Raymond James - Why the EIA DUC Count is More Daffy than Donald

[James Regan + 1,776]

11 hours ago, Old-Ruffneck said:

You can't lose what you don't have. In time the wells will be producing and if you bought into the futures you assume the risk also of each hole that gets drilled and not completed in the couple month window some would like. Drilling rigs aren't just plopped on a location and start drilling as the cost. Method to the madness, just gonna take some time to sort out the vast amount of DUC wells. So like I have said before, buyer beware!! If you can't wait on your return, don't buy into the game. 

If you are correct then we are talking about a completely different animal to a conventional viable producing and investment viable Oil well. Which is a valid point you bring up as it shows that Shale oil plays are not long term and also shows how fickle this side of the industry is. A conventional well will produce and be able to be worked over for tens of years therefore each day not producing is lost money. Shale not fitting into this box indicates it’s not a long term healthy investment. IMO...

[wrs + 893]

17 minutes ago, James Regan said:

If you are correct then we are talking about a completely different animal to a conventional viable producing and investment viable Oil well. Which is a valid point you bring up as it shows that Shale oil plays are not long term and also shows how fickle this side of the industry is. A conventional well will produce and be able to be worked over for tens of years therefore each day not producing is lost money. Shale not fitting into this box indicates it’s not a long term healthy investment. IMO...

What level of output are you claiming for these "conventional" wells you speak of?  We have had a number of them over the years and they barely produced in their entire life what a shale well on the same tract produced in a couple of months.  I calculated that the most recent ones we had which were drilled in the early 90s and late 80s still took 20 years to pay out and at that point were only producing a few barrels per day at that point.  What kind of return is that?

[James Regan + 1,776]

I’m talking about oil wells of 150,000Bbls/day plus, to be honest I’ve never been around the land side but never the less it all takes capital at cost to drill any well and once any funding is given the clock is ticking, milestones must be met and deliverables delivered, that’s the kind of projects I am involved with, where there is accountability and fiscal measures which must be accounted for. Maybe we are talking about two different industries?

[Douglas Buckland + 6,308]

I am not familiar with the legal 'in's & out's' of the US shale game, but it continually sounds like the 'shell game'. Pun intended.

[Mike Shellman + 548]

On 3/29/2019 at 8:56 AM, James Regan said:

 Maybe we are talking about two different industries?

Indeed, sir.

In fact, some of the comments on this thread evidence the fact that until the onslaught of the US shale oil phenomena, not very many people paid much attention to the oil business at all. For instance, the entire world was industrialized, and is what it is today, because of abundant, inexpensive conventional oil and natural gas production...not shale oil, nor shale gas. Shale oil extraction is only ten years old, is deeply in debt, and as an industry has not made any profit, yet. As to conventional production in the Permian Basin, for instance, from 1920 to 2012 over 27G BO and 68 TCF of natural gas has been produced from conventional sources, most of that incredibly "profitable" and, I hope folks are sitting down, all those wells eventually became evil stripper wells. While your sitting down, every stinkin' shale oil well in America is on its way to becoming a stripper well...if it does not reach its economic limits before 15 BOPD, which I suspect many will. 

Setting casing on a $3-5MM well and letting it sit for years, with no revenue generated from it, while paying 5-8% interest rates on the $3-5MM CAPEX, is unique to the shale phenomena. It occurs strictly thru the use of other people's money (shareholder stock purchases, bonds, junk bonds, bank loans, MLP's, private equity, etc.) and because nobody making those business decisions is personally on the hook for default. Hess, for instance, has/had nearly 500 DUC wells in the Bakken that it drilled when the price of oil was in the $70's and $80's, and now it is completing them with prices in the low $50's in North Dakota. That's smart? If you don't have a market for your oil, or all that gas being flared, leave the shit in the ground until you do. Nobody in their right mind, with their own money, is going to spend $3-5MM and let it sit for years earning nothing. 

DUC's are a side affect of onerous continuous drilling commitments and retained acreage clauses. The poor relationship between parent and child wells and obvious over-drilling in sweet spots is also a side affect of continuous drilling commitments. DUC's can be used to extend primary terms and in the shale oil business are, in fact, almost always "booked" as having proven undeveloped reserves (PUD) in them. That is why they are used so conveniently by the shale oil industry; the SEC will allow proximity based PUD reserves in DUC wells, a percentage of which the shale oil industry can borrow more money against, and go drill more wells elsewhere. The SEC then allows you 5 years to turn those PUD reserves into proven developed reserves. In many areas they have drilled child wells so close together, their economics so poor, child DUC's might not ever be completed. 

 

 

 

Edited March 31, 2019 by Mike Shellman

[Outlaw Jackie + 78]

As Mike Shellman points out, this shale development is a fairly new technology.  It started on gas plays like the Barnett, and then was tried on oil. Because of this, some of the older DUC's may never be completed because of poor geosteering and boreholes not being properly landed in the formation. They simply did not know what they were doing, and after all, it was other people's money...

[wrs + 893]

23 hours ago, Mike Shellman said:

Indeed, sir.

