Shale Oil Fiasco

[Gerry Maddoux + 3,627]

1 minute ago, James Gautreau said:

Chevron buying Cheniere would make the Occidental/Anadarko purchase look idiotic, and make Warren Buffet a stooge quite possibly for the first time. They're the only game in town until 2024. If there' s room, maybe add another train. 

Well, Warren is nobody's fool, but this LNG stratospheric growth has become obvious (to me, at least) since that transaction. Cheniere's success is equivalent to Aubrey McClendon bragging about the prolific Haynesville. I loved Aubrey but he just couldn't help himself. He didn't realize that his own success was going to bring it all down. Cheniere brags too, but they are a publically-traded company and Chevron sees the handwriting on the wall--heck, everyone sees the handwriting on the wall. 

Chevron isn't desperate; they have many other projects, such as offshore, which are immensely profitable. Their petchem plants and refineries are humming. BUT, even CVX can't continue to hemorhage money by subsidizing Cheniere Energy. They'll look at Exxon's LNG plans and smile, b/c it's going to take a while. CVX buying Cheniere would take, what, two months, and they'd have a going concern out the gate. It would have to be a hostile takeover (which used to be taboo in the O/G business) b/c believe me, Cheniere is fully aware of the potential this has. LNG, as a matter of fact, has the potential to eventually swallow Chevron. And anyone else in the shale basins. I imagine they're also quite aware of the fact that they're being looked at by predators, and are busily circling the wagons. The hostile takeover price would probably have to be 2X the current share price to get the board to go along with it. That's pricey, but it's the only way to really get what they want, which is an instant turnaround. Things like this--the tail wagging the dog--don't last forever, b/c the dog just can't stand it any longer. That's where we are, James.

[James Gautreau + 86]

7 minutes ago, D Coyne said:

Thanks Gerry,

Note that I pulled back on my oil price estimates based on hints by Mr Shellman (though he in no way endorses my estimates, I believe he thinks any model of the future is likely to be wrong, and I agree 100%).  Some at oil price have suggested a "Goldilocks" oil price of $65/bo for Brent, that price does not work for very long in the tight oil plays (the average well breaks even at $60/bo today at a 10% discount rate where NPV of future discounted net cash flow is equal to well cost.)  So I assume oil prices gradually rise from $60/bo in 2018$ today to about $90/bo in 2018$ in June 2027 and then remain at that level until 2050 and then decrease to $40/bo by 2070 and remain at that level until 2080 (end of my scenario).  The EIA's AEO 2019 reference oil price case has Brent increasing to $108/bo in 2018$ by 2050.  I doubt scenarios that have oil prices higher than about $140/b in 2018$ long term, this only occurs with a major war between all Persian Gulf Oil producers which takes 20 Mbopd of the World Market.  That kind of scenario would result in an oil price spike to $300/bo and much damage to the World economy.

A lot of my focus has been on the Permian basin.  The USGS has a mean TRR (technically recoverable resource) estimate for the Permian basin at about 75 Gb. My Permian scenario has about a 60 Gb URR for the oil price scenario I suggested above.  A higher oil price scenario that goes to $171/bo in 2018$ for Brent in 2051 could lead to as high as a 74 Gb URR, with higher maximum completion rate for the high price scenario (910 vs 730 wells completed per month at highest rates).  A lower oil price scenario (max price $70/b in 2018$) leads to lower URR of 34 Gb.  I assume there is no change in completion rate for the low price scenario compared to medium price scenario up to 2027, then economics dictates that completion rate falls rapidly because it is no longer profitable to complete wells at the higher rate due to lower oil prices.  I do not think the low price scenario is realistic and expect oil prices will fall between the medium and high price scenario, this actual Permian output might fall between the medium and high price scenarios.

I fundamentally have disagreed with those estimates almost from the beginning. The Permian has produced 20 GB of conventional oil. If there were really 46 GB left down there, I estimate only 20%  recoverable or 9.2. We have already produced something like 6 GB. Technology will increase to 25 - 30% or 11.5 -13.8 GB. So 5.5 - 7.8 GB is left, and it'll take 2 -3 times the number of wells to get what's left out of the ground. But as Gerry points out the frack fleets going electric will yield huge cost savings, the infrastructure is in place so no more flaring, and additional LNG facilities are being built. 

