the surrounding water, air, and soil, or the public will have to pick up the tab. This represents just one of the many ways the public subsidizes the oil and gas industry. ..."
"... The mineral extraction business model in the U.S. is set up to maximize profits for executives, even as they lose investor money and bankrupt their companies. That is true of the coal industry and that is true of the shale oil and gas industry . ..."
Increasingly, U.S. shale firms appear unable to pay back
investors for the money borrowed to fuel the last decade of the fracking boom. In a similar
vein, those companies also seem poised to stiff the public on cleanup costs for abandoned oil
and gas wells once the producers have moved on.
"It's starting to become out of control, and we want to rein this in," Bruce Hicks,
Assistant Director of the North Dakota Oil and Gas Division,
said in August about companies abandoning oil and gas wells. If North Dakota's regulators,
some of the
most industry-friendly in the country , are sounding the alarm, then that doesn't bode well
for the rest of the nation.
In fact, officials in North Dakota are using Pennsylvania as an example of what they want to
avoid when it comes to abandoned wells, and with good reason.
The first oil well drilled in
America was in Pennsylvania in 1859, and the oil and gas industry has been drilling -- and
abandoning -- wells there ever since. Pennsylvania's Department of Environmental Protection
(DEP) says that while it only has documentation of 8,000 orphaned and abandoned wells, it
estimates the state actually has over a half million.
"We anticipate as many as 560,000 are in existence that we just don't know of yet," DEP
spokesperson Laura Fraley told
StateImpact Pennsylvania . "There's no responsible party and so it's on state government to
pay to have those potential environmental and public health hazards remediated."
According to StateImpact, "The state considers any well that doesn't produce oil and gas for
a calendar year to be an abandoned well."
That first oil well drilled in Pennsylvania was 70 feet deep. Modern fracked wells, however,
can be well over 10,000 feet in total length (most new fracked wells are drilled vertically to
a depth where they turn horizontal to fracture the shale that contains the oil and gas).
Because the longer the total length of the well, the more it costs to clean up, the funding
required to properly clean up and cap wells has grown as drillers have continued to use new
technologies to greatly extend well lengths. Evidence from the federal government points to the
potential for these costs being shifted to the tax-paying public.
The Government Accountability Office (GAO)
released a report this September about the risks from insufficient bonds to reclaim wells
on public lands. It said, "the bonds operators provide as insurance are often not enough to
cover the costs of this cleanup." The report cited a Bureau of Land Management (BLM) official's
estimate of $10 a foot for well cleanup costs.
StateImpact Pennsylvania noted that costs to reclaim a well could add up to $20,000, and
DEPspokesperson Fraley said they could be "much, much higher." The
GAO report noted that "low-cost wells typically cost about $20,000 to reclaim, and
high-cost wells typically cost about $145,000 to reclaim."
In North Dakota, where state regulators have raised concerns about this growing problem, one
of the top industry regulators, State Mineral Resources Director Lynn Helms, estimated that
wells there cost
$150,000 to plug and reclaim.
And this problem isn't just in the U.S. Canada is facing a similar cleanup crisis.
Financial Bonding Requirements for Well Cleanup
Legally, oil and gas companies are required to set aside money to pay for well cleanup
costs, a process known as bonding. These requirements vary by state and for public lands, but
in all cases, the amounts required are so small as to be practically irrelevant.
The GAO report reviewed the bonds held by the Bureau of Land Management for wells on public
lands and found that the average bond per well in 2018 was worth $2,122.
The Western Organization of Resource Councils summarized bonding requirements by
state, and none of them came even close to being adequate to cover estimated costs to deal with
old wells. In North Dakota, a $50,000 bond is required for a well. But a $100,000 bond can
cover up to 6 wells, which comes out to $16,667 per well -- or approximately one tenth of the
estimated cost to reclaim a well in that state.
North Dakota has a history of bending to oil and gas industry pressure when it comes to
regulations. While North Dakota's bonding rules fall far short of what's needed to actually
cover full cleanup costs, the reality on the ground is much worse. Regulators allow companies
to
"temporarily abandon" wells, which requires no action from companies for at least seven
years. Wells can hold this "temporary status" for decades. And another practice in the state
allows a company to sell old, under-performing wells to another company, passing along the
liability but not the bonding funds.
By any measure, the amount of private money currently allocated in the U.S. to plug and
reclaim oil and gas wells is a small fraction of the real costs. That means oil and gas wells
-- and the U.S. had one million
active wells in 2017 , and even more abandoned -- will either be left to fail and
potentially contaminate the surrounding water, air, and soil, or the public will have to pick
up the tab. This represents just one of the many ways the public subsidizes the oil and gas
industry.
A South Dakota Case Study
South Dakota allows companies to post a $30,000 bond for as many wells as the company
chooses to drill. Spyglass Cedar Creek is a Texas-based company that was operating in South
Dakota and recently
abandoned 40 wells, which the state has estimated will have a cleanup cost of $1.2
million.
However, there is a twist to this story. That $30,000 bond doesn't really exist. The owners
of the company had put $20,000 of it into a Certificate of Deposit. But when the state went
looking for that money, the owners said they had cashed it in 2015 because, as reported by the
Rapid City Journal , "company officials did not remember what the money was for."
Spyglass Cedar Creek does not have the money set aside that was required to clean up these
wells, the state does not have recourse to get that money, and some of the wells are reportedly
leaking. So, what can be done?
According to Doyle Karpen, member of the South Dakota Board of Minerals and Environment, the
answer is for the taxpayers of that state to cover the cost.
" I think the only way we can correct this is go to the Legislature and ask for money,"
Karpen
said earlier this year.
Following the Coal Industry Business Model
What is starting to unfold with the oil and gas industry is very similar to what has already
been playing out with the U.S. coal industry.
The paper notes how the bankruptcy process is used by coal companies to rid themselves of
environmental cleanup liabilities and pension costs "in a manner that has eviscerated the
regulatory schemes that gave rise to those obligations."
This summer, Blackjewel famously failed to pay its coal miners, and even pulled funds out of
their bank accounts, after the company suddenly declared bankruptcy in July. That prompted
workers to sit on train tracks in Kentucky, blocking a $1 million shipment of coal, in a
two-month protest . And Blackjewel is poised to leave behind
thousands of acres of mined land in Appalachia without adequate reclamation.