In fact, some of the comments on this thread evidence the fact that until the onslaught of the US shale oil phenomena, not very many people paid much attention to the oil business at all. For instance, the entire world was industrialized, and is what it is today, because of abundant, inexpensive conventional oil and natural gas production...not shale oil, nor shale gas. Shale oil extraction is only ten years old, is deeply in debt, and as an industry has not made any profit, yet. As to conventional production in the Permian Basin, for instance, from 1920 to 2012 over 27G BO and 68 TCF of natural gas has been produced from conventional sources, most of that incredibly "profitable" and, I hope folks are sitting down, all those wells eventually became evil stripper wells. While your sitting down, every stinkin' shale oil well in America is on its way to becoming a stripper well...if it does not reach its economic limits before 15 BOPD, which I suspect many will. 

Setting casing on a $3-5MM well and letting it sit for years, with no revenue generated from it, while paying 5-8% interest rates on the $3-5MM CAPEX, is unique to the shale phenomena. It occurs strictly thru the use of other people's money (shareholder stock purchases, bonds, junk bonds, bank loans, MLP's, private equity, etc.) and because nobody making those business decisions is personally on the hook for default. Hess, for instance, has/had nearly 500 DUC wells in the Bakken that it drilled when the price of oil was in the $70's and $80's, and now it is completing them with prices in the low $50's in North Dakota. That's smart? If you don't have a market for your oil, or all that gas being flared, leave the shit in the ground until you do. Nobody in their right mind, with their own money, is going to spend $3-5MM and let it sit for years earning nothing. 

DUC's are a side affect of onerous continuous drilling commitments and retained acreage clauses. The poor relationship between parent and child wells and obvious over-drilling in sweet spots is also a side affect of continuous drilling commitments. DUC's can be used to extend primary terms and in the shale oil business are, in fact, almost always "booked" as having proven undeveloped reserves (PUD) in them. That is why they are used so conveniently by the shale oil industry; the SEC will allow proximity based PUD reserves in DUC wells, a percentage of which the shale oil industry can borrow more money against, and go drill more wells elsewhere. The SEC then allows you 5 years to turn those PUD reserves into proven developed reserves. In many areas they have drilled child wells so close together, their economics so poor, child DUC's might not ever be completed. 

 

 

 

I am not sure that shale wells will ever be stripper wells, they will instead just be shut-in because you can't use the same lift techniques on horizontal wells to produce a trickle like the vertical stripper wells.  The geology is entirely different, the flows are entirely different as is the technology for lifting the product.  

I agree that more output now isn't a good idea and that the industry should scale back and save some money by not drilling nearly as much as they have been the last couple of years.  I think they are doing that, we should see a plateau in US production by June I think.  The rig count is dropping and that always has a lagging effect.  With rig counts having plateaued and starting to decline in the Permian, production should be doing the same.

[D Coyne + 305]

On ‎3‎/‎31‎/‎2019 at 12:42 PM, Mike Shellman said:

Indeed, sir.

In fact, some of the comments on this thread evidence the fact that until the onslaught of the US shale oil phenomena, not very many people paid much attention to the oil business at all. For instance, the entire world was industrialized, and is what it is today, because of abundant, inexpensive conventional oil and natural gas production...not shale oil, nor shale gas. Shale oil extraction is only ten years old, is deeply in debt, and as an industry has not made any profit, yet. As to conventional production in the Permian Basin, for instance, from 1920 to 2012 over 27G BO and 68 TCF of natural gas has been produced from conventional sources, most of that incredibly "profitable" and, I hope folks are sitting down, all those wells eventually became evil stripper wells. While your sitting down, every stinkin' shale oil well in America is on its way to becoming a stripper well...if it does not reach its economic limits before 15 BOPD, which I suspect many will. 

Setting casing on a $3-5MM well and letting it sit for years, with no revenue generated from it, while paying 5-8% interest rates on the $3-5MM CAPEX, is unique to the shale phenomena. It occurs strictly thru the use of other people's money (shareholder stock purchases, bonds, junk bonds, bank loans, MLP's, private equity, etc.) and because nobody making those business decisions is personally on the hook for default. Hess, for instance, has/had nearly 500 DUC wells in the Bakken that it drilled when the price of oil was in the $70's and $80's, and now it is completing them with prices in the low $50's in North Dakota. That's smart? If you don't have a market for your oil, or all that gas being flared, leave the shit in the ground until you do. Nobody in their right mind, with their own money, is going to spend $3-5MM and let it sit for years earning nothing. 

DUC's are a side affect of onerous continuous drilling commitments and retained acreage clauses. The poor relationship between parent and child wells and obvious over-drilling in sweet spots is also a side affect of continuous drilling commitments. DUC's can be used to extend primary terms and in the shale oil business are, in fact, almost always "booked" as having proven undeveloped reserves (PUD) in them. That is why they are used so conveniently by the shale oil industry; the SEC will allow proximity based PUD reserves in DUC wells, a percentage of which the shale oil industry can borrow more money against, and go drill more wells elsewhere. The SEC then allows you 5 years to turn those PUD reserves into proven developed reserves. In many areas they have drilled child wells so close together, their economics so poor, child DUC's might not ever be completed. 