[Gerry Maddoux + 3,627]

Dennis: Is it possible to produce a model for what I've so verbosely expounded, namely, the concept that a supermajor also becomes--by hook or by crook--the dominant player in the LNG business?

Input variables: LNG grows by 50%/year, the spread narrows to one dollar per, that particular supermajor becomes a profitable shale op.

Output interests: how many potential shale wells might there be, how might the price of oil be affected, does it capsize the rest of the group.

[D Coyne + 305]

2 minutes ago, James Gautreau said:

I fundamentally have disagreed with those estimates almost from the beginning. The Permian has produced 20 GB of conventional oil. If there were really 46 GB left down there, I estimate only 20%  recoverable or 9.2. We have already produced something like 6 GB. Technology will increase to 25 - 30% or 11.5 -13.8 GB. So 5.5 - 7.8 GB is left, and it'll take 2 -3 times the number of wells to get what's left out of the ground. But as Gerry points out the frack fleets going electric will yield huge cost savings, the infrastructure is in place so no more flaring, and additional LNG facilities are being built. 

James,

Note that the TRR includes resources already produced and proved reserves, for the Permian at the end of 2018 that was about 15.4Gb, if 2P/1P=1.5 then 2P reserves plus cumulative output would be 21 Gb.  The USGS F95 estimate for Permian basin TRR is about 43 Gb, which would leave about 22 Gb more than the 2P plus cumulative output estimate.  It is possible the URR might be as low as 43 Gb, but I doubt it would be lower than that, unless oil prices remain very low.

I will stick with my 60 to 70 Gb estimate, probably around 65 Gb would be my best guess as I expect Brent oil prices will reach $120 to $140/bo by 2026, they will probably settle around $130/bo+/-10 until 2035 and then start to decline as the World moves to alternatives to C+C.

[James Gautreau + 86]

There are more than 900,000 active oil and gas wells in the United States, and more than 130,000 have been drilled since 2010, according to Drillinginfo, a company that provides data and analysis to the drilling industry.Feb 14, 2017

The new estimated mean of undiscovered, technically recoverable resources in the Permian basin are 46.3 billion barrels of oil, 281 Tcf of natural gas (17.5 times higher than the 2016 estimate!), and 19.9 billion barrels of NGLs.Dec 27, 2018

They're going to need between 250,000 - 400,000 new wells. 

[D Coyne + 305]

7 minutes ago, Gerry Maddoux said:

Dennis: Is it possible to produce a model for what I've so verbosely expounded, namely, the concept that a supermajor also becomes--by hook or by crook--the dominant player in the LNG business?

Input variables: LNG grows by 50%/year, the spread narrows to one dollar per, that particular supermajor becomes a profitable shale op.

Output interests: how many potential shale wells might there be, how might the price of oil be affected, does it capsize the rest of the group.

Gerry,

Anything is possible, but I would have to be convinced the scenario makes sense before investing a lot of time to produce such a model.  Lot of competition at the World level for LNG, so fundamentally it would be unlikely that a supermajor would become dominant over NOCs.

[D Coyne + 305]

3 minutes ago, James Gautreau said:

There are more than 900,000 active oil and gas wells in the United States, and more than 130,000 have been drilled since 2010, according to Drillinginfo, a company that provides data and analysis to the drilling industry.Feb 14, 2017

The new estimated mean of undiscovered, technically recoverable resources in the Permian basin are 46.3 billion barrels of oil, 281 Tcf of natural gas (17.5 times higher than the 2016 estimate!), and 19.9 billion barrels of NGLs.Dec 27, 2018

They're going to need between 250,000 - 400,000 new wells. 

James,

The 46 Gb UTRR is Delaware basin only, one needs to include the Spraberry (4 Gb), and Midland basin(20 Gb) as well.

So 46+20+4= 70 Gb for UTRR and at the time "discovered" resources (cumulative output and proved reserves) were about 4 Gb for the Permian basin for a total of 74 Gb TRR.  My estimate for wells drilled for the entire TRR to be produced is about 255,000 wells.  For my "high oil price scenario with a 72.6 Gb URR there are 247,800 wells completed, for the 59.6 Gb URR scenario (medium oil price scenario with maximum oil price of $90/b reached in 2027) there are 192,000 wells completed, for the low oil price scenario ($70/b maximum price) with a URR of 33.8 Gb there are 98,400 wells completed.

