The Chart above compares several different combinations of past (vintage) data to estimate output. The dotted line is based on the most recent 8 months (August 2016 to March 2017) of data saved from the RRC website, the blue solid line is based on the past 12 months of data, and the yellow line is based on the most recent 3 months of data.
Each estimate uses the most recent 24 months of data from each month. A significant change in the size of the correction factors began in August 2016, which is the basis of the 8 month Corrected estimate. Dean Fantazzini prefers a 3 month estimate and an estimate using all vintage data (see chart below), I show the 3 month and 12 month estimates for comparison to the 8 month estimate, I expect the final data will be somewhere in the range of the 3 month to 12 month estimate (or between 3 month and 8 month estimate from June 2016 to March 2017).
The annual rate of increase in Texas C+C output from Sept 2016 to March 2017 was 250 kb/d per year and average annual 2016 output was 3269 kb/d, if the linear trend continues through Dec 2017, then average annual Texas C+C output would be 3420 kb/d in 2017, about 150 kb/d higher than 2016. The increased rig count will likely lead to a larger increase in output, possibly 300 kb/d.
Dean Fantazzini’s estimate for Texas C+C, the natural gas estimate follows.
Using the 12 month Corrected estimate combined with Texas railroad commission data for the Permian Basin (Districts 7C, 8 and, 8A) and statewide crude plus condensate(C+C) output to find the percentage of Texas C+C produced in the Permian basin, I multiply the percentage by the corrected 12 month Texas estimate to find an estimate of Permian Basin C+C output.
From February 2015 to March 2017, the linear trend for Permian basin output has been an annual rate increase of about 154 kb/d each year, the rising rig count may result in a faster rate of increase in the second half of the year. A similar estimate was done for the Eagle Ford region (Districts 1-5), note that both these estimates include output from vertical wells and conventional reservoirs that may not be included in other estimates (such as the EIA’s tight oil estimate and the estimates at shaleprofile.com).
Eagle Ford output dropped sharply from 1866 kb/d in March 2015 to 1326 kb/d in August 2016, a drop of 640 kb/d in 17 months (an annual decline rate of about 450 kb/d per year), since that time there has been a gradual increase at a rate of 136 kb/d per year.
Average Eagle Ford C+C output was 1409 kb/d in 2016, if the annual rate of increase continues at 136 kb/d for all of 2017, then the average for 2017 would be 1430 kb/d, or nearly flat from 2016 to 2017.
The annual increase in average C+C output for the Texas Permian and Eagle Ford combined from 2016 to 2017 is likely to be between 200 kb/d and 500 kb/d with a best guess of 350 kb/d. Including the New Mexico Permian basin in the estimate would increase the best guess of the 2016 to 2017 average annual increase to 400 kb.
Caelan,
with all due respect, this is a Petroleum thread
Yes, I was hoping Caelan would stick to the other thread. I tend to skip over most of the discussions there because they usually don’t have much to do with gas and oil. I can find off-topic discussions on many places on the Internet. I come here to find the best gas and oil depletion numbers available.
Please repost in the non-Petroleum Thread.
Dennis,
So yours and Dean Fantazzini’s interpretation of the TRRC data implies a decline in Texas oil production in March?
Meanwhile, the EIA/Drillinginfo data for Permian LTO and the EIA data for the Permian region (including conventional output) shows continued and accelerating growth
Both sources also show that production growth has restarted from March in the Eagle Ford.
Hi Alex,
The EIA Tight Oil Estimates for the Permian include output from New Mexico and does not include conventional output, the DPR estimates include the conventional, but remains different from my estimate due to the inclusion of New Mexico output. The RRC data is incomplete so we do the best we can.
The EIA tight oil data now goes through April 2017 and the trend for the Permian (TX an NM) from Feb 2015 to April 2017 is an annual increase of 216 kb/d per year. The larger increase than I had found is due to both the inclusion of New Mexico and because conventional output is declining.
Hi AlexS,
We can also consider only Jan 2016 to April 2017 (EIA data) and then the trend is somewhat steeper, an annual rate of increase of 283 kb/d per year. Possibly this could accelerate further as I suggested in the post due to the increase in rigs, we will see how quickly costs rise which may dampen enthusiasm if oil prices remain under $55/b. I believe I suggested output might increase by as much as 400 kb/d.
Including the New Mexico Permian basin in the estimate would increase the best guess of the 2016 to 2017 average annual increase to 400 kb.
Forgot chart.
Dennis, what if TRRC has improved its data collection system and the correction factor should be changed again?
My point is that there is no logical explanation for the decline in Texas oil production in March.
Hi AlexS,
Look at the estimate carefully. It could be that the Feb estimate is too high. The trend is what matters. Note that the estimates are revised each month, based on the RRC data. Note that the correction factor just based on the changes from April RRC data to May RRC data was quite a bit higher than the previous 7 months. These are estimates, they can be incorrect relative to actual output (which is unknown). The output often moves in unexpected ways, look at Bakken output data vs completions for an example. The DPR is a WAG, and the EIA tight oil estimate is just another estimate which cannot be directly compared to my estimate which is Texas only and includes conventional.
Have you looked at the completion data?
http://www.rrc.texas.gov/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/
Yes. Output fell between 43 and 49 kb/d for the 3 month and all data estimates by Dean and between 62 and 65 kb/d for the 8 month and 12 month estimates that I used.
The estimates are highly uncertain so output might gave fallen between 40 and 70 kb/d in March, the trend is more important and using the 12 month estimate the trend from Aug 2016 to March 2017 is shown in the chart below, (the data should be rounded to 3 significant digits).
Excellent post and discussions. I’m keeping busy trying to contact political leaders to increase pressure on the Maduro dictatorship, by enhancing sanctions on individual regime leaders. We are seeing a bit of movement in Europe, but it’s not good enough, violence is escalating, the regime has begun to use shooters to fire at protesters, there are government directed looting incidents against private businesses, and I hear oil production continues to dive.
I see dozens of individual stories of heroism, pain, rage, you name it, everyday. I sure hope this gets documented in a movie someday.
Best wishes for the good people of that troubled country, Fernando.
Kudos and then some for your ongoing efforts on their behalf.
I second coffee’s kudos.
Fernando, please see here.
I didn’t see anything in particular. Maybe you want to be more specific?
I had posted some links to some possible ecovillages in Venezuela, for what they were worth. I tried to post them as a comment to your blog, under one of your articles (Maduro’s generals), but for some reason, it didn’t stick. Do you have ‘Comments’ enabled?
In Venezuela’s Difficult Times the Grassroots are Stronger
I’ve been saying that teens and young adults are no longer as interested in owning cars as previous generations.
I got this in my email today. It’s written by a music writer. He’s not an expert in transportation at all. But a young woman came to his house on business and he learned that although she has a driver’s license, she has never owned a car. For a $10 a month payment to Uber, she is entitled to 20 rides a month anywhere in LA for just $3 to $6 a ride.
He’s saying that if young people can go carless in LA, they can likely go carless other places as well.
It used to be that having a car meant freedom. Now not having car-related bills to pay is freedom.
Lefsetz Letter: No Car: “There’s a whole generation living in spread-out Los Angeles without wheels.”
Here’s a link to the program.
Uber Los Angeles – Flat Fares
population of California was 39.14 million in 2015
18 years and over 24,621,819
number of registered vehicles in California as of Jan 1 2016 was 33,768,367
you might want to spend a bit more time in your “analysis” regarding the desire to own a vehicle.
https://www.dmv.ca.gov/portal/wcm/connect/bf92a9db-aada-4b16-80e0-b52c904b2f0d/top_10_dmv_facts.pdf?MOD=AJPERES
Hi Texas Tea,
Very little is learned from a single data point. The trend in vehicles registered vs population would tell us something.
See
https://www.fhwa.dot.gov/policyinformation/statistics/2015/
Section 6.2.1.
Chart below shows US population divided by vehicle registrations from 1960 to 2015.
So far we do not see the ratio increasing very much, peak oil in 2022/2023 will change this.
Millennials spurn driver's licenses, study finds: “Young adults are ditching driver’s licenses at a quickening pace, according to a new study, raising a red flag for automakers as they grapple with the emergence of ride-sharing services and an indifferent attitude about cars.”
Millennials and car ownership? It's complicated – LA Times: “An online survey conducted in September for the personal finance website NerdWallet reported that while 75% of millennials who own a car plan to buy another within the next five years, they just don’t seem to be that into it. Some 43% of them called owning a car a hassle.”
Millennials Driving: Decline in Drivers' Licenses for Americans | Money: “From 1983 to 2014, for instance, there’s been a huge drop of 47 percentage points in 16-year-olds with drivers’ licenses. For people ages 20 to 24, there’s been a 16 percentage point decrease over the same time span. And for those ages 30 to 34, the decrease has been about 10 percentage points.”
Forget Cars, Millennials Don't Even Want Driver's Licenses: “CARS.COM — Is the millennial generation’s license to drive taking a backseat to its license to chill? It appears so, judging by a new University of Michigan Transportation Research Institute study. It shows a steep decline in licensed drivers among younger people who increasingly prefer to live in urban areas and leave the driving to Uber or public transit.”
Younger people (Millennial and Zero Generation people) also may be less interested in buying a car (even a beat-up HoopDee(TM), because they just cannot afford one on today’s wages for the new generations.
“That wage is too damn low!”
Just a thought.
Green People has a point.
Kids these days don’t have the opportunities they had in the past to learn to work on cars for themselves, and newer cars are much more sophisticated than older ones, making them harder to repair. You can’t even WASH a car in the parking spot allotted to the use of a lot of apartment dwellers, never mind change the oil or repair it.
And newer cars and insurance premiums are higher than ever before. In some places, it costs about as much to own a reasonably new car per month as it does to put a modest roof over your head.
Get rid of six hundred bucks or more in car ownership costs and you have a lot of money left for electronic toys, classy clothing, meals out- and car fare.
The need to own a car is one of the main drivers of poverty in America.
I think the traditional oil powers are signaling that they see the end of oil. Here’s this from the Saudi finance minister.
Saudi Finance Minister: “I Wouldn't Care If The Oil Price Is Zero" | OilPrice.com: “We are planning to totally [end] that dependency that we have been living for the last 40, 50 years. Hopefully by 2030, I wouldn’t care if the oil price is zero.”
“I think the traditional oil powers are signaling that they see the end of oil. Here’s this from the Saudi finance minister.” ~ Boomer II
That is a very simplistic analysis. Do you believe everything you hear from Saudi Oil Ministers? If the traditional oil powers saw the end of oil what would be there motive for signaling that perception, benevolence?
I suggest that the goal of some traditional oil powers (KSA, BP etc), who know that the world is past peak oil, is to artificially depress the price of “Clean New Energy”, by dropping the price of fossil fuel- this way they can create an environment where they can buy investments in wind/solar etc at a lower cost. Once they are all invested, the price of both “New Clean Energy” and “Old Dirty Energy” will rise rapidly. A critical technology they will want to get their hands on is energy storage. Whether thermal, mechanical or electrical, they will want to grab anything that is proven to work at scale while ensuring that they pay as little for it as possible. This is why BP puts out forecasts that assert the world will be forever drowning in oil, and this is why KSA is talking down the future price of oil.
Hi Survivalist,
There are many different threads pointing to the gradual realization that peak oil may be here soon and Boomer II has pointed to many of them. This is just one of a multitude of examples that have been presented.
Your criticism is unwarranted in my opinion.
Could you explain more clearly how a signal that the Saudis recognition of a potential near term oil peak is likely to reduce alternative energy cost? Also can you explain how OPEC’s actions currently match the oil industry’s desire to reduce oil prices?
I do not follow your reasoning.
Hi Dennis, thanks for the reply, and the interesting article you posted here. I’ll try to clear up my position, as well as enquiry about yours.
Is it my criticism that Boomer has a simplistic analysis that you find to be unwarranted? Do you find it a complex and insightful one to take the word of a Saudi oil minister at face value? Do you believe the minister is speaking truthfully when he says that an oil price of zero is unconcerning to the interests of his nation? I do not. I find it laughable. While I do believe that KSA does see its days of being so entirely reliant on oil coming to an end, I do not believe that what they are attempting to signal is that they see the end of it entirely. I shall explain.
Premise #1- KSA wishes to invest in renewables and alternatives etc and they wish to do so at the cheapest price possible (buy low sell high and all that). They’re playing a long game.
Premise #2- Cheap oil dampens enthusiasm for costlier alternatives. Here is an example of some discussions that revolve around that widely held belief.
https://www.carbonbrief.org/what-falling-oil-prices-may-mean-for-the-future-of-renewable-energy-investment
By talking down the price of oil, like saying such things as ‘we don’t care if the price is zero’, the traditional oil powers, in this case KSA, are making investments in alternatives seem less certain to be profitable ones. If investors believe it takes oil at $75/barrel to make solar/wind/alternatives etc competitive, and they are then led to believe that oil will be $50/barrel for the foreseeable future, and that a major oil producer like KSA doesn’t care if the price is zero, do you think many investors would buy shares in a co’s that build solar/wind/alternatives etc and expect them to be profitable ones? It seems to me that many would not (especially in an investment culture where quarterly returns are paramount and not longterm investments. Indeed in today’s investment culture 3 quarters seems for many to be long term). That belief would reduce demand for the shares in those co’s in comparison to what the demand would be if the opposite belief was held, that reduced demand would then lower the price for those shares, and that would make it less costly for KSA to buy those shares. See premise #1.
I suggest that the Saudis know very well that the future price of oil will be high, but they communicate a belief that it will be low, and that they couldn’t care less, in order to manipulate certain elements of the market. While they do this they are securing investments in alternative energy production and storage co’s at a cheaper cost than if they had communicated their true belief that oil price in the future will be high. The statements they make are in accordance with their interests as per premise #1. You see?
OPEC is not exactly a homogenous organization, so I don’t feel it’s correct to address OPECs desires, after all, what are OPECs interests. Different OPEC members seem to desire different things and have very different, often contradictory, interests. However, OPEC does seem to be engaged in measures to hold the price at around $50/barrel. Perhaps OPEC desires that. If so then they are getting what they desire.
KSA does seem to send a lot of mixed messages. For example, one week they speak of wanting production cuts to shore up prices, then the next week they make statements that it is of no concern to them if the price drops to zero. Volatility is perhaps what they desire. Or maybe they just can’t string together a coherent narrative. I suspect the former and doubt the latter. To what end I have wondered do they desire volatility. My conclusion is that it is to multiple ends, one of which is to be able to make invest in renewables at a cheaper cost, not to signal that they see an end to oil.
Or perhaps they’re all just idiots pissing around with a sovereign wealth fund and they couldn’t care less about what they invest it in or what price they pay.
https://en.m.wikipedia.org/wiki/Public_Investment_Fund_of_Saudi_Arabia
I suspect BP of a similar ruse when they publish an outlook that claims we’ll be swimming in $50 oil for quite some time to come.
I tend to believe the HSBC report is more truthful, after all it was produced for their clients and not the general public.
https://drive.google.com/file/d/0B9wSgViWVAfzUEgzMlBfR3UxNDg/view
And as well, perhaps my criticism is unwarranted. I suppose that depends, if I understand you correctly, on what boomer meant, and what I think he meant, by ‘signalling’. I would say that KSA is exhibiting the profile of them seeing their days of being so exclusively reliant on oil coming to an end, but I very strongly believe that they are not trying to signal (aka communicate) that. To the contrary, if my argument is correct, they wish to conceal that so they may invest alternatively at lower prices.
Saying that the price of oil will be low isn’t going to make investing in renewables a bigger opportunity. It’s not that tight of a market. China is going full out with renewables no matter what the price of oil is. They see an opportunity whether oil is expensive or is cheap. I sincerely doubt the KSA is trying to manipulate the price of renewables by “lying” about oil prices.
And since solar and wind aren’t in direct competition with gas and oil companies, it seems to me to be a stretch to suggest that driving down the price of oil will result in bargain prices for renewable companies and infrastructure. We’re talking electricity versus transportation.
Besides, if KSA and big oil companies are looking to buy up more renewable assets, that bodes well for the renewable industry because that means there are more potential buyers out there. As people have pointed out, there’s a lot of room to grow in renewables, so having more investors looking for ways to get in should be a good thing.
Oil powers, KSA in this example, saying that the price of oil will be high in the future will drive up the purchase cost of the investments they wish to make in purchasing shares in companies that produce renewable energy and own patent rights to effective energy storage systems. Would you agree? Or do you think KSA saying either zero or $200 a barrel is inconsequential. I do not. I believe there are market consequences for their utterances, and that is why they make such statements. It’s hardly a bridge to far to suggest that if the KSA oil minister said the oil will be $150/barrel in 2025 that it would result in increased investments in renewables, increaeee demand for shares in renewables companies, and an increased cost of shares in those renewables companies. Or maybe the KSA oil minister just talks out of his ass when he feels like it and makes rediculous statements. Or maybe he truest thinks that oil will be free and renewables will be even cheaper.
I don’t think his comments will drive down the purchase price of investments in renewables.
I guess we’ll have to wait and see.
Hi Survivalist,
First, the Saudi Minister said he hopes that a low price for oil won’t be a problem because they will have reduced their dependence on oil. They did not say they believe that the price of oil will be zero.
“We are planning to totally [end] that dependency that we have been living for the last 40, 50 years. Hopefully by 2030, I wouldn’t care if the oil price is zero.”
So we are talking about different things. The Saudis are trying to raise oil prices at present. If that was not the case, they would not have cut output.
Does this mean they want to pay more for alternative energy? I agree with Boomer that it will make very little difference.
As for what I meant by “signaling,” I am saying that both big oil companies and producing countries and industry organizations are all saying that the future of oil looks less promising that it did. Some are saying it’s because prices are too low to make money. Others are saying they are running out of discoveries. Others are saying demand is shifting.
Collectively, I see a number of established players being less optimistic about the future than they were in the past. The LTO folks keep talking about what a great future they see ahead, but they seem to be the only ones.