 

 

 

Thanks Mike.  I learn a ton with every comment of yours that I read.  Do we have any idea how many of these DUCs (10%, 20%?) are not likely to be completed due to spacing that is suboptimal?

In another thread claims have been made that Permian wells are at a breakeven price of $25/b at the well head.  I tried to point out that is not true if we assume 33% of wellhead revenue goes to royalty and tax payments and LOE is about $13/b (possibly too low), this would suggest an average Permian Basin well completed in 2017 with average cumulative output of about 284 kb after 60 months (which might be considered a minimum for payout, 36 months would be better). So 67% of 25 is $16.75/b and after LOE we would have take home pay of $3.75/b.  Multiply by 284,000 barrels and we have $1.065 million of net revenue after 60 months.

I believe you have suggested that an average Permian horizontal oil well cost (full cycle) is about $10 million.  As far as I can tell, the average 2017 Permian well would come up almost $9 million short of breakeven at $25/b at the well head. The reality is that more like $65 to $70/b is needed at the wellhead for an average 2017 Permian basin horizontal tight oil well to break even, many people don't seem to get this. 

Edited April 1, 2019 by D Coyne

[Mike Shellman + 548]

Dennis, the stuff I get indicates Midland Basin wells are around $7.5-8.5MM and Delaware Basin wells $9.5-10.5MM, full cycle. Shale oil economic analysis that conveniently leaves out costs is like buying a new car to find wheels and tires are extra. XOM's $15/BO BE would be like buying a car with no engine. The E in BOE is now NA so I believe most PB wells have to ultimately recover 450K or BO to payout.

I think the DUC's that won't get completed, or that will have to be plugged back with new, costly laterals to different benches (because of over drilling) will be much higher than 20%; just my take. What will be interesting to me is the ensuing reserve impairments that companies will have to take and what THAT will do, along with already over exaggerated EUR's, to debt to asset ratios. 

By the way, after shale oil wells are gutted with ESP's and gas lift, etc. they all ultimately go on rod lift, or will; there are tens of thousands of rod lift wells in all four of the major shale basins.  They are pumped from the top of the radius and when gas is pooped off and fluid conductivity wanes, most of these rod lift wells go on pump off controls waiting for well bores to fill up, so to speak. Half of the Eagle Ford shale oil wells I drive by every day have lost their umphf and are on POC. At that point in the well's life rod lift is the only AF that is economic. So they all, wherever, end up being, and looking like stripper wells, lifted in conventional rod lift manners... until they reach economic limits.   

 

[wrs + 893]

Here are the results of the 6 wells that XTO has filed IPs for to date on my section.  They have one well left to file and I don't know if they have done the testing and just not filed yet or what.  Oil production in January was 93kbbl and that was apparently from only three wells unless they had 1h going which I can't tell because all of the data for the lease is consolidated still.  Gas production increased in February to 530mmcf but oil production fell to 78kbbl.  However, I think that might be due to limitations on their pipeline capacity and that they are likely constraining production so as not to flare too much.  Only 22mmcf was flared in February.

The three wells that came online in late December and early January had total oil IP of 3522bbl/day and that is consistent with the 93kbbl oil production.  They also had a combined 14297mcf/day gas production which is consistent with the production report of 350mmcf gas production for January.   What I don't understand is what combination of wells produced the data for February.  The oil could be attributed to the three wells that were started at the end of January and beginning of February but the gas for those wells is only half of what their IP would be for 28 days.  Clearly they are constraining production somewhere while they are still bringing on wells.  BOE does matter.

2h -- 1/29/2019   1126 bbl  3734 mcf  TVD 10168   1770 BOE/day Wolfcamp A

3h -- 1/31/2019   1244 bbl  3257 mcf  TVD 9905     1805 BOE/day Wolfcamp A

4h -- 12/23/2018 1257 bbl  4817 mcf  TVD 10205   2087 BOE/day Wolfcamp A

5h -- 12/31/2018 1410 bbl  5598 mcf  TVD 10002   2222 BOE/day Wolfcamp A

11h -- 2/2/2019    327  bbl  1392 mcf  TVD  9703    562   BOE/day  Bone Springs 

12h -- 1/2/2019   855   bbl  3882 mcf  TVD  9749    1524 BOE/day  Bone Springs

Edited April 1, 2019 by wrs

[D Coyne + 305]

25 minutes ago, wrs said:

Here are the results of the 6 wells that XTO has filed IPs for to date on my section.  They have one well left to file and I don't know if they have done the testing and just not filed yet or what.  Oil production in January was 93kbbl and that was apparently from only three wells unless they had 1h going which I can't tell because all of the data for the lease is consolidated still.  Gas production increased in February to 530mmcf but oil production fell to 78kbbl.  However, I think that might be due to limitations on their pipeline capacity and that they are likely constraining production so as not to flare too much.  Only 22mmcf was flared in February.