[James Gautreau + 86]

I don't know. If there is 46 GB down there why is production growth slowing to a crawl? By my calculations 6 GB has been produced. We should not see production growth slowing until another 17 GB have been produced which is 50% of recoverable reserves and the peak production. Now that nomenclature really does not apply to LTO since it is for the most part front loaded, and by that it means things are much worse than we thought. 

Edited December 24, 2019 by James Gautreau

[D Coyne + 305]

2 hours ago, James Gautreau said:

I see your point. I don't know the EUR of nat gas for a typical well. 

Oil production thousand barrels/day				Gas production million cubic feet/day
Region	December 2019	January 2020	change		December 2019	January 2020	change
Anadarko	568	553	(15)		7,655	7,523	(132)
Appalachia	169	171	2		33,506	33,432	(74)
Bakken	1,523	1,526	3		3,115	3,118	3
Eagle Ford	1,366	1,357	(9)		6,844	6,775	(69)
Haynesville	39	39	-		11,962	12,085	123
Niobrara	746	747	1		5,575	5,588	13
Permian	4,694	4,742	48		16,864	17,077	213
Total	9,105	9,135	30		85,521	85,598	77

 

By my calculations 9,105,000 X$60 is $546 million a day in oil revenue. Since 1 mbtu is basically 1 mcf (1.036 is the conversion) then I figure 85,600 X 2.17 is $185,000 a day in nat gas revenue. Am I missing something? Calculating it wrong. I do know worldwide the nat gas market is roughly half the size of the oil market. 

James,

It is 85,600 million cubic feet, one million cubic feet is 1000 times a MCF so 85,600 times 2.17 times 1000=$185 million per day.

For the average 2017 Permian basin tight oil well the EUR of natural gas is about 1630 million cubic feet over the life of the well, the oil EUR is about 385 kbo.  Permian basin wells normalized by lateral length have had pretty steady oil EUR from 2016 to 2019.

At some point the EUR will decrease as sweet spots become fully drilled, but so far there is little evidence this has occurred.

Breakeven price where the present value of the discounted net revenue over the life of the well is equal to the full cycle cost of the well is $52/bo (in constant 2018$) at the wellhead assuming wellhead natural gas price of 1.50/MCF and I assume an extra 25% for NGL sales so $1.875/MCF at wellhead (including the extra revenue from NGL sales).

Edited December 24, 2019 by D Coyne

[D Coyne + 305]

15 minutes ago, James Gautreau said:

I don't know. If there is 46 GB down there why is production growth slowing to a crawl? By my calculations 6 GB has been produced. We should not see production growth slowing until another 17 GB have been produced which is 50% of recoverable reserves and the peak production. Now that nomenclature really does not apply to LTO since it is for the most part front loaded, and by that it means things are much worse than we thought. 

James,

The trendline annual growth rate for Permian output from Feb 2019 to October 2019 is 841 kb/d growth each year, that is slower than the 2018 annual growth rate (1170 kb/d), but that is in part due to lower oil prices in 2019.

Ignore the EIA's DPR, especially the last 3 months of their forecast (it is garbage).  Best estimates at link below

https://www.eia.gov/energyexplained/oil-and-petroleum-products/data/US-tight-oil-production.xlsx

Growth rates depend on completion rates which depend on the price of oil, if oil prices rise, completion rates will rise and growth rates will increase.

[Gerry Maddoux + 3,627]

12 minutes ago, James Gautreau said:

I don't know. If there is 46 GB down there why is production growth slowing to a crawl? 

The sound you fellows hear is my pounding the table. I tell you, the reason shale is going bust is b/c all the producers have been either paying to get their NG burden taken away, or they're selling it for nothing--depending on where you are. If Chevron wrote down $11B in one quarter, what do you think it cost Pioneer (who has no Petchem plants, refineries, or offshore to offset the loss)? Has to be murderous. 

I understand that there are several other LNG companies out there, esp. from Australia and Qatar (partnering with Exxon, per usual). However, if Chevron, again as an example, had enough resources to merely haul off their own endogenous NG production, it would make them dominant over everyone else: immediately. I still maintain that this is the only solution to this sordid mess we have in the shale basins. 

