Top-notch analysis, thank you, Art.
Would you expect Permian to be profitable enough to keep the game going for longer? Or are we about to experience moonshot you’ve alluded to earlier?
regards,
daniel
Art
You say that technology does not create energy, just increases rate of extraction from a source.
I understand that.
Can technology however leave less energy in the ground at many locations?
I am a non-specialist and your work has been the essential ‘sense of proportion’ over the years.
I understand the relatively modest obtainable US resource (reserve) by world standards.
Subsidiary question: will there be 90,000 plus ‘stripper wells’ for oil over a long follow-on period?
best
Phil
Much tight oil would not be extracted w/o new technology so the real question is economic. The argument has been that new technology has made the extraction commercial. Until recent combination of higher prices and lower costs, that was not true. Ordinarily, cost inflation with rising oil prices limits or eliminates profits. We shall see.
The low-rate “stripper” wells will contribute small volumes until sales fail to cover operating expenses. Theoretically, they will be plugged at that point.
Excellent analysis Art! I especially like your comment regarding price deflation vs technology/efficiency. Does this suggest that the EIA’s forecast is overly optimistic for tight oil?
Also, I am curious where you plugged in the initial land costs?
Hi Art, please can you discuss why the increased decline rates that you report do not appear to be affecting Eagle Ford production as reported by the EIA Drilling Productivity report. That report appears to show no increase in decline rates, growing drilling productivity per rig, and growing production from the basin overall – April production is forecast to rise by 23k bpd. How do you reconcile what you are seeing from the 6 companies that you analysed with the EIA forecasts? Many thanks for your help. I’m a big fan of your blog, and now your Twitter feed.
Rigs can be hugely more “productive” but that says little to nothing about oil production b/c rigs don’t produce oil. An analogy would be that more fuel-efficient cars mean that people are driving more miles when, in fact, the opposite seems to be true.
The reality is that it takes more wells to produce less oil so let’s talk about well productivity.
This was an excellent presentation and answers not only why well-level IRRs quoted by E&Ps are deceptively high but also why EURs quoted by producers are materially overstated. Regarding the latter, I think your point about energy equivalence vs value equivalence is a big part, and the other primary factor is an assumption about terminal declines. The terminal decline assumption is so far out on the tail that it doesn’t change IRRs much, but it can pretty drastically impact the EUR quoted.
The only area where I disagreed a bit with your analysis relates to the price producers are receiving on Eagle Ford barrels. Based on my EOG Eagle Ford check stubs in 2017, I believe they received something approximating LLS on a pre-transportation deduct basis. I can crunch the numbers if you want me to, but I believe that, even after deducting transportation they were still netting back above WTI-Cushing. It could be this varies a lot by producer and how far away the acreage is from Houston hub.
Thanks for a great article. The truth about the shale game that E&Ps don’t want people to know is just what your analysis showed. On the whole, shale drilling is not highly profitable and produces a very low ROIC when we use GAAP and pay no attention to non-GAAP “fuzzy math” that ignores many of the full-cycle, debt service, and G&A costs.
I used Sanchez Energy’s 10-K realized prices to determine differential to WTI. Your checks are an important data point also so please check them if you would.
An additional source of over-stated EUR is from recent wells with limited (<24 months) of production history.
These, of course, are the wells that supposedly have the greatest performance improvement. How are these EURs determined? By using type curves from previous years shifted upward to match higher initial production rates. The problem of course is that the decline rates may be very different.
I pulled my stubs from EOG for one DSU in Gonzales County, and the average realized price for 2017 on these EOG wells (Gonzales County) was $53.49 for crude, which, I believe, is a couple bucks higher than WTI over the same period. The realized price definitely depends on location to some degree; my realized price in other counties (DeWitt, Karnes) with EOG as operator varies a slight amount (~$1-2/bbl per month), but all lease terms are the same and so the price differentials should just reflect different realized prices in different parts of the basin.
I’m trying to paste below the table so you have the data. Condensate realized price was generally a buck or so less, but most of the volume is from crude. Also for reference, January 2018 realized prices for EOG ranged from $65 all the way up to $68.98!
Thank you Art on the excellent presentation. In the conclusion:
“Over-production was the main factor in the oil-price collapse in 2014. Resurgent over-production is
likely to depress prices again.”