I have no investments in this area. Nor am I trying to predict a date for peak oil. I am mostly interested in economic strategies and government policies. While the oil may not be running out, the opportunity to make money from producing it may no longer be there to sustain the industry.
I think we are going through something comparable to the Industrial Revolution. First we had the changes that digital technology has brought to the world economy, and now we’re seeing changes in energy generation. Both have had and will continue to have profound effects. Whether we will see collapses or just major shifts, I don’t know. But some old industries will be destroyed and some new industries will arise. Whether together they will be sufficient for long-term global economic and environmental sustainability, I don’t know.
Investments in wind/solar are useful, no matter what the motivation. Once it is installed, it’s unlikely that it will be uninstalled.
China has quite likely been selling solar panels too cheaply. That has made competition with them difficult, but it has made it cheaper for individuals and companies to buy.
I can’t see that there would be any problem with countries going so far as to subsidize renewables so that there is even more use of them.
I don’t think fossil fuel use will disappear, but if companies and countries use less of it, there will be less pollution and gas and oil will be conserved for more critical uses.
Boomer
You might be surprised to learn that disposing of no-longer-viable wind farm components can be troublesome.
In fact, it seems nearly never acknowledged that wind farms possess their own ‘decline’ rate due to wear and tear.
Lifetime practical useage of a wind farm is only about 20/25 years, supposedly … depending on the source.
Like everything else, Boomer, researching this stuff can produce copious amounts of info, frequently contradicting.
Sign of the times, I guess.
These aren’t problems that would result in an uninstall of wind. Anything that uses equipment is going to require maintenance and parts replacement. So I don’t see how it makes a difference in whether or not wind is an option.
Boomer
Economics.
PJM just held their capacity auction for future electricity production. PJM manages a huge swath of the eastern US electric grid.
Capacity factor is the percentage each source can count on delivering (compared to nameplate) before penalties kick in for under delivery. (Short, incomplete description).
Wind sources in PJM area were pegged at 13%+.
So, in the fiercely competitive power generation market, the Zephyr boys are starting out from the gate considerably hampered.
If you are unaware of the high expense in changing parts 400 feet up off the ground way out in the middle of Bumfuck Egypt, word is … it’s expensive.
Kinda like what happened off of Block Island a few months back when the country’s first offshore wind venture cranked up.
Some guy left a tiny 6 inch drill bit where he shouldn’ta, bang goes the whirly, months later, a jack up with crane came in to change the damaged piece.
A little more cumbersome than just calling the Maytag repairman.
In all seriousness, Boomer, virtually nothing can compete – economically – with the latest iteration of gas fired Combined Cycle Gas Turbines … which is a big reason the anti fossil fuel folks have gone ballistic thwarting natgas pipeline development.
Natural gas is currently a good thing because it put the coal industry into permanent decline.
Now it is a matter of supply, cost, and carbon. I don’t expect natural gas plants to disappear soon, but there is no reason not to use wind as well.
Hi Boomer II,
It depends on what you mean by soon. We really need to transition away from all fossil fuels as quickly as is feasible or global warming will be a big problem. If by soon you mean 5 years, I agree, but in 15 years natural gas use should be cut in half and that rate of decline should continue.
It is certainly better than coal or oil, but still needs to be reduced ASAP. The aim is 1000 Gt of carbon emissions (or 3667 Gt of CO2), we are already at about 600 Gt of carbon emissions, so 400 Gt left in the budget and the lower the emissions the lower the risk.
I would prefer aggressive action to reduce CO2, but I don’t know how quickly the US will get there. We can see that coal is already being phased out, and that renewables are expanding, but how soon renewables will phase out natural gas I can’t predict.
Hi Boomer,
Yes the future is difficult to predict. I misunderstood you I think. I thought you were saying its ok if natural gas is phased out later rather than sooner, but you were just saying we don’t know how quickly it will occur (unless I still misunderstand).
I agree that we don’t know.
Wind sources in PJM area were pegged at 13%+.
Which is pretty good – that’s maybe 40% of their average capacity factor.
high expense in changing parts 400 feet up off the ground
Sure. That’s taken into account.
virtually nothing can compete – economically – with the latest iteration of gas fired Combined Cycle Gas Turbines
Wind and solar still beat gas in a lot of places – it all depends on the local costs.
the anti fossil fuel folks have gone ballistic
Do you think that might have something to do with the pollution costs that aren’t taken into account in most accounting? Costs which would make gas pretty uncompetitive in most places?
Nick
I’m no authority in these matters, but the wind info was from the site ‘rtoinsider’, a trade site for the wholesale power generating industry.
Site said, of 6,528 MW nameplate capacity from wind, 888 MW was committed … giving capacity factor of 13%.
Re pollution, New York state, having banned hydraulic fracturing and denying pipeline construction, is nevertheless heavily touting the ‘clean’ vehicles that are being operated by government entities all over the state. Not mentioned is the fact that they are CNG fueled.
Albany’s government complex just announced a big savings on the new power plant that will heat and power the numerous buildings … natgas fueled.
And, I gotta tell ya, Nick, even I was surprised that the whirley’s only lasted 20/25 years. Fairly brief lifespan.
Mebbee Dennis and the boys could make some decline curves on the annual 1.6% decline in wind output due to infrastructure wear. And who’s gonna pay to take ’em down?
Biggest hurdle the wind folks may face is the growing, fierce opposition on … wait for it … Environmental grounds.
Seems like the noise, vibrations, and a myriad other aspects are thought to harm migrating whales, fisheries, birds, pristine whatevers.
Should be entertaining drama observing the unfolding theatrics.
6,528 MW nameplate capacity from wind, 888 MW was committed … giving capacity factor of 13%.
That’s not capacity factor. CF is the average output divided by nameplate. In this case, it might be around 33%.
The 13% number is the percent that can be guaranteed (statistically) to be available during peak periods. Divide 13% by 33% to get the percent of power generation that is “reliable”. In this case, it’s around 40%, which is really not bad.
New York state…touting the ‘clean’ vehicles…they are CNG fueled.
Yeah, some contradictions there. Don’t forget, the people who object to pipelines aren’t the same people who promote CNG vehicles.
the whirley’s only lasted 20/25 years… annual 1.6% decline in wind output due to infrastructure wear.
That sounds wrong. Got sources?
Seems like the noise, vibrations, and a myriad other aspects are thought to harm migrating whales, fisheries, birds, pristine whatevers.
Nah. It sounds like you’ve been reading anti-wind websites, which are about as reliable as Fox News.
Nick
My limited understanding in these matters exactly coincides with your description of capacity factor and this specific 13%.
That rtoinsider site was pretty clear about it, so where the perceived discrepancy lies, I do not know.
As far as the wind farms lifespan being incorrect, I would not only tend to agree, I think it a bit bizarre. An awful lot of resources goes into the siting, building, and transmitting power from these sources.
20 year output seems paltry.
Nevertheless, this ‘sciencedirect.com’ site contains a study of 262 UK wind farms and drew those conclusions, along with 16% per decade decline.
Go figger.
Bigger issue, perhaps, is the growing opposition to the siting of these wind farms, especially in the northeast.
Lottsa stories on the net about various locations, onshore and off, encountering stiff opposition.
Coffeeguyz,
The wind turbine can be repaired or upgraded, happens all the time in every power plant, do you believe there is no maintenance, repair, or upgrades on natural gas turbines?
The operations and Maintenance costs are very low for natural gas, link below covers various types of power. $25/kWh for CCGT and $46/kWh for onshore wind, $43/kWh for coal and $198/kWh for nuclear, $25/kWh for utility scale photovoltaic, and offshore wind is $181/kWhr (these are 2014 estimates, wind and solar are probably lower in 2017).
http://www.power-technology.com/features/featurepower-plant-om-how-does-the-industry-stack-up-on-cost-4417756/
I doubt wind is going away. A number of states require a certain amount of power generation from renewable sources.
Gas has its place right now, but so does wind. The points you are making won’t make a difference to communities that want the cleanest possible sources of electricity.
Wind is the lowest cost way to generate electricity in some places.
Do you feel the natural gas industry is threatened by wind power?
Look at the map in this article. All the green areas are where wind is the cheapest source of power generation.
Natural Gas and Wind are the Lowest-Cost Generation Technologies for Much of the U.S., New UT Austin Research Shows | UT News | The University of Texas at Austin
Boom
No uncertainty whatsoever that I am a staunch advocate of fossil fuel extraction and consumption.
Difficult to effectively engage in debate in these matters when subjective views strongly prevail.
Having acknowledged that, the very first paragraph in your linked piece says the study not only measures cost, but social and environmental impacts as well.
That, to me, can take a pure dollar and cents issue (Mary pays 10 cents per kW, John pays 16 cents) and go far afield in what some may characterize as crucial aspects, while others scorn as selective BS.
Whatevuh.
Politics as well as ideology play a role, which is a big reason I heartily applaud the folks up in New England.
By shunning the copious amounts of nearby natgss to heat their homes, uninterruptedly provide power through the hottest and coldest times, those folks have gone full on Thereau.
And even ol’ David his self left Walden Pond after two years. Freakin’ cold out in the woods.
But their commitment to embrace renewables has the full force of law and should prove very instructive to a wider audience in the coming years.
I think they are nuts, but that’s just me.
If wind was so much cheaper, Boom, why does the government need to enforce mandates for its implementation?
Why do you want to frame wind power so negatively? Do you fear that it will undercut natural gas use? We’ve had a mix of electricity generation for a long time: coal, nuclear, geothermal, natural gas, hydropower.
If natural gas is the answer and for a long time to come, then you can ignore wind, right?
I, personally, do pretty much ignore wind. Solar too.
Not that I’m against it.
On a micro scale, I think the burgeoning applications of solar are both fascinating and pretty neat.
Thing about wind generated electricity is that it is extremely expensive, reliably unreliable, and – but for the coercive power of the state – would only be used in highly selective areas.
I say, bring on the wind entrepreneurs, the solar visionaries, the battery pioneers.
But fer cryin’ out loud, let them all compete against one another in the marketplace. The most efficient, the most desired would come out on top.
The way I see it, the market for natural gas is going to come from utilities retiring coal fired plants and converting to gas. Wind really isn’t a factor in natural gas sales right now. So I don’t see it as a problem for the natural gas industry.
As for competing, I think renewable advocates would be open to elimination of all tax benefits for energy companies, including fossil fuels.
That, to me, can take a pure dollar and cents issue (Mary pays 10 cents per kW, John pays 16 cents) and go far afield in what some may characterize as crucial aspects, while others scorn as selective BS.
Yes, some people are willing to say anything. But…pollution is real. So is climate change.
You can say that the idea that the earth is round is just a theory, and that there is controversy there. Doesn’t make it true.
Hi Coffeguyzz,
If Natural Gas is so profitable, why are various government tax breaks needed for the fossil fuel industry such as master limited partnerships, accelerated depreciation, and other write offs?
When all the tax subsidies given to the fossil fuel industry are eliminated, then the various subsidies given to wind and solar can be eliminated as well, as long as pollution continues to be regulated either through cap and trade or direct taxes on pollution.
In areas with good wind resources such as Iowa and surrounding states, natural gas cannot compete with wind. In areas with good solar resources (US southwest) natural gas cannot compete with solar.
I agree New England needs more natural gas pipelines, but that is up to the states involved.
I thought you had said in the past a bunch of pipelines were about to come online.
Based on the webpage link below
https://www.iso-ne.com/about/regional-electricity-outlook/grid-in-transition-opportunities-and-challenges/natural-gas-infrastructure-constraints
from iso new England, pipeline capacity is constrained because power generators are unwilling to commit to natural gas deliveries the way that natural gas utilities do. Without those commitments the pipeline capacity will not be built.
Demand pricing would help, where electricity prices are allowed to spike when natural gas supplies are short (mostly during cold winter days). In that case people may reduce their electricity use in response to high prices.
Hi Coffeguyzz,
The current subsidies for Wind and Solar, do exactly what you ask. Nobody is mandating a specific wind or solar technology, it takes time to develop the technology and if we wait for oil and natural gas and coal to deplete we will be out of time. There is also the very real concern that if we burn too much fossil fuel we may have dangerous levels of global warming so alternatives need to be developed. The wind can be forecast, just like the weather so the output from wind power can be predicted fairly accurately 48 hours into the future, widely dispersed wind power, combined with solar and hydro and connected by the grid over an area such as the L48 of the US will require very little backup once built out to 3 times average load (for wind, solar, and hydro capacity combined). Note that current total US generating capacity is about 2.5 times average load, such a system would require about 5% to 10% of total load hours per year to be backed up by natural gas, batteries, fuel cells, or vehicle to grid with whichever of these is cheapest being used initially, but natural gas being phased out eventually due to carbon emissions (unless the CO2 is captured and sequestered, but that is unlikely to be the cheapest option).
Dennis
Gonna try to address some of your points best as I can with this tablet …
The subsidy issue is a perennial, extraordinarily contentious topic that has at least three times as many analyses as the folks doing the analyzing. You all don’t need my two cents.
Next, there are three pipelines coming online shortly with the Phase 1 of the biggest – Rover – set to deliver 2.8 Bcfd to western Ohio in just a few weeks.
None of these pipelines will deliver natgas to New England.
The ISO site you linked to is outstanding and informative in many ways.
There are at least one million “players” in this New England electricity supply saga, but, in a nutshell ..
The power generators certainly will not commit to gas supply, but the gas UTILITIES did long ago for the existing pipelines.
The ELECTRIC utilities DID commit to offering financing via higher customer rates, with the approval of their regulating bodies.
The courts, overturned the regulator’s decision (s), so, absent financial certainty – coupled with siting/building opposition – no new pipelines.
The “real world” justification for committing ratepayers money for pipeline expansion is the recognition of long term, low pricing for electricity assuming cheap natgass fueled plants will (would?) be supplying it.
Now, the sparse natgas entering New England every day will be directed towards the GAS UTILITIES first since their customers paid for the pipe. On very cold winter days, New England electricity consumers will be shit out of luck.
If you ever glance at the ISO Express site and see the fluctuations of power consumption throughout the day, you should immediately see that the fast startup gas plants have an enormous economic advantage.
Hi Coffeeguyz,
Thanks. I am not familiar with the details.
http://www.pressherald.com/2016/08/17/mass-decision-throws-fate-of-n-e-pipeline-project-into-question/
Probably you are talking about this decision in Massachusetts.
Possibly the problem could be overcome with legislation. I don’t know, but seems like a potential problem.
So reading up a little further, in Massachusetts electric utilities are separated by law from power generators to reduce the electricity monopoly’s power. You seem to be a free market guy and would seem to support such a move in general as it can easily be shown in economics that monopolies will not allocate resources efficiently relative to a competitive market.
Note I am not a believer in the religion that free markets always yield the optimum outcome.
For those that have drunk the koolaid, the freely competitive market outcome (which the Massachusetts law supports) is what we have.
This is a case where the Governor was trying to do an end run around the law to support the electric utilities and was stopped by the Supreme Court of Massachusetts.
It is also a case where the natural gas industry would have been supported by government regulation, tsk, tsk.
Dennis
While a lot of what you posted above is accurate, it is still only a small part of a much bigger picture.
Utilities, in general, do not make a profit on the product supply, only on the efficiencies derived from providing the services (electric/water/gas/).
They are motivated to ‘keep their customers happy’ while operating under rigid regulatory structures.
This is the perceived monopoly granted for a common, necessary good.
The people of New England use and need electricity.
The local utilities DELIVER it.
The various power generators, profit motivated, privately owned using various fuels (nuclear/oil/coal/wind/gas/hydro and more), PROVIDE the juice.
The ISO folks manage the six state grid as all this stuff is interconnected and ensure – as best they can – that there will be sufficient juice available at all times.
One of the big ‘uh-ohs’ looming shortly is the bulk of power generation is increasingly coming from new gas fueled plants with little additional gas supply to fuel them, especially when the existing gas is diverted to heat homes on cold days.
The builders of the needed pipelines, profit motivated private companies, will not (actually cannot, as per FERC) build the pipe without firm, legally enforceable contracts with specific dollar amounts.
The political and social consensus was (is?) to strive for juice generation to come from Canadian hydro or offshore whirleys.
Time is running short up there and the cost keeps rising.
One small quibble: there really aren’t any uses for gas and oil for which we need to conserve them. There are better and cleaner ways to power transportation (even aviation). We have vast amounts of hydrocarbons “in the ground” for petrochemical feedstocks – kerogen, oil sands, coal, methane hydrates, peat, etc., etc. Not to mention all the H2 and carbon in seawater and air.
I suspect that in 100 years the idea of burning fossil fuels will seem very, very odd, unimaginable even.
I can imagine that, with better batteries this will happen.
I already own an electric bike – the motor is completely noiseless, just the power. Breaking means getting energy back. A normal scooter feels like a steam engine comparing them – something from the tech museum. Loud, stinky, hot parts. Only not shoveling coal to heat it on.
Steam engines haven’t been phased out because they where weak – look at the Titanic, or trains going over 200 Km/h. They where not modern at some time.
Yeah, steam worked, but better things came along. It’s such a common story – lots of things are viable, but something out-competes them. Oil is the Beta to electric transportation’s VHS.
There were steam powered cars for a little while. They had one of the same advantages as EVs: instant, high torque at startup.
Are there enough resoirces around to build all those batteries?
Yeah. Lithium is adequate, and there are lots of other chemistries: sulfur, sodium, lead, vanadium, etc., etc.
For everyone? Globally? Cradle to grave? If the transition really kicks in? In the face of assorted contractions, depletions and (environmental, etc.) degradations? In the context of a crony-capitalist plutarchy?
I have my serious doubts. In fact, much of this kind of thing is not a good idea.
Peer at numbers too closely and you risk looking merely at a tree in a forest.
Batteries can be used over and over again and will probably outlive the cars they are in. Then they will be used in a somewhat depleted state for grid storage — this market already exists.
Lithium is not in any greater threat of running out than iron is. The attempt to compare it with fossil fuels — which are depleted in use — makes no sense.
The potential problems with batteries, like anything else perhaps, can come with scale, numbers, complexity and time.
Things can look fine now, but now is not later.