Privatize the Profits, Socialize the Losses
The mineral extraction business model in the U.S. is set up to maximize profits for
executives, even as they lose investor money and bankrupt their companies. That is true of the
coal industry and that
is true of the shale oil and gas industry .
At the same time, the regulatory capture by these industries at both state and federal
levels allows private companies to pass on environmental cleanup costs to the public, and the
inadequate bonding system for oil and gas well reclamation represents just one more
example.
The so-called fracking revolution in America has resulted in many new records: record
amounts of U.S. oil and gas exported (to the detriment of a livable climate), new levels of
human
health impacts on surrounding communities, record numbers of industry-induced earthquakes , record amounts of flaring
natural gas
in oil and gas fields, and record-breaking
depths and lengths of wells.
And the cleanup costs for the fracking boom are also poised to be staggering.
The answer to the question posed is yes. History confirms this. Present laws allow
companies to get away with this. I don't see this changing in the future.
Socializing the cost of cleanup/decommissioning was one of the reasons the people in our
township fought, and won, to stop Duke Energy's wind power project which would have put a few
hundred industrial turbines over three townships.
I was offered a contract and it was truly toxic. Duke would not have been required to fund
decommissioning until 20 years into what is a 25 year lifespan for the generators and that
bond would have been held in Duke's accounts. Duke could have merely walked away before 20
years leaving a liability for any landowner. My expectation would be a $250,000 escrow for
each tower/generator and held by the landowner so that Duke would have no access to it until
decommissioning.
My reaction to seeing the headline was "is the Pope Catholic?"
Of course, the public will pay. Texas govt already pays to cap abandoned wells.
As for decommissioning costs, utilities typically keep decom accounts, and include the costs
of decom in their revenue requirement, when coming in for a rate case. The money should be
there, when needed. (Of course, anything can happen – but if that were the case, we'll
have bigger things to worry about than the decommissioning of wind turbines.)
Rich Texans like small government when they can profit from governmental smallness.
Rich Texans like big government when they can profit from governmental bigness. If Rich
Texans can make the Texas government pay bigly for capping abandoned privately profitable
frack well, such Texas big government payments to cap the abandoned wells just make the Rich
Texans richer by relieving them of paying themselves for the costs they themselves caused by
fracking those wells.
1. Increase the EPA budget tenfold or more for cleanup, adding fracksites to the superfund
list. This will provide much-needed jobs for millions of Americans as they help in greening
Earth.
2. Require that Native American tribes get busy recovering natural resource damages. If
they refuse, this would provide a much-needed opportunity to establish military bases on
reservations to quell rebellions against superfund cleanup.
3. Some alarmists have alleged that cleanup of toxic superfund sites can pose health
risks, which is a well-known talking point of enemies of Earth. Even so, Congress can require
healthcare providers to deliver all necessary treatments to superfund workers in order to
assuage any concerns of the workforce.
4. Congress can relax labor laws so that undocumented migrants and their children are
allowed to participate in healing Earth by joining the superfund cleanup workforce.
These measures will ensure Full Employment, Earthhealth, Native Pacification, and
Demographic Diversity throughout the nation.
>>>Require that N<ative American tribes get busy recovering natural resource
damages. If they refuse, this would provide a much-needed opportunity to establish military
bases on reservations to quell rebellions against superfund cleanup.<<<
It has been a decade since I have done any research, but that said, requiring the
destitute to demand that they somehow get the money needed to get recompense from the Feds
and corporations is silly. Many tribes are dirt poor and others are marginal, even though
many nations have been trying for decades, perhaps longer than anyone alive, to get the
payments owned from the mineral and oil extraction from their lands. Records and payments
that the federal government are supposed to manage, but never have. Records go missing, the
decision making process is obfuscated, and billions have gone missing.
One of the big reasons I just loathe Identity Politics, victim blaming, and other current
dodges is that the current political establishment and all their little minions in social
media and nonprofits pay no mind to the continuing financial, political, legal and social
rape, impoverishment, and degradation of millions of Americans have and do endure is just
ignored. Although Standing Rock was a nice blip. At least the Disposables are worthy of
conscious contempt. The Indians are sent to oblivion where they can go finish
dying.
Well, yes and no. Yes, the public will pay for any 'cleanup' that is actually done (ie,
YOOGE dollars to 'remediation' companies), but really, my bet is that most of these orphan
wells and mines will just be left as they are.
Exactly what I was about to say. The wells will leak their toxins, the rich will escape to
some idyllic bunker, while the poor are offered oxycodone or fentanyl to alleviate their
suffering.
Cleveland is an example not one of the dying industries that once flourished here cleaned
up after themselves before they shut down most of the former degraded sites don't rise to the
level of a superfund problem, but they are virtually irredeemable nonetheless
do not know how the figure for abandoned well cleanup is derived. In Canada, estimates by
the industry friendly Fraser Institute and the CD Howe Institute claim those figures:
C.D. Howe estimates there are more than 155,000 wells with no economic potential that
must be reclaimed, with cleanup costs for an orphan well ranging from $129 million to $257
million, with a total provincial cleanup bill of $8 billion. Glen cites a far higher
estimate from the Orphan Well Association -- $47 billion.
And the problems regarding financing are the same as in the USA – although the
Supreme Court of Canada has ruled in favour of clean-up cost coverage before debtor
payout:
Glen quotes Daryl Bennett of My Landman Group who observes that not only are the funds
on deposit insufficient, but "the cost to reclaim all these assets is now far higher than
the value of those assets." With the oil and gas sector unable to shoulder these costs, the
costs look likely to land in two places -- the pockets of landowners with land dotted with
abandoned wells, and the taxpayers who will pay those landowners to ensure the land is kept
in productive use.
Energy companies must fulfil their environmental obligations before paying back creditors
in the case of insolvency or bankruptcy, Canada's Supreme Court has ruled.
The top court's ruling released Thursday overturns two lower court decisions that said
bankruptcy law has paramountcy over provincial environmental responsibilities in the case
of Redwater Energy, which became insolvent in 2015. That meant energy companies could first
pay back creditors before cleaning up old wells. In practical terms, that means energy
companies could walk away from old oil and gas wells, leaving them someone else's
responsibility.