Is the resurgent over production likely to come from mostly from the Permian? It seems this basin dwarfs the production from any of the other shale oil plays depicted on the graph.
Do you suppose the threat of possible Iranian sanctions will continue to keep oil prices supported despite the bearish factors seen by oil traders (increasing rig count and production and numerous DUC wells)?
Listening to Art talking with Martenson and others very impressively, one realises how “..it is impossible to do an EROI study that has all of the inputs or all the externalities [for crude, coal and gas production, yet alone shale oil and gas]” as Alice Friedemann states on her blog.
This becomes pressing when nobody today can tell what portion of the incredible fossil fuels daily production goes straight into setting in-motion the production process of more fossil fuels production.
It is irreconcilable having 23000 man-hour in a barrel of crude, 100m/b consumed daily but two thirds of the population of the globe live largely energy-less, resources are exhausted like no tomorrow, reserves are vanishing like vapor, wars never end, poverty is rampant, the environment in tatters and we have not counted for the energy in coal and gas, yet!
Therefore, it must be that most of all fossil fuels produced today is being consumed internally by that same production process – as a recently circulating thesis in thermodynamics inspires;
This far, the thesis postulates that no humans-run processes, whether industrial or otherwise, will exceed the <=2% efficiency of living plants when they internally converting solar energy into useful work, no matter how much fossil fuels reserves humans burn.
This could explain why the astronomical solar and geological energy, stored in fossil fuels reserves over hundreds of millions of years, have vanished so quickly in a mere 300 years since the Industrial Revolution.
Top-notch analysis, thank you, Art.
Would you expect Permian to be profitable enough to keep the game going for longer? Or are we about to experience moonshot you’ve alluded to earlier?
regards,
daniel
Art
You say that technology does not create energy, just increases rate of extraction from a source.
I understand that.
Can technology however leave less energy in the ground at many locations?
I am a non-specialist and your work has been the essential ‘sense of proportion’ over the years.
I understand the relatively modest obtainable US resource (reserve) by world standards.
Subsidiary question: will there be 90,000 plus ‘stripper wells’ for oil over a long follow-on period?
best
Phil
Phil,
Much tight oil would not be extracted w/o new technology so the real question is economic. The argument has been that new technology has made the extraction commercial. Until recent combination of higher prices and lower costs, that was not true. Ordinarily, cost inflation with rising oil prices limits or eliminates profits. We shall see.
The low-rate “stripper” wells will contribute small volumes until sales fail to cover operating expenses. Theoretically, they will be plugged at that point.
All the best,
Art
Excellent analysis Art! I especially like your comment regarding price deflation vs technology/efficiency. Does this suggest that the EIA’s forecast is overly optimistic for tight oil?
Also, I am curious where you plugged in the initial land costs?
I don’t include land costs. I gave up that battle years ago. It should be included but no analysts do so, to remain comparable, I dropped it.
Art
Hi Art, please can you discuss why the increased decline rates that you report do not appear to be affecting Eagle Ford production as reported by the EIA Drilling Productivity report. That report appears to show no increase in decline rates, growing drilling productivity per rig, and growing production from the basin overall – April production is forecast to rise by 23k bpd. How do you reconcile what you are seeing from the 6 companies that you analysed with the EIA forecasts? Many thanks for your help. I’m a big fan of your blog, and now your Twitter feed.
Rigs can be hugely more “productive” but that says little to nothing about oil production b/c rigs don’t produce oil. An analogy would be that more fuel-efficient cars mean that people are driving more miles when, in fact, the opposite seems to be true.
The reality is that it takes more wells to produce less oil so let’s talk about well productivity.
Art,
What royalty % does this analysis assume?
thanks
Ryan
Ryan,
75% NRI.
Art
This was an excellent presentation and answers not only why well-level IRRs quoted by E&Ps are deceptively high but also why EURs quoted by producers are materially overstated. Regarding the latter, I think your point about energy equivalence vs value equivalence is a big part, and the other primary factor is an assumption about terminal declines. The terminal decline assumption is so far out on the tail that it doesn’t change IRRs much, but it can pretty drastically impact the EUR quoted.