We are talking about a little more than just one battery, one car and a jar of lithium in the context of an apparent ‘oversupply’ of a particular species that thinks it knows what it is doing.
For some reason, the term, ‘apeshit’ suddenly comes to mind, along with the phrase, ‘going apeshit on and with the planet’.
“One small quibble: there really aren’t any uses for gas and oil for which we need to conserve them.”
Dang nab it Nick, you make it HARD for me to be polite when you say things such as this, things which are so easily twisted into pretzels by BAU mouthpieces, and make renewable energy advocates look like idiots.
Now there may be plenty of hydrocarbons in the ground, but plenty is a weasel word in some respects. I’m sure the remaining supply is large enough to last a long time, but probably nowhere near a hundred years, at least not at affordable prices, unless we quit wasting these one time gifts of nature.
We for sure do need to conserve gas and oil for purposes such as space heating, the production most industrial and consumer goods, food, the transportation of virtually all goods where railroads are impractical or non existent at this time, etc, the manufacture of fertilizer and other industrial and agricultural chemical inputs , etc etc..
Now twenty or thirty or forty years from now, we really may not need to conserve oil and gas for such purposes. Maybe we will have ample renewable energy supplies and maybe we will have a grid adequate to compensate for bad weather in some regions, maybe we will have cheap super duper batteries or other storage tech on the scale that will be needed.
But maybe we WON’T.
But for now, and for the next generation at least, and maybe longer, oil and gas are critical industrial inputs, and if they come up too short in supply, or too expensive, there will be hell to pay.
I get all bent out of shape when people talk like salesmen all the time. I like balanced coverage, it pays off in credibility over the long term.
If nobody is providing the flip side coverage, I often take supplying it on myself. Call me contrary, the description fits.
“We for sure do need to conserve gas and oil for purposes such as space heating, the production most industrial and consumer goods, …”
yes, because isn’t it true that all solar and wind equipment is manufactured by the power of fossil fuels, from the mining to the final assembly?
which brings to mind:
does anyone know how much fossil fuel is used by the Gigafactory?
isn’t it true that all solar and wind equipment is manufactured by the power of fossil fuels, from the mining to the final assembly?
No. It’s true that some is used, but it’s not essential.
Remember: the first oil wells were drilled, and the first barrels of oil were moved, by horses!
Coal was moved by horses (remember horsepower?).
So, the first solar panels may be manufactured used by coal electricity, but who cares? That won’t be the case forever. Heck, they may not be, even now: they may use solar power, or nuclear, or wind…
isn’t it true that all EVs are manufactured by the power of fossil fuels, from the mining to the final assembly?
I’m still having difficulty finding out how much fossil fuel is used in the Gigafactory.
It must be a massive amount!
Tesla will power its Gigafactory with a 70-megawatt solar farm – The Verge: “Tesla plans to power its Gigafactory in Nevada with a 70-megawatt solar farm, according to a company investor relations document obtained by Electrek.”
I’m impressed by that Gigafactory!
One of so-called America’s ‘flagship’ projects, and it’s still ‘planning’?
How much or what percentage is ‘some’ and what do humans do that is not essential? Anything at all? Are solar panels or electric cars ‘essential’?
Parse the comments carefully, folks.
Mac,
We just disagree. I feel confident that we have all the tech and engineering we need right now to dramatically reduce FF consumption. If FF were properly priced, we would do so right now. The alternatives to FF will only get cheaper, the costs of FF will only get clearer and higher.
We have far more FF in the ground that we need, far more than we can burn for the health of the planet or our children’s lungs.
We consume for more FF right now than we need. Just ask Dennis if he agrees.
——————————
As for propagandists misusing my words: I don’t think you’ll find anyone on Fox News arguing for conservation of FF. I think they’d argue for selling it as fast as possible. Free market absolutism…
Perhaps I should expand and clarify a little.
I think you, Dennis and I all agree that a good carbon tax would be very good: it would reduce FF consumption (thus conserving it and help prevent supply problems), reduce pollution/GHGs, and accelerate the transition away from FF.
I also suspect we all agree that the possible impact of PO (even a depression) is probably less risky than the impact of higher levels of oil consumption on our environment.
That’s the important stuff, I think. I suspect we might disagree on the possible impact of PO on the economy – I think there’s a lot of good evidence that PO would have a relatively short term impact (I can point you to the research, if you like, such as studies by the Philadelphia Federal Reserve, and Prof James Martin), but that’s less important.
Hi Nick,
We agree to some extent. The difference is the level of optimism. For the environment peak oil would be a good thing and a carbon tax would help speed the transition and make it less risky.
I think it very unlikely that a carbon tax would become law in the US before 2022 (when I expect peak oil will be here). So that driver of change and many other appropriate policy steps will not happen in the US in the near term.
As to whether there will be a severe recession in response to peak oil, this is difficult to predict.
If Tony Seba’s predictions prove accurate we may be ok (mild recession at worst), I think his scenarios are quite optimistic and that the timing of the transition he foresees will be 10 to 20 years later than he predicts.
In the mean time there is a better than 66% chance that there will be a severe recession (at least a bad as the GFC) around 2030 with Worldwide unemployment rates at above 12% (at recession bottom).
Hi Dennis,
Well, I think the things we agree on are far more important: public policy should accelerate the transition away from oil/FF, and reduced oil/FF consumption is overall a good thing, even if it’s caused by supply limits.
As for the risk of recession, I think it’s important to distinguish between the world economy and regional economics. PO would sharply raise oil prices, and this would likely cause a large shift in income and wealth from oil importers to oil exporters. Oil importers would likely succeed in recycling their income back to oil importers (by buying their manufactured exports, or by investing there) and then we would see a reduction in net consumption in oil importing countries and an increase in oil exporting countries.
If oil importers implemented sensible public policy this could be a relatively short period: car sharing (aka carpooling) could be implemented very, very quickly – this would be inconvenient, but much less painful than a long recession. Similarly, freight could adapt very quickly, if it were desired: a move from trucks to rail could be done pretty quickly, and truck fleets could reduce fuel consumption pretty quickly.
Even without proper public policy, very high fuel prices would greatly accelerate a transition by commercial users, and even individual consumers.
Hi Nick,
Potentially it could happen quickly and easily, but it will be disruptive and people are slow to change their habits so there is a big potential for high oil prices to lead to a recession, though it will depend how high oil prices become and how easily people adapt to the changes, potentially it might lead to a financial crisis as well. Always difficult to predict and a big unknown is how high oil prices go and how rapidly it occurs. The rate of change in oil prices will be important and it is not possible to predict in advance.
Hi Dennis,
I agree with all of that.
Some thoughts: where the incentive for change is modest, that change will be slow. As incentives/pressure/pain rises, change accelerates.
Right now there’s little pressure to change. Frankly, the pace of change is pretty good given how little market pressure there is to push it along.
But…if oil prices rise to $150, and stay there for several years? If countries, corporations and households are in serious pain due to oil prices? To think that PO could cause a deep recession for 5 years or more is to suggest that no one will respond to the problem. That seems highly unrealistic to me. The US could eliminate imports by reducing consumption by about 30%. The average car gets only about 23 MPG. The average driver could reduce their consumption by 60% by changing their vehicle to a convenient hybrid. New cars account for about 10% of VMT. On average US drivers change their vehicle about every 3 years, when high mileage drivers could move to high MPG vehicles. And, while they were waiting they could car pool. The upshot: eliminating imports would be far less painful than a deep recession. So….would we really do nothing?
Now, I agree that the world economy is a bit fragile. A sudden large shock could possibly create mayhem (primarily if mistakes were made in response). We saw that with Lehman Brothers. But…to suggest that is likely seems to me unrealistic.
What did you think of my distinction between world economics and regional economics? For instance, N. America has only a small level of net oil imports. If oil prices rose sharply, that would help Canada and Mexico, and depress the US. But overall, the net impact would be small for all of N. America. Does that make sense to you?
I’ve invested in solar but at a greater expense than the FF generator. Needed the backup/resilience.
Investment in wind may be useful now in some locations, but evidently it doesn’t make any sense in Congo. Investment in solar seems to be a waste because the technology isn’t fully mature and prices are coming down. I can see sine niches, like for example in Saudi Arabia if they figure out a cheap way to keep panels dust free.
Investment in solar seems to be a waste because the technology isn’t fully mature and prices are coming down.
From a public policy point of view that’s entirely incorrect: it’s only past and current investment that is causing prices to go down.
For utilities and countries, if they can delay investment entirely then that might make sense, as prices are indeed falling fast. But, if new generation is needed now then they have to invest in the cheapest option, which increasing is solar.
I see lots of instances where the wind and solar industries are given permits as well as preferential access to the grid at subsidized prices, forcing existing plants to close. That’s irrational.
And in Congos case installing wind and solar is super irrational, but I guess renewables advocacy is either a cult or its driven by greed (I suspect the corporate interests engaged in the industry push at least 50 % of the propaganda), so of course when I mention Congo I get nonsense as a response.
I don’t really care much about these debates, they are mostly based on fake numbers, what ifs, and a heavy dose of cultism fed by a barrage of propaganda. Given humanity’s tendency to behave irrationally, this renewables worship movement is just one more case of wrongheadedness. No big deal. At least my son is doing well installing solar panels.
You haven’t mentioned Congo before. Have you seen anything specific and quantitative about it’s energy?
Saudi Arabia and independend from oil? Good joke.
They are that wasteful, they never had to look for costs, they need foreign workers for anything they do – that won’t work out.
At the moment they have zero income without energy sector, if you don’t count the Hadsch around Mekka as income.
And they are too big to copy the Dubai model, just to build real estate as an industry to live from.
They could go solar – but then they should start to invest billions in infrastructure to sell the stuff to Europe and China now.
Looks like they are putting a lot of money into a fund to build infrastructure in the US.
I’ll bet some money is going into upgrading their escape pod fleet of jets.
My chips in for that bet too.
Leave the peasantry behind to sort things out.
Perpetual Fall to the Sun
The joke’s on them — American roads are totally over-sized and if they try to charge for them use will simply fall.
There’s a plausible sounding theory, even though posted on Zero Hedge, that the Chinese have been filling their SPR over the last two years, and that is about to stop. This would mostly account for why OECD storage levels only took about 35% of the supply-demand imbalance. If they do stop then about 1 mmbpd of demand would suddenly be lost, but it might also imply that the real economy demand growth in the period since January 2015 has only been half what it looks to have been. Taking account of the sudden drop and a slower growth in demand would mean a longer time would be needed to draw down OECD stocks. However if the China SPR scenario is correct then almost all the drawdown would come from OECD. By my reckoning this would push a balancing out to late 2018 (although by then we may be seeing some bigger supply drops as the pipeline for new project start-ups will be drying up). But if the balancing is pushed out then the chances of many FIDs this year or next will decline and the possibility of a sudden supply crunch in 2019 through 2022 would be greater. The green curve below gives possible drawdown under this scenario. The red one was a previous assumption that the OECD stocks would be drawn down at only about 35% of the imbalance (as happened when they were rising). I seemed a bit iffy when I fitted it that way, and I think the China SPR filling is a better explanation.
SPRs in general try to have 90 days of domestic consumption in them. This was a standard put into place mostly in Europe. China has embraced it.
The US at 750ish million barrels and having a consumption (net of production) of about 11 million bpd (remember, this is real stuff . . . consumption, no refinery gain BS allowed) and so not quite 70 days domestic consumption.
China, at net consumption of about 7 million bpd X 90 needs an SPR of 630 million barrels. That’s about what they have, but of course with 5% consumption growth they’ll have to adjust up, but for now . . . all is well.
There probably is no flow in or out of China for SPR reasons. Already full. Have been for a while.
Hi Watcher,
Crude inputs to refineries and blenders was 16.2 Mb/d for the 2016 average.
https://www.eia.gov/dnav/pet/pet_pnp_inpt_dc_nus_mbblpd_a.htm
So 700/16.2 is 43 days for SPR alone. For commercial crude stocks plus SPR it is 1200 Mb so 1200/16.2=74 days.
https://www.eia.gov/dnav/pet/pet_stoc_wstk_dcu_nus_m.htm
Wouldn’t the relevant metric be net imports of about 5M?
If the Strait of Hormuz is suddenly blocked, the SPR won’t be expected to replace oil produced in Texas.
Here’s the official line:
“Current Days of Import Protection in the SPR – The SPR holds the equivalent of 149 days of import protection (based on 2015 net petroleum imports).
International Energy Agency (IEA) Requirement – 90 days of import protection (both public and private stocks). In past years, the United States has met its commitment with a combination of SPR stocks and industry stocks. The days of import protection may vary based on actual net U.S. petroleum imports and the inventory level of the SPR.
Drawdown Capability – Maximum nominal drawdown capability – 4.4 million barrels per day, Time for oil to enter U.S. market – 13 days from Presidential decision”
https://energy.gov/fe/services/petroleum-reserves/strategic-petroleum-reserve/spr-quick-facts-and-faqs
The actual “drawdown capability” of 4.4M matches the 5M of imports it needs to replace.
Hi Nick,
Probably correct.
For net imports of crude oil in 2016 it was 7.4 Mb/d
https://www.eia.gov/dnav/pet/pet_move_neti_a_epc0_IMN_mbblpd_a.htm
So 95 days of net imports of crude oil.
It would make the most sense to wait for oil prices to increase to sell the oil in the SPR, maybe reduce it to 60 days of imports. Or we could wait until 2030 when US output will have declined significantly and then the current SPR level will be correct for 60 days supply. It is possible less crude will be needed at that point as demand for oil may wane.
NickG et al.,
As I recall from some time back, not all the oil in the SPR is available for sale because about half is reserved for the Department of Defense.
Somebody help?
According to recent articles about the Trump proposal, only half of the SPR would be sold. So that matches your understanding that half has to be reserved for defense.
Trump sure is sounding stupider by the minute.
I agree, in general and on this issue in particular – the SPR is probably needed at full capacity.
This is the chart Zero Hedge had, or linked to – the key is Xinhua CFC, who have Chinese data not otherwise available and charge a lot of money for it. I don’t know how you’d go about checking if it’s correct.
Hello, don’t forget that Xinhua doesn’t publish China’s SPR figures. The SPR figure in the chart is an estimate based on (Production + Imports – Refinery Inputs). I’m not sure if all the teapots are included in the official refinery data.
I think Zero Hedge borrowed the chart from here:
Scotiabank pdf file: http://www.gbm.scotiabank.com/scpt/gbm/scotiaeconomics63/SCPI_2017-04-12.pdf
Latest figures from Xinhua news agency…
2017-05-26 Chinese oil inventories month/month April changes: crude +1.64%, oil products -7.87% (gasoline -0.27%, diesel -14.4%) – OGP/BBG
Chart showing March
China’s April diesel stocks fall for second straight month -Xinhua
http://af.reuters.com/article/energyOilNews/idAFL4N1IS2EJ
So are the numbers you are posting supporting or not the Zero Hedge theory and/or my projection based on it? And if not why?
This is commercial (and it´s declining). Zero hedge is only showing SPR, right?
Yes as Jeff says but also looking at the figures released by China’s Commerce Ministry that method of estimating China’s SPR must be wrong. The estimate for the start of last year is 10x the official figure recently released.
Bloomberg – 2017-05-01 China SPR inventories: 244mb as of mid-2016, just 10mb higher since early 2016 – NBD/NDRS/Ministry of Commerce
Reuters – China strategic oil reserves rise to 33.25 mln t by mid-2016 – govt
http://www.reuters.com/article/china-oil-reserves-idUSB9N1HS080
In this section of the Tanker Trackers website “GOV STATS – China 2016 & 2017” you can see the calculation for spare barrels that everyone is using. For the first half of 2016 this estimation gives a figure that is more than ten times larger that the official one from the Ministry of Commerce.
http://tankertrackers.com/#/
Tanker Trackers – Line 37 – Spare Barrels, screen shot, direct link: https://s1.postimg.org/7tl98zb73/2017-05_China_SPR_Estimate_for_start_of_2016.png
I guess that Chinese demand must be higher than estimated. Like this article was suggesting…
Bloomberg – October 11th 2016
China’s appetite for oil.
Fuel use grew by about 5 percent in the first half of 2016, according to China’s biggest oil refiner, faster than the 0.4 percent derived from government data. That “official” number is clouded by rising gasoline exports — blends that don’t show up in official figures, according to the International Energy Agency, Sinopec Group and Energy Aspects Ltd.
Chinese authorities are also having trouble tracking refinery activity because of the surge of processing by independent refiners, known as teapots, according to Energy Aspects’ Meidan.
http://www.bloomberg.com/news/articles/2016-10-10/gasoline-cocktails-mix-with-gaps-in-data-to-cloud-china-oil-view?
https://www.wsj.com/articles/get-ready-for-peak-oil-demand-1495419061
Excerpt from Wall St Journal piece linked above:
Forecasts for peak oil demand diverge by decades. The Paris-based International Energy Agency argues that demand will grow, albeit slowly, past 2040. And the two biggest U.S. oil companies, Exxon Mobil Corp. and Chevron Corp. , say peak demand isn’t in sight.
But some big European producers predict that a peak could emerge as soon as 2025 or 2030, and they are overhauling their long-term investment plans to diversify away from crude oil. Royal Dutch Shell PLC and Norway’s Statoil SA are placing bigger bets on natural gas and renewables, including wind and solar.
“Nobody knows” when demand will peak, says Spencer Dale, group chief economist for BP PLC , which issues a widely watched annual outlook. The company’s base case calls for a peak in the mid-2040s—with the caveat that it could come sooner or later. “There are huge bands of uncertainty around that,” Mr. Dale says.
John Kemp, the Reuters energy and commodities columnist, has started up an email news digest.
Send him an email at john. kemp at tr. com asking to be signed up.
I signed up and he even responded, was expecting an automated reply…
I smell monetizing.
