Guest Post by Willis Eschenbach
Well, having had such a good time with M. King Hubbert meeting the EIA, I thought I’d toss out another puzzle. This one is inspired by a statement from the King himself that someone quoted in that thread, viz:
“A child born in the middle 30s,” Hubbert told reporters, “will have seen the consumption of 80 percent of all American oil and gas in his lifetime; a child born about 1970 will see most of the world’s [reserves] consumed.”
Since M. King Hubbert was concerned about how most of the world’s reserves were going to be consumed, I thought I’d see how much of the US reserves have been consumed over the last third of a century. It’s an interesting answer …
Figure 1. A comparison of the annual estimates of the US proved oil reserves (red line), and the US cumulative oil production (blue line), for the period 1980-2012. Data from the 2013 BP Statistical Review of World Energy. “Proved reserves” in the dataset are defined as follows: “Proved reserves of oil – Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions.”
It appears that since 1980 we’re totally out of luck. First we completely used up every drop of the proved reserves.
Then we used them all up again. Then we used them all up for a third time … and the proved reserves are still about where they started. Go figure.
Since the King was also concerned about using up the US and global natural gas reserves, I thought I should look at that as well.
Figure 2. A comparison of the annual estimates of the US proved gas reserves (red line), and the US cumulative gas production (green line), for the period 1980-2012. Data from the 2013 BP Statistical Review of World Energy.
Well, it’s about the same story. We started in 1980 with 6 trillion cubic metres of proved reserves of gas. Since then we produced almost 18 trillion cubic metres, about three times our original reserves. The main difference between the gas and oil is that the proved reserves of gas are about a third larger than they were in 1980 … go figure indeed.
I bring this up for a simple reason—to show that we don’t know enough to answer any questions about how much oil and gas we’ve used, or to determine if the King was correct in his claims. According to all the data, since 1980 we’ve used three times the proved reserves of oil and gas, and despite that, the proved reserves are the same size or larger than they were back in 1980. So how can we decide if Hubbert was right or not?
Now, please don’t bother patiently explaining to me all of the reasons for this curious phenomenon, because I’ve heard them all. I assure you, I understand the difficulties in estimating proved reserves, and the fact that the numbers come from the oil companies, and that technology improves, and that the companies tend to explore until they’ve got maybe twenty years in the bank, and the fact that the reserves numbers are sometimes radically revised, and that economics plays a huge part, and the rest … I know all the reasons for what I showed above.
I’m just pointing out that it is very, very hard to say what will happen to future reserves, or what their total extent is, or how much recoverable energy the world contains.
The underlying problem is that the proved reserves represent the amount of economically recoverable gas and oil … and that, of course, depends entirely on the current price and the current technology. In other words, the amount of “natural resources” in the world is not really a function of the natural world—it is a function of human ingenuity. For example, in the 1930s, the big concern was “peak magnesium”, because the proved reserves of magnesium were dropping fast. Or they were, until a clever chemist realized that you can extract magnesium from seawater … at which point the proved reserves of magnesium became for all purposes infinite.
Now, did the natural world change when the proved reserves of magnesium went from almost none to almost infinite? Like I said, the amount of natural resources depends on human ingenuity, and not much else.
Best regards to all,
w.
PS—Again, if you disagree with something that I or someone else said, please QUOTE THEIR EXACT WORDS and state your objection. That way we can all understand just what you are objecting to, and the nature of your objection.
Sorry if I offended you Willis, as I am a big fan. It is only that proven reserves and extracted assets are two entirely different things, and that is the reason I find it peculiar that such a composite chart is shown. I believe you try to make a mockery of my previous comments (sorry, not native english speaker), but your examples can be easily be countered. The way one would count proven reserves against extracted and newly discovered reserves, would not be a case of adding the given reserves for consecutive years. It would be an accountancy where proven reserves would be discounted by the extracted amount, and finally, newly discovered resources would be added to the remaining proven reserves.
Still, if you find my suggestion ridiculous, I recommend you choose a different benchmark when showing the folly of projections vs. expectations. Proven reserves does not make much sense, because the entire fossil community may have expected a continual rise in projections. What would make a greater impact, would be the projections of accepted papers on the subject, in which you could show that the expected total have been broken time and time again.. 🙂
HLx says:
January 14, 2014 at 8:39 pm
No offense taken, HLx. As I said, I just found the idea of “cumulative proved reserves” to be something I couldn’t understand.
They are very different things. However, many people don’t know that. As a result, they look at the extraction rate, and they look at proved reserves, and they go “YIKES! We’re running out of oil!”.
So as the title suggests, I thought that I’d have some fun. I thought I’d demonstrate, in the clearest way that I could, that the fact that the proved reserves are small does NOT mean that we are running out of oil. I demonstrated that by showing that since 1980, we’ve extracted three times the proved reserves, and we still have the same size proved reserves.
My best regards to you, HLx, and your English is excellent.
w.
Pathway says:
January 14, 2014 at 10:22 am
I have 1,500,000,000 barrels sitting in my back yard. It is generically known as oil shale. Estimates go as high as 40 barrels to the ton in the high grade Mahogany zone.
—————————————————————————————————–
Tough to make that one work— there are only about 7 barrels of pure oil in a metric ton
vangelv says:
January 14, 2014 at 9:15 am
Well, thanks for the good word. Here’s the record for North Dakota Bakken Formation shale oil wells.
I see that you are all exercised by the change from 142 BPD to 132 BPD. But when you look at the longer term record, you can see that this is the range it has been fluctuating within for the last five years, up and down and up and down and up again … so I don’t find it worrisome.
Also, here’s the record for new wells in the Bakken:
As you can see, the production per new well continues to climb.
Finally, you keep claiming that people are not making money on the Shale oil play, viz:
I’m sorry, but oil companies are not stupid. If the cost of production gets larger than the return, they SHUT DOWN. Your idea, that the companies are selling oil that costs them more to produce than the sale price, doesn’t even pass the smell test. I asked you above for a citation to back up this cockamamie claim … so far I have nothing but handwaving at Chesapeake Energy. Now, you may be all bearish on Chesapeake, and indeed you may be 100% right … but the market certainly didn’t get your memo, it hasn’t noticed your concerns …
So I’m left with no evidence that the companies are stupidly losing money on shale oil … and lots of evidence that they are making money. See the red line in the first figure, showing new wells? Are you seriously claiming that they are lining up to lose money?
w.