The three wells that came online in late December and early January had total oil IP of 3522bbl/day and that is consistent with the 93kbbl oil production.  They also had a combined 14297mcf/day gas production which is consistent with the production report of 350mmcf gas production for January.   What I don't understand is what combination of wells produced the data for February.  The oil could be attributed to the three wells that were started at the end of January and beginning of February but the gas for those wells is only half of what their IP would be for 28 days.  Clearly they are constraining production somewhere while they are still bringing on wells.  BOE does matter.

2h -- 1/29/2019   1126 bbl  3734 mcf  TVD 10168   1770 BOE/day Wolfcamp A

3h -- 1/31/2019   1244 bbl  3257 mcf  TVD 9905     1805 BOE/day Wolfcamp A

4h -- 12/23/2018 1257 bbl  4817 mcf  TVD 10205   2087 BOE/day Wolfcamp A

5h -- 12/31/2018 1410 bbl  5598 mcf  TVD 10002   2222 BOE/day Wolfcamp A

11h -- 2/2/2019    327  bbl  1392 mcf  TVD  9703    562   BOE/day  Bone Springs 

12h -- 1/2/2019   855   bbl  3882 mcf  TVD  9749    1524 BOE/day  Bone Springs

wrs,

I think when Mike says BOE doesn't matter, he means it does very little to help the bottom line when natural gas prices are negative or close to zero. It's mostly the oil that makes the well profitable when natural gas prices are very low.  

[D Coyne + 305]

2 hours ago, Mike Shellman said:

Dennis, the stuff I get indicates Midland Basin wells are around $7.5-8.5MM and Delaware Basin wells $9.5-10.5MM, full cycle. Shale oil economic analysis that conveniently leaves out costs is like buying a new car to find wheels and tires are extra. XOM's $15/BO BE would be like buying a car with no engine. The E in BOE is now NA so I believe most PB wells have to ultimately recover 450K or BO to payout.

I think the DUC's that won't get completed, or that will have to be plugged back with new, costly laterals to different benches (because of over drilling) will be much higher than 20%; just my take. What will be interesting to me is the ensuing reserve impairments that companies will have to take and what THAT will do, along with already over exaggerated EUR's, to debt to asset ratios. 

By the way, after shale oil wells are gutted with ESP's and gas lift, etc. they all ultimately go on rod lift, or will; there are tens of thousands of rod lift wells in all four of the major shale basins.  They are pumped from the top of the radius and when gas is pooped off and fluid conductivity wanes, most of these rod lift wells go on pump off controls waiting for well bores to fill up, so to speak. Half of the Eagle Ford shale oil wells I drive by every day have lost their umphf and are on POC. At that point in the well's life rod lift is the only AF that is economic. So they all, wherever, end up being, and looking like stripper wells, lifted in conventional rod lift manners... until they reach economic limits.   

 

Thanks Mike, great stuff.  If I use an annual discount rate of 10% and an oil price of $50/b at the well head (where I assume this is a "real price" that will gradually increase with inflation, assumed to be at a constant annual rate of 2.5%/year) then the discounted net revenue over the life of the well is $8.1 million, so for the midland basin well that produces at the entire Permian basin average of 384 kbo over its life the well barely breaks even at a well cost of $8 million.  The Delaware basin wells would need about $59/bo at the wellhead for discounted net revenue (discount rate 10%) to reach $10 million, again the $59/bo oil price is in constant
2019$.  

On those POC Eagle Ford wells, if we assume oil prices at $80/b in 2019$ at the well head what would your guess be on the economic limit for such wells, my analysis suggests about 10 bo/d would probably be the limit and for a $10 million Delaware Wolfcamp well the annual ROI would be a pretty anemic 6%/year over the 17 year life of the well.  For the midland it would be a bit better at an annual ROI of 7.3% due to lower average well cost.

[wrs + 893]

1 hour ago, D Coyne said:

wrs,

I think when Mike says BOE doesn't matter, he means it does very little to help the bottom line when natural gas prices are negative or close to zero. It's mostly the oil that makes the well profitable when natural gas prices are very low.  

Right but he is wrong.  Natural gas prices aren't negative or close to zero and after processing you get more money than hub price because of ethane, butane, propane and natural gasoline.  Not everyone is connected to the same pipelines and so when you read WAHA hub prices that is not relevant for all producers in the Permian.  We haven't been paid on any of this new production yet because the DOs haven't all been signed.  However, the XTO gas production for November from the old well produced about $3.25/mcf while from the independent we got $4.58/mcf.  This was during a time that they were claiming zero or negative prices at WAHA.

Edited April 1, 2019 by wrs

[Mike Shellman + 548]

3 hours ago, wrs said:

Right but he is wrong

No I'm not wrong. 

WAHA postings matter, as does the 1+BCF of gas getting flared from the Permian and not stripped, and other BCF's that don't get stripped. I get that you make lots of money from family royalties. Good for you. If you have a 1/32 RI in the wells you outlined you must be making several hundred thousand dollars a month. Personally, I don't give a rats ass. Your good fortunes are not representative of what is going on out there. For instance, I don't get squat from associated gas anymore from that part of the world. The stupid shale oil phenomena is now producing more associated gas than is produced from gas wells in the entire APP Basin and there is no place to put the stuff anymore, anywhere. The price sucks. 