Much of Nigeria’s production comes from deep water offshore, via large FPSOs. Field data is available through NNPC but it seems to be only released a year after the fact (the latest monthly data is for May 2016). The chart below shows average annual production for the six largest producers. 2016 data is just for five months. The numbers in brackets show the percent of original field reserves that have been produced through the facility up to May 2016. Yoho shows over 100%, but in fact the Yoho fieldrecovery was almost exactly as predicted at 440 mmbls, the extra has come from later, small field tie-backs (and I haven’t found reported reserve data for these). Erha and Bonga also are likely to exceed 100% as they have had recent additions (Erha phase II in 2015, Bonga North West in 2014). I don’t think there have been any disruptions to these flows from rebel activities except for a short shut down to Bonga, actually based on nameplate capacities average production their availabilities look pretty good.
All the FPSOS are designed for high and short plateaus, it is quite possible that Erha, Bonga, Akpo and Abgemi will all start serious decline at about the same time this year or next (note Akpo is a gas condensate field, the others oil – production shown is C&C). Egina is due on line next year This too is designed for a relatively short life – 200 kbpd for a 500 mmbbls field. If the mature field decline is in line with the expected remaining reserves it will not be enough to compensate. Nigeria claim over 35 Gb reserves, I have no idea where that is supposed to be, even NNPC themselves are saying that their future lies in natural gas.
Interestingly recent statements from E&Ps active in deep water seem to indicate an opposite trend from these FPSOs – i.e. lower production and longer plateaus, and therefore smaller and cheaper developments.
Hi George,
I am not very familiar with Nigeria, how much of the 2.12 Mb/d of C+C produced in 2015 was from deepwater offshore? Are there any projects waiting in the wings that might be sanctioned when oil prices rise? According to BP Statistical review, reserves were 37 Gb at the end of 2015, I have no idea if that is 1P, 2P, or 3P reserves, for most OPEC nations they seem to use 2P or perhaps even 3P reserves as their “proved” reserves. Or they may just make stuff up.
The 37 Gb is given in the OPEC annual statistics, which is probably where BP get their numbers, as “proven”. I guess you can take it at face value or assume it is bollocks. It is interesting they have so much higher numbers than Angola – who have a more reasonable figure around 8 to 9 Gb, but a difference may be that Nigeria has onshore fields that do not involve international, publicly traded oil companies, and can probably say what they like about those, Angola does not.
I think most offshore deepwater production is from the six fields above, there are other smaller fields which might add up to another 100 to 200 kbpd, but it’s too much of a pain to get all the data individually (I haven’t found any numbers showing totals by onshore, deep, or shallow, only by company and field).
There are some other projects, apart from Egina in development: a small shallow gas field and another FPSO at 30 kbpd in development. The other big deep water FPSOs under appraisal are: Bonga SW, Bonga North, Owowo, Bosi and Nsiko/Uge which, with Egina, would add about 1000 kbpd. There are also a number of tie-back opportunities for Erha, Usan and Aje that could go ahead (probably 20 to 40 kbpd each – but for the last two only possible once there is production space in the existing FPSOs). I think the deep water FPSOs left represent complicated and expensive developments. Bonga was a very bad project for all involved, late and with cost overruns – I think it was Amec as the EPC contractor (but might be wrong), whoever it was they almost went bust as a result of the fixed price contract they’d entered into. Those left might be more difficult than that.
There are corruption issues (I think concerning Shell mainly), and also changes in rules for licensing, taxes and local content that make it less attractive for the IOCs to invest there than previously. One recent exploration success was an appraisal well in Owowo (for ExxonMobil / Total) I don’t know of much else, or any serious ongoing exploration.
One other I missed: Zabazaba-Etan for Eni, 80 kbpd due around 2021. I’m not sure if full FID has been agreed but work is proceeding in some form, maybe still just FEED.
Hi George,
Thanks. Where did you get the 35 Gb reserve estimate? I agree the 35 Gb sounds like a lot, but the National Oil companies just say reserves are the amount needed so they can continue to produce close to maximum when OPEC cuts. The only decent reserve data is probably from IHS and is proprietary. Basically OPEC is a black box as far as reserves.
Laherrere has claimed the OPEC 2P reserves are overstated by about 300 Gb. If we assume OPEC reserves reported in BP Statistical Review are 2P reserves and deduct the Orinoco Belt reserves, this would put OPEC 2P reserves at about 700 Gb at the end of 2015. Total World 2P reserves (excluding oil sands and Orinoco) would be about 1200 Gb (assuming non-OPEC 2P reserves are 1.6 times 1P reserves).
35 Gb comes from OPEC annual statistics, I think that is the only place to come up with new numbers and everyone else quotes them – they have 2015 numbers and I knocked off a bit to cover production and a couple of cancelled projects, but I doubt that will actually happen. As I said above they are given as “proven”, not 1P, 2P, 2C or anything else. I don’t know what the rest of your comment has to do with Nigeria, however assuming a 5% decline rate for developed fields then there are 600 to 650 Gb online, I estimate about 165 to 180 for identified fields to be discovered and, if the geometric decline we’ve seen since 2010 continues, about 15 to 30 Gb still to be discovered. That gives 780 to 810 Gb, but some is XH which would need to be taken out and included separately if it’s worth the effort. So 700 might be right. Of course 5% decline might be optimistic: recently the Saudi CEO gave 10% without in-fill drilling (the most likely place he based that on would be Saudi), and the number of countries or companies with properly audited numbers that have R/P numbers above twenty years (implying that future average natural decline must be greater than 5%) is few to one (i.e. Canada).
2P reserves are not 1.6 times 1P, that used to be a reasonable rule of thumb on conventional (and not deep) developments when first bought on line but not mature fields. The probable get converted to proven early on. At the end of life, which most fields are approaching, all reserves, by definition almost, have to be proven. If probable are always 1.6 proven I think you might end up with an infinite series that never converges (i.e. abiotic oil on demand). With current seismic, modelling, visualisation and analysis methods the 1.6 doesn’t really work for new fields either (too high), it came from early USA fields which were found by much older methods (not quite a man with a musket but close), and even then there was huge variability.
George and Dennis,
I find this discussion quite interesting.
George, your explanation of the changing relationship of 1P and 2P reserves as fields mature makes sense and confirms what has seemed intuitive to me. Using the experience from old, mature, onshore US fields to extrapolate future reserve additions for the world seems likely to overstate future oil still to be found. thanks for the excellent work and for sharing it!
Dennis, IIRC you have done some nice work creating scenarios that include this type of projection for future reserves additions to calculate a date for peak oil. I can’t remember if you did any with lower reserve additions in line with George’s reasoning that much of what we have recently found will not add reserves the way fields did in the past. I would very much appreciate your thoughts on this and maybe a re-posting of your charts. I suspect you are way ahead of me:-)
Thanks again for your fine work in moderating and making scenarios.
Jim
Hi Jim,
My low scenarios would essentially be consistent with less reserve growth. A reasonable minimum estimate in my opinion is 2500 Gb of C+C less extra heavy oil with 500 Gb of extra heavy (XH) oil (API<10 degrees) for a total URR of 3000 Gb. This is 500 Gb lower than the USGS estimate from 2000 for conventional resources. It is also consistent with a Hubbert linearization of World C+C-XH which in the past has tended to underestimate World URR, which is why I believe actual output is likely to be higher than this (probably 3300 to 3500 Gb of C+C URR) unless future demand is constrained by technological change and climate policy (which I hope will be the case). Chart below is an older scenario, an updated chart is further down thread.
I would do it separately for heavy oil, and run Venezuela as a separate entity which won’t respond at all to market signals. Venezuela is simply too chaotic, and I suspect the conflict may lead to destruction and sabotage of existing infrastructure.
Yesterday Maduro was shown playing the piano, meanwhile I see increasing calls for a “350 rebellion”. The Venezuelan constitution allows armed rebellion against a dictatorial regime, and Maduro’s qualifies.
Hi Fernando,
I do separate models for C+C less extra heavy and a separate model for Venezuela and Canada for extra heavy oil.
Hi George,
Sounds reasonable thanks.
What would a reasonable 2P/1P ratio be? I understand that nobody knows, but your guess may be better than mine. For the US at least from 1980 to 2005, using 2P/1P=1.6 results in reserve growth of about 60% over that period (2P reserve growth assuming 2P/1P=1.6).
If we assume the ratio is lower, then reserve growth must be higher for the numbers to match up. So either probable reserves are lower and reserve growth is higher or vice versa.
Using data from link below (Appendix 2)
https://www.ogauthority.co.uk/data-centre/data-downloads-and-publications/reserves-and-resources/
I show the basis for my 2P/1P ratio of 1.6. The average from 1973 to 2015 for the UK was 1.7. The minimum was 1.29 in 1974 and the 2P/1P was higher than 1.49 all but 8 years (1973-78 and 1982-83).
Hi George,
I forgot to ask, would you consider the average UK field to be “mature”?
The US 1980-2005 reserve growth (total increase over 25 years divided by 1980 2P reserves) vs the assumed 2P/1P ratio (varied from 1.2 to 3.45).
Those like Jean Laherrere that assume 2P reserve growth is close to zero would require 2P/1P to be 3.45 for the US from 1980 to 2005, if the EIA proved oil reserve data is correct. For those that believe the 2P/1P ratio must be very low, say 1.2, then reserve growth would be 115% from 1980 to 2005. A 2P/1P ratio of 1.7 (as in the UK from 1973-2015) would result in reserve growth of 63% from 1980 to 2005.
A 2P/1P ratio of one would mean reserve growth was 150% from 1980 to 2005.
Most of the UK fields are mature, but about half the production comes from fewer fields started since 2008. That ratio will go up to about 75% in the next few years as there is a relatively large amount coming on line (a last hurrah). I think that curve above will continue down as they are bought on line and other fields tail off.
If you are using UK government numbers then I think there might be some very strict rules about what is called proven and probable – i.e. there might have to be an installed facility and/or drilled wells before it counts as proven. I can’t remember exactly, but it’s not the same as a casual 2P estimate from a reservoir team.
I don’t believe 2P versus 1P matters if you are talking about large scale fields. A back dated 2P number gives the expected recovery, whether within that the reserves are P1 or P2 doesn’t matter, the 2P number doesn’t grow – it is the best estimate of expected recovery and is mostly about right these days, some a bit high some a bit low. Under new SEC rules for companies it does matter as they can only claim proven reserves for projects that are to be developed within 5 years. But I don’t know what any of that has got to do with Nigeria claiming 35 or 37 or whatever. Are you saying their actual number should be 1.6*37=59.2, because I think that is extremely unlikely? Somewhere around 10, which is I think what Rystad had for 2P looks better. Your reserve growth extrapolation might apply to some new fields or not, but so what? My estimate of 165 to 180 on identified projects is a 2P number, if you are querying that, and an observed 5% decline rate doesn’t care if the reserves have been listed as 1P or 2P – it’s just what it is.
Growth in reserves on undeveloped fields estimated in 1980 made without current technology has absolutely no bearing on growth from now on for developed fields or new fields that I can see.
I think your actual argument might be more about the ratio of 3P to 2P, i.e. growth from possible to probable, I think on average that is pretty much zero nowadays. Sometimes, in fact quite often offshore, a topsides facility processes more than it’s original design because neighbouring fields are tied-in, but that isn’t really discovered reserve growth, it’s new discoveries, and recent evidence suggests those are fading away.
Hi George,
It had very little to do with Nigeria specifically. I looked at the BP reserves data and it got me thinking about OPEC reserves in general which as I said are not well known.
You had said the proven (1P) reserves were “claimed to be 35 Gb”, I agree (if I am interpreting you correctly), that proved reserves are probably less than 35 Gb, maybe about 20 Gb at most, and maybe more like 14 Gb, if we use UK 2P/1P=1.7 (20 Gb guesstimate) or UK 3P/1P=2.43 (14 Gb guesstimate) as a guide to possible Nigerian proved reserves.
I am skeptical of the claim that 2P reserve estimates will not change over time both due to changes in technology in the future and changes in oil prices in the future.
One could also claim (and I would agree with such a claim) that these 1P, 2P,and 3P reserve estimates may decrease as technological change in the future may lead to a decrease in oil prices as oil becomes obsolete as a transport fuel. I doubt that will be the case before 2040 or so.
Hi Jim,
The updated scenario for World URR of 3000 Gb below. The difference is that the old chart only has data through 2014, the new chart has data through 2016 and the scenario was adjusted slightly to correct for the underestimate of the old scenario (in 2015 and 2016).
Dennis,
Thank you very much. I guess it doesn’t make much difference. The trend is obvious and the future is less.
I find George’s comment above about zero a bit unnerving: “I think your actual argument might be more about the ratio of 3P to 2P, i.e. growth from possible to probable, I think on average that is pretty much zero nowadays.”
I suppose he may be right in that I (and seemingly maybe you) are interested in the 3P number in essence, trying to guess at ultimate recovery. His comment about some new finds being too expensive to develop makes me think lower numbers may be more realistic. We won’t be able to afford it all, either monetarily or environmentally, and a bunch of it will be left in place, at least for awhile.
Thanks for posting the scenarios (some folks expect too much from anything called a model). I’m impressed how little difference there is in the runs. I think the shorter time period will be more “interesting” as the system shocks from less net energy will accelerate change to a traumatic level.
Your scenarios and George’s bottom up analysis have finally put some measure to the variable of time as it relates to Rockman’s peak oil dynamic. It looks to me that by 2020, two and a half years from now, peak oil should be obvious to all except the deniers, and our world will be in an accelerated state of change.
Best wishes to us all.
Jim
Dennis – It appears that some of your comments might be related to something on the previous OPEC post, which I hadn’t read as they must have been added just before this new one came up:
Note that Laherrere estimates about 2700 Gb for the C+C URR, see
…
pages 55-60 covers his World estimate and notice Figure 99 on pp 55-56 where he has two estimates for World C+C-XH(extra heavy oil less than 10 degrees API)of 2200 Gb and 2500 Gb, he chooses the lower estimate, I would argue that technology and reserve growth makes the 2500 Gb estimate more reasonable.
The way I read it Laherrere is rejecting the higher URR number because it is skewed by recent US LTO activity, not because it requires technology or investment. He presents the logistic curves for 1983 to 2015 and 1993 to 2015 and then states:
”HL of crude oil less extra-heavy (Athabasca and Orinoco) could be extrapolated for the period 1983-2014 towards 2200 Gb but towards 2500 Gb for the period 1993-2014.
We prefer the first ultimate of 2200 Gb in line with the extrapolation of backdated discoveries
World crude oil production is disturbed since 2009 by US LTO production and the world excluding US crude oil production (in blue) displays a plateau since 2005”
So, as you say, 2,200 Gb seems his expected non XH recovery – leaving about 1,000 Gb to come (in 2015): therefore say 60 Gb produced since then, about 650 Gb from developed fields (4 to 5% decline), 160 mmbbls from identified undeveloped conventional fields, 25 Gb yet to be discovered, 30 Gb from Iran and Iraq, and 25 Gb from LTO gives exactly 1,000 Gb. There may be some more in the Arctic or offshore Africa, but there may be less in existing fields if the decline is being propped up by in-fill wells. So I think his numbers fit pretty well with what we are actually seeing at the moment. The big technology advances in part contributed to the recent glut through 6th and 7th generation rigs, seismic and visualisation advances etc., there may need to be a new geological challenge for it to have a similar effect, and I can’t see anything like that at the moment.
I’ve posted my chart of estimated production again below. It doesn’t exactly correspond to the numbers above as it includes existing XH production and identified projects, uses 4% decline rate and misses out some small condensate additions, but I’ve included nominal ramp-up on 2016 projects and all 2017 start-ups, which I’d accidentally omitted previously. Iran, Iraq, any OPEC spare capacity, new XH projects, LTO growth and new discoveries would need to be added onto this. I don’t think it is possible now for the industry to ramp up to develop the putative bulge of projects in 2022 to 2025, it would be flatter than shown.
Hi George,
CAPP has estimate for future oil sands projects.
http://www.capp.ca/publications-and-statistics/publications/282894
http://www.capp.ca/publications-and-statistics/crude-oil-forecast
Earlier I underestimated cumulative C+C output which is about 1310 Gb through the end of 2016, I believe you said your scenario is about 810 Gb (output from 2017-2100?) your estimate is about 2100 Gb, but Laherrere’s estimate is 2700 Gb (with 500 Gb from Canada and Venezuela extra heavy oil). I believe Laherrere’s estimate is very conservative. Perhaps the main difference is the stuff you left out (OPEC and XH oil mostly).
What percentage of world output is from deep water offshore? I would think that the growth in the US reserve estimates from 1980-2005 of 63% (assuming 2P/1P=1.7 on average in the US over this period), suggests that for the rest of the World’s onshore oil basins (which in general are less mature today than the US basins were in 1980) might have considerable room for reserve growth.
You are putting words in my mouth. I didn’t estimate anything for URR – I just presented what current decline rates and identified projects would give, and said they seem to agree with Laherrere’s numbers. I specifically said the 810 Gb number included some XH which would need to be taken out for direct comparison. Your 2P argument based on old US numbers does not suggest what you say, no matter how many times you want to repeat it. There is an old USGS paper that quite specifically states that reserve growth numbers from one field, basin or country are not applicable to anything except that specific domain, and it uses the old US reservoirs as an example.
Hi George,
Your scenario was 810 Gb. Cumulative is roughly 1300 Gb.
So I take your scenario plus cumulative and that would be URR (or at least a minimum). Yes XH would need to be removed to compare with Laherrere and Iran and Iraq would need to be added.
Are you proposing there will be no reserve growth (like Laherrere)?
I doubt it.
Yes the USGS paper suggests older fields from the US have higher reserve growth.
What about older fields from middle east and Russia, many of which are larger than US fields?
I do not think World reserve growth would be the same as the US, but Laherrere’s suggestion that it will be zero? Hard to believe, and you seem to imply that you agree with Laherrere. I don’t.
Just trying to reference your scenario to something else, so we will just forget any comparisons as that would be difficult.
Due to those things you leave out (Iran, Iraq, Venezuela, Canada, and future projects not yet sanctioned) output is likely to be higher than your scenario. By how much, I do not know.
I have shown what my scenarios are, which lack the bottom up detail of yours, the problem with bottom up is that it may not anticipate future changes (a la US LTO circa 2007).