The only area where I disagreed a bit with your analysis relates to the price producers are receiving on Eagle Ford barrels. Based on my EOG Eagle Ford check stubs in 2017, I believe they received something approximating LLS on a pre-transportation deduct basis. I can crunch the numbers if you want me to, but I believe that, even after deducting transportation they were still netting back above WTI-Cushing. It could be this varies a lot by producer and how far away the acreage is from Houston hub.
Thanks for a great article. The truth about the shale game that E&Ps don’t want people to know is just what your analysis showed. On the whole, shale drilling is not highly profitable and produces a very low ROIC when we use GAAP and pay no attention to non-GAAP “fuzzy math” that ignores many of the full-cycle, debt service, and G&A costs.
Brad,
Thanks for your excellent comments.
I used Sanchez Energy’s 10-K realized prices to determine differential to WTI. Your checks are an important data point also so please check them if you would.
An additional source of over-stated EUR is from recent wells with limited (<24 months) of production history.
These, of course, are the wells that supposedly have the greatest performance improvement. How are these EURs determined? By using type curves from previous years shifted upward to match higher initial production rates. The problem of course is that the decline rates may be very different.
All the best,
Art
Thanks for the reply, Art.
I pulled my stubs from EOG for one DSU in Gonzales County, and the average realized price for 2017 on these EOG wells (Gonzales County) was $53.49 for crude, which, I believe, is a couple bucks higher than WTI over the same period. The realized price definitely depends on location to some degree; my realized price in other counties (DeWitt, Karnes) with EOG as operator varies a slight amount (~$1-2/bbl per month), but all lease terms are the same and so the price differentials should just reflect different realized prices in different parts of the basin.
I’m trying to paste below the table so you have the data. Condensate realized price was generally a buck or so less, but most of the volume is from crude. Also for reference, January 2018 realized prices for EOG ranged from $65 all the way up to $68.98!
Month EOG Crude Realized Price WTI EOG – WTI
Jan-17 $52.98 52.5 $0.48
Feb-17 $54.21 53.47 $0.74
Mar-17 $51.34 49.33 $2.01
Apr-17 $52.40 51.06 $1.34
May-17 $50.54 48.48 $2.06
Jun-17 $47.15 45.18 $1.97
Jul-17 $48.74 46.63 $2.11
Aug-17 $50.24 48.04 $2.20
Sep-17 $52.57 49.82 $2.75
Oct-17 $55.73 51.58 $4.15
Nov-17 $62.14 56.64 $5.50
Dec-17 $63.87 57.88 $5.99
Jan-18 $68.98 63.7 $5.28
Thank you Art on the excellent presentation. In the conclusion:
“Over-production was the main factor in the oil-price collapse in 2014. Resurgent over-production is
likely to depress prices again.”
Is the resurgent over production likely to come from mostly from the Permian? It seems this basin dwarfs the production from any of the other shale oil plays depicted on the graph.
Do you suppose the threat of possible Iranian sanctions will continue to keep oil prices supported despite the bearish factors seen by oil traders (increasing rig count and production and numerous DUC wells)?
Listening to Art talking with Martenson and others very impressively, one realises how “..it is impossible to do an EROI study that has all of the inputs or all the externalities [for crude, coal and gas production, yet alone shale oil and gas]” as Alice Friedemann states on her blog.
This becomes pressing when nobody today can tell what portion of the incredible fossil fuels daily production goes straight into setting in-motion the production process of more fossil fuels production.
It is irreconcilable having 23000 man-hour in a barrel of crude, 100m/b consumed daily but two thirds of the population of the globe live largely energy-less, resources are exhausted like no tomorrow, reserves are vanishing like vapor, wars never end, poverty is rampant, the environment in tatters and we have not counted for the energy in coal and gas, yet!
Therefore, it must be that most of all fossil fuels produced today is being consumed internally by that same production process – as a recently circulating thesis in thermodynamics inspires;
https://the-fifth-law.com/pages/press-release
This far, the thesis postulates that no humans-run processes, whether industrial or otherwise, will exceed the <=2% efficiency of living plants when they internally converting solar energy into useful work, no matter how much fossil fuels reserves humans burn.
This could explain why the astronomical solar and geological energy, stored in fossil fuels reserves over hundreds of millions of years, have vanished so quickly in a mere 300 years since the Industrial Revolution.