What I am interested in, and most other people are interested in, is general trends, economics, well interference, finances of shale oil companies facing reserve impairments, debt, interest on debt, debt maturities, prices and other things that might affect our hydrocarbon future in America. Like, for instance, how far our government is going to go to subsidize the gig with low interest stimulus. If your BS was all true and applicable to the entire basin, everybody out there would be out of debt, increasing rig counts, not decreasing rig counts and production would be going up, not down; dividends and share prices would be thru the roof and investors and lenders would all be really happy. Last I looked, they're not.  

 

 

 

 

 

 

Edited April 2, 2019 by Mike Shellman

[wrs + 893]

10 hours ago, Mike Shellman said:

No I'm not wrong. 

WAHA postings matter, as does the 1+BCF of gas getting flared from the Permian and not stripped, and other BCF's that don't get stripped. I get that you make lots of money from family royalties. Good for you. If you have a 1/32 RI in the wells you outlined you must be making several hundred thousand dollars a month. Personally, I don't give a rats ass. Your good fortunes are not representative of what is going on out there. For instance, I don't get squat from associated gas anymore from that part of the world. The stupid shale oil phenomena is now producing more associated gas than is produced from gas wells in the entire APP Basin and there is no place to put the stuff anymore, anywhere. The price sucks. 

What I am interested in, and most other people are interested in, is general trends, economics, well interference, finances of shale oil companies facing reserve impairments, debt, interest on debt, debt maturities, prices and other things that might affect our hydrocarbon future in America. Like, for instance, how far our government is going to go to subsidize the gig with low interest stimulus. If your BS was all true and applicable to the entire basin, everybody out there would be out of debt, increasing rig counts, not decreasing rig counts and production would be going up, not down; dividends and share prices would be thru the roof and investors and lenders would all be really happy. Last I looked, they're not.  

 

 

 

 

 

 

Man you don't get it at all and you are wrong.  All but one of these wells are gas wells in case you didn't notice the GOR while you were busy guessing at my royalties.  Good producers know they will get a lot of gas and they will make sure they have a place to put it BEFORE they complete their wells.  Irresponsible producers will think they can flare and hope.  I am sure there are a number of the latter but in every well I have had out there in both Reeves and Culberson county the gas has produced about 20-25% of the income stream.  We have had three operators now, BHP, XTO and Capitan, all of them sold their gas without flaring very much at all and have always paid good money for the gas except in a few months when gas prices were bad and that can happen but it's not by any means permanent.

You don't like the specifics because it contradicts your shale is a ponzi meme.  The low interest rates are a product of the Federal Reserve easy money policy (QE twist and so on).  You think the oil business is the only one living on low rates?  How about the auto industry?  Real Estate and most of all the stock market.  The entire dollar based economy runs on low interest rates and it's a ponzi which you live in, we all do.

What is making you mad is that I am giving specific examples of wells here that are profitable.  My sections are in a triangle with 12 miles on the long side and about 5 on the other two.  Two are in Reeves county and one in Culberson.  I don't think BHP did very well on the two they drilled but I know that Capitan is doing OK and I think XTO will given the IP on these wells.  They are better than the two in Culberson for sure and they are better than the initial well that XTO drilled in 2016 which had IP of 728 bbl oil and 1902mcf gas at a TVD of 10020.  Clearly they have learned something in the last two and a half years.  You are singing a tune that is out of date. 

I will say this.  I understand what it is to compete with companies that get free money when you don't.  I ran a high tech business on cash flow for 17 years here in Austin from 1993 to 2010, right through the dotcom mania.  We only had one money losing year, 1999 because of y2k.  It was hard to attract employees when we didn't have stock options and free investor money to rent fancy office space and have lot's of perks.  We survived and thrived.  Good business owners tend to do that.  

Edited April 2, 2019 by wrs

[D Coyne + 305]

1 hour ago, wrs said:

Man you don't get it at all and you are wrong.  All but one of these wells are gas wells in case you didn't notice the GOR while you were busy guessing at my royalties.  Good producers know they will get a lot of gas and they will make sure they have a place to put it BEFORE they complete their wells.  Irresponsible producers will think they can flare and hope.  I am sure there are a number of the latter but in every well I have had out there in both Reeves and Culberson county the gas has produced about 20-25% of the income stream.  We have had three operators now, BHP, XTO and Capitan, all of them sold their gas without flaring very much at all and have always paid good money for the gas except in a few months when gas prices were bad and that can happen but it's not by any means permanent.

You don't like the specifics because it contradicts your shale is a ponzi meme.  The low interest rates are a product of the Federal Reserve easy money policy (QE twist and so on).  You think the oil business is the only one living on low rates?  How about the auto industry?  Real Estate and most of all the stock market.  The entire dollar based economy runs on low interest rates and it's a ponzi which you live in, we all do.