I live in the hills of SE Ohio. Gas is everywhere down here, but (fortunately) not in the
commercial quantities needed for major fracking operations. Small gas wells dot the
landscape. Due to the crash and the oversupply of the fracking boom, gas prices fetch a small
fraction (about 20%) of their previous peak. No new wells have been placed in years.
A neighbor of mine has a has well that has ceased commercial operation. He still gets free
gas from it as per the lease agreement, but the small local gas company no longer wants to
pay to maintain and operate it, as in no longer yields any appreciable commercial output. The
gas company initially said that they would sell him the well for $7,000, and he agreed
(verbally, I believe) to that price. The gas company then said it wasn't even worth that, and
would just give him the well.
It struck me as decidedly odd that a business, which by all accounts is cash-strapped and
barely getting by, would voluntarily forgo any amount of money. It makes me think that there
must be certain laws and regulations that apply to a commercial transaction that do not apply
to what is in effect a donation.
Does anyone know if there are reasons why someone would give away as opposed to sell an
asset, particularly one that has clear and significant liabilities and/or associated cleanup
expenses? I know that the landowner should be responsible for cleanup and capping costs
whether they bought for money or were given the gas well for free, but does the gas company
get out of something by giving as opposed to selling the asset? They certainly did not do it
out of the kindness of their hearts; they hate that landowner. He opened up a business and a
commercial kitchen and hooked it to his gas well, which was almost certainly responsible for
its commercial depletion.
Can't give you that answer but have a similar observation. My homeplace is just up the
road a bit–bought sans Mineral Rights in the 1960's–and had a well placed just
off the property line on a pad located in the swamp/drainage next door in 1981.
We got no free gas–but hundreds in the Township couldn't resist. Too good to be true.
Lots of wells installed–with FREE GAS and a Royalty Check which helped many heat
through winter and constant Lay-offs in that churning, rust-belting economy of late 80's and
90's
It was a 90 day drill–24/7, then pumped with an electric skip jack until early 2000s
when production petered out.
Still idled–however that swampland finally sold 2 months ago–and Seller was
insistent that well ownership transferred with the sale. No transfer–No Sale. There was
a token of 1,000$ for the well included in the Land Price. The five adjoining landowners (all
No Mineral Rights and 2 with located wells) all looked at purchase and walked
away–partly because of the Lay(2 of 7 acres high ground) but all because you had to
take the "dead well" with the land.
Locals thought that was just plain "fishy" about something.
Ohio EPA isn't very effective–note the Mud Spill at the Tuscarawas R–and as more
and more well plays are petering out and Service Co.'s going out of business concern IS
rising among landowners.
I won't say my Homesteads neighbors are environmentalists as much as PO'd that the access
roads have not been graded and graveled and that inconsistent gas flows are causing them to
go Propane
It might come under Real Estate full disclosure laws, which require a seller to notify
buyers of any liabilities – like the cost of closing and cleanup of a well. Might not
apply to a "gift."
If course, if the owner keeps it operating for their own use, they don't have to cap and
restore it – but it will run out some day.
Not well understood is the fact that:
State taxpayers fund state spending, and
County taxpayers fund county spending, and
City taxpayers fund city spending, but
Federal taxpayers do not fund federal spending.
The federal government neither needs nor uses tax income for anything. In fact, federal
taxes are destroyed upon receipt.
The federal government, being Monetarily Sovereign, creates brand new dollars, ad hoc, by
spending.
Thus, all the federal spending to remediate any polluted sites in America add dollars to
the economy, and thereby benefit taxpayers.
Benefits natural-person taxpayers just how? By underwriting the looting behaviors of
corporations and their executives, sparing them from having to internalize the "costs" that
leavings from industry impose on "neighbors" and all the natural persons, and nature,
downwind and downstream and living next to those industrial and extractive spots? Not much
healthy incentive or public benefit in that formulation.
The federal "Superfund" was funded by a tax on feedstock chemicals, and "responsible
parties" that caused or contributed to the release of hazardous substances, anyone related by
contract to them, and site owners, were to pay all removal and remedial response costs. Why
not that model, which sought to force the costs back into the calculus? And yes, the
Superfund program had its share of problems, still does -- contractor gold-plating,
goldbricking, and fraud, corruption of the processes, and others, and of course the exemption
of "petroleum products" from the definition of hazardous substances. But it did effect some
significant changes, along with the federal Resource Conservation and Recovery Act, in
generation and disposal of hazardous substances.
Its pretty simple. Most governments have been collecting royalties on the extracted oil
and gas. They can just repurpose that past and future money to cleanup. The politicians said
it would pay for schools and firemen but future politicians will likely need to repurpose
money. At least Superfund exists, so there is a mechanism to do it.
In Colorado there are 60,000 active oil and gas wells and 20,000 that are abandoned. That
count is from 2017. Several thousand more wells have been permitted and drilled since
then. https://corising.org/colorado-map-oil-gas-wells/
A more-to-the-point question in response to this title is; When has Big Oil, Big Mineral,
Big any natural resource exploiter ever paid to clean up their mess? The answer is only when
there is a gun at its head and all the owners have not yet run off with their booty.
Beulah, North Dakota, has a coal gasification plant, open for free public tours. It's a
closed loop – shallow strip mining on their property, has sold to a single nearby
customer. The size of the equipment is mind-boggling. They are required to recontour the land
to exact pre-mining measurements and to replace every shrub and tree. The reclaimed land
looked lovely.
As a passing tourist, I know nothing in depth, but I was impressed and see no reason why
the same is not required of any resource extraction.
I think it's time we take a long hard look at this country's bankruptcy laws. For as long
as I can remember, bankruptcy has been a "tool" of business to escape what is most often the
responsibility of the business and/or business owner. See DJT et.al. The idea that a business
like the ones in this article can declare bankruptcy , dump the debt owed to creditors, and
continue to give huge bonuses to management members is foolish. When a business like the
fracking industry operators can't pay it's debts, the doors should close, the assets sold and
the creditors (in this case, the state involved) receive everything necessary to "clean up"
the mess. Most cases involving fracking wells would need more in funds than the company has
in assets. Bottom line, that's it folks. The state gets it all (which will almost never be
enough) and the folks go home, no bonus, no car, end of story. Many things would change in a
system that does not allow the dumping of debt onto society so people who were very bad at
running a business can continue to be rewarded. Just sayin ..