Hi George,
The 2P/1P ratio is based on UK government data from 1973 to 2015.
I am only showing what the reserve growth was in the US based on different assumptions about 2P/1P (because I don’t have data on US 2P reserves (only 1P).
I also do not assume reserve growth for the rest of the World will be the same as the US. You seem to think that reserve growth will be zero.
If reserve growth is zero, why would there be any need to backdate reserve additions?
If reserve growth was in fact zero, all current 2P reserve estimates should be correct (on average).
There are many that insist we must back date reserve additions to get an accurate picture of URR, I agree.
But if I believed as Jean Laherrere does that reserve additions will be equal to reserve reductions so that on average there will be no change in 2P reserves, backdating would be less important.
I suppose one could argue that only old reserves will grow while newer reserves will shrink by an equal amount, which would change the shape of the creaming curve.
There are those that argue that newer 2P reserves are relatively accurate, if that is correct and reserve growth is close to zero, that would mean that older discoveries are also currently estimated relatively accurately.
The geologists and geophysicists at the USGS, believe that reserve growth will be significant (World Petroleum Assessment 2000), about 600 Gb of conventional oil reserve growth from 1998 to 2030).
The USGS reserve growth estimate may be a little high, but judging from the change in the HL URR estimate from 1985-2000 to 2001-2016 (an increase of 500 Gb from 1900 Gb to 2400 Gb), might not be far off.
USGS estimated about 3000 Gb for Conventional C+C URR through 2030 (cumulative discovery excluding “continuous resources”). I think they overestimated new discoveries (they estimated about 500 Gb) and 2700 Gb might be a more reasonable estimate with about 600 Gb of continuous resources (extra heavy oil and LTO), total C+C URR of 3300 Gb (including continuous resources). Pessimistic C+C URR 3000 Gb, optimistic 3600 Gb.
Hi George,
I did an HL for World conventional C+C (where both LTO and extra heavy oil are excluded). If we use the data from 1984 to 2000 the URR would be about 1850 Gb for conventional C+C, for the next 16 years (2001-2016) the HL points to about 2400 Gb for conventional C+C URR.
Hi George.
There is also the Ogo discovery in opl 310 it is scheduled for appraisal drilling this year and estimated p50 of 774 mmboe but it is all bogged down following the Afren debacle.
Got it thanks
According to PETAN (Nigerian petroleum association) fewer than 0 exploration wells have been drilled there is the last ten years:
Nigeria’s depleting reserves addition has been hinged on lack of exploration activities due to the uncertainty created by the non-passage of PIB. The administration of former President Olusegun Obasanjo had set a production target of four million barrels per day and reserves of 40 billion barrels by 2010 but these were not achieved.
http://www.petan.org/index.php/news-events/news/176-petan-advocates-for-increased-exploration-activities-reserves
I think you can have depleting reserves, not sure wether reserve additions can deplete, but nevertheless the PIB was passed this week so their objections have been removed in theory. I think, though, that geology beats politics, and sooner rather than later.
Hi George,
I agree that reserves will tend to decrease, though if we consider economically recoverable reserves, those can be influenced by the oil price (so reserve additions may be positive or negative if prices change), clearly we don’t (or at least I don’t) know what the reserves are in any OPEC nation, including Nigeria. The reserves reported by OPEC nations are likely to be overstated, by how much we can only guess.
I don’t think this was posted in this forum when it first came out. We’ve had a lot of discussions about the extent to which EVs might impact petroleum usage. But I think changes in driving patterns will be the result of many factors all coming together simultaneously. This report lays it out for you.
My sense is that few politicians have looked at reports like this, but I will guarantee that gas and oil industry and auto industry and tech industry people have.
The future of mobility’s impact on transportation fuel | Deloitte University Press
I had a thought. In a way, the Trump administration’s plan to sell off the SPR could serve as a signal that the oil era is ending.
Selling it off won’t help, and will likely hurt, oil prices. So from an industry point of view, it’s not a great idea.
Selling it off means the reserves won’t be there if we should need them. So that means we would need to get by without those reserves: an emergency future with less oil. Strategically one would need to plan for getting by with less oil. In other words, someone is thinking (or isn’t thinking at all) that the future involves less oil demand.
To be clear, selling SPR reserves is a continuation of Obama era policies.
Previous sales have been much, much smaller.
Mexico C&C dropped about 6,000 bpd for April (there was no condensate data so I estimated it by pro-rating March numbers and April gas production). They are down 91,000 from October, just short of the 100,000 they promised as part of the NOPEC cuts. KMZ still declining slowly. Overall decline y-o-y is 7.5%, individual field declines are shown against the basin names. Oil rigs were up four in the month.
Ahh yes, look at that US expertise boost output. And look at the new tax rules do it, too.
All such crap.
When did the Mexicans offer the second round? How long do you think it takes to sign the final deal, do preliminary engineering, recruit personnel, open offices, lease warehouses, prepare bid packages, do more detailed engineering, do preliminary field work, do enviromental Impact activities and get permits, sign rig contracts, get all the pipe, well heads, production equipment, drill and test wells, build facilities and produce first oil? In a low price environment where rushing is counterproductive? Would you like a cheap seminar on how this works?
Maybe it is just my computer. But, this Texas Update page and the most recent open thread are not posted on the Home Page. I even went to Google and got into the site new. They are not on the Home page, but they are on all the rest of the pages.
you gotta refresh. happens to everyone
You have to refresh each topic page, not just the Peak Oil Barrel site. So each time you want to see new messages on the Texas page, you have to refresh. Each time you want to see new messages on the non-petroleum page you have to refresh.
I can see when new comments are posted by looking at the recent comments list. But to actually see the comments when I click on them, I have to refresh the page that they are on.
I appreciate your answers, but I am well familiar with your comments.
Go to the top of Peak Oil Barrel and click on Home Page. When I do that, this topic is not shown and the most recent “topic” [not comments] available is the May 15th OPEC production. Since, I have the Home page loaded as a site to click on, I noticed that after seeing the post (at the bottom of the OPEC comments) that there was a new “topic” available (this one).
Perhaps there is something wrong with my computer. But if you read this comment, take a second and scroll to the very top and click on the “Home” page. If this topic is listed as the most recent – then my system is somehow screwed up.
When I click on home, I get Texas Update as the most recent post.
So everything is current on my computer as long as I hit refresh each time I visit a page on this site.
really, I finally learned what they are saying. When you go to the home page, you MUST hit function F5 to get the updated page. Then AFTER you click on the newest topic, you might have to hit function F5 again. Really.
My procedure is refresh the top page.
Then I click where it says comments. The article beginning is on the top page, not all of it. The “comments xxx” link is below the article beginning.
That puts you at the top of the comments and a count of them. Refresh and you get them all.
It’s not horrible once the habit is embedded.
If anyone is a computer expert (or more so than me), suggestions would be appreciated. I don’t know why the refresh thing is needed and more importantly I don’t know how to fix it.
Hi Dennis,
Browsers cache the files used to render the page. When a page request is made the browser looks to see if the respective URLs for the various files needed for that page match an URL for a a file in the cache. If it it does it uses the cached file.
If a file is cached by the browser then the browser uses the cached file for better performance. If resources (files) used by the page are constantly changing then you need to break the caching of these files. There are various ways around this. I’ll take a look at the page tonight when I have time and see if I can suggest a solution.
Each web page sent should have these parameters set. Maybe you could ask your web site host how to set these in WordPress?
“The correct minimum set of headers that works across all mentioned clients (and proxies):
Cache-Control: no-cache, no-store, must-revalidate
Pragma: no-cache
Expires: 0”
https://stackoverflow.com/questions/49547/how-to-control-web-page-caching-across-all-browsers
India data for April below. They may be holding a plateau or maybe noise on a downward trend. Most of the talk from the local E&Ps is of natural gas or expanding outside of India, and also that they may all be merged into one (almost certainly a sign of long term production decline in my opinion).
Hello Mike, this post is for you. Since you relish badmouthing US producers as sort sighed and greedy traitors for exporting oil and nat gas that somehow, in your worldview will negatively impact our fellow citizens, this list will help you expand your effort to tell other exporters just how foolish they are. You can start with some of our closest allies like Canada and Mexico and then move to the United kingdom and I am sure once you explain just how ignorant they are we can get a good and proper trade embargo going where we all just produce and consume products from within our national borders. I nominate you to lead your fellow comrades this noble effort?
U.S. has brought into its refineries crude oil from 80 nations
In the past 30 years the U.S. has imported more than 91 billion barrels of oil, drawing from a large variety of sources.
The EIA began carefully tracking American oil imports in 1986, meaning there is now now a significant amount of historical data. From 1986 to 2016 the U.S. imported 91.2 billion barrels of crude oil, in just under 244,000 individual records.
In total, the EIA lists 80 different countries from which the U.S. has imported crude oil.
The top ten countries are listed below by oil volume. These ten represent 86% of all imports in the last thirty years.
Rank Country Oil Volume (billion barrels)
1 CANADA 17.288
2 SAUDI ARABIA 14.528
3 MEXICO 12.093
4 VENEZUELA 11.885
5 NIGERIA 7.773
6 IRAQ 4.018
7 ANGOLA 3.610
8 COLOMBIA 2.658
9 KUWAIT 2.255
10 UNITED KINGDOM 2.141
Where does Oil in the U.S. Come From? Import Sources May Surprise You
https://www.oilandgas360.com/oil-u-s-come-import-sources-may-surprise/
Got it tee-tee; America is still a net importer of crude oil. That’s some good investigative reporting there.
Look, worm, inventory levels are still at an all time high in America and the bulk of that is light tight condensate. The export ban has been lifted in the US for over three years now; nobody afar wants to import LTO, or much of it, and we still can’t lower those inventories. The price of oil is low, and volatile. In the mean time all those big wells you own in Oklahoma are just making the problem worse. And while all this is going on, hold onto your knickers….oil imports into America are going UP, not down. Google it.
Canada is the 10th largest oil consuming nation in the world, Mexico the 11th and the UK the 18th. America, on the other hand, is the largest oil consuming nation in the world, by a wide margin. We do not have the LTO resources to achieve, nor sustain, hydrocarbon independence. Forget the costs, and the additional burden that attempting to achieve hydrocarbon independence would place on our national debt, it can’t be done. There is not enough of it.
I dislike the American shale oil industry, in general, because it cannot function without borrowed capital and it no longer has the ability, in my opinion, to pay back the hundreds of billions of dollars it owes. I understand that doesn’t bother you, and I understand why. I also dislike the lying the shale oil industry engages in that convinces other stupid people that we have all the shale oil we ever need in America, enough for ourselves, and anybody else in the world that wants to buy it.
Personally, I would rather sell my oil for a higher price than current prices, but then again I have to pay to get it out of the ground, unlike yourself, I am sure, who gets it free and clear of all costs. I also embrace oil price stability as that leads to employment stability and a healthier oil industry for America’s future. I also believe it is important to conserve our remaining hydrocarbon resources in America and to otherwise develop what is left of those resources at a pace that is commensurate with the world crude oil market. Again, I understand completely why you don’t get that. I can’t help you.
Mike says:
FALSE.
U.S. Oil Exports Hit Record Levels
https://www.forbes.com/sites/rrapier/2017/02/28/u-s-oil-exports-hit-record-levels/#4479b6f351a6
This might add some clarity to the discussion.
Offshore, not shale, driving U.S. oil exports – UPI.com: May 18 (UPI) — “Asian markets are drawing more on U.S. crude oil to quench their appetites, but it’s mostly coming from offshore, not shale, analysts said Thursday.”
Hi Glenn,
It is net imports or net exports that matters. Net imports (crude plus products) are still around 5200 kb/d on average from Jan 2, 1015 to May 19, 2017.
See
https://www.eia.gov/dnav/pet/pet_move_wkly_dc_NUS-Z00_mbblpd_w.htm
Dennis,
No, in context of Mike’s comment, it is gross exports that matters.
After all, what Mike said was “nobody afar wants to import LTO, or much of it.” Then lower down on the thread Mike reiterates his point by saying, “LTO is crap.”
Mike’s bad mouthing LTO is nothing but sour grapes, because the shale oil producers flooded the world oil markets with LTO and drove the price of oil down, which cut into his income. And it looks like they may continue to do so. Producers like Mike simply cannot compete with the shale oil producers. It’s not difficult to discern why he’s sore.
The reality is, of course, that plenty of people want to import LTO. LTO is a light, sweet crude that has almost identical refinery product yields as WTI (see graph below).
The reason the US needs to export light sweet crude, and concomitantly import heavy sour crude, is because the vast majority of U.S. refineries are not designed to refine light sweet crude, whereas the rest of the world’s are.
But what about the article saying that exports are from offshore drilling, not LTO?
Boomer II,
Since the sum total of offshore Gulf of Mexico crude production has been almost flat at about 1.5 million BOPD for the past 15 years, and U.S. exports of crude oil and petroleum products now exceed 6 million BOPD, I hardly believe offshore Gulf of Mexico crude is what is “driving U.S. oil exports.”
The 6 million includes petroleum products, as you say, so I don’t see the connection between GOM crude and total US exports. Can you show the direct path between LTO and exports to refute the article?
I am trying to get beyond hype to some definite numbers.
Is this the sort of thing you’re looking for?
For me it’s a non-issue whether it is LTO, WTI or LLS that gets exported, since they are all sweet crudes with similar product yields, and thus are fungible.
This, as far as I am concerned, is the only thing that is important.
But it does matter to some that the Permian exports may not be LTO.
Bommer II,
Why would it matter?
It’s a distinction without a difference, unless you can point out some reason why it’s not.
Mr. Stehle, you are pissing me off, pardnor. Try your best not to put words in my mouth and stick to making your feeble points. I am no threat to your mighty shale oil industry so there is no reason to get personal.
Never in my 50 years in the oil business have I felt the need to “compete” with another facet of my own domestic industry. On the contrary, I have always felt as an American oil producer we are all in this together, in the best interest of our country.
As to this matter of competing with the US shale oil industry; you conveniently overlook the fact that it exists, entirely, on the back of borrowed capital. Without that borrowed capital it cannot stand on its own two feet. I had to laugh at your comment about people having “skin” in the shale oil game. That was a goodun. I don’t chose to borrow money to drill oil or gas wells and the wells that I drill have 3 times the ROI a shale oil well does. My incremental lift costs are low and my employees are secure in the knowledge they won’t be working 6 months on and 3 years off; nobody “owns” me. Truthfully, there is absolutely nothing endearing to me about the shale oil business model that I remotely would ever want to compete with.
My opinions regarding shale oil, which you refer to as sour grapes, are genuinely based on the long term energy future of my country. The Federal Reserve recently determined that 44% of American adults do not have $400 dollars saved to meet an emergency monthly expense. That’s the American way, it seems, and definitely the shale oil way; we should be importing as much of this cheap oil as we can and saving our horrendously expensive, marginally profitable shale oil production for a time in the future when we will really need it. Now we’re just pissing it away, putting it in storage, or as to your idea, exporting it to others so someday we can buy it back at 3 times the price. Brilliant.
My own anecdotal attempt at speculation: I find it interesting that people who supposedly have decades of experience in the oil business, who have “grease under their fingernails,” never accumulated enough of a conventional production base in their careers to be even remotely concerned about LTO overproduction and low, volatile oil prices. My immediate thought would be that they were not very successful all those years.
Mike,
“Making your feeble points”?
I happen to belong to the old school where factual accuracy counts, and where listening to people who make frequent mistatements of fact is a good way to get misled.
The rest of your screed sounds like some sort of a morality tale.
I would just point out to you that there are probably many, many more people who low oil prices help than people like you and me who they hurt.
How you ever came to the conclusion that high oil prices are “in the best interest of our contry,” even though they would very much be in your and my best self-interest, is beyond me.
All your arguments ring of special-interest pleading.
“Since inequalities of privilege are greater than could possibly be defended rationally, the intelligence of privileged groups is ususally applied to the task of inventing specious proofs for the theory that universal values spring from, and that general interests are served by, the special privileges which they hold.”
— REINHOLD NIEBUHR, Moral Man and Immoral Society
Mike says:
FALSE.
Net imports went up from Feb to May (see weekly data). And they have been pretty flat from Jan 2015 to May 2017 (weekly data).
I think the long-term securlar trend — U.S. net imports have declined steadily from around 13 million BOPD in 2006 to about 5 million BOPD in 2016 — is what is germane.
Do you really believe a few little squiggles in the graph over the past few months is what is important?
Hi Glen,
The trend has been pretty flat from Jan 2015 to now. Not many LTO players have been profitable, if LTO is as plentiful as you (and the EIA) claim oil prices will be low and LTO producers will continue to lose money. If oil prices rise and LTO producers expand slowly (so they don’t drive prices back down) then potentially LTO output might increase by 2 Mb/d above the previous peak by 2023, then there will be a relatively rapid decline in output as the sweet spots run out and further drilling is no longer profitable.
Dennis,
You certainly use that “will” word a lot, as if your crystal ball is infallible.
Mike said:
Maybe so. Maybe not.
According to the EIA’s Annual Energy Outlook 2017, in the reference case the United States will become a net hydrocarbon exporter by 2026, but the transition occurs earlier in three of the AEO2017 side cases.
And in two of the EIA’s side cases, the United States becomes a net petroleum exporter no later than 2022, and remains a petroleum exporter until 2040 and beyond.
Mr. Stehle, we can throw links at each other all night if you want; here is one regarding how heavy oil imports into America are up since fall of 2015: https://ycharts.com/indicators/oil_imports. We both know why they are up (LTO is crap), but that is hardly relevant, is it?
As to LTO exports from the US being up since the ban was lifted by a hoodwinked congress in 2014, sure they went up and have “hit record levels”…since the ban was lifted. Good grief. I have no doubt they will inch there way up even more, but it will not be sufficient to draw down inventories, raise the price of oil, and help make the American oil industry great again, will it? No.
TRUE, I should say.
Or is it just the American shale oil industry you want to make great again?
TRUE, I should think.