There are a few issues I have with your statements. I will cover them one at a time.
Let me begin with the HLx statement (January 14, 2014 at 8:39 pm), “It is only that proven reserves and extracted assets are two entirely different things, and that is the reason I find it peculiar that such a composite chart is shown.”
Your response was, “They are very different things. However, many people don’t know that. As a result, they look at the extraction rate, and they look at proved reserves, and they go “YIKES! We’re running out of oil!”.”
There are so many problems here that I have trouble figuring out where to begin. But let me give it a shot by starting with the comment that individuals that are knowledgeable of the ‘Peak Oil’ theory do not claim that we run out of oil. They simply point out that we will reach a production peak and that once that happens we will have less and less oil produced each year.
That is a minor point compared to a much larger one that is totally ignored in the mainstream media as well as the analysts who provide most of the talking points. What matters in the natural resource game is the transformation of inferred mineral resources into proven reserves. For most sectors there are strict rules about how that happens. If I am a small junior looking for copper I begin by staking out a property, exploring, drilling, coming up with a pre-feasibility study, doing further drilling, metallurgical testing, etc., until I can produce a bankable feasibility study that will provide me with access to capital. These steps all help to move inferred resources into a proven reserve category that allows me to get a positive return.
The oil and gas sector has very similar rules. Companies need to perform a number of activities before they move resources into the proven reserve category. All petroleum analysts know this and understand that the reserves are always understated since there is no need to do all of the work necessary to book them before they are ready to be produced. THIS IS THE REASON WHY MANY UNDERGROUND MINES HAVE ALWAYS 2-3 YEARS OF RESERVES THROUGHOUT A LIFETIME THAT MEASURES TO THE CENTURY MARK.
If I have a field in a conventional reservoir I do not need to keep drilling past the boundary until I need the production the same as if I am following a vein of gold bearing quarts I do not need to drill more than is necessary to plan my next year or two of production.
The trouble is that these rules were waived for shale producers. They can book reserves even though they have failed to produce a profitable product or do all of the necessary testing to prove that the average well in the formation is productive. This was done so that the fledgling industry could get access to capital. The trouble is that without a sound methodology it is easy to have misleading information that claims reserves even though extraction is not economic.
I will continue my comments on the next posting.
Willis Eschenbach says:
January 14, 2014 at 9:48 pm
“I see that you are all exercised by the change from 142 BPD to 132 BPD. But when you look at the longer term record, you can see that this is the range it has been fluctuating within for the last five years, up and down and up and down and up again … so I don’t find it worrisome.’
But you are the math guy. If I triple the number of wells by adding new ones that show initial production rates of around 450 bpd how can I fail to raise the average production rate UNLESS there is a huge decline rate? Note that the massive increase in production came from the huge investment in the drilling of very expensive wells. That is not a positive unless those wells can pay for themselves. And from what I see in the 10-K statements they can’t because the shale producers are not capable of self financing shale operations unless they get cash from other sources.
“As you can see, the production per new well continues to climb.”
Longer horizontals will do that. But notice that the new, higher IP wells cannot get the average to go up? This would not be a problem if we started off with a very high number of shale wells and the number of new wells is small but that is not the case. As I wrote above over a 24 month period we saw the number of operating wells go from 2981 to 6643. This means that an increase of more than 100% led to a decline in average well production even though the new wells have a high IP rate. Your math is far better than mine. What kind of depletion rate do you need to observe these results?
And while you are at it, if we begin at an IP of 500 bpd and follow the depletion curve down what kind of revenue do we get when we integrate the daily production? After you account for the drilling costs, the land acquisition, overheads, etc., and after taking into account the royalty of 20-25% or so how do you ever make a profit by producing shale oil that sells at $95 a barrel? Since high IP rates but a low average means that you get most of your cash in the first two or three years why can’t the producers self finance? And what do you think happens when they run out of drill prospects in the prolific core areas and move to the marginal part of the formations?
“I’m sorry, but oil companies are not stupid. If the cost of production gets larger than the return, they SHUT DOWN. Your idea, that the companies are selling oil that costs them more to produce than the sale price, doesn’t even pass the smell test. “
Who said that it is stupid to produce shale oil at a loss? If I were a CEO of a tiny player I could make more in two or three years by selling off shares than I could in three lifetimes as a geologist or in middle management at a conventional player. You are under the impression that taking actions that are ultimately terrible for your lenders and investors is stupid but a series of bubbles have shown otherwise.
If you are in Toronto during the first week in March come to the Prospectors & Developers Association of Canada conference and I can show you hundreds of CEOs who will explain patiently how they got wealthy while most of the companies that they worked for went bankrupt. Note that these guys tend to be in the business for decades and more than 95% of the companies that they worked for went under.
“I asked you above for a citation to back up this cockamamie claim … so far I have nothing but handwaving at Chesapeake Energy. Now, you may be all bearish on Chesapeake, and indeed you may be 100% right … but the market certainly didn’t get your memo, it hasn’t noticed your concerns …”
The market did not agree with my bearish assessment of Nortel either when I pointed out that during a massive bubble in tech spending the company failed to make a true economic profit. Like the shale producers Nortel was not depreciating assets quickly enough and wound up writing off large parts of its balance sheets. The shares ran from the high $60s into the $120 range or so (Canadian dollars) before collapsing to under $1.00. The funny thing was that the annual reports were showing that the company was worth $0.60-$0.80 when it was selling for $80. Nobody paid attention because everyone is a momentum player these days. While that is fine if one is a speculator these postings should be about longer term fundamentals so it might make more sense to stick to reality.
PS. Perhaps you, me, and some other readers on this fine site should position ourselves for the next bubble. I am sure that after this latest bubble bursts we could make a fortune selling investors on the merits of methane hydrates as the next possible energy solution. While there are some serious technical issues they are nowhere near the level of what shale producers have to overcome.
A final comment, vangelv. It is true that the fracked wells decline quickly. A typical well that comes in at 500 barrels per day declines typically like this:
Initial, 500 bbl/day
End Year 1, 150 bbl/day
End Year 2, 99 bbl/day
End Year 3, 76 bbl/day
End Year 4, 60 bbl/day
However, this can obviously still be quite profitable, as shown by the number of people getting in on the game. All this does is change the decline cure analysis which is routinely done for all wells, q.v.
w.