In many cases, the state could impose a unit royalty dedicate to future clean-up. The
royalties could go into a dedicated trust fund. The cash flow of producing wells would set
aside the means to cleanup many wells.
If by "the public," the author is referring to federal taxpayers, the answer is, "NO." Not
well understood is the fact that:
State taxpayers fund state spending, and
County taxpayers fund county spending, and
City taxpayers fund city spending, but
Federal taxpayers do not fund federal spending.
But, but, but we are "energy-independent!". Surely a small price to pay for massive
environmental despoliation in the era of late-capitalism, where "externalities" are booked on
the public ledger.
Yes, so Dubya invades Iraq to make sure the supply of black gold to the US is not
interrupted (and hey Dad – look, we got Saddam .), then the pendulum swings and Obama
mostly pulls out of the ME and " encourages" fracking to get domestic oil security. In the
meantime the political vacuum caused allows the rise of ISIS, so Syria is destroyed and
millions of refugees overwhelm Jordan, Turkey and Europe. Then along comes Trump and doubles
down, allowing the Saudis to commit unfettered genocide in Yemen (with a nice little side in
US arms sales), and now the Turks to indulge in a bit of "ethnic cleansing" of their Kurds
– you know that mob who have fighting for a bit of their own country for a hundred
years since they were unfortunately overlooked when the British and French divided up the
Middle East.
We all really need to get off this addiction to fossil fuels ASAP and convert to electric
cars and road transport and household and industry power derived from solar, wind and hydro
electricity.
It is not just climate change which is the " collateral damage" of fossil fuel use.
And in my country we have to do the same, and STOP MINING F .. COAL and allowing new coal
mines to be run by environmental vandals like Adani. AAAAAAAGH!
Obama pulled out of the ME? I must missed that during the US invasion/occupation of parts
of Syria as part of its illegal regime change war, that provided safe haven for jihadists and
ISIS in Syria
Skip-As I read it Obama pulled many, but not all obviously ,of the troops from Afghanistan
and Iraq, – and was widely criticised for doing so "prematurely" by the media and
commentariat.
Mind you, that could have been just " fake news" .
Of course that the Public will pay for the environmental cleanup of the pollution of dead
fracking wells. Just as they will pay for dead oil platforms in high seas, or
"decommissioning" of spent nuclear fuel (when someone figures out how that's done), or
underfunded pension plans or any other such scam that was advertised as doing something for
greater good but which always was, and always will be, extraction of something out of
presumed public ownership (earth) for benefit of those who figured out what to extract.
Bottled water comes to mind too.
How will public pay? Entropy, of course. No need to involve printed papers masquerading as
"money". Public will simply work harder and harder, but will have less and less of
everything, firstly less hospitals and schools, then less police and firefighters, then less
judiciary and then less water, less food and less air suitable for breathing.
The sad part is, we taxpayers, continue to live in an imaginary world where we expect that
"government" will do "something for us, the people". Governments do not look at it that way.
"Governments" are just an extraction apparatus, by which those that can extract, extract, and
those that cannot, provide the extracted material.
I looked at governments and economical systems all over the world and there is no
exceptions to this. The conundrum is, what to do about it and how?
I apologise to the commentariat but I simply must enclose two links to my favourite brain
washing outlet, BBC, here in UK. While our parliament continues to work for everyone else but
the British People, the Big Brother outfit goes on to disseminate dross like this:
It seems as if ole David Hughes, which I have a lot of respect, decided to come on the
website and leave a few comments. Basically, Hughes's reply was, "WHAT'S THE BIG DEAL IN
2018?" He went on to say that we all know these wells decline 50+% in the first year, so why
start to make a STINK about it now?
I also had several email replies from some other folks. And then we had a bit of a TIT for
TAT here in this blog with HUNTY.
However, what is going on in the Permian is only a small part of the overall situation.
Regardless if we bicker about the future Permian revisions due to the incomplete TRRC data,
the fact remains, if you look at the "Annual Compounded Decline Rate" presently, it resembles
a 70-75% STEEP CLIFF. And, the Permian isn't the only one that looks like that. You can add
the Bakken and Eagle Ford to varying degrees.
So, while a portion of the "OIL FOLKS" and a large percentage of the "DUMBED DOWN PUBLIC"
believe there is NOTHING TO SEE HERE, they couldn't be more wrong.
Furthermore, the U.S. public debt just ballooned by $227 billion in less than two weeks
and $814 billion since August 1st. While everyone has seemingly become NUMB to the amount of
these figures, the rate at which debt is being added in the United States and globally is
heading up in an exponential trend. But, there is nothing to see here.
And, then we have the fun taking place in the REPO MARKETS when, according to a specialist
in the field, a large BLOCK of CASH has been removed from the market and hasn't come back, I
gather it's just another sign that EVERYTHING IS OKAY . .nothing to see here.
Also, ExxonMobil, the largest U.S. oil company, had to borrow $7 billion in August to
repay the huge $11 billion in short term paper it borrowed 1H 2019 in order to pay dividends
and fortify its balance sheet as its Permian stake is destroying its bottom line.
And today, we see that ExxonMobil just sold its $4.5 billion upstream assets in Norway.
Yes, this is part of Exxon's plan to sell $15 billion by 2021 to focus on KEY ASSETS. I
gather that really means, they are going to have to fill in the RED they will be suffering in
the Permian as its U.S. upstream earnings continue to suffer. But again nothing to see
here
Lastly while the NOTHING TO SEE here mentality will continue even as the U.S. and global
economy heads over the cliff, taking the highly leveraged debt-based financial system down
with it, I'll make sure that I schedule some time from my day to come in here and read all
the "I TOLD YOU SO" comments.
Pop on over to the BP spreadsheet and find the regional consumption tab. For some regions
there are countries broken out and for others, not. But on this tab you can get granularity
on what kind of oil, what constituent part of crude, was consumed.
Japan. The population decline is actually pretty recent -- only since 2010. Their decline
in consumption is popularly attributed to population reduction, and I have gotten this wrong,
too, but consumption decline has been since 1995 with population gain for 15 of those years.
In more detail, their consumption decline is not gasoline. They have increased gasoline burn
since 1995. (The Prius is the 2nd most popular car in Japan and it first went on sale in
1997, so Prius didn't kill gasoline burn, which has increased).