Improved sensors, computer software, and machine learning: cost reduction of 10-20% in drilling and completion. Electric fracking using wellhead NG: maybe another 10% cut. Production: goes up perhaps 10-20%. That's a lot but it comes with extra cost per well, too.

The only way out, the only thing that will keep shale going, is for the drillers/operators to get into the LNG business. That's the only lucrative aspect in the whole shebang right now. There's not an LNG company out there that can withstand a hostile takeover attempt by a company like Chevron. Now. But give Cheniere another two years and they might be trying to buy Chevron. The LNG market is going that fast.

[James Gautreau + 86]

2015	9,383	9,507	9,585	9,655	9,474	9,354	9,442	9,415	9,478	9,396	9,322	9,263
2016	9,197	9,056	9,089	8,869	8,823	8,654	8,646	8,676	8,534	8,834	8,897	8,798
2017	8,863	9,103	9,162	9,100	9,183	9,107	9,235	9,248	9,512	9,653	10,071	9,973
2018	10,018	10,281	10,504	10,510	10,460	10,649	10,891	11,361	11,498	11,631	11,999	12,038
2019	11,856	11,669	11,892	12,123	12,113	12,060	11,823	12,397	12,463

[James Gautreau + 86]

From the end of last year to now is 425 K growth. It was 2 million in 2018. The first 6 months of 2018 was flat. That's when they started hitting the DUC's. But DUC completions dropped from 225 to 131 last month, nearly half. That probably means the 7500 DUC's are mostly not frackable based on geological readings; in other words it is an illusion of quickly being able to ramp up production. 

Edited December 24, 2019 by James Gautreau

[James Gautreau + 86]

2 minutes ago, Gerry Maddoux said:

The sound you fellows hear is my pounding the table. I tell you, the reason shale is going bust is b/c all the producers have been either paying to get their NG burden taken away, or they're selling it for nothing--depending on where you are. If Chevron wrote down $11B in one quarter, what do you think it cost Pioneer (who has no Petchem plants, refineries, or offshore to offset the loss)? Has to be murderous. 

I understand that there are several other LNG companies out there, esp. from Australia and Qatar (partnering with Exxon, per usual). However, if Chevron, again as an example, had enough resources to merely haul off their own endogenous NG production, it would make them dominant over everyone else: immediately. I still maintain that this is the only solution to this sordid mess we have in the shale basins. 

Improved sensors, computer software, and machine learning: cost reduction of 10-20% in drilling and completion. Electric fracking using wellhead NG: maybe another 10% cut. Production: goes up perhaps 10-20%. That's a lot but it comes with extra cost per well, too.

The only way out, the only thing that will keep shale going, is for the drillers/operators to get into the LNG business. That's the only lucrative aspect in the whole shebang right now. There's not an LNG company out there that can withstand a hostile takeover attempt by a company like Chevron. Now. But give Cheniere another two years and they might be trying to buy Chevron. The LNG market is going that fast.

Well it's obvious Exxon agrees with you. Buying the Permian and building an LNG plant in Texas, that says it all. That's the part the Independents got wrong. 

[Gerry Maddoux + 3,627]

Just now, James Gautreau said:

From the end of last year to now is 425 K growth. It was 2 million in 2018. 

Right, b/c nobody can make any money, despite what you've been reading on this site for months now. Not at $50. If Chevron can't make money with their breadth and depth of scale, who can? 

In our best oil wells (conventional) over the last few decades, if you'd zeroed out the NG, we wouldn't have made 50% as much. Granted, the price of NG was higher for most of that time and we had wells in gassy areas, but still, NG has always helped make or break a well. X this out and you have one big splat. Make the NG by-product burden as large as it is in the Permian and you've got yourself a major problem. 

[James Gautreau + 86]

From Oilprice.com

Permian wells getting gassier. Permian shale wells are producing a higher gas-to-oil ratio than expected, another blow to shale drillers’ profits. “Activity levels are no longer what they were,” said Artem Abramov, head of shale research at Rystad Energy. “The oil ratio is no longer sufficient to offset gas in older wells, so we’re seeing some increase in basin-wide” gas-to-oil ratios. The focus on the Delaware sub-basin is also contributing, as that area is gassier. 

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[D Coyne + 305]

11 minutes ago, James Gautreau said:

From the end of last year to now is 425 K growth. It was 2 million in 2018. 