@Leopold Danze Morgan:
January 14, 2014 at 7:52 am
Such a pleasure to read such a response normally I get nothing about irrational emotional responses to my arguments… let me clarify a few things to mentioned
” My view differs in that I see the price point as a function of technology.”
We’re not in disagreement here at all, I agree with this statement and if indeed a technology breakthrough will happen that will dramatically reduced extraction costs my view will change…
“and the crucial point is they have all been higher than comparable costs for fossil fuels.”
This is have to disagree with, numerous levelized cost studies have shown new wind and solar installation are fast equalling and in some countries are lower than new coal and gas and easily nuclear…
“Of course, the economic case for renewables will make a substantial change when or if we ever develop a vastly improved electricity battery.”
Yes I agree wind and solar are intermittent and this is a major issue, however, we’ve always had backup electricity, coal fire plants go down all the time, hence in a real sense they too are unreliable. However, these issues are not insurmountable, Spain has recently hit 50% renewables penetration, Germany is also an example as is South Aus with also have high renewables penetration, clearly – while problematic indeterminacy is not that much of an issue as evidenced by these cases.
I believe the integration of electric cars into the grid will create a storage buffer – but not for over night – I mean just for that 2-3 hour peak before and after the solar peak, base load will still be needed but clearly much more renewables can be easily be integrated, hence there are no barriers to entry for renewables here
What’s fascinating to me is how to solve the issue of who gets to sell power at specific times… for example I think it’s not really fair on fossil fuel generators to mandate they shut down to accommodate high solar and wind output…
On the other hand given a free market where anyone can sell to the grid at the lowest price fossil fuel generator can act uncompetitive and simply drop prices to shut solar and wind during those times and increase prices during non- solar and win times…
Hence how do you solve that issue? You can’t use free market, and it’s not fair governments mandate renewables, I can’t get my head around how to solve this to keep both parties happy
richardscourtney says:
January 13, 2014 at 4:15 am
Yes I read this, however I felt no reply was required as your seemingly confident assertions are simply out of date, and can easily be disproved by example – you talk about indeterminacy and how intermittent forms cannot have high penetration without introducing issues into the grid (but you do not specify a maximum % penetration)
Yet the examples of Spain (which has recently hit 50% renewables penetration, Germany and South Aus show high renewables penetration.
Clearly your denial of big foot (just for an amusing example) is disproved when big foot walks up to you and shakes your hand!
People here say electric cars can never work due to battery storage issue, yet Tesla cars is doing just fine! The cars work just fine and I dare say will be a saviour to base load fossil plants.
People here seem to be stuck in the past – like Willis which seems to think “cheap energy is a saviour to the poor”, sure i agree with the literal mean but not the implied meaning, i.e. that the form of this energy is cheap oil – cheap oil is starting to become an oxymoron, and will be so more and more over the next 50 years
Oil production in a given oil field with a given technology increases and then decreases. e.g. see Rise & Decline of UK Crude Oil
Increasing resource must come from finding new fields, or developing new technologies to access new hydrocarbon resources, or extract more from the same resource.
Eventually we have to develop fuels from nuclear/solar.
Vangel Vesovski says:
January 15, 2014 at 10:55 am
Vangel, regarding the shale wells, no matter what I say, you keep coming back with the same thing—shale wells have a high “decline rate”, they lose production faster than regular wells.
But since I posted that myself, and (unlike you) provided figures to back it up, why do you keep repeating it? Yes, they decline faster, I said that, you said that … so what? My problem is with your claim that the shale plays are uneconomical. Whether a well is economical has little to do with how fast they run out. If you invented a new well technology that could pump an entire field dry in one day … would that mean the well was uneconomical because of a high decline rate? No way. Either a well makes money for their owner/operators, or it doesn’t. Either they figure the decline rate properly, or they don’t.
And to date, the shale oil wells do make money for their operators, and lots of it. That’s why the red line showing the number of wells drilled is going vertical.
Now, I see that you claim that a significant number of the shale oil companies are deliberately cooking the books and defrauding their investors, viz:
However, just like the rest of your claims, you haven’t provided a scrap of substantiation for that claim either. I’m sure you could find a few companies doing that, but your claim that the shale oil play is a result of companies cheating their lenders REQUIRES CITATIONS, and a whole pile of them, to be believable. Yes, there are shale companies that are gaming the system as I discuss below … so what’s new? A certain percentage of companies always game any system.
Next, you say that:
Well … in a word, no. You’ve got the basic idea but your details are all wrong. There were no rules waived for shale produces. What happened was a change in the rules that applied all across the oil and gas industry, to every producer. It didn’t waive anything. Instead, it created an entirely new class of reserves, called PUDs, for “proved undeveloped” reserves.
As with any such change in the rules, two things happened. First, people took advantage of the rule, and many consumers were unaware of the change. Second, people started breaking the rules. As a result, there certainly are shale companies out there with “reserves” on their books that are “proved undeveloped reserves”, which many consumers have not actually realized yet are NOT proved reserves in any sense of the word, and whose share values are thus inflated.
However, that can’t last long, and indeed there was a big shakeout at the end of 2012 as the size of the machinations became visible, and the SEC stepped in and started issuing warning letters to the companies that were overbooking reserves … nothing like a warning letter from the SEC to drive your stock price down.
But that’s just folks gaming the rules, and you have to know that will happen with any new rule. Despite that, there are plenty of folks out there making plenty of money off of various tight oil and tight gas plays.
There’s a good overview of how the companies are gaming the system at the Energy Policy Forum. As always, the public is waking up to the scam, the SEC is late to the party but is now acting, and those companies that have played fast and loose are falling by the wayside … and the black gold rush in the shale country continues.
Regards,
w.
Willis Eschenbach says:
January 15, 2014 at 4:36 pm
Vangel, regarding the shale wells, no matter what I say, you keep coming back with the same thing—shale wells have a high “decline rate”, they lose production faster than regular wells.
That is not all I said. I said that when you start with the initial production rate and add up all future production based on the real world well production data you get a number that is mush smaller than the ESTIMATED ultimate reserve values that are being used to determine the depreciation schedules. This is why companies have a serious cash flow problem.