It's middle distillates and Fuel Oil that are way down. Stuff that fuels big commercial
engines. That's what has fallen. Fuel Oil is more than maritime bunker fuel. It powers big
stuff. There was a sharp uptick of Fuel Oil consumption . . of 44% in 2012 because it was
Fuel Oil that was called on to generate electricity when all the reactors were shut down
during the quake panic. But the reactors returned and Fuel Oil resumed its decline.
One last thing that could blow all those paras out of the water. Japan had until recently
more refinery capacity than internal consumption. It's a lot like Singapore. The crude comes
in and product exports and this seems to somehow corrupt all measurements. The govt recently
shut down many of the refineries. It wasn't voluntary. Gov't ordered. Now Japan has to import
fuels, not just crude. Quite a lot. Which likely confuses the consumption measurements
further.
Ok I read this blog quite regularly but now I'm confused. US oil production has actually
fallen since the start of the year?
Dennis, can you respond to that? I thought I was just reading in the last post that the
current completion rate in the Permian was enough to raise production for five more years or
so. July is probably skewed because of the hurricane, but what gives?
It's definitely slowing. See my first post on June monthly production. When you add all the
states with shale production, there is no growth from May to June. Yes, July should be down
significantly due to the hurricane, but I expect no growth from shale.
Dennis sees an increase, Ron sees it plunging. I see it flat for a few months, and slowly
trending down. Pick your poison.
Yes the increase is pretty small for tight oil over the next 5 years only an average
annual rate of increase of 344 kb/d for US tight oil from 2019 to 2024 for the flat
completion rate scenario. This is a far cry from the 1620 kb/d increase in US tight oil
output from Dec 2017 to Dec 2018, a factor of 4.7 times slower on average than the rapid rate
of increase in 2018.
No US C+C output in June 2019 was 12,082 kb/d and in Dec 2018 US C+C output was 12,038
kb/d, so output has risen, but not by much. Yes a flat completion rate could lead to a rise
in tight oil output until 2025, though conventional output could fall to offset this.
Conventional output has been falling of late as fewer new conventional wells have been
completed for the past 6 months.
The current financial strain on shale producers is likely to intensify as many companies that
took on debt after the 2016 oil slump face large debt maturities in the next four years. As
of July, about $9 billion was set to mature throughout the remainder of 2019, but about $137
billion will be due between 2020 and 2022, according to S&P.
Seems that there will be more bancurupt filings in the years to come.
What is interesting is the footnotes. The first one says: " The supply of existing oil
production naturally declines at an **estimated 7 percent per year** without further
investment. Significant investment is needed to offset this natural decline and meet the
projected demand growth." The 7 percent figure caught my eye.
Also see the footnote about the switch over to Biofuels but Biofuels are such a very small
amount.
Continuing to look at the Regional Consumption tab from the World Stat stuff.
There is this category called Others. BP defines it as:
" 'Others' consists of refinery gas, liquefied petroleum gas (LPG), solvents, petroleum
coke, lubricants, bitumen, wax, other refined products and refinery fuel and loss."
This is not trivial afterthought. This is over 20% of the total oil consumption for nearly
all countries/regions. 24% for the whole world, and that deserves a !!!
It's 41% for India, also deserving a !!! I happen to know this derives from LPG, a hugely
popular transportation fuel in India.
China, 30%.
US 22.6%
India's total oil consumption last year was 5.9%. Light distillates had 10% growth,
gasoline 8.9%. Others, 6%. EVs and hybrids did nothing to gasoline burn there, which you
would expect for such a narrow niche product for rich people in year-round warm cities. They
didn't drive much anyway. And of course rural driving is a big thing in India, per the recent
item about political campaigns travelling place to place by road.
China's total oil consumption last year was +5.6%. Light distillates +7.3%. Kerosene/jet
fuel + 14% (!!!) Others, 7.1%.
And ditto.
As noted above Japan's consumption drop has been from lost economic activity, not
population, and it burns more gasoline today than in 1995, so Prius didn't do much there.
Their big loss is in middle distillates, because they shut down a lot of factories. Repeat,
population ROSE in Japan up to 2010. Only since then has it fallen and middle distillate
consumption (and Others consumption) has been falling steadily since 1995, even when
population was rising.
First you lose your economy, then you lose your food.
(Caveat about refinery exports from previous comment)
From the EIA monthly I see the US oil and condensate production was:
April 12. 123 Mbpd
May 12. 115 Mbpd ( – 8 000 bpd / 0,1%)
June 12. 082 Mbpd ( – 33 000 bpd/ 0,3%).
Will be very i teresting to see the production for July and August including new pipeline
capacity. To me it seems like the DUCS that was good have now been used, Baker Hughes drill
statistick document number of riggs still go down. In January EIA and Rystad believed US oil
production would reach 13 Mbpd in 4th Quartile 2019, the truth is this might already be below
12 Mbpd . As they told the growth in US shale have be funded by borrowed money , now
investors have far from get back what they where promissed, they are pissed off
There is no good real time data, at least not publicly available, on global stocks but US
stocks have declined so far this year ( https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WCESTUS1&f=W
). It seems to me that we are starting to see the effect now on lower OPEC production (cut or
whatever reasons) and LTO not growing as fast as forecasted.
A quote from IEA's last OMR (
https://www.iea.org/newsroom/news/2019/august/economic-woes-hold-sway-over-geopolitics.html
): "If the July level of OPEC crude oil production at 29.7 mb/d is maintained through 2019,
the implied stock draw in 2H19 is 0.7 mb/d, helped also by a slower rate of non-OPEC
production growth." Note that this assumes LTO-growth in US causing the market to be
oversupplied next year
The market sentiment is currently bearish on oil for whatever reason (US LTO growth,
economic slowdown, etc.), you can see this on the yield curve that Art provides, the curve
has become more flat ( https://pbs.twimg.com/media/EDENJx2XUAIR5lC.png:large
). I find the herd mentality of the oil market interesting and would not be surprised if the
herd changes direction in a not too distant future. The big question mark I see is what will
happen with the Iran-deal if/when stocks continue to decline.
Even though Norway is "the darling of alternative transport", EV sales are still a small part
of their transportation mix. All-electric 7.8%, Plug-In hybrids, 3.6%, and Hybrids 4.0%.
Without the impact of EVs, their consumption would likely have been higher.
It looks like Nick Cunningham, the author of the article below, reads peakoilbarrel.com
"The more important point is that the oil industry is slowing down more generally.