James,

Use

https://www.eia.gov/energyexplained/oil-and-petroleum-products/data/US-tight-oil-production.xlsx

Permian is sum of spraberry, wolfcamp, and bonespring output.

For past 2 years growth rate has been about 930 kb/d, see chart of Permian basin tight oil output in kb/d.

[Gerry Maddoux + 3,627]

Permian wells getting gassier. Permian shale wells are producing a higher gas-to-oil ratio than expected, another blow to shale drillers’ profits. “Activity levels are no longer what they were,” said Artem Abramov, head of shale research at Rystad Energy. “The oil ratio is no longer sufficient to offset gas in older wells, so we’re seeing some increase in basin-wide” gas-to-oil ratios. The focus on the Delaware sub-basin is also contributing, as that area is gassier. 

 

And who's profiting from that? Not CVX, OXY, XOM. Let's see now, would it be Cheniere? I rest my case.

[James Gautreau + 86]

1 minute ago, D Coyne said:

James,

Use

https://www.eia.gov/energyexplained/oil-and-petroleum-products/data/US-tight-oil-production.xlsx

Permian is sum of spraberry, wolfcamp, and bonespring output.

For past 2 years growth rate has been about 930 kb/d, see chart of Permian basin tight oil output in kb/d.

From what I've been told by the EIA, the monthly numbers are the best hard data out there. The weekly numbers are guesses based on models like the one you've shown. There is a 2 month lag so they can collect the actual data. The above model does not show the flat line of the first 6 months of 2019. 

[James Gautreau + 86]

My mistake I'm talking national and you're talking Permian.

[D Coyne + 305]

12 minutes ago, Gerry Maddoux said:

Right, b/c nobody can make any money, despite what you've been reading on this site for months now. Not at $50. If Chevron can't make money with their breadth and depth of scale, who can? 

In our best oil wells (conventional) over the last few decades, if you'd zeroed out the NG, we wouldn't have made 50% as much. Granted, the price of NG was higher for most of that time and we had wells in gassy areas, but still, NG has always helped make or break a well. X this out and you have one big splat. Make the NG by-product burden as large as it is in the Permian and you've got yourself a major problem. 

Gerry,

In my models I assume eventually the natural gas will be sold, not all of it is flared, my natural gas price assumption is pretty conservative at $1.50/MCF ($1.87/MCF when we account for NGL sales), if we bump the natural gas price assumption up to say $2.50/MCF ($3.125/MCF when NGL sales are included), the breakeven price for the average 2017 Permian basin well falls from $52/bo at wellhead to $47/bo at wellhead.

Note that not all of the natural gas is vented or flared, some gets sold, though it has been very cheap.  As pipelines open up to remove the bottle neck the economics will change.

[D Coyne + 305]

8 minutes ago, James Gautreau said:

From what I've been told by the EIA, the monthly numbers are the best hard data out there. The weekly numbers are guesses based on models like the one you've shown. There is a 2 month lag so they can collect the actual data. The above model does not show the flat line of the first 6 months of 2019. 

James,

See "tight oil production estimates by play" at page linked below.

https://www.eia.gov/petroleum/data.php#crude

Chart below is what you get at the link, notice the text in the yellow box (I added the yellow box to highlight).

[James Gautreau + 86]

10 minutes ago, D Coyne said:

James,

See "tight oil production estimates by play" at page linked below.

https://www.eia.gov/petroleum/data.php#crude

Chart below is what you get at the link, notice the text in the yellow box (I added the yellow box to highlight).

Why doesn't this chart show the declines in Oklahoma. I read it was a  complete bust. 

[D Coyne + 305]

Newer tight oil data is out.

Permian basin from Dec 2017 to Nov 2018 and from Dec 2018 to Nov 2019 with linear trend, there has been a slow down from an 1175 kb/d annual increase in the earlier 12 months to a 765 kb/d annual increase in the most recent 12 months.  Part of the explanation is lower oil prices lately compared to 2018.

[D Coyne + 305]

10 minutes ago, James Gautreau said:

Why doesn't this chart show the declines in Oklahoma. I read it was a  complete bust. 

Can't see it because output is so low.

Check spreadsheet

https://www.eia.gov/energyexplained/oil-and-petroleum-products/data/US-tight-oil-production.xlsx

Chart for Oklahoma tight oil below