This bullshit: http://www.cnbc.com/2015/12/16/lifting-oil-export-ban-could-be-long-term-game-changer.html didn’t work out too well, either, did it?
That’s a big TRUE, it wasn’t a game changer.
In a previous comment you criticized the EIA, now you embrace its grandiose plans for America being a net exporter of crude oil by 2026; you say the Bakken is the worse of all shale plays so I assume all this miracle is going to occur from the Permian? Is all this going to get paid for from net cash flow, at $50 prices? Will OPEC “assist” the shale oil industry in reaching this goal by cutting its production, again, and keeping prices propped up, again?
I am not going to engage with you on this matter of shale oil miracles; my position is clear…we do not have the resources left in America to become hydrocarbon independent (increasing GOR, WOR, the astounding number of shale oil wells in all of America’s shale plays, including the Permian, that now make less than 35 BOPD, costs, economics and DEBT matter) and I feel it would be a good idea to conserve America’s remaining oil and gas resources for our children someday, not piss them all away for the benefit of short term greed.
You clearly don’t feel that way at all. You have come to a peak oil blog, of all places, to deliver your message of abundance; I trust that there are numerous minds here yet to be changed about this whole matter. Please carry on and good luck with that.
And the largest ship to ever dock at the US Gulf coast is taking on 2.2 million barrels of oil for export.
The port of Corpus Christi is in the process of a decade long, $1 billion upgrade that includes channel deepening and widening.
The existing roadway bridge is being replaced with one with much higher clearance, all to facilitate US hydrocarbon exports.
Mike says:
More fact-free nonsense.
Here’s the reason why it makes sense to increase imports of heavy oil and to increase exports of LTO. And your claim that “LTO is crap” has nothing to do with it:
I just posted this link under a different comment, but it seems relevant here, too. According to this, it’s not LTO that we’re exporting.
Offshore, not shale, driving U.S. oil exports – UPI.com
Glenn,
Maybe you don’t realize it, but you come across as arrogant, ignorant, and full of crap, sounding like a shill, a promoter trying to steal OPM. It doesn’t become you, nor help you deliver your sales pitch effectively. You have alienated me with your greedy, obnoxious and insulting writing. Guess your momma never taught you any manners. Pity.
Excuse me for holding my nose and not reading any more of your self-serving posts. You are not making a positive contribution here due solely to your attitude. You need a new business model. This approach is a bust.
I’ll ignore you from now on.
Cracker,
Just like clockwork, when you can’t defend your message with verifiable facts, figures and sound logic, you attack the messenger.
But you’re right about one thing. I have little tolerance for ignorance of the willful variety, and no intentions of developing a tolerance for it.
This is for Mike, GS, TT .
I posted on PO com the issue that Mike has referred to, viz that that LTO is shit oil and is only going into storage leading to glut . Rockman came along with the explanation that LTO of +45 Api is blended with the heavy oils from the tar sands and Venezuela to make a blend of 37.5 Api and that is what the refiners use.According to him there is no extra storage for LTO . In response “shorton oil” of ETP model says that, yes you have a blend of 37.5 Api but this blend has a different molecular structure than the true 37.5% Api .It is like saying that you are drinking Gin while you are drinking a Margarita . The blend only allows the liquids (heavy oils) to flow thru the refineries which would not have been possible otherwise . His take is that though the blended oil has an Api of 37.5 the output is not the same as the “pure” 37.5 because of the difference in molecular structure . This issue was also pointed out by WT (Jeffery Brown) which he called the “dumbell effect” where you have gasoline and bitumen etc but the middle distillates viz diesel,ATF are low or missing after refining . I think that even Art Berman referred to this but not very sure . Could someone make an effort to clarify ?
You might want to start with this.
It pretty much blows the claim that “LTO is shit oil,” or that “the middle distillates viz diesel,ATF are low or missing after refining” to smithereens.
LTO has almost the same product yields as WTI, although it has dissimilar product yields to Maya or Eocene.
https://inside.mines.edu/~jjechura/Refining/02_Feedstocks_&_Products.pdf
The way the peak oil community comes up with all its misinformation, and then proselytizes it as if it were sure truth, is beyond me.
IHS – Driven by inflating input and restart costs, frac pricing to improve in 2017
25 May 2017 by Caldwell Bailey
The hydraulic fracturing services industry, after two years in the doldrums, is on pace for significant improvement during the remainder of 2017. Capacity utilization of all existing frac horsepower (raw utilization) is forecast to average 56% in 2017, up from an average of 36% in 2016. When adjusted for utilization of ready-to-work horsepower, utilization is forecast to average 79% in 2017 – a level just below our threshold for a shift in market power. Things seem to be looking up for services firms, and, as a consequence of the tightening, we also forecast a 26% increase in overall US Land frac services pricing in 2017 – with further increases in 2018 and beyond.
Our forecast pricing increase will be driven by many factors, as frac services companies operating at-or-below breakeven levels during the downturn had cut all expense categories as far as possible…
http://blog.ihs.com/take-me-higher-driven-by-inflating-input-and-restart-costs-frac-pricing-to-improve-in-2017
Wood Mackenzie
After a flurry of development activity in Q1 2017, the US Lower 48 onshore sector is beginning to feel the squeeze of cost inflation.
Our base case assumption of 15% cost inflation draws from an uptick in confidence around oil price, increased capital budgets for operators and negative margins for oilfield services (OFS) companies.
https://www.woodmac.com/ms/highest-returns/l48_breakevens/
What does this cost inflation entail for the total cost/well (time to reach pay-out)? And how does this in combination with higher interest rates affect the economics of LTO? Is it likely to have any effect or is it just marginal?
The only public company that is solely focused on fracking services in the US shale basins in Keane Group, ticker symbol FRAC. The company just went public at the end of 2016.
Keane’s 10Q for 1/17 is interesting. The company lost $72 million. Their costs of services, which excludes depreciation, selling, general and administrative expenses and interest, was just $16 million less than revenues. The margin between revenues and costs of services was just 6%. This was an improvement over 2016, where costs of services were actually more than revenues.
In the business outlook section, the company states they are seeing higher pricing for services. In particular, due to greatly increasing volumes of sand per well, the company has seen certain grades of sand doubling in price since the second half of 2016.
This is not a small company, they are in all shale basins and do work for some of the big names. Clearly, as more fracking crews are utilized, costs are headed up.
Of course, they still do not have all of their frack crews working. There is still overcapacity in all service areas, as active rigs are still far below the peak in 2014. Well costs have fallen several million dollars since 2014. It is interesting that even with the price recovery in Q1, 2017, most upstream US shale companies showed losses or small earnings per share. ExxonMobil, Chevron, Pioneer, Marathon and EOG all either showed small positive or negative EPS in Q1 from US upstream.
There were outliers, such as Diamondback(FANG), which showed high EPS. However, a close look shows FANG’s CAPEX is still significantly higher than D,D&A.
Looking back since 2014, very interesting how the US shale industry battled to maintain production. Saudi Arabia surely didn’t anticipate the ability of US firms to operate at a loss for such a long time. 2 1/2 years later, US service firms are still operating at a loss, if Keane’s example is accurate. US financial markets are very deep, interest rates remain very low on a historic basis, and executives earning 7-8 figures annually are not simply going to shut down, as no growth equals lower bonuses.
The numbers reported in 2015 and 2016 in aggregate by US shale firms clearly show that the vast majority of 2015 and 2016 shale oil wells were operated at a loss. Almost all will not reach payout in 36-60 months at the current futures strip. Hopefully, when this shale phenomenon has concluded, there will be some in depth studies conducted of the financial side. Those reports should make for very interesting reading.
Our small family business was not immune from cutting, such that 2016 was in the black, despite well head prices for the year it just $36. True, we are not drilling still, and production is slowly declining. This will continue until prices solidly rise into the $55-65 WTI band we desire. However, we can take several more years of $45-53 WTI, if that is what the future holds. The consensus in our small oil patch is that we need to be more worried about future demand, than future supply. As US shale continues to climb the wall, taking total US C+C to 10, 11 or even 12 million BOPD, that climb will get tougher, and more expensive per barrel. Maintaining 10-12 million BOPD for a few years will take more CAPEX than is currently being spent. Maybe Dennis knows how much more?
It seems more of the public is pushing for EV, ride sharing, autonomous vehicles, etc. I have tough time envisioning this, living in the middle of nowhere, in the middle of “fly over territory”. But, even though these initiatives are also generally hemorrhaging cash, just as shale has, dollars and cents do not seem to matter. Kind of like how a company like Facebook can be worth $450 billion, yet I have not used it once and see it as nothing but online gossip and a complete waste of time. I can’t understand it, but it is reality.
It’s reasonable to be skeptical of companies and industries that continue to lose money, and I usually am.
The perception is that there is a lot more “potential” money to be made in new transportation and energy companies than in fossil fuel-based companies. Fossil fuel-based companies have a business model based on declining resources, so they aren’t perceived as growth industries, nor are they perceived as disruptive ones. Of course, LTO has disrupted the oil industry for the moment, but the numbers suggest that decline rates will put an end to that before long.
The folks running Silicon Valley companies aren’t necessarily more altruistic than those running gas and oil companies, auto companies, and utilities. But as the money shifts their way, they gain more economic and political power. I am surprised at how little the current administration appears to acknowledge new business trends. They are retreating to an economic system that has been in decline for a number of years now. But then again, if you intentionally want to stifle research that doesn’t support your beliefs, you won’t be aware of changes going on around you.
The fact that you are going to see levels of hype in both established and new companies doesn’t mean the changes aren’t happening. And with disruptive business models, the changes can snowball so quickly that established companies are caught unprepared.
> In particular, due to greatly increasing volumes of sand per well, the company has seen certain grades of sand doubling in price since the second half of 2016.
Son of a gun. Imagine that.
Here’s my fave photo of fracking in the Bakken. It’s from 2012:
http://www.businessinsider.com/youve-never-seen-anything-like-the-williston-oil-boom-2012-3#here-is-a-load-of-proppant-from-china-used-to-frac-a-well-sitting-at-the-rail-head-25
Look real careful. Bags of ceramic proppant. From China. It’s better at holding fractures open than sand. Sand was the downshift because of cost. hahahahahaha
We never do hear about the lower ultimate recoveries simply accepted from use of inferior proppant. Not part of the narrative.
Hi Shallow sand,
I use face book a little because of children, nieces and nephews, but agree it is a waste of time. The US would require a lot of wells to be drilled, an optimistic model would see another 2 Mb/d of LTO in 2023 (6.5 Mb/d peak) over previous peak, in the mean time conventional would decline at about 5% per year so that’s about 2 Mb/d (roughly), so basically output doesn’t really increase by much maybe 1 Mb/d at most from the previous peak (LTO increases are offset by conventional decreases). This would require about 127,000 more LTO wells after Dec 2016 (200,000 total). At about 10 million each this would be $1.27 trillion in capex (in 2016$).
It only happens with higher oil prices.
You are kidding about demand I assume, that was a good one, though 🙂
Dennis.
Thanks for the reply.
I do not know if I am kidding or not, I am not smart enough to know what future oil demand will be.
I noticed this week a big push by the media to get Tony Seba’s predictions out there of $25 oil and demand down to 70 million BOPD worldwide in 10 years.
I have a hard time envisioning all of this EV, ride sharing, autonomous stuff, but I do note:
Toyota Motor Corporation P/E 9.92 Market Cap: $159 billion
Ford Motor Company P/E 11.62 Market Cap: $43.63 billion
General Motors Company P/E 5.10 Market Cap: $49.79 billion
Telsa, Inc. P/E: no earnings Market Cap: $53.33 billion
It is really kind of like shale, makes no sense in terms of making money, but that does not matter. It is a disruptive technology, like Facebook, Google, etc. That seems to be the big thing.
Shallow,
There is disconnect between the real world and Central Banks fantasy world represented by stock market valuations. That is all. CB can’t even normalize the rates. Even A 50bp hike would be a “monetary shock”. So, CB are left only to blow real state bubbles and print extraction of remaining uneconomical oil from the ground.
And you know probably more than anybody else (when looking at shale balance sheet) that is bleak picture when even crap shale appeals attractive for CB/Fed to throw money in order to keep those fairy tale of FB, Tesla sky high valuations. Society is throwing real resources to keep fantasy world of market valuations alive. Total insanity.
Enno’s shaleprofile.com is full of facts. I went back and looked at his 1/17 summary of all US oil producing shale fields. Interesting that despite adding over 13,000 new wells since the peak in 3/15, US as of 1/17 was still 600K bopd below the 3/15 peak.
I do realize data is somewhat incomplete due to TX. I also realize not all wells are included. Still, going to take a lot of CAPEX to climb the ladder back to 5, 6 and maybe 7 million bopd from the shale fields.
Soon, GOM will start declining. Onshore conventional is like the sun setting. Just 60 or so straight hole rigs active, half of the 1998-99 trough. Alaska doesn’t appear to add anything.
Unless demand tanks, per Tony Seba’s theories, maybe its time to be bullish? When it is clear US shale has hit the wall, price could sky?
Hi Shallow sand,
I am also not smart enough to know what future oil demand will be, not many are.
Eventually Tony Seba’s vision of the future may prove correct, but I think it will be 10 to 20 years later than he believes (and perhaps more).
Almost no EVs where I live as well, it is fairly rural around here. A Tesla would work as I am within 200 miles of a super charger and supposedly they are strategically placed on the interstates. Eventually there will be more charging stations, but on long trips it would require careful planning.
I won’t try to predict when we’ll have more oil than we need, but I don’t think the outcome will depend on EVs alone. I think there will be economic and cultural reasons why people may not drive so much in the future. Whether they use EVs, whether they leave their ICE vehicles parked more often, or whether they switch to more fuel efficient vehicles, the result can be the same: less need for gasoline and diesel.
Hi Boomer,
Yes the EV vision of Seba is really more about AVs and TaaS (Transportation as a Service) rather than EVs, but EVs would reduce oil demand more than just better fuel economy and would require less energy as well due to the greater efficiency of electric drives vs ICE.
How quickly this all happen is a big question mark, but nations such as Norway and China are leading the way, leaving the US behind. Hopefully Tesla’s Model 3 (and Model Y) will change that.
I’ve not seen any recent news on energy debt, no doubt Bloomberg will write an update sooner or later…
Had to laugh, earlier in the week I noticed zero hedge suddenly started reporting in “Lower 48 production” after US production dropped last week.
Noticed today some other guy in the comments picked it up too.
http://www.zerohedge.com/news/2017-05-26/us-crude-production-hits-21-month-highs-rig-count-rises-19th-straight-week
Yours is a distinction without a difference.
The EIA projects U.S. crude production to continue its upwards trajectory for the next 18 months.
My issue isn’t about production. It’s the underhanded methods to switch from one measurement to another to suit their narrative.
When US production was declining last year they stopped posting US production charts. The moment that changed and production had consistent increases the charts reappeared. I don’t understand their issue with being honest.
They have some good stuff there, but for anyone paying attention it really detracts and casts a dark light on them.
Hi Glenn,
The EIA makes lots of predictions and many of them are wrong. Conventional output will decline, GOM will be flat or declining and LTO may increase by as much as 2 Mb/d from the previous peak by 2023 and will then decline sharply (peak LTO will be about 6.5 Mb/d at most, but other US C+C output will decrease by 1 Mb/d at 3%/year annual decline). US output might reach 10.5 Mb/d, but not until 2022 rather than 2018, note that this does not satisfy 2016 crude inputs to refineries and blenders which was about 16 Mb/d, unless demand decreases by 5 Mb/d from 2017 to 2022.
I doubt that will be the case, by June 2019 we will probably see $80/b (2016$) for Brent crude. and by June 2020 the price may be North of $100/b (2016$).
Dennis Coyne,
You are absolutely correct. Many of the EIA’s predictions certainly have been proved wrong.
But if you look at the EIA’s track record regarding shale oil production, it has been consistently too pessimistic. Heck, the revolution in U.S. shale oil production didn’t even appear on the EIA’s radar until it had already happened. And then, after the EIA finally did acknowledge the shale revolution, even its most optimistic case scenarios underestimated future shale oil production.
Most folks in the shale oil business — that is, people with skin in the game — fear the EIA may be up to its old tricks again. Why do yo think most of them hedged their production for 2017, 2018 and 2019 when oil prices were in the $50 to $55 range?
texas tea said it best:
Dennis Coyne said:
Well, as Oliver Cromwell so famously put it: “I beseech you, in the bowels of Christ, think it possible you may be mistaken?”
Hi Glenn,
Yes of course I could be mistaken, it will probably be lower than 6.5 Mb/d.
Remember that the USGS estimates are technically recoverable resources, if LTO is as plentiful as EIA high technology and high resource cases predict, then oil prices will be low and the LTO will not be profitable to produce. High oil prices suggest the resource and technology assumptions of those “high” cases are incorrect and even high oil prices won’t get us much of a boost in output.
Using reasonable economic assumptions total US economically recoverable LTO from 2005 to 2050 is about 40 Gb with a peak of 6.56 Mb/d in 2023 (about 2 Mb/d above the previous peak in March 2015.)
Well when the shale guys wanted to massively hedge their 2017, 2018 and 2019 production when oil was at $50 – $55 per barrel, they certainly found no shortage of those willing to take the opposite side of the wager.
So you’re certainly not alone in your predictions.
This difference of opinions is what makes a horserace. It is time alone that will tell, however, and in two or three years we’ll see who got it right.
Texas oil production has increased in Districts 5,7c,and 8 since October 2014. All the other 10 districts have dropped by a total of 714,406 bbls per day. I am using Texas RRC District production October 14 to January 17.
Coal Miners Crushed As White House Admits Trump Lied About Bringing Back Coal Jobs: “The White House’s real position on bringing back coal jobs was revealed after Trump economic adviser Gary Cohn made it clear in a meeting with reporters that coal isn’t even good feedstock anymore, and the future of American energy is in natural gas, solar, and wind.”
Cohn is an ex Goldman swamp dweller. I don’t think he’s going to last.