For example, when you listen to the conference call you hear that companies like Continental argue that their AVERAGE Bakken well is going to produce for decades and will yield 600,000 barrels over its lifetime. But the USGS uses real world data to come up with a range of around 70,000 to 250,000 barrels. So what you have is a depreciation schedule that does not account for the full cost of production. And that is the reason why you can have a company report $800 million in profit even though the reported free cash flow is a NEGATIVE $1.9 billion.
But since I posted that myself, and (unlike you) provided figures to back it up, why do you keep repeating it? Yes, they decline faster, I said that, you said that … so what? My problem is with your claim that the shale plays are uneconomical. Whether a well is economical has little to do with how fast they run out. If you invented a new well technology that could pump an entire field dry in one day … would that mean the well was uneconomical because of a high decline rate? No way. Either a well makes money for their owner/operators, or it doesn’t. Either they figure the decline rate properly, or they don’t.
Shy do I repeat it? Because using the right depreciation schedules matter. Do you really think that Nortel shares would have gone up over $100 if its management depreciated worthless facilities to reflect the true market value of old production lines producing obsolete products? The same is true of shale. You look at a well and see a profit because you do not check to see if the EURs are realistic. I look at SEC filings and see an explosion of debt on the balance sheet and the constant negative cash flows and see the same pattern that I have seen many times in the past. You are hopeful of a revolution while I see just another scam.
And to date, the shale oil wells do make money for their operators, and lots of it. That’s why the red line showing the number of wells drilled is going vertical.
You have no empirical evidence that this is true. The producers can only show a profit if they use a depreciation schedule that is not derived from the actual production data. It is ironic that when it comes to shale hype you sound just like the people that you criticize for failing to understand the AGW hype.
However, just like the rest of your claims, you haven’t provided a scrap of substantiation for that claim either.
Of course I have provided evidence. Take a look at ANY 10-K filing and look at what happens to the balance sheets and is reported on the cash flow statements. And take a look at what has happened to the production for companies like Chesapeake. Or what happened when majors purchased supposedly good shale properties only to write most of the cost because there was no way to make the math work. It might help if you took a look at some of the analysis done by the skeptics.
http://www.globalresearch.ca/the-fracked-up-usa-shale-gas-bubble/5326504
http://www.desmogblog.com/2012/11/13/shale-sas-bubble-about-to-burst-say-energy-insiders-art-berman-bill-powers
http://peakoil.com/enviroment/shale-truth-interview-arthur-berman
http://oilprice.com/Energy/Natural-Gas/Has-the-Shale-Bubble-Already-Burst.html
http://www.afr.com/f/free/blogs/christopher_joye/the_real_oil_on_us_shale_may_be_w07tCAT80ChWN4RYUjcgpM
Yes, there are shale companies that are gaming the system as I discuss below … so what’s new? A certain percentage of companies always game any system.
You are too trusting my friend. I could not find a single shale producer that is capable of self financing shale operations without using non shale cash flows. I could not find a single shale producer that uses EURs that are remotely close to what the real production data is suggesting as a valid ultimate recovery rate.
As with any such change in the rules, two things happened. First, people took advantage of the rule, and many consumers were unaware of the change. Second, people started breaking the rules. As a result, there certainly are shale companies out there with “reserves” on their books that are “proved undeveloped reserves”, which many consumers have not actually realized yet are NOT proved reserves in any sense of the word, and whose share values are thus inflated….
All of the primary shale producers are in the same boat. If they use realistic estimates their stock price is lower and they risk being taken out by producers that can use overvalued equity paper for acquisitions. No matter how you spin it reality is very different from what is being reported by the promoters and the companies themselves. Which is why you hear the words ‘estimated’ and ‘funding gap’ on most conference calls. Anyone who listens carefully and reads the footnotes in the Annual Reports cannot claim that the companies lied because they make it very clear that much of what is in the reports is based on guesses.
And you are missing the point again. I am asking for a SINGLE primary shale producer that can finance its operations out of the cash flows generated by shale operations. Note that the high depletion rate shows that most of the cash is recovered very early in the game. If shale were truly profitable why would companies that have been in the business for nearly a decade still have so many cash flow issues and have to resort to more and more debt, equity issues, or asset sales just to keep their development operations going? Why wouldn’t they pause for a year and use the accumulated cash to finance operations?
As I said, for a very smart math guy you are missing something very obvious.
Willis Eschenbach says:
January 19, 2014 at 12:18 pm
Robert, if you and Vangel want to believe that the oil companies are so incredibly stupid that they are investing billions of dollars in wells that will cost more than they produce, then hiding it with some unspecified “accounting games”, then be my guest. My advice, however, is that if [you] don’t want people to point and laugh, you might at least find a conspiracy with a believable premise.
Wow. Do you mean to say that if 97% of the primary shale producers are bullish on shale I have to ignore the empirical evidence?
There is no such thing as, ‘the companies are doing…” Decisions that are made regarding capital spending in shale operations do not come from companies that are investing their own money; they come from a group of primary decisions makers who are using loans to keep their operations going so that they can be compensated as much as possible. If I am the CEO of some shale outfit that discloses that the ultimate recovery rates for its wells are too low to make the extraction process economic what is the downside to using ESTIMATED ultimate recovery rates that assume that the extraction of the average well in the formation will match the extraction from a few wells in the core areas? I comply with all the regulations because they permit me to use inflated EURs for long periods of time. Note that if I admit that the process is not economic the value of the leases will have to be written down and earnings will have to be ‘adjusted’ to reflect the actual reality. If I play the game the directors, managers, and employees get a chance to earn as much money as they can until reality intervenes and the party is over. Not only do I collect high pay and bonuses I get the chance to cash in stock options before equity holders are wiped out. Note that I never lied or broke the law. My conference calls were full of comments about funding gaps that will need to be closed by new borrowing or asset sales. If you read the footnotes on the SEC filing and Annual Reports that the board approved you will find clear disclaimers that the volume of oil that is recoverable from each well may be lower than the estimates and that any divergence between the estimated and real performance would impact the financials.
None of what I am writing about is new. The financial companies were not using the proper value for their mortgage backed paper before the housing crash and the GSE never accounted for their exposure to overvalued houses properly. In the end the taxpayer was on the hook for the losses and trillions of dollars were wasted bailing out the idiots who created the problem in the first place.
And note that we saw this same scenario play out during the tech boom. Not only were the internet startups playing games by reporting eyeballs and users that would be monetized in the near future but we even saw the equipment manufacturers get into the accounting game by not writing off obsolete product lines and facilities. When reality intervened the skeptics who saw the problem were proven right and those that got caught holding overvalued shares got wiped out. I do not see how it plays out differently this time around.