What is making you mad is that I am giving specific examples of wells here that are profitable.  My sections are in a triangle with 12 miles on the long side and about 5 on the other two.  Two are in Reeves county and one in Culberson.  I don't think BHP did very well on the two they drilled but I know that Capitan is doing OK and I think XTO will given the IP on these wells.  They are better than the two in Culberson for sure and they are better than the initial well that XTO drilled in 2016 which had IP of 728 bbl oil and 1902mcf gas at a TVD of 10020.  Clearly they have learned something in the last two and a half years.  You are singing a tune that is out of date. 

I will say this.  I understand what it is to compete with companies that get free money when you don't.  I ran a high tech business on cash flow for 17 years here in Austin from 1993 to 2010, right through the dotcom mania.  We only had one money losing year, 1999 because of y2k.  It was hard to attract employees when we didn't have stock options and free investor money to rent fancy office space and have lot's of perks.  We survived and thrived.  Good business owners tend to do that.  

WRS,

No it is you who don't get it.  Have you ever taken a course in statistics?  Here is a simple example.  Lebron James is a great basketball player, your wells are also very nice wells, perhaps the level of an all star professional basketball player compared to the league average player.  Not all players are all stars, and all tight oil wells are not profitable, most of the gas being produced is being flared in the Permian basin last I checked you don't get a dime for natural gas that is flared and the NGL goes up in smoke as well.  Mike's point is that there aren't many "good producers" as is evident from the amount of natural gas being flared in West Texas, fact is there is not enough pipe to move the gas.  Also just remembering that XTO is owned by XOM, so very deep pockets and they probably have all the pipe locked up that they need, many independents do not have that luxury.  XTO will be limited by available pipeline capacity.

So far the productivity of their wells is unremarkable.  For the entire Permian basin 2016 wells the 25 month cumulative was 186 kbo (2247 wells), for the 102 XOM wells which started producing in 2016 the 25 month cumulative was 174 kbo with cumulative gas at 347 MMcf, this suggests about 90% of revenue comes from oil at $60/b and $2.50/Mcf, unsure of how many average barrels of NGL per Mcf of NG.

Edited April 2, 2019 by D Coyne

[wrs + 893]

24 minutes ago, D Coyne said:

WRS,

No it is you who don't get it.  Have you ever taken a course in statistics?  Here is a simple example.  Lebron James is a great basketball player, your wells are also very nice wells, perhaps the level of an all star professional basketball player compared to the league average player.  Not all players are all stars, and all tight oil wells are not profitable, most of the gas being produced is being flared in the Permian basin last I checked you don't get a dime for natural gas that is flared and the NGL goes up in smoke as well.  Mike's point is that there aren't many "good producers" as is evident from the amount of natural gas being flared in West Texas, fact is there is not enough pipe to move the gas.  

What is your source for the data you claim?  Statistics require data and I see very little of that around here.  I am providing data to back up my claims and so far, you guys are providing generalizations without much data.  These vague references to "shale industry debt" and "shale industry cash flow" aren't useful data points.

As you can see in the data I produced from the XTO results, the first well they drilled in 2016 was IP of 728 bbl oil and 1902 mcf at 10020 TVD.  Look at the IPs for the wells at the same depths in the new group.  They are 50% to 95% better in oil.  These are all on the same section and on the same side of the section as the original 1h well.  Kind of kills all this chatter about sweet spots and infill wells and other such blather that is constantly spouted around here without a single iota of supporting data that I have seen.  It appears that they have drilled these wells on a wine rack spacing model and are getting fantastic production.  

BTW, I have a Masters in Engineering from UT Austin along with a BA in CS and a BSEE, I have the equivalent of a BS in math because of all the math courses I took over the years getting those degrees and I made a 100 on the engineering statistics course final so yes, I know more than a little about statistics.

Edited April 2, 2019 by wrs

[D Coyne + 305]

1 hour ago, wrs said:

What is your source for the data you claim?  Statistics require data and I see very little of that around here.  I am providing data to back up my claims and so far, you guys are providing generalizations without much data.  These vague references to "shale industry debt" and "shale industry cash flow" aren't useful data points.

As you can see in the data I produced from the XTO results, the first well they drilled was IP of 728 bbl oil and 1902 mcf at 10020 TVD.  Look at the IPs for the wells at the same depths in the new group.  They are 50% to 95% better in oil.  These are all on the same section and on the same side of the section as the original 1h well.  Kind of kills all this chatter about sweet spots and infill wells and other such blather that is constantly spouted around here without a single iota of supporting data that I have seen.  It appears that they have drilled these wells on a wine rack spacing model and are getting fantastic production.  

BTW, I have a Masters in Engineering from UT Austin along with a BA in CS and a BSEE, I have the equivalent of a BS in math because of all the math courses I took over the years getting those degrees and I made a 100 on the engineering statistics course final so yes, I know more than a little about statistics.