Most oil forecasters expected explosive production growth to continue through this year
and into 2020. But with June U.S. production at 12.082 mb/d, output is only about 80,000 bpd
above levels seen at the end of 2018. In other words, growth has been pretty slow this
year.
Financial stress is really setting in, forcing drillers to cut back. The rig count fell by
12 in the last week of August, part of an ongoing slide since reaching a peak late last year.
Bankruptcies are on the rise. As the Wall Street Journal notes, an estimated 26 U.S. oil and
gas companies have declared bankruptcy this year, which is close to the full-year 2018 total.
More are expected.
Worse, there is a tsunami of debt that comes due in the years ahead. According to the WSJ,
roughly $9 billion worth of debt was set to mature over the second half of 2019. But a
whopping $137 billion in debt matures between 2020 and 2022, a massive total that stems from
the huge debt issuance following the oil market meltdown a few years ago. A serious reckoning
is just around the corner."
Raymond James recently estimated that over the last three years the U.S. decline rate for oil has doubled from
1.6 to 3.2 million barrels per day. The drilled but uncompleted well inventory ("DUC") is back to normal, so the
number of wells being drilled and the number of wells being completed is now about the same. We need over 12,000 new
horizontal oil wells completed each year to hold production flat and the number of completed wells will need to go up
each year.
The U.S. Energy Information Administration ("EIA") forecast at the beginning of this year was that the U.S.
shale oil plays were just getting started and that production would increase by at least 2 million barrels of oil per
day ("MMBOPD") each year for several more years.
Now if you believe that U.S. shale production will increase by 2 million barrels per day each year for several
more years, then I have a bridge that I think you might be interested in. But let's just play "what if", or what if
it really did increase by 2 million barrels per day for the next five years.
According to the EIA's Drilling Productivity Report, December 2018 shale production, all basins, was 8,232,750
barrels per day and the legacy decline, for all basins, averaged 6.14 percent per month or 505,737 barrels per day.
Legacy decline of over one million barrels per day would be a crippling requirement of shale producers. But not to
worry, that is simply not going to happen. Now total US production did increase by two million barrels per day 2018.
In fact, according to the EI.s Monthly Energy Review, US production increased by 2,064,000 barrels per day in 2018.
But for the first 7 months of 2019, total US production has declined by 54,000 barrels per day.
USA production appears to have hit a snag. July production is now below November 2018 production.
In my opinion, legacy decline in shale production has reached a point where new production only replaces legacy
decline. In fact, legacy decline may have reached a point where it is crippling shale oil production.
Those who have followed this blog for years know that Texas oil production is reported by the Texas Railroad
Commission. But their data is very slow coming in, sometimes it is more than a year before all the data has come in.
However, Dean Fantazzini, Energy economist, Deputy Head of MSU's Chair of Econometrics and Mathematical Methods in
Economics, has developed a program that uses the vintage data to make a pretty good estimate of the actual data. His
past corrected data has been relatively accurate.
If Dr. Fantazzini's data is correct then Texas peaked in December 2018 and has declined by 280,000 by June.
All the below charts were created from the EIA's Drilling Productivity Report. The data is through September 2019
and the last few months is, of course, an estimate. Historically the estimate for those last few months has been
overestimated.
Notice the last six months is pretty much a straight line. That is because most of it is just an estimate.
It looks like the Permian is pretty much the story as far as US shale is concerned.
The Permian is now just over 50% of total US shale production.
Permian Legacy Decline has been slowly rising and now sits at about 6%.
Eagle Ford has the highest legacy decline rate, now about 8.5% per month.
It looks like shale production, outside the Permian, has pretty much hit the wall. Pay no attention to those last
four months. They are just the EIA's wild ass guess.
In conclusion: Very high legacy decline, now over 6% per month, is shale's Achilles heel. Of course, there are
other problems as well. Bankruptcies are rampant, running out of sweet spots and the price of oil is just not high
enough. It appears that the USA has peaked, or peaked until the price of oil rises at least $20 a month.
Dean's charts self correct after a couple of months. Good estimates. Red Queen is already catching up. And,
it will catch up faster the next six months from June, as most of the independents have severely cut back on
capex.
Your Wall Street journal link has a firewall. Never mind, I got through. Good post.
Pioneer has not only reduced its capex, it's reduced its workforce by 25%. Apache has given up on
the Alpine High, their biggest capex. It's 90 % gas, how stupid can you get? Yadda, yadda, Yadda. Just
google the company for capex, and put 2nd quarter 2019. Voila!
Your sure to get a positive statement from the company, but just concentrate on the capex going
forward. For example, we're losing money had over fist, translates to reduced operating expenses will
provide an increased return for 2019. Get serious. None of these companies are going to say, we are
screwed.
EOG could make it, most of the rest are totally screwed.
"I have no doubt in my mind that U.S. shale will peak, plateau and then decline like every other basin in
history," Al-Falih told reporters at OPEC's Vienna headquarters. "Until it does I think it's prudent for
those of us who have a lot at stake, and also for us who want to protect the global economy and provide
visibility going forward, to keep adjusting to it."
Dr. Raymond Pierrehumbert will be proven right belatedly.
The article does say US production still has an up side, but prices would have to be higher.
If there is
not enough supply then oil prices will obviously go higher as the did in 2003-2005 and in 2012-13.
US drilling rig count is very low at the moment being only 742, at it's highest recently the US could
have 1,400 drilling rigs working.
1,400 drilling rigs will certainly complete enough wells so new supply would exceed decline rates. When
oil prices are over $100 as they were in 2012 and the number of drilling rigs are 1,400 then you can wake me
up.
You want to focus on horizontal oil rigs. The count was as high as 1100, but many of those rigs
were lower power rigs no longer economic to operate, a lot of the current rigs are higher power and far
more efficient at drilling 3300 meter laterals commonly drilled today.
Holy f*ck Hugo, you are a raving lunatic. The oil prices can't go higher, otherwise there will be a
repeat of 2008. Clearly you are incapable of learning from the past.
Yeah, there is sort of a contradiction there. Sorry about that. But we are seeing the physical limits hit
in much of the world, regardless of the price. But if oil hits $80 to $100 a barrel, a lot more shale
could be produced. But that will not change things in the long run. It could delay peak oil by a year or
two.