Wind Project in Wyoming Envisions Coal Miners as Trainees – The New York Times: “On Thursday at an energy conference in Wyoming, the company announced plans for a free training program for one of the nation’s fastest-growing jobs: wind farm technician. And it is aiming the program at coal miners having trouble finding work, as well as those from other industries.”
Trump proposes selling Northwest's transmission grid | OregonLive.com: “The Public Power Council, which represents many of the BPA’s public utility customers, said it was opposed to the proposal for several reasons, including the loss of regional control and value; the risk of increased costs to consumers; the potential for remote areas of the system to be neglected, harming rural communities; and, impacts to reliability.
‘We’ll want the details, but the effect appears to be a transfer of value from the people of the Northwest to the U.S. Treasury,” said Scott Corwin, the council’s executive director. ‘Electricity consumers in the West have paid to construct and maintain a system that would be sold off to fund the federal government.'”
Don’t think Oregon voted for him. Why would he care about them?
This will not be good for higher oil prices, since the projected increase in U.S. crude production will be sufficient to completely meet the anticipated increase in world oil demand.
It will also not be good for some members of OPEC, Russia or any other non-U.S. producer who would like to increase their oil prouction. If they don’t want to crater global oil markets again, the only way they can increase production will be at the expense of one of their fellow OPEC or non-U.S. oil producers.
The data plotted is from the latest EIA Short-term Energy Outlook.
One this is for sure – Few agree on future energy flows
“BP’s World Energy Outlook 2017 concludes that there will be major growth in two key areas (oil and gas) on which it focuses its business. BP has no Plan B. ”
https://seekingalpha.com/article/4076854-gas-answer-bps-plan-b
Don’t really have to agree. The data emerges every year. This year’s in a couple of weeks.
Watcher,
You do realize that there is a difference between the past, the present and the future?
The fifth-century bishop St. Augustine was probably the first western thinker to pay attention to human memory. In his Confessions, Augustine observes that it is memory — the ability to bring into present awareness past experiences and the ability to recognize the difference between past, present, and future — that makes us self-aware beings.
The past is knowable to some extent. The future not so much.
Unfortunately, “the ability to recognize the difference between past, present, and future” is a rapidly disappearing art in our culture and society. The so-called “experts” have gone hunting for certainty, blurred the distinguishing line between thought and knowledge, and believe in all earnest that their speculations and predictions of future events posess the same kind of validity as historical events that have already occurred.
They have entered “the Platonic fold” — “the explosive boundary where the Platonic mindset enters in contact with a messy reality, where the gap between what you know and what you think you know becomes dangerously wide,” Nassim Nicholas Taleb observes in The Black Swan. “We produce thirty-year projections of of social security deficits and oil prices without realizing that we cannot predict these for next summer.”
US shale production increase scenarios at different $WTI prices and cost inflation levels assuming no new debt (no mention of paying down existing debt?)
May 24, 2017 – Leslie Wei – Rystad Energy
Figure 3 shows the estimated Y/Y growth in NA liquids shale production for different WTI oil prices and cost inflation scenarios compared to 2016 cost levels. The “Call on shale” highlighted section represents the 1.3 million bbl/d average taken from figure 2. The key assumption for this analysis is that the E&P companies will balance the investments with operational free cash flow (cash neutrality). For example, in a 70 USD/bbl oil price range, cost inflation within the range of 0% to 25% is required to meet the 1.3 million bbl/d y/y growth in the “call on shale.” In a 50 USD/bbl scenario, the liquids production may only grow as much as 0.5 million bbl/d on a yearly basis even if the costs remain flat. To reach the call on shale of a yearly growth of about 1.3 million bbl/d, the oil price needs to move into the range of 70 to 80 USD/bbl for the companies to stay cash flow neutral.
https://www.rystadenergy.com/NewsEvents/PressReleases/the-call-on-shale
Thank you for the link.
“call on shale” – they may return the call if the price is >70 to 80 USD/bbl.
“call on OPEC” – what will it take for them to return the call?
Energy News,
Thanks for the link.
I particularly liked these calculations:
“Figure 2 shows the necessary yearly growth in shale production to balance supply and demand from 2017 to 2021. To achieve this, shale has to grow by 1.6 million bbl/d in 2017, and more than 2 million bbl/d in 2021. This implies a total shale oil production of 14.1 million bbl/d in 2021. To achieve such growth in shale production, the number of spudded shale oil wells has to reach ~20,000 wells in 2021, or two times the number of spudded wells in 2016.”
Now we have roundabout 4-5 million b/d shale production – how can only the double number of new wells bring the triple production?
On the other hand, is shale now unlimited in resources and can supply the whole world with oil, enough wallstreet silly money (TM) provided?
Oh, and another thing: Do the shale oil wells no more decline rapidly after drilled, but add up nice to such production numbers.
PS: Here in financtial newspapers the typical shale break even price is now at 23$/barrel. There are only a few oil wells left production cheaper than US shale oil.
Let us see the well completion numbers from Texas for May first (RRC), and step by step judge if enough wells are actually completed. The trend is not going right through the roof when looking at the April oil well completion numbers tbh. I don´t like the expression “call on shale” as it implies that there is a vast base of resources there to be exploited, which could turn out to not be true. I also do not like the term “call on OPEC” as it implies the same. The countries in OPEC are very different and just some of them can ramp up I can imagine. Who knows actually with all the secrecy and lack of accurate oil field data coming from some of the participants in the organisation.
1. The areal extent of the Permian Basin shale oil plays is quite large in comparison to other plays.
http://www.shaleexperts.com/images/Permian-Basin-Geology.png
2. The shale column in the Permian Basin is about 4,000 feet thick, whereas in the Eagle Ford and Williston Basin it is only a few tens or hundreds of feet thick.
3. There are at least seven productive shale zones (which have already been tested), and several more that have not been tested, stacked like pancakes, one right on top of the other, in the Permian Basin.
http://www.aogr.com/assets/images/content/4_0616_fig3_sp16.png
4. The stacked plays in the Permian Basin allow for economies of scale not offered by the other shale plays.
5. Improved drilling techniques have cut the number of drilling rig days needed from spud to finishing of drilling operations (that is, the cementing of production casing) substantially.
6. Post-2015 fracking techniques (Fracking 2.0 and Fracking 3.0) are producing far more prolific wells. Offsetting wells, with identical lateral lengths, and completed with Fracking 3.0 are producing almost twice as much oil as the pre-2015 wells completed with Fracking 1.0.
7. The Permian Basin, being a mature oil and gas basin, already has a great deal of existing infrastructure already in place, and is not too terribly far from the refinery complex on the Gulf Coast, as the Williston Basin is.
Leslie Wei writes:
Why on earth would anyone make that assumption, when there is an overwhelming amount of evidence indicating that it is false?
There are rivers of outside money pouring into the Permian Basin shale plays. Even the IOCs are now boarding the shale express, and in a big way. The shale party, folks, is just beginning.
Oil Giants Upending Shale Turf Where Wildcat Drillers Once Ruled
http://www.rigzone.com/news/oil_gas/a/148918/Oil_Giants_Upending_Shale_Turf_Where_Wildcat_Drillers_Once_Ruled
Chevron Pivots To Permian Shale As Mega-Project Era Fades
http://www.rigzone.com/news/oil_gas/a/149103/Chevron_Pivots_To_Permian_Shale_As_MegaProject_Era_Fades
Shale Drillers Are Outspending the World With $84 Billion Spree
http://www.rigzone.com/news/oil_gas/a/150055/Shale_Drillers_Are_Outspending_the_World_With_84_Billion_Spree
There seems to be increasing mention of Occidental being bought out by someone with extremely deep pockets. Owning over 2 million net acres, Oxy is the biggest leaseholder in the Permian.
Two points in following up on Glen’s post …
The productive footprint of the Permian continues to expand up into New Mexico.
The output from wells in many of the basins has significantly increased in the past 12 months.
More precise targeting, staying in zone near 100%, and diversion processes are the biggest reasons.
…aaannd, speaking of Oxy, they just loaded the first VLCC – Very Large Crude Carrier, capacity 2.2 million barrels – at their dock at Corpus Christi.
66 foot draft is too deep, presently, for the channel so 60% loading at dock and balance from smaller vessel when out in deeper water.
Cowboyistan.
That’s really exciting. So was their latest earnings report.
OXY -$0.69 / share
Oh and btw, EOG -$1.08/share
The plan would be to sell the acreage to some shale operator with more expertise at achieving profit, like Continental Resources.
CLR -$0.54/share
Red balance sheet ink doesn’t matter for shale companies – as long as there is a story. They’ll get new loans, or enough investors buying new stock.
Shale companies are like .coms in the 2000s – they are about the story, not paying big dividents. That’s what old oil is for.
If now everyone of big oil drills in perminal and abandones deep water and other long run projects – it’s a 0 sum game in global supply. Perhaps permian can get really 15 millions or more barrels a day, but without deep see and Alaska + other difficult projects, that’s not 1 barrel more in global supply.
And it will be the mother of all oil rushes, with not being able to see a piece of Texas without drilling towers.
Watcher,
Read it and weep.
I know the information I am providing is anathema for those who have been waiting around with baited breath for the last forty years, hoping to see the last gasps of the Age of Oil. But it looks like you might have to wait a bit longer for that longed-for event, maybe quite a bit longer.
It is also anathema to those like Mike and shallow sands, and OPEC and Russia, who with their conventional oil portfolios had hoped for the quick demise of shale. After all, if the cost to produce that marginal barrel is now $50 to $60, and it remains at that cost, there is little hope for an oil price recovery much above that price. Shale killed the price of oil, and may continue to do so for some time in the future. This is not what those vested in conventional oil had hoped for, and continue to hope for.
Occidental profit beats; shares fall on weak output forecast | Reuters: “Occidental Petroleum Corp’s quarterly profit beat estimates on Thursday but the company’s shares fell to a near eight-year low as the oil and gas producer forecast lower-than-expected production for the current quarter.”
No surprises there.
Oxy’s great vulnerability is that it is 80% invested in conventional oil, and only 20% in Permian Basin shale.
See the chart I have already posted below, and it becomes clarion why Oxy is being punished by the market.
It’s never been an easy chore to get these aircraft carriers turned around, to get them headed in the right direction. But to its credit, the management at Oxy is trying.
Oxy is still largely a conventional producer.
Permian EOR is conventional, not sure about South Texas. Non-US accounts for almost half of total output.
So Oxy’s 1Q results are not representative for the shale sector in general
And even within the shale sector there are large differences.
Pioneer Resources, for instance, with the biggest chunk of its assets in the Permian Basin (the best of the major shale oil plays), is a long shot from Continental Resources, with the biggest chunk of its assets in the Bakken (the worst of the major shale oil plays).
And Pioneer Resources, with the biggest chunk of its production being liquids, is a long shot from Devon, EOG, or XTO with half or more of their production being natural gas. The markets have not been nearly so kind to U.S. natural gas prices as they have to oil prices.
If one wants to paint shale as a failure, one therefore picks Oxy, XTO, Devon or Continental Resources to make their case.
If one wants to paint shale as a success, one picks Pioneer, Concho or Diamonback.
.
In fact, during the years of the shale boom, in 2011-14, OXY was one of the very few publicly traded U.S. E&Ps with positive free cash flow. All of those 3 or 4 companies had large non-shale operations. On the contrary, all pure shale players had significant negative free cash flows.
Alex,
So what?
Are things the same in 2017 as they were in 2011 – 2014?
Most of the giant oil companies seem to think they’re not, as they write off or sell their crown jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It’s called creative destruction, as older producing properties and techniques can no longer compete with the new ones.
And what does having “significant negative free cash flows” signify?
One of the things it can signify is that a company is investing heavily in new projects, which means the company believes it has attractive investment opportunities. That’s not always a bad problem to have, regardless of what the anti-shale polemicists would have us believe.
As Investopedia explains:
“[I]t is important to note that negative free cash flow is not bad in itself. If free cash flow is negative, it could be a sign that a company is making large investments. If these investments earn a high return, the strategy has the potential to pay off in the long run.”
Read more: Free Cash Flow (FCF) http://www.investopedia.com/terms/f/freecashflow.asp#ixzz4iakNBuWa
Follow us: Investopedia on Facebook
Glenn,
I agree that “negative free cash flow is not bad in itself”. The question is for how long
negative free cash flow is not bad?
Most shale companies had negative free cash flows since 2011 (already 6 years), having accumulated large debts. There was a short period in 2H16 when, due to sharply reduced capex, the shale sector was
free cash flow neutral. But recovering investments since 2017 will result in renewed period of burning cash (as evident from 1Q17 results). So how many more years the markets will tolerate shale companies’ negative free cash flows?
I personally think that the shale sector could remain cash flow neutral or even slightly free cash flow positive, especially with gradually rising oil prices. But that would imply very modest growth in capex, and hence in production. And that still does not solve the problem of repaying accumulated debt, unless shale companies sell part of their assets and/or issue new shares, diluting existing shareholders.
Exposure to shale operations has actually proven a burden for the U.S. oil companies’ financials
In Oxy’s case,from 2014 to 1Q17, domestic upstream operations were a negative contributor to the company’s earnings (unlike international oil and gas). Positive 1Q17 earnings were due to non-shale operations that offset a $122 million loss from the US oil and gas segment. For 2016 as a whole, U.S. oil and gas had a net loss of $999 million, while all other segments, combined, have shown net earnings of $493 million. The same is true for the large US integrateds, like Exxon, which consistently had negative earnings in its US upstream segment in the past few years due to shale exposure.
That’s the reality!
OXY’s segment earnings
click to enlarge:
AlexS,
How do you know those losses were attributable to Permian Resources, and not Permian EOR, or to Oxy’s other domestic upstream operations?
And if the Permian shale is such a horrible investment, why do you believe Oxy plopped down $2 billion to buy extra acreage in the Permian Basin last year?
Why do you believe Oxy has committed a full one third of its 2017 capital budget to drilling new wells in the Permian Basin?
Do you believe Vicki Hollub and the rest of the managment crew at Oxy are just stupid, and only you know what’s going on in the oil field?
Do you understand that new wells drilled during 2011 – 2014, whose drilling was justified when oil prices were $100, may not look like very good investments in hindsight, with an oil price of $30 to $50?
AlexS,
You say, “In Oxy’s case, from 2014 to 1Q17, domestic upstream operations were a negative contributor to the company’s earnings (unlike international oil and gas).”
Well, it’s mighty funny how you manage to gloss over that $4.445 billion loss that Oxy’s foreign O&G operations experienced in 2015. Because if we add it in, then Oxy’s foreign O&G segment from 2014 to 1Q17 also experienced a loss.
“how you manage to gloss over that $4.445 billion loss that Oxy’s foreign O&G operations experienced in 2015. ”
It was a one-time issue, and was due to asset impairment (non-cash item).
Generally, if you look at segment earnings of oil companies with exposure to both US and non-US upstream, most of them made losses in the US, but still had profits (albeit significantly diminished) in the international upstream segment.
AlexS,
You say, “It was a one-time issue, and was due to asset impairment (non-cash item).”
Like when ExxonMobil de-booked its entire pro rata 3.5 billion barrels of reserves in a Canadian oil sands project earlier this year, which amounted to 14% of its total reserves?
Believe it or not, these things are important, and can’t just be shrugged off.
And furthermore, something tells me that if it were shale assets being de-booked, you wouldn’t be so quick to shurg those off.
“Most of the giant oil companies seem to think they’re not, as they write off or sell their crown jewels of 2011 – 2014 (Shell, Conoco and Exxon have all done so with their Canadian sands, and as you point out Oxy did with its Bakken shale) and pivot towards the Permian shale. It’s called creative destruction, as older producing properties and techniques can no longer compete with the new ones.”
Glenn,
To make a sale someone must buy. Logic does not apply that the sellers are smart and the buyers are dumb at this point. There was a seller and there was a buyer and that is all that we can say about oil sand deals. We don’t know the real reasons for these sales. It is just interesting that all deals with oil sands with majors happened in downturn and that all buyers are Canadian companies.
And there is nothing creative about Shell, Exxon, Conoco acquiring all these oil sands properties at inflated prices when oil was at north of $100 during 10 years span and selling all at ultimate bottom when price at one point was $26.
coffeeguyzz,
I too have heard the rumors that Oxy is a takeover target, but up until this moment it is Oxy that has done the taking over:
Occidental Petroleum buys Permian Basin acreage for $2 billion
http://www.reuters.com/article/us-occidental-m-a-permian-idUSKBN12V2CK
The problem with Oxy as a takeover target is that only a small portion of its producing asset porfolio is composed of Permian Basin shale assets.
So here’s the rub: if one wants to buy the Permain Basin shale acreage, one has to buy all the non-Permian Basin stuff too, as well as the Permian EOR stuff. These are not very attractive takeover targets in the current price environment. They are money losers with little growth potential.
Of Oxy’s total worldwide production in 2016 of 630,000 BOPD, only 124,000 BOPD, or about 20%, came from Permian Resources (Oxy’s business unit that operates its non-EOR Permian Basin properties). The other 80% came from Oxy’s international operations, its Permian EOR operations, and its South Texas operations.
Oxy is working furiously to correct this situation. There is, for example, the 2016 acquisition of Permian Basin acreage like the one linked above.
And in 2016, Permian Resources drilled 63 horizontal wells in the Permian Basin which added 92 million BOE to Occidental’s proved reserves ( see 2016 annual report: http://www.oxypublications.com/annualreport/PDF/2016/OXY_2016_10-K.pdf ).
Oxy plans to drill even more wells in the Permian in 2017. According to the 2016 annual report, “In 2017, Occidental expects to allocate approximately one third of the 2017 capital budget to Permian Resources for focused development areas in the Midland and Delaware Basins.”
Nevertheless, this chart from Oxy’s 2016 annual report amply tells the story.
As can be seen, Permian Resources is one of the few bright in Oxy’s portfolio:
https://s16.postimg.org/c8zbs0u2t/Captura_de_pantalla_942.png
Oxy breaks down EPS by segments.
For Q1, 2017:
US upstream -$191 million
Foreign upstream $418 million
Chemicals $170 million
Marketing and Midstream -$47 million.