Great, for some data see

https://shaleprofile.com/2019/04/01/permian-update-through-december-2018/

XOM is unremarkable as far as productivity.  The increases in average well productivity has been due to an increase in lateral length and pounds of proppant per lateral foot.

see

https://shaleprofile.com/permian-basin-report/

For a statistical approach to the oil depletion problem see

https://www.amazon.com/Mathematical-Geoenergy-Discovery-Depletion-Geophysical/dp/1119434297

Seems you need to think bigger picture, the Permian basin is about 86,000 square miles, the area you are talking about may indeed be a sweet spot, though IPs don't really tell us very much, we need an output curve over the first 18 to 24 months to give us a better picture, see shaleprofile.com for some well profiles in well quality tab.  You can also look at the productivity distribution tab in the advanced insights to get an idea of the statistics.

Your 3 wells look to be pretty nice wells, a little better than average for the average 2018 well which had maximum monthly output at 731 b/d with your wells at about an average of 1000 b/d for the month of January. Your wells are probably in the top 20% of wells completed in the Permian for 2017 (I don't have data yet for the 2018 distribution.)

Edited April 2, 2019 by D Coyne

[wrs + 893]

I read those when they were first posted.  So what?  The laterals on these wells are all in the 4400 foot range because this is a single section one mile square, 640 acres.  No longer lateral games here.  This is a sweeter spot than the wells in Culberson for sure although it wasn't apparent from the original well XTO drilled in 2016.  You care to comment on that?  This section is 12 miles from the Culberson section, care to comment on that?  These are fairly random locations.

Edited April 2, 2019 by wrs

[D Coyne + 305]

Some areas have better geology than others, and there will be random differences in natural fracturing and such from place to place, again there is natural randomness in nature as I imagine you are aware, this is the reason why picking a very small random sample (as in 3 wells out of 19,000 wells completed) might not capture the statistics of the population very well, this is pretty basic statistics.  I am rather surprised that you would think that statistics from 3 wells tells us very much or that a single point (IP) on a production curve is very descriptive.

Also we would need to know if the lateral lengths, proppant loading and so forth were the same and even then there can be big changes even in the space of 12 miles or less.  Focusing on a couple of wells tells us very little about how the industry as a whole is doing.

Note that you asked about data, there is plenty of data at shaleprofile.com for the entire Permian Basin, as well as North Dakota Bakken, Eagle Ford, Niobrara, etc.

Using that data and fitting a hyperbolic to the first 24 months of data we can develop a well profile for the average 2016 well, the average 2017 well is very close after 12 months so I use the 2017 data for the first 12 months added to 2016 well profile from month 13 to 24 to estimate a hyperbolic well profile, terminal decline is assumed to be 15%.

 

Edited April 2, 2019 by D Coyne

[D Coyne + 305]

4 hours ago, wrs said:

What is your source for the data you claim?  Statistics require data and I see very little of that around here.  I am providing data to back up my claims and so far, you guys are providing generalizations without much data.  These vague references to "shale industry debt" and "shale industry cash flow" aren't useful data points.

As you can see in the data I produced from the XTO results, the first well they drilled in 2016 was IP of 728 bbl oil and 1902 mcf at 10020 TVD.  Look at the IPs for the wells at the same depths in the new group.  They are 50% to 95% better in oil.  These are all on the same section and on the same side of the section as the original 1h well.  Kind of kills all this chatter about sweet spots and infill wells and other such blather that is constantly spouted around here without a single iota of supporting data that I have seen.  It appears that they have drilled these wells on a wine rack spacing model and are getting fantastic production.  

BTW, I have a Masters in Engineering from UT Austin along with a BA in CS and a BSEE, I have the equivalent of a BS in math because of all the math courses I took over the years getting those degrees and I made a 100 on the engineering statistics course final so yes, I know more than a little about statistics.

Most producers are using a lot more proppant now than they did in 2016, this likely affects output, there have also been changes in the number of frac stages per foot, the frac fluids used, etc.  Eventually an optimal setup is determined and there is little further progress, the Permian may reach this stage fairly soon, probably by 2022, after that further progress in well productivity per lateral foot is likely to be very limited.  Also keep in mind the random variation seen in the recent 6 wells you posted with a range of about 25% in wells spaced closely together and completed over a two month period.  The difference between the lowest of these wells and the 2016 well is about 54%, it is pretty easy to imagine that over a 2 or 3 year period (you didn't give the month in 2016 that the first XTO well was completed) that the drilling and completion methods might have changed enough to lead to a 54% change in IP, we have been given very limited information in this case, some of the difference might be simply a bad location due to fewer natural fractures where the first well was drilled, in addition several wells fracked close together might have led to better results for initial production, but might result in faster decline rates with most of the gain in cumulative output realized over the first 24 months and with potentially lower output in later months.  Petroleum engineers that I have talked with have suggested that the most likely scenario for these high IP wells due to more frack stages and high levels of proppant is very little change in overall cumulative output, but simply a higher IP steeper decline and lower output later in the life of the well, the area under the output vs time curve is unlikely to change by much.  This is basically what we see for the North Dakota Bakken from 2008 to 2017.  I have been following this for quite a while and have learned a lot from the professionals in the oil industry.