In a
study of 29 fracking-focused oil and gas companies by the Sightline Institute and the
Institute for Energy Economics and Financial Analysis (IEEFA), only 11 companies posted
positive free cash flow. Even then, the figures were paltry. Collectively, the group only
reported $26 million in free cash flow for the second quarter, "far too modest to make a
significant dent in the more than $100 billion in long-term debt owed by these companies, let
alone reward equity investors who have been waiting for a decade for robust and sustainable
results," the report said.
I think a key point about a future shale bust is that it will leave very little in long
term assets. In other busts, someone comes along to cherrypick the assets with potential
profitability – its the early investors who get burnt. But if shale operators aren't
even breaking even on cashflow excluding early borrowings, then its likely that any attempt
to consolidate and shrink the industry to make it profitable would fail in the absence of a
significant price rise. Since a typical fracked well for tight oil or gas has about 18 months
production, this means that constant capital inputs are essential, an investor can't just get
a free ride for a few years on past investments.
What this means in reality is that a year or more after the inevitable bust, there will be
a massive drop off in production. Ironically of course this will lead to exactly the sort of
price rise the industry is craving – but by then it may be too late. It could of course
also be highly disruptive to the world fuel market if the US suddenly finds itself needing a
few million barrels a day of SA crude.
I tend to think of shale as an out of the money option, that the industry keeps on early
exercising to generate the appearance of a going concern, despite it losing money. As absurd
as this model of events sounds, it would predict that in a consolidation, these assets would
be picked up by oil majors, who would "mothball" till higher prices. Of course the longer
these bozos are allowed to pump at capital depleting oil prices, the less there is for the
eventual buyer in bankruptcy.
There's an interesting story in Reuters today about how towns in the Permian are starting
to make long-term bets on shale production there, in the form of investing in education and
infrastructure. It seems like the entrance of oil majors sent a signal to people there that
the bust hasn't come yet and apparently won't come for a little while. After reading the
coverage of fracking on NC and Bethany McLean's book Saudi America this seems like a bad
idea, as the financial problems of fracking stem from physical limitations of the technology.
It doesn't seem like a big oil company would be able to solve this problem, besides maybe
having deeper pockets and greater ability to ride out low prices, but that still doesn't make
fracking profitable, just less unprofitable. Here's the link:
Yes, I fwded that link to Yves & Lambert earlier today – the key thing to me is
that the oil majors don't make such long-term investments lightly. From the story:
Some of the smaller producers that pioneered shale drilling in the Permian, such as
Concho Resources (CXO.N), Laredo Petroleum (LPI.N) and Whiting Petroleum (WLL.N), are
downshifting as West Texas oil prices have lost 16% and natural gas has tumbled 36% over
the past year.
But the world's biggest oil majors are increasingly taking control of the Texas shale
business, and their drilling plans – sometimes sketched out in decades rather than
years – are envisioned to withstand the usual price drops.
The Permian Strategic Partnership, a group of 20 energy companies operating in the area,
promises to spend $100 million to promote training, education, health care, housing and
roads. The partnership chipped in $16.5 million for the charter school initiative, which
will open its first campus in August 2020 and plans to offer public education to 10,000
students over time.
The only thing in all this that is baffling me is that Wall st. just keeps giving loans to
and buying bonds for these companies to the tunes of 10s of billions of dollars. Everyone on
Wall St can't all be willfully in denial and completely blind to the fact that these were bad
investments from the beginning and that continuing to give them money is just throwing good
money after bad. Everyone makes a bad investment from time to time, but the solution isn't to
just burn money indefinitely to turn it into a zombie corporation when there are no signs it
will ever be profitable – indeed from what I have read fracking and shale's best ROI is
right after the well is turned on, after that it only gets worse so these bad investments are
only gangrening and rotting faster and faster. Yet still, ever more more money from Wall st.,
the same people who chide any and all public services for being unprofitable and engendering
unprofitable subsidized behavior.
So if they can't all be that stupid, the only other explanation is that at least some of
them are just plain evil. In this case that would entail them working on "greater fool
theory" where they are planing something like the old sub-prime mortgage CDOs. Something
like: 1. package all this festering financial garbage they created into illegible little
financial products; 2. pay-off the rating's agency to give this repackaged garbage AAA
rating; 3. sell to sovereign wealth, retirement, and pension funds; 4. take out
credit-default swaps and other bets against the garbage they have sold off because they know
it is going to imploade; 5. run like hell; 6. blame poor people for destroying the economy
while begging for a government bailout as a result of fallout from destroying the world
again.
I'm somewhat familiar with Noble Energy, one of the 29 companies the authors claim to have
examined.
They report Noble as having a cash flow deficit of $499 million, a full 20% of their grand
total for all 29 companies. The grand total, of course, purports to demonstrate the weakness
of the US shale plays.
The thing is, the cash flow from Noble's shale operations in Texas and Colorado is solidly
positive. The company has a cash flow deficit because it is finishing up its share of the
Leviathan project offshore Israel, which by this time next year will have that country energy
independent while enabling a massive shift from coal to natural gas as their primary energy
source. Not a bad thing, IMO.
The anti-hydrocarbon jihadists have some valid points, but they also generate a lot of
propaganda that has no relation to reality. This "study" is an example of what happens when
you know the answer you want before you do your investigation.
The risks and benefits of hydrocarbon energy is an important question. Unfortunately
there's a lot of garbage produced on both sides.
Why should the Shale Business feel bad about bleeding money? It isn't their money. It is
"other peoples' money". It is investors' money. As long as the Shale Business operators are
retaining for their personal selves some of the "investor peoples' money" which they are
bleeding from investors, why should they feel bad about it? Maybe their whole business model
was based on bleeding other peoples' money till other people have no more money left to
bleed. . . . and keeping a little bit of the money-bleed for themselves.
It's like with mosquitoes . . . . mosquitoes aren't "bleeding" blood. They are sucking
blood. It is the animals they are sucking blood FROM . . . which are bleeding blood. If the
animals eventually die from blood loss, the mosquitoes at least got some blood in the
meantime.
And so it is with the shale frackers. They aren't bleeding money. They are sucking money.
The investors they suck money from are the people who are bleeding money. And if the
investors finally die from money loss, the shale frackers at least got some money in the
meantime.