I hate to be so blunt, but really?? The idea that everyone is engaged in some giant scam, from the drillers on the ground to the oil companies at the top of the heap, is a joke.
What scam? If you look at the SEC filings you find that the companies have disclosed their funding gaps. we have seen huge amounts of growing debt on the balance sheet year after year even though most of the cash flow from each well is produced in the first two to three years. We have seen Encana, BHP, Shell, Exxon, Chesapeake, BG Group, Exco Resources, and others write down billions in shale assets report that further write-offs are likely. So how exactly is it that I am wrong when we cannot find a single primary producer that is cash flow positive for its shale operations.
While I am at it let me point out a few other things that you may not have thought about. The first is that the management of most shale companies did not want drills turning because the only way to make a profit was through high prices. The problem was that the leases that they acquired had clauses that required drilling operations to take place within a specified time. Failure to meet the conditions meant giving back the rights to the property back and having to write off a big chunk of the balance sheet. This was why companies that needed $9-$11 gas were still drilling when prices were below $3. The second point that you are missing is the reserve problems of the majors. They are now producing more oil each year than they are adding to their reserve base. To hide this problem and keep share prices up some of the major are more than happy to buy uneconomic shale assets and add inflated reserve claims to their balance sheets. Not only that but gas gets the approximately 6:1 conversion rate that is based on BTU content, not the 30:1 or higher price ratio. With a compliant Federal Reserve and SEC the stage is set for yet another asset bubble. Too bad you do not use your considerable math skills to see why the claims have to be false.
Dear Willis: I once believed the AGW theory until Vangelv convinced me otherwise to look behind the IPCC statements using, in large part, articles by you. It would be fair to say that we are both big fans of your work. I just want to point out some points that you may not have appreciated, please take them in the spirit that they were given.
I actually think you and Vangelv are in agreement about the fundamental thrust of your article
“The underlying problem is that the proved reserves represent the amount of economically recoverable gas and oil … and that, of course, depends entirely on the current price and the current technology. In other words, the amount of “natural resources” in the world is not really a function of the natural world—it is a function of human ingenuity. “
[Just an aside: Your statement seems to imply that King’s peak oil/gas theory has merit for a given/current technology level.]
I think Vangel is saying that your graphs of “proven reserves” is suspect due to the true economics of fracking. If I may summarize Vangelv arguments:
1. you can’t rely on newspaper articles or SEC summaries, you have to go deeper into the actual numbers; and that analysis shows
2. the cost of a well exceeds the returns from the production; and that
3. this is being hidden in accounting games with depreciation of “the cost of a well “ at a lower level then the decline of the well.
The depreciation (i.e. the EURs) must be at a much higher level in order to match the lower value of the assets i.e. the high decline rates of the well.
Willis Eschenbach says:
January 14, 2014 at 10:10 pm
“A final comment, vangelv. It is true that the fracked wells decline quickly. A typical well that comes in at 500 barrels per day declines typically like this:
Initial, 500 bbl/day
End Year 1, 150 bbl/day
End Year 2, 99 bbl/day
End Year 3, 76 bbl/day
End Year 4, 60 bbl/day
However, this can obviously still be quite profitable, as shown by the number of people getting in on the game. All this does is change the decline cure analysis which is routinely done for all wells, q.v.”
This mismatch is depreciation shows up as a “profit” on the accounting results, but as a short fall in cash flow; thus requiring new cash infusions and the lack of
“a SINGLE primary shale producer that can finance its operations out of the cash flows generated by shale operations”.
The “number of people getting in on the game” is not proof that the returns from the production of a well exceeds its cost. It took me awhile to figure out the effect of accounting depreciation rates on “profit”.
AGW is not the only fraudulent game in town. Who knows Fracking may die at the same time as AGW.
Robert Liang says:
January 18, 2014 at 11:10 pm
Robert, if you and Vangel want to believe that the oil companies are so incredibly stupid that they are investing billions of dollars in wells that will cost more than they produce, then hiding it with some unspecified “accounting games”, then be my guest. My advice, however, is that if [you] don’t want people to point and laugh, you might at least find a conspiracy with a believable premise.
I hate to be so blunt, but really?? The idea that everyone is engaged in some giant scam, from the drillers on the ground to the oil companies at the top of the heap, is a joke.
w.
Robert Liang says:
January 18, 2014 at 11:10 pm
Robert, a part of the problem has come from the opposite effect that you are talking about. One reason that the shale gas producers are not making the money they had hoped for is that the shale gas plays are too successful, and as an inevitable result, the glut of natural gas on the market has driven the prices way down …
And yes, it’s not conventional oil or gas, and as a result, some companies have miscalculated the economics. However, the fact that wells continue to be drilled should give a clue about whether they are profitable.
It seems to me that you guys are looking at cash flow as the be all and end all. Let me point out a curiosity about negative cash flow … it’s not the proper measurement of success. To illustrate why, here are some rough figures regarding the Bakken formation from above:
Now, as Vangel and you point out, that is a very fast decline. It can be modeled quite accurately as a double exponential decline, with about 70% declining at 4.16 years (tau) and about 30% declining with a tau of about 0.4 years.
Applying this to a ten-year lifetime of the well, we get an average production of about 72 bbls per day, and a total ten-year production of about 265,000 barrels.
Now, these days a well in the Bakken costs about $10 million dollars to drill, although costs are dropping daily. That means the following:
1. Breakeven cost for the well is on the order of $37 per barrel, well below current prices.
2. Oil price today is $94/barrel … assuming a (high) pumping cost of $10 per barrel, that means that the well would recoup its capital cost in about a year and a half.
3. Again at todays prices (and oil prices are more likely to go up than down), over ten years each well will show a profit of 10 million dollars.
Given that … you can see why companies are investing in the wells.
You can also see that if you want to drill say a well this year, and two next year, and three the third year, for the next ten years, you’re going to have a huge cash flow problem, DESPITE THE FACT THAT YOUR WELLS WILL MAKE YOU MILLIONS.
For example, using that plan of drilling one well now, two the next year, at the start of the third year, you’ve made almost $30 million dollars … but you’ve drilled four wells, and spent $40 million dollars, and guys like you and Vanglev think it’s all terrible, and that it’s held up by “accounting tricks”.