[D Coyne + 305]

Data for Reeves county for Permian 2016 to 2018, about 240 wells in 2016 and 467 wells in 2017, and 649 wells in 2018.

Chart from shaleprofile.com

https://shaleprofile.com/2019/04/01/permian-update-through-december-2018/

I would be a little worried about February output of 78 kb as the average Reeves well in 2018 had 620 b/d of output in month 3 so for 28 days and 6 wells this would be 104 kb of output, so you would be about 33% lower than the average Reeves county Permian Basin well for February, again a small sample like this would not be expected to exhibit the behavior of the population average.

Edited April 2, 2019 by D Coyne

[Mike Shellman + 548]

21 hours ago, wrs said:

 something about a Ponzi scheme meme.

I don't believe the shale oil phenomena is a "Ponzi" scheme. That's a poor, over used term to describe something very complicated.  I am not in the least bit jealous of the shale oil thing,  or envious of its capital availability; none of that. I am not "mad," nor am I a communist, which you have called me in the past. I comment occasionally here because, after 50 years of being an operator, I understand well economics and decline/depletion and think I might have something to offer. 

You represent less than 1% of the American population blessed to have mineral interest under the shale phenomena and a beneficiary of approximately $400B of free royalty and lease bonuses. That's a wonderful thing about living in America; congratulations. Where I come from, however, if you need to brag about how many oil wells you own, how much money you make, you don't have much of either. All hat, no cattle, as we say. 

The shale oil phenomena is deeply in debt and still unable to generate profit, that after ten years and close to 70,000 wells. In 2018, in spite of low costs, lies about breakeven calculations in the $20's, and OPEC's help propping up prices  the shale oil industry, once again, as it has since its inception, outspent revenue.   https://www.reuters.com/article/usa-shale-finances-idUSL1N211001.

If you can't make money at $67 (weighted WTI for 2018), replace reserves, make investors happy and deleverage debt, you should get out of the oil business and into the pizza business.  

 

 

 

 

 

 

Edited April 3, 2019 by Mike Shellman

[James Regan + 1,776]

9 hours ago, Mike Shellman said:

I don't believe the shale oil phenomena is a "Ponzi" scheme. That's a poor, over used term to describe something very complicated.  I am not in the least bit jealous of the shale oil thing,  or envious of its capital availability; none of that. I am not "mad," nor am I a communist, which you have called me in the past. I comment occasionally here because, after 50 years of being an operator, I understand well economics and decline/depletion and think I might have something to offer. 

You represent less than 1% of the American population blessed to have mineral interest under the shale phenomena and a beneficiary of approximately $400B of free royalty and lease bonuses. That's a wonderful thing about living in America; congratulations. Where I come from, however, if you need to brag about how many oil wells you own, how much money you make, you don't have much of either. All hat, no cattle, as we say. 

The shale oil phenomena is deeply in debt and still unable to generate profit, that after ten years and close to 70,000 wells. In 2018, in spite of low costs, lies about breakeven calculations in the $20's, and OPEC's help propping up prices  the shale oil industry, once again, as it has since its inception, outspent revenue.   https://www.reuters.com/article/usa-shale-finances-idUSL1N211001.

If you can't make money at $67 (weighted WTI for 2018), replace reserves, make investors happy and deleverage debt, you should get out of the oil business and into the pizza business.  

 

 

 

 

 

 

Conventional Oil or let’s say non shale IOC have just reported some of their most lucrative profits and set to be higher next year, this has nothing to do with Shale plays. The IOCs have learnt to handle short prices and still make a very healthy profit and the rebound of Exploration is evident. I don’t mind saying it Shale has damaged the world oil industry, what shale brings to table is political rhetoric which influences the market through the tweets of POTUS, the shale industry in general is being ran by money grabbers who at some point will pay the price. IMO

[Mike Shellman + 548]

29 minutes ago, James Regan said:

I don’t mind saying it Shale has damaged the world oil industry,

I am glad you said it. Its true. Years of price volatility, due entirely to overleveraged oversupply of US LTO, and reaction to that by other international producers, has changed the entire world oil order forever. Its harmed entire social structures around the world. While most people have their heads up their ass about America shale oil, net exports from other countries in the world are declining at an alarming rate. In a few months Mexico will cease to be an oil exporter entirely. Lack of exploration investment for instance in deep water, is going to hurt the international oil industry's ability to keep up with demand. Here in America we are being led by idiots set on developing our last remaining oil resources as fast as possible, on credit, to export for use as a foreign policy tool. In 5-8 years shale oil production in the US will be on the down hill slide, dropping like a rock, and we'll be wishing we had kept American oil IN America. And had all that flared gas back. Then we will be crying for OPEC oil again. Begging for it. 

Gross mismanagement of shale oil and shale gas, a wonderful amazing gift to America that is being pissed away, is going to ultimately cause a great deal of harm. But you have to be able to think past next week to understand that and for most Americans the future is now. Something like 60% of Americans don't have a thousand dollars saved for emergencies, same for conserving America's oil resources.