The only production preventing Oil from peaking as far back as 2013-2014 was US Shale,
which can only function by borrowing Billions from gullible investors that will never be paid
back. If investors were not so gullible, US production would have peaked years ago. Global
Peak Oil is controlled by cheap & easy credit. Take away the credit punch bowl and US
Shale production collapses, and global production peaks. PO is no longer dependent of
geology, but credit.
FWIW: I suspect Shale drillers are going to have a hard time finding more investors
willing to part with their capital, especially when Oil prices are very low. That said its
possible that the Federal gov't (via Fed) will step in and start buying billions of shale
debt (via QE or some other financial bailout mechanism) so Shale drilling can continue on. It
appears that the US is running into liquidity problems again as Bond markets are showing
signs that they are freezing up again.
Banks and investors took away the punch bowl, and second quarter losses reflect that. Third
is going to be the same, and too late for any price increases to reflect anything but losses
for this year. No positives going into 2020. Their best option is to find adoption. And being
a bunch of spoiled brats, that's going to be somewhat difficult.
I agree that shale has been the biggest contributor to increase in global oil supply.
However it has also distorted the entire industry.
If the shale companies had to make a profit each year, global supply would have been a
less and prices much higher.
This in turn would have supported e&p investment around the world. The fall in
investment has been due entirely to shale companies that have been allowed to run at a loss
for so many years.
I don't think we would see a massive rebound in E&P if US shale was eliminated. Shell,
Exxon, BP and other started pulling back on Megaprojects back in 2012-2013, since it was
doubtful that it would be economical. Basically megaprojects (deepwater & arctic)
required $120 to $150 (in 2013 dollars) per bbl to be economically. I don't believe those
prices would be sustainable as it would result in demand destruction as consumers would cut
back on consumption. The fact that Oil majors were looking at Arctic and deepwater back in
2010-2013 indicates they are reaching the bottom of the barrel for production. There was a
long term trend of declining exploration finds even when exploration budgets increased.
At this point any major rebound isn't going to make a difference, if a Oil major started
on a new megaproject it would be between 5 and 7 years before new oil reaches the market, and
very unlikely to offset declines from existing production (5% to 7% annual declines). We are
already behind the curve on gains from any new projects to offset ongoing declines with out
shale growth). Perhaps a some of the declines in existing fields could be offset some with
higher oil prices. Still reaching to scrap the bottom by trying to extract trapped oil in
fields in terminal decline. With all of the supergiants in terminal decline (with the
exception of Kazakhstan), its going to be very difficult to expand production further.
Personally I am guessing that global production has already peaked or within the next 18
months if we are lucky). Its difficult to pinpoint an exact period since their are way to
many variables to gage effectively. That said I cannot say my record for guessing peak
production is any better than winning a lottery, but as the window narrows due to depletion
and a shrinking supply of future projects the guessing gets a lot easier.
Shale had already taken off by then and predictions of possible productions were being
made and importantly have come true.
The majors would have realised there would be too much oil in the short to medium term, so
they sensibly postponed more expensive drilling.
How this mess with heavy indebted shale companies and years of under investment plays out
I am not sure.
Probably a lower and sooner peak oil than would otherwise have been.
Not sure anyone has said US has peaked, the point is that US tight oil growth will slow
and it is not apparent that any other nations are increasing output in 2019, so far the drop
by OPEC/NOPEC has been greater than any US increase in 2019 and it is looking like 2019
output will be lower than 2018 if current trends continue. When we get to the point that oil
prices rise to $80/b, I expect OPEC/NOPEC will increase output, but we do not know when that
will be and it is certainly possible that US output might be falling at a faster rate than
the rest of the World's rise in output so the net might be a plateau or decline.
Note also that my "medium URR" estimates might be too optimistic, if my "low URR
scenarios" prove correct, the peak is likely to be earlier (2022/2023), and if there is a
fast transition to EVs, more public transport, etc perhaps the peak in World C+C output could
be earlier still. I doubt this will be the case, but in the past I doubted that World C+C
output would exceed 80 Mb/d, I was wrong then and I may be wrong now.
Hugo, something peaked in 2011, so I'd say the peak oil gang is onto something worth
listening to. Perhaps you disagree. The graph is a bit dated, but you get the point I'm
sure.
I'd say calling peak oil to be in 2018/2019, vs to be within 2022 to 2026 time frame, is
pretty much splitting hairs. Perhaps you're just smarter than everyone else here and don't
tolerate such loose parameters?
How did you come to your prediction, riding on Dennis' coattails, or do you have any original
ideas of your own to contribute?
The assumptions make all the difference. And no one can accurately predict what will happen
the rest of the day, much less tomorrow.
The key to the future, so far, is how the majority of independents will fare. Dennis sees
prices improving so that many of them heal up, and production is restored to a norm. Ron sees
them as totally messed up, which is more my take.
And I am also betting on the majors. They don't lay out hundreds of billions of dollars
for downstream without a big plan in mind. And, that plan could not call for those
investments to be totally useless in ten years. It wouldn't surprise me to see the skies over
the shale areas filled with golden parachutes.
Ten years, or less, based on EOGs quarterly tell sheet. Do you opt for the golden
parachute soon, or use your own just before the plane crashes?
Inventory draws should begin to pick up for the US soon. 1 million in pipeline from the
Permian to the coast. Exports to increase, Cushing to decrease, and production mostly flat. A
lot of the Permian production has been going to Cushing as an outlet. Depends on how much can
be loaded on to ships, now, and how much lite oil can be sold. Pipelines are going to be
losers for awhile. Additional pipelines need to take note.
There are two, sure fire, statistics and reports that will define where we are going. You can
argue them, but you will lose. One is the EIA monthly 914 report, the other is the Texas RRC
permits. There's some DUCs, but by this time, I consider them as normal DUCs between drilling
and completion as is norm. And the 914 May show it up a little for June, but I don't see it
going up further. Or, much more.
Attached is the latest LTO data from the monthly EIA 914 page. The main difference that I
can see is the drop in the monthly production growth from 2018 to 2019. 2018 production
growth averaged 153 kb/d/mth. 2019 production growth over the first seven months has dropped
to an average of 97 kb/d/mth. The total July increase over June was 107 kb/d/mth. The biggest
increases for July came from Sprayberry (33 kb/d) and Wolfcamp (46 kb/d).
RON PATTERSON IGNORED 03/26/2021 at 8:57 am