It’s not, of course. If you stopped with those four wells, you’d make a total profit of about $40 million at the end of ten years of well life … but you want to continue your expansion. So if you want to continue to drill, you’ve got negative cash flow, and you might be borrowing money for your drilling program … but so what?
Now, you could avoid that. You could drill a single well, and then wait for years, and then drill the second well when you have not only paid for the first well, but you also have ten million in profits from the first well to drill the second well. That way you’ll have positive case flow, as you and Vangel seem to think is so important. At current prices, that would be in the middle of the sixth year … so then you’ve paid for the first well and you have ten million in profits.
So you drill your second well in the middle of the sixth year, and then it will be about in the tenth year you can drill your third well … meanwhile, at the end of ten years, the guy next to you has drilled 20 wells or so. Yes, he had to borrow big to do it, and yes, he had no cash flow for the first six years … but he’s also going to make a PROFIT of $200 million, while your two wells, funded entirely out of positive cash flow, are going to make you $20 million.
In other words, your concentration on the cash flow is misplaced. Every businessman knows that cash flow is an irritant that in general your bank will be happy to solve … as long as your bank is happy with your bottom line.
w.
Willis Eschenbach says:
January 19, 2014 at 12:18 pm
Applying this to a ten-year lifetime of the well, we get an average production of about 72 bbls per day, and a total ten-year production of about 265,000 barrels.?
But the average shale well is nowhere that prolific. The shale companies are using the classical Arps formula but the actual well data disagrees with the EURs calculated by using that formula. It is ironic that you side with models that make assumptions and overestimate recovery rates while you ignore the real data even as you attack the AGW crowd for siding with models that overestimate the actual warming observed in the real world.
And note that the argument has shifter far away from shale because even the promoters have moved away from shale gas because it is such a capital destroyer. The fact that shale gas failed while it was hyped as the next big thing should lead you to question some of the arguments, not accept them without checking. Note that the same type of argument that you now give for oil did not work out well for shale gas.
http://online.wsj.com/news/articles/SB10001424052702304753504579282900212162522
I was looking for the Bakken production data and just ran into this commentary. It supports what I have argued so I am providing the link below the quotes. The paragraphs of interest to me were:
“According to Ryder Scott in late 2011, 80% of the top 10-K oil and gas companies were issued comment letters by the SEC for anomalies in their public filings. Further, only 16% could show with reasonable certainty that their PUD’s would be developed in 5 years. That meant that 84% of the companies were not in compliance with the new SEC rule. In fact, some companies were apparently declaring PUD’s that were described as “mathematically impossible”.
…….
Equally problematic is that fact that such PUD’s accounted for nearly half of all reserves at companies like Chesapeake and PetroHawk. These are assets that according to company SEC filings would take almost 3 times longer than allowed to develop. So it raises the question, just how viable are such assets? And can an investor truly get a real picture of this company’s prospects and financial health? In a sense, it could be argued that this is the equivalent of smearing Vaseline over a camera lens. You can discern shapes but that is about it.
………..
Let’s presume that you aggressively leased acreage in a play and then equally aggressively apply a public relation campaign to tout the enormous potential. (Note that the word aggressive is appearing on a regular basis). You drill a few wells and “prove up” the acreage. Only no one really knows at this point whether the wells are actually economically viable. Because under the new rule changes, the SEC does not require independent third party verification of reserves. (But even this would not be a fail-safe because, let’s be honest, who wants to bite the hand that feeds you if you are a reservoir analyst?). So if a company and it’s management are aggressive, they book these reserves. Indeed, we know now that they have significantly overbooked reserves.
http://energypolicyforum.org/2012/09/11/the-magic-of-shales/
In case you think my estimate of per-well profit is high (ten million in ten years), here’s the New York Times Magazine on the question …
My figures say less than that, but note that none of my analysis includes the inevitable technology gains that already are occurring, I’ve assumed $10/barrel pumping costs, $10 million drilling costs, and oil prices which are lower now than at the time of the NYT article..
Well prices are dropping, from $10 million to around $8 million in a few years. And new technologies like “downspacing” are appearing all the time, including ways of using less water per well, and the like.
So … yes, there are and will be cash flow issues with the wells … and yes, the wells are most definitely making a profit for their owners.
w.
Willis Eschenbach says:
January 19, 2014 at 12:18 pm
Robert, a part of the problem has come from the opposite effect that you are talking about. One reason that the shale gas producers are not making the money they had hoped for is that the shale gas plays are too successful, and as an inevitable result, the glut of natural gas on the market has driven the prices way down …
That does not change the fact that the shale producers cannot generate economic profits. When the shale producers are forced to keep drilling to meet the terms on their leases at a time when the price for their product is a small fraction of the total cost they are destroying capital. We have seen the battle of worlds between Chesapeake, Devon, and Arthur Berman go on for years. Arthur claimed that when you added up all of the costs the shale producers needed prices around $10 giver or take a buck or two for the companies to make a true economic profit. He also pointed out that the estimates for the lives of the wells were too high. (The producers use a hyperbolic decline curve that cannot be justified by the actual production data.)
http://www.bloomberg.com/apps/news?pid=newsarchive&sid=asEUlpJcuZB4
In 2009 the shale industry managed to get Mr. Berman fired from his job at the World Oil Journal because shale companies and Wall Street analysts did not like what he was writing about shale prospects. Since then Mr. Berman has been proven right as many of the assets had to be written down and since the real world data has shown that the actual life of shale wells was nowhere near the assumed. (That is where my depreciation argument comes in.)
Let us look at one of Mr. Berman’s biggest critics, Aubrey McClendon, the former CEO of Chesapeake. In an interview with Jim Cramer (http://tinyurl.com/qfta6g6
) Mr. McClendon called Arthur Berman, “a third-tier geologist who considers himself a reservoir engineer,” who thought that he knew, “more about the shale gas revolution in America than companies that have combined market caps of almost $2 trillion and have spent hundreds of billions of dollars to develop these new resources.” That argument is the same one that you are giving right now except that it was made three years ago.