The above are pre-interest and pre-tax. Oxy paid quite a bit in foreign taxes, received a large US tax benefit due to US losses, and paid over $70 million in interest, a good chunk being on debt incurred by spending in excess of cash flow on US unconventional in 2010-2014. OXY lost a good chunk of change in the Bakken and completely left the area including a multi-million $ regional headquarters they had just built in Dickinson, ND. Took a big write down on it.
I have looked a OXY Permian unconventional wells. Many pre-2016 were bad, sub 100K BO to date. I assume they are getting better, like the rest of the Permian.
If I am not mistaken, XOM, CVX and COP made positive EPS other than in US upstream in Q1, 2017. CLR broke even, PXD posted a small loss, EOG posted small net income.
FANG and XEC were outliers with strong EPS, but upon closer look, these numbers were aided greatly by low DD&A per BOE, as both elected to not place substantial CAPEX on DD&A yet.
Although I’d like $55-65 WTI, can live with $45-53. We will see how many years it takes for Permian to top out, akin to Bakken and EFS. Could take awhile, given land area. Will take awhile to see how much of the Permian is “good”.
Data on OXY hz Permian wells.
I looked under both OXY and OXY WTP.
504 with first production months of 1/10-3/17.
Best to break them into groups, as wells have improved over time.
1/10-12/13
70 wells.
3 with cumulative production of 200,000+ BO.
69 with daily production averaging under 100 BOPD 3/17.
1/14-12/15
291 wells
30 with cumulative production of 200,000+ BO.
214 with daily production averaging under 100 BOPD 3/17.
1/16-3/17
143 wells
10 with cumulative production of 200,000+ BO
61 with daily production averaging under 100 BOPD 3/17.
Also, note GS comments above that maybe OXY is losing boatloads on EOR. Wish our old Permian EOR friend MBP would chime in on that. I am sure 2015-2016 were not banner years for EOR, but not sure about big time losses.
I would suggest looking at OXY’s 2003-2004 10K and 10Q to see how domestic production was faring financially. I am sure operating costs are up since 2003-2004. That era would be a good comp oil price wise to 2015-2016. EOR was a decent part of OXY domestic production in those years. I know OXY had a lot of domestic gas then, plus CA, so maybe not the best comparison.
If no one else looks at OXY 2003-2004, I will try to when I get time.
Lordy, lordy, shallow sand, where did you come up with your “data”?
You say Oxy brought 143 Permian Basin horizontal wells online between 1/16 and 3/17.
But Oxy’s 2016 annual report says it completed 63 Permian horizontal wells in 2016.
And Oxy’s 1st quarter 2017 earnings release (see the slides) says it brought 21 Permian horizontal wells online during the first quarter of 2017.
That’s a total of 84 horizontal wells Oxy completed in the Permian Basin for the period between 1/16 and 3/17. So where did your source come up with the additional 59 wells it claims were brought online during that period?
IHS Energy.
I looked at that again. 48 of the 143 wells were Hz San Andres wells in West Sundown Unit, Slaughter Field, Hockley Co, TX. These are Permian Hz wells, but I agree those should be excluded from the analysis as they are much shallower and cheaper wells to drill.
That gets us to 95 wells, which is pretty close to the number you set forth from their reports.
What do you think about Oxy drilling so many Hz San Andres wells?
Of further note, the same database shows 107 vertical wells of Oxy with first production 1/16-3/17. Again, the majority in Slaughter Field, West Sundown Unit.
I may be mistaken, but isn’t that a large, over 1 billion barrel cumulative field that is mostly under CO2 flood? Interesting there was all that activity in an “EOR” area during that timeframe.
GS. Glad you questioned me about Oxy. I find that there were 1,397 vertical wells put on production in the Permian Basin from 1/16-3/17.
Most of the big names. XTO put on 70, mostly in Fullerton and Means. Chevron put on 48. I also saw Pioneer, Parsley, Apache, Encana, Matador and many other companies I have heard of. Others I have not. Looked like a mix of Spraberry Wolfcamp, along with San Andres, Grayburg, Clearfork, Seven Rivers, Devonian and other formations.
I assume on the Spraberry and Wolfcamp, maybe some verticals drilled to hold leases. But, I saw Summit and Henry both drilled verticals, as I recall they were big private companies that drilled a lot of the vertical commingled Wolfberry wells before oil crashed in late 2008. I think Henry Petroleum sold out at the peak in late 2007 or early 2008.
I highly recommend IHS Energy US Data online, if one wants to spend some $$. Shaleprofile.com is the best free data I have found, but it is limited to LTO wells. Can’t say enough how much I appreciate Enno’s work on shaleprofile.
shallow sand,
Pioneer Resources had a graphic in one of its annual reports a few years back that illustrated the history of Spraberry/Wolfcamp completions in the Permian Basin.
There aren’t too many people drilling conventional vertical wells in the Spraberry/Wolfcamp any more, because the economics of these conventional wells are so poor in comparison to the eonomics of the horizontal shale wells that operators just don’t bother with them any more.
And of course what’s going on in other formations (e.g., Grayburg-San Andres, Devonian or Ellenburger, etc.) has absolutely nothing to do with what’s going on the in the Spraberry/Wolfcamp.
I would add that there is nothing cheap about producing oil from EOR projects, and the drilling of many new wells is a requirement.
https://www.google.com/finance?q=oxy&ei=GVcuWcD8FcKd2AbAy7aYDg
That’s the OXY quote as of today on finance.google.com. Reading 69 cents/sh loss.
Odd they’d be out of date, or maybe they report GAAP.
IEA, download the free executive summary of our 5 year oil market report
IEA’s direct link (pdf file): https://t.co/mQA8eg0vPR
IEA’s estimate for demand growth, chart on Twitter…
https://pbs.twimg.com/media/DA8NSgHV0AA2H0T.jpg
“IEA, download the free executive summary of our 5 year oil market report”
It was available for download since early March here:
http://www.iea.org/bookshop/740-Market_Report_Series:_Oil_2017
I have a question for anybody knowledgable concerning the Permian. The map below is from the Texas RRC GIS of an area just south east of Midland, pretty much in the middle of both Wolfcamp A and C. The USGS gave most likely untested proportion of 85% for A and 77% for C, and expected success ratio in those areas (i.e. non-dry hole) of 95% for A and 70% for C. But I look at that map and see some production wells (admittedly vertical) surrounded by a perimeter of dry holes and abandoned or cancelled permits (very similar to the Bakken in a lot of places) and then nothing but a few undrilled permits dotted about. My conclusion would be, not that there is a lot of oil in the bare spots just waiting to be found in 19 out of 20 wells as the USGS seem to assume, but that there is nothing there, and that the drillers just drilled out until they hit dry sand and understood the geology enough to stop spending any more money. A lot of places in the Permian area look like this when you zoom in. What’s the alternative that USGS, or whoever gave USGS the info. to model, are proposing?
George,
Is that possible to identify how old are those dry holes?
Which part of them were targeting conventional reservoirs before the shale boom?
George Kaplan,
Those wells are in the Howard-Glasscock Field. The field is part of the Eastern Shelf San Andres Platform Carbonate play.
The Howard-Glasscock Field was discovered in 1925.
The wells are completed in the Grayburg-San Andres formation, which is found at a depth of 2,000 to 3,000 feet.
The wells have nothing to do with wells completed in deeper formations (e.g., the Wolfcamp).
.
Thanks – if I may ask a couple of more clarifications, is this general over the Permian, with lots of layered reservoirs? What was the source rock for the shallow fields’ oil, e.g. in places could it come from the deeper tight reservoirs? What happens when there’s a need to drill, say, another two horizontal wells for the LTO in the same area where there is an operating shallow field?
George. I am not in the Permian and own nothing there, so would defer to those who are/do.
It is very common in the Permian to have severed ownership of different productive zones on the same acreage. For example, as majors and large independents divested leases/units producing from the Queen, San Andres, Grayburg, and other shallower zones, the divesting companies routinely reserved their interests in the deeper zones.
This occurs in most mature basins in the United States. We do not own the “deep rights” in some of our leases, as they were reserved when a large independent sold to a predecessor in interest to us. On one lease, we have continued to produce the same two wells, that were completed in the 1950s, while a larger company acquired the deep rights, drilled several wells, including two about 50′ away from our two wells. We own from the surface to the base of a shallow sandstone formation, the other company owns the rest.
Looking at both IHS Energy data and shaleprofile.com leads me to believe there are areas where the LTO zones are not so hot, assuming that is what you are driving at. As companies have delineated their acreage, they have tended to drill infill wells on strong leases. Just like there are areas in the Bakken and EFS that are not “premium” the same appears to be the case in the Permian.
One example of high grading in PB would be Pioneer Natural Resources USA. 252 Hz wells with first production 1/16-3/17. 42 of those on Hutt leases, 22 on Sale Ranch, 23 on Brook leases, etc. Clear PXD has identified strong areas and is drilling and completing several wells per pad. I suspect this is commonly what is occurring. If you look back to 2010-2014, you will see a lot of single well leases that were weak. I assume companies will head back to those areas later and try larger fracs and longer laterals if the have the acreage “blocked up”.
A poignant question, Mr. Kaplan. Source beds for prolific fields in the Midland Basin are underlying organic-rich shale or shaley carbonate beds. Oil “baked” in these ovens, so to speak, migrated upwards into overlying structural, stratigraphic/ facie change traps like the one you have identified in Howard County; Howard Glasscock Fld. produces from the Glorieta and Clear Fork, mostly, on 20 acre spacing requirements. Those source beds for this field are the Wolfcamp and Woodford, etc. This field has produced 118M BO, by the way. There are hundreds of fields like this in the Permian Basin that have historically produced tens of billions of barrels of oil.
Are the source beds under and/or near these prolific fields still loaded with oil and ready for $10M dollar HZ well that will recover 1M BOE EUR’s? Doesn’t look like it in densely drilled areas of vertical Spraberry wells, not by realized production data. It most certainly is NOT true in the Giddings Fld. of Central Texas where thousands of Austin Chalk wells produced several billion barrels of oil sourced from underlying, organic Eagle Ford shale.
So to calculate the OOIP per acre foot of source beds over a vast areal extent and claim there is 20B, 40B, the Atlantic Ocean barrels of oil still in these source beds is bad science and a misrepresentation of America’s last remaining oil reserves.
Mike. What do you think about the fact that companies are drilling vertical Spraberry wells in addition to horizontals?
I assume it is not an easy thing to drill hz wells in an area where there are already a lot of vertical wells producing from the same zone.
Pioneer operates over 6,000 vertical Spraberry wells. What were the spacing requirements for these? I don’t read about these often, but assume they take up a significant part of PXD’s acreage in the Permian?
You get my last comment, Shallow: I drilled some vertical Spraberry wells in my day; I don’t recall making much, if any money from them at all. Costs are 100% higher, or more, from when I drilled those wells; I have no idea what they are doing out there, or why. Source beds deplete over geological time thru migration, that then gets produced from shallower reservoirs. Its a finite thing some people can’t seem to grasp.
In the well control business we often used magnetic resonance imaging in relief well intersections; that is the ability to zero in on iron downhole, like casing. They use the same technology off Long Beach in California, for instance, to avoid other well bores when they are snaking deviating wells thru the maze. Wells drilled off land into South Bay out there look like a bowl of spaghetti. I heard a rumor that PDX was doing the same thing with it’s HZ wells in the middle of all those vertical Spraberry wells, though I cannot confirm that. For what? To earn a 115% return on their capital investment?
For the record $45 dollar oil prices may make a lot of those guys out there cash flow neutral, or even slightly positive, but to keep doing what they are doing they are kicking old debt down the road, for other people to deal with later. People do stupid things with other people’s money.
Keep a bind on it, Shallow.
Cash Flow Includes Borrowing.
If you sold not a single barrel of oil, paid your people and had other expenses of $20 million, and borrowed $20 million that period, then you are cash flow neutral. If you sold no oil, had expenses, and sold assets, that’s also cash flow neutral.
Cash flow is just something hypesters quote to show that burn rate isn’t going to fold the company soon.
Free cash flow = cash flow from operating activities – capex.
It does not include borrowings
Mike said:
FALSE.
Wells in the Howard Glasscock Field produce from the Yates, Seven Rivers, Queen, Grayburg, and San Andres reservoirs. The Glorieta and Clearfork are located well below the producing zones of the Howard-Glasscock Field.
See, for example, this report from the USGS:
https://pubs.usgs.gov/fs/2012/3051/fs2012-3051.pdf
Mike said:
FALSE.
According to a report published by the Bureau of Economic Geology, the Howard-Glasscock Field had produced a cumulative of 432,182,615 BO through the end of FY2000.
Here’s a link to the report:
http://www.beg.utexas.edu/resprog/permianbasin/pdfs/PA_FinlRpt.pdf
Mike said:
The typical Permian Horizontal well no longer costs $10 million dollars to drill.
Costs have come way down.
Here’s what Occidental Petroleum reports it costs to drill their average horizontal well in the Permian Basin now, from their 1Q2017 earnings release:
Mike said;
Most oil professionals –those who have actual knowledge of the Pemian Basin — would roll their eyes over this comment.
Take, for instance, what Chevron’s chief executive, John Watson, had to say about the Permian Basin shale play:
View what corporate execs say with a bit of skepticism. They say what sounds good to Wall Street.
George Kaplan,
To answer your questions:
1. Is this general over the Permian, with lots of layered reservoirs?
Yes.
2. What was the source rock for the shallow fields’ oil, e.g. in places could it come from the deeper tight reservoirs?
Here you go:
3. What happens when there’s a need to drill, say, another two horizontal wells for the LTO in the same area where there is an operating shallow field?
There’s problem at all. The laterals of the deeper wells are thousands of feet below the shallower wellbores.
XOM – Potential 2nd Downgrade – unless APPL or Bazos jumps to the rescue. / sarc
“However, unlike its peers such as Chevron and BP, Exxon Mobil is not targeting meaningful growth in production. Although Exxon Mobil is working on a number of shale oil, conventional oil and LNG projects which will come online in the near term, they will largely help the company in offsetting the negative impact of field declines and asset sales — Shell, Chevron, and BP carry debt loads of $91.6 billion, $45.3 billion and $61.8 billion, respectively. ”
https://seekingalpha.com/article/4077223-exxon-mobil-make-s-and-ps-warning
XOM and the conventional majors face what they’ve faced relentlessly for many years now — the IOCs have all the reserves. Statoil, Rosneft, PetroChina, PetroBras, S Aramco . . . they scooped it all up. Nothing left for Exxon and Chevron etc.
err NOCs
TROUBLE BREWING FOR OPEC AS ONCE COSTLY DEEPWATER DRILLING TURNS CHEAP
WorldOil has this article, citing a come back for deepwater and lots more supply.
http://www.worldoil.com/news/2017/5/30/trouble-brewing-for-opec-as-once-costly-deepwater-drilling-turns-cheap
Over the next three years, eight offshore projects may be approved with break-even prices below $50, according to a Transocean Ltd. presentation at the Scotia Howard Weil Energy Conference in New Orleans in March. Eni SpA could reach a final investment decision on a $10 billion Nigeria deepwater project by October.
First off they seem to have forgotten that it takes at least 3 and more like 5 to 6 years between sanction and first oil for deepwater so I doubt if OPEC are even thinking about them (in fact the OPEC CEO gave a speech recently bemoaning the lack of such investment); second, eight projects in three years is really not very many; and third the projects they are discussing, I think, are from the slide of TransOcean’s below, which is from Rystad data. Of the eight lower cost projects six are already operating and some for a few years (Stones, Heidelberg, Lucius, Tahiti, Mars, Thunder Horse), and Appomatox has been in development for a couple of years, so only North Platte might be new – and I think would be a medium sized semi-sub or maybe just a tie-back.. I guess Tahiti had plans for some upgrades but I think the project was stopped late last year with a few redundancies (and the contractor may have gone bust), Thunder Horses South has started, there is Heidelberg phase II to come, but none of these are large projects with major new production (mostly they just cover declines in other fields feeding the facilities). Of the other five more expensive projects: Logan has been abandoned by Statoil (lease expired, Statoil has left GoM); Buckskin – much downgraded as it was part of the Moccasin project, which has been cancelled; North Hadrian – lease expired for ExxonMobil, may be some production to Lucius; Mad Dog II – approved so OPEC know all about it; Shenandoah – seriously downgraded from original expectations.
I don’t know what the TransOcean investors would have made of it all, but surely the reporter should make some effort to get to the bottom of this stuff. And why is Rystad still carrying all these projects with apparently equal weight?
All those projects are in the GoM where, so far, this might be the slowest year ever at BOEM (or MMS as was). Last year there were 5 new discoveries, 9 new qualified lease, 8 new fields in production, 4 new leases in production and 16 expired leases; this year so far, respectively, 0,0,0,0 and 1. Maybe they take a few months to work through the system, but news of discoveries and new projects would suggest there’s not that much more to come.
A few charts that are in the news today…
Libya’s oil exports. According to Reuter’s tanker tracking their exports have been steady since the start of the year at around 0.5 million barrels per day
https://pbs.twimg.com/media/DBI7nTSXUAA4xta.jpg
Bloomberg’s chart for global oil demand, estimating the effect of efficiency gains & EVs
https://pbs.twimg.com/media/DBJLrkaUIAAgezm.jpg
https://www.bloomberg.com/graphics/2017-oil-projections/
China’s crude oil imports vs $WTI starting 1999. From Zero Hedge
https://pbs.twimg.com/media/DBHcZIDXgAAbliF.jpg
Generic envirowacko wishful thinking.
Just wait for the data.
If you look at that chart of China oil imports- they grew from 29 to 39 (what units?) in just 3 years.
Demand growth/domestic depletion in action.
China crude imports, units on that chart are: 1,000,000 tons per month (I hope that I’ve counted the zeros correctly)
A chart with a 7.32 barrel/ton conversion (the same as JODI Data uses)(Data from China’s General Administration of Customs)
Hi all,
New post up
http://peakoilbarrel.com/world-crude-plus-condensate-and-conventional-oil/
Also a new Open Thread.