So what has happened to Aubrey McClendon’s claim since then? Well, we now know that Mr. McClendon was given a right to participate in all of Chesapeake’s wells and that he exercised that right. He did that because the rubber stamp board allowed him participation with non-recourse borrowed money with no collateral other than interest in those same wells. Mr. McClendon lost more than $50 million in 2009, more than $100 million dollars in 2010, and yet more in 2011. Why would Mr. McClendon need to borrow to cover his losses if the shale wells are economic? Mr. McClendon was stripped of most of his power in 2012 and finally fired by the board in 2013. Although the company shares had managed to fall by more than 20% before he was stripped of his powers Mr. McClendon received more than $300 million in compensation. And when the SEC investigated his activities it found him secretly operating a $200 hedge fund that was in the natural gas futures trading business.
http://www.huffingtonpost.com/2013/01/29/aubrey-mcclendon-steps-down_n_2577300.html
http://www.cnbc.com/id/47410404
Of course, there is a sucker born every minute and the discredited Mr. McClendon used the hype to start up a private equity firm that will destroy shareholder capital in Ohio’s Utica Shale formation as Mr. McClendon gets paid an obscene amount in fees regardless of performance. As Frobes points out, a great deal for him but a terrible one for investors.
http://tinyurl.com/la98h83
Let me repeat this again. The skeptics were right on shale gas while the promoters, Wall Street, and industry were wrong. That is not my opinion. It is documented history. Yet you still want to use an appeal to authority as the primary foundation of your position. Sorry Willis but no matter how smart you may be you are going to need facts to support your claims of economic profitability in an industry that sells its products at well below cost.
And yes, it’s not conventional oil or gas, and as a result, some companies have miscalculated the economics. However, the fact that wells continue to be drilled should give a clue about whether they are profitable.
Why? As was demonstrated by Chesapeake, the board of directors, kept approving activities that led to massive losses. The CEO called all the shots and the board that he appointed and paid $600,000 per year for very little in the way of work approved his actions even when they may have been illegal according to the SEC.
Once again, companies don’t make decisions. Individuals do. And when you have a huge concentration of power the people who call the shots can get others to go along simply by paying them to agree.
Vangel Vesovski says:
January 19, 2014 at 5:32 pm
Vangel, I’ve provided two separate sources that agree with those numbers. When I posted the numbers before, you didn’t complain about them. Now that I’ve shown what they mean, you don’t believe them … but all you provide in the way of evidence is your unadorned words.
OK, you come up with some numbers.
While we’re waiting for your numbers, here are some more:
At the current price of $94 per barrel, that puts the per-well profits at thirty million dollars after ten years … and I’ve estimated them much more conservatively, at $10 million profit after ten years.
Finally, you seem to think that the companies overbooking of reserves has something to do with whether a well is profitable or not … but a well knows nothing of claims of reserves, or whether they are overbooks.
w.
PS—you do provide more evidence that some companies were gaming the system by overbooking reserves … but since I already agreed with that, so what? Doesn’t affect a well’s profitability by one penny.
Oh, and you’re back on the Chesapeake bandwagon, as though the fate of one carefully selected company means something about the industry. And that’s about as convincing as someone saying “HP lost money on computers, so that means that all computer manufacturers are losing money producing computers and hiding it with accounting games”.
I’ve provided three independent sources for my numbers, and my calculations use the most conservative of the three. Someday, perhaps you’ll provide some numbers to back up your claims … until then, they’re just hot air.
Willis Eschenbach says:
January 19, 2014 at 8:04 pm
Vangel, I’ve provided two separate sources that agree with those numbers. When I posted the numbers before, you didn’t complain about them. Now that I’ve shown what they mean, you don’t believe th em … but all you provide in the way of evidence is your unadorned words.
Let me be clear. The numbers that you give are supposed to be for the AVERAGE Bakken well. But they do not come from real world data. They come from a model that uses the typical Arp’s formula, which is then used to calculate a decline curve that is fairly typical in CONVENTIONAL reservoirs but is NOT OBSERVED in shale wells.
Since you asked for an example that differs from what you provided I went to Google and searched for the terms, “arp’s formula shale oil bakken decline” and looked at the top three hits.
In the first link (http://tinyurl.com/plxn57r) we get a look at a very prolific well with a slow decline rate. This well is not typical but is not too far from the better wells in the core areas of the Bakken. As the analyst points out, This well is the kind of best performing shale wells that the industry would love to pitch to investors. When it started, it was one of the highest producing well at the time. The well decline was also one of the slowest. First year production decline was only 55%. Compare that to the 80%-85% first year decline in the latest Bakken wells!
The analyst finds that the Arp formula is pretty good for the first three years of this particular well but after that there is no way to choose the right parameters to get the model to agree with the real world observations. I think that the reason for this are obvious; conventional oil reservoirs have very different permeability and porosity characteristics so it makes little sense to assume that shale declines will be similar. Which is why REAL WORLD OBSERVATIONS MATTER. And those observations suggest that, “the ultimate production of this well will be 280 MBOE, or roughly 44% of the EUR calculated from classical Arps formula.”
http://tinyurl.com/nmch8ag
Note that the example was for one of the great wells drilled in the core area of the formation. While that well should produce a nice profit even if its ultimate recovery is only 40% of what the misapplied Arp’s model predicts, the profitability of the shale industry depends on the performance of the average shale well. And on that front things are not looking so good. For one, as drillers move away from the core areas well productivity is in decline. For another, the divergence between the EURs and actual recovery rates are catching up as wells get older. As Mark Anthony points out, There are mounting indisputable evidences that critics like Arthur Berman are right. The shale industry has systematically exaggerated EUR projects of shale wells by more than a double. More over, they systematically under-calculated the armortization of the capital expenditures as the wells deplete much faster than they expected.. As I have argued many times before, everything hinges on that amortization rate. If the depreciation schedule, which is determined by looking at the EURs is right the industry should be fine. But if the EURs are higher than the ultimate recovery rates that are suggested by the real world data the industry is in big trouble. Where this will all show up is the balance sheets and the cash flow statements. If the EURs are reasonable companies will get huge amounts of cash within two or three years of the well coming on-line and that cash should be sufficient to financed further expansion. While negative cash flows and debt are not a problem early in the game a truly economic process will produce positive cash flows within a few years and will not have the need to sell off assets to deal with funding gaps.
And please look at your own statements about how companies book PUD and what that does when they look to obtain further loans. What I see is a giant Ponzi scheme being driven by a few insiders in the industry, Wall Street analysts looking for fees, and regulators who change the rules to allow uneconomic producers to access capital. Those don’t work out very well.
If you are interested you can find a number of references in the Hughes report below the quotes. Of particular interest may be the few takeaways that I have lifted from the report.
“As with shale gas, tight oil plays are not ubiquitous. More than 80 percent of tight oil production is from two unique plays: the Bakken and the Eagle Ford. The remaining nineteen plays produced just 19 percent of current tight oil production. There is also considerable variability within these plays, and the highest productivity wells tend to be concentrated within relatively small sweet spots.”
” Well decline rates are steep – between 81 and 90 percent in the first 24 months. The plays are too young to assess overall well lifetimes but production rates in the Bakken after five years are 33 bbls/d on average and after seven years will likely approach stripper well status (10 bbls/d). Eagle Ford wells could reach stripper well status within four years.”
(http://www.postcarbon.org/reports/DBD-report-FINAL.pdf)
Willis Eschenbach says:
January 19, 2014 at 8:04 pm
While we’re waiting for your numbers, here are some more:
First, dilling a well costs about $8.5 million. Each Bakken well will produce a cumulative 500,000 barrels or so over 10 years — about 450,000 after deducting royalty payments to landowners. That works out to drilling costs of roughly $19 per barrel.Then there’s roughly $5 a bbl in taxes and $3 a bbl for pipelines and infrastructure and a couple bucks for seismic and other overhead, for total costs of about $29 per barrel.
First, where do you get a credible ultimate recovery rate for EACH BAKKEN WELL of 500,000 over ten years? I do not see any production data that supports that claim. But if you can find a reference please correct me and cite it. Second, you forgot to add the $4.5 billion that was paid for the rights to the leases. A good accountant would include those as part of the cost calculations.
Note that we are exactly in the SAME PLACE yet again. All of our costs depend on the number of barrels that will be pulled out of the ground. What if we are not looking at a well in the core area but one that is in the average part of the formation? That would give us closer to 125,000 barrels, which just jacked up your drilling cost to $60 a barrel. Add the acquisition costs, overhead, royalty payments, taxes, transportation costs, etc., and you are looking at a cost that is higher than the production price.
But suppose that you managed to eek out a small profit. Given the fact that your company took a huge bath on shale gas production you have to pay back the loans taken on for shale gas production first. It takes years to repair a balance sheet even if you are prudent and have no need to hype up your shares by taking on more leverage and risk. The trouble is that you don’t have years to fix the balance sheet because the rate of production increase is slowing appreciably in the Bakken. Some time in the next year or two even the optimists will see that the peak is either directly ahead or that it is behind us. At that time the shareholders are wiped out and creditors tighten the screws as the depreciation schedule issue comes back to bite management in its collective arse.
And while I am at it let me point out a problem with the author of the article that you are citing. A few years ago Mr. Helman slagged Berman and some of the people cited in the NYT story when they blew the whistle on the gas problem. He took exactly the same approach that you did and cited all of the capital spending as proof that shale gas could not be uneconomic. Well, a great deal of water has passed under the bridge and Arthur Berman and the shale skeptics were proven to be correct. The production increases were very real but they were driven by lease commitments, not cash flows or profits. The EURs overstated the real recovery rates by more than 100% and the great success stories turned out to be destroyers of capital. I suspect that this is the reason why Mr. Helman is far more cautious even though he is clearly using industry EURs that depend on hyperbolic decline rates that overestimate the true returns. You might try reading the article that you cited once again and pay more attention this time. It might be appropriate to ask where the numbers that you are citing come from. What real data set shows a hyperbolic decline rate that justifies the assumptions? I can assure you that if such a data set existed it would not be hidden from view and that analysts would not be citing ESTIMATED values produced by models.
Finally, you seem to think that the companies overbooking of reserves has something to do with whether a well is profitable or not … but a well knows nothing of claims of reserves, or whether they are overbooks.
Correct. All the well does is produce oil and gas. Which is why you should look at the actual production data rather than estimates coming from models that deviate from reality.
PS—you do provide more evidence that some companies were gaming the system by overbooking reserves … but since I already agreed with that, so what? Doesn’t affect a well’s profitability by one penny.
Sure it does. If the average well in a formation produces 150,000 barrels before it hits stripper status but your use a depreciation schedule that assumes 450,000 barrels your costs are understated. That allows you to report a profit. Luscent and Nortel did this in the 1990s when they would depreciated plant and production lines that became obsolete in two years over an assumed useful life of 20 years. Many of those ‘one-time’ write offs happened because those assets had to be devalued. The shale industry has just began doing the same as many of the players have began to write off acquisition costs as acreage that used to be carried at a particular value on the books is now selling for a fraction of that value.
Look at the article that you cited. We read, “Early this year Hess sold out of its Eagle Ford acreage for $6,000; just 18 months earlier good acreage in the region was going for $24,000. There is tons of acreage on the market right now, enough stuff to keep the industry drilling for hundreds of years. But who’s going to buy it? The problem is that oil and gas prices are simply not high enough to justify the investment; so if that acreage does exchange hands it’s going to do so at prices far below what the industry has gotten used to. Or the acreage may not sell at all.”
That is exactly my point. What happens when assets on the balance sheet have to be written down?
Oh, and you’re back on the Chesapeake bandwagon, as though the fate of one carefully selected company means something about the industry. And that’s about as convincing as someone saying “HP lost money on computers, so that means that all computer manufacturers are losing money producing computers and hiding it with accounting games”.
Who said one ‘carefully selected’ company? Chesapeake is just the leader. It began hyping up shale gas first and got the most attention and the most coverage. It is not the only company that has written off assets or sold pieces of itself to cover the funding gaps. The article that you cited mentions, “$26 billion in asset impairment charges,” for the 50 biggest shale players and companies have already said that the impairment charges will continue. As I said, the empirical evidence is on the side of the skeptics. You might want to look at some of it.
One last reply…
Willis Eschenbach says:
January 19, 2014 at 8:04 pm
I’ve provided three independent sources for my numbers, and my calculations use the most conservative of the three. Someday, perhaps you’ll provide some numbers to back up your claims … until then, they’re just hot air.
Please do not confuse numbers coming from an industry model with actual production data. What you give me are EURs that are provided by analysts who are given the same estimates. That data is clearly not independent. All of the claims depend on an Arp’s formula that a hyperbolic decline and does not have a terminal phase that produces a curve that actually fits the real world data.
Please see the information on the links that I have provided and look at the real world data yourself.