Shale Oil Fiasco

[James Gautreau + 86]

Rig weighted average is more like 800, especially since I am talking more Permian. More like 5,000 wells, since that number will now decrease over time. An 82% decline rate means the average EUR is below 100,000 so at $50 it's break even for your $5 million dollar well, which may be true in the Bakken, but not so much in the Permian. Permian wells are $10 million from what I hear. So you need $100 oil to break even, $150 to be profitable, and at $50 you're losing your shirt. 

[James Gautreau + 86]

I think people are going to be shocked by how fast this thing rolls over and starts declining. There just isn't anywhere neat the oil people thought was down there. As fast as it went up, it'll come down twice as fast. You're right those old stripper wells provide a nice "trickle" of cash. At elevated prices their little gold mines. 

[James Gautreau + 86]

Merry Christmas everyone!

[Gerry Maddoux + 3,627]

42 minutes ago, James Gautreau said:

42 minutes ago, James Gautreau said:

	New-well oil production per rig barrels/day				New-well gas production per rig thousand cubic feet/day
Region	December 2019	January 2020	change		December 2019	January 2020	change
Anadarko	606	625	19		4,141	4,230	89
Appalachia	161	164	3		18,662	18,740	78
Bakken	1,515	1,553	38		2,235	2,282	47
Eagle Ford	1,432	1,449	17		4,920	4,929	9
Haynesville	27	27	-		10,322	10,366	44
Niobrara	1,210	1,214	4		4,224	4,229	5
Permian	796	798	2		1,558	1,563	5
Rig-weighted average	821	833	12		4,186	4,092	(94)

Well, no surprises here: I've been preaching for some time that the new well production was higher in the Bakken than in the Permian. I'm telling you, the Bakken has been dramatically understated and written off. For one thing, it's a contiguous massive pool of oil held in by two giant anticlines: the Nessen to the east and the Billings Nose to the south. There's a natural drainage from the Canadian border to the Billings Nose. The biggest wells in the Bakken are clearly as big as those in the Permian--but those are circus stunts. What is important is that one entire county has been written off due to thin shale, despite the fact that it's 3,000 feet shallower, and therefore cost about $2M a well less to drill. EUR? Likely 200,000.

The chart above, sadly, explains just how injurious those eastern Permian child wells were to the bottom line. Everyone--even the majors--felt the infills would be comparable to the wildcats. The child wells in the eastern Permian are an unmitigated disaster; I don't care what the Sec. of Energy says. Part of the success--quiet and tortoise-like--of the Bakken has been that the child wells are of good quality, can be spaced densely (12/1280), and their fracking only makes the parent well better.

BTW, look at the Anadarko (which translates, for all rights and purposes, into the SCOOP/STACK). The amount of by-product NG that comes up with the LTO is massive. In the Anadarko, the NG/LTO ratio is almost 7:1, compared to 1.5 in the Bakken and about 2 in the Permian. In the current pricing environment, low LTO return and high NG return = failure. Especially when you figure in the cost of prodigious water disposal.

Are those January 2020 results some sort of computer projection?

 

Edited December 25, 2019 by Gerry Maddoux

[James Gautreau + 86]

The way I understand it is they are projections or models and the hard data is the monthly EIA that has a 2-3 month lag to assemble the data. Do you know how to invest directly in the Bakken or Eagle Ford? If I make any real money next year I want to put it in oil wells.

[Jabbar + 465]

3 hours ago, Gerry Maddoux said:

 

With respect to you both, I see this somewhat differently: oil and gas pricing used to move hand in glove (11:1), but that decoupled dramatically, and now, at long last, it's going to recouple. Why? Supply/Demand.

NG: The Marcellus, which now produces nearly 40% of US natural gas, is pretty much going to wither on the vine--nobody can make a profit at these NG prices. It'll take a few months, but not many. Chevron's 10B impairment was about the last gasp. Forty-percent is huge: there's going to be a massive hole in the supply chain at the exact time LNG is surging like nothing else I've ever seen in my long life. 

Oil: LTO from shale is going to decline too, for the same reasons. Especially if Mr. Berman is right, and we're going back down to $52 oil--that will be the fatal blow to an awful lot of companies. With a decline in the shale-drilling frenzy for LTO, there goes another very large volume of by-product NG. 

Unless I'm mistaken, we're setting the stage for a very tight market--about this time next year--in both domestic LTO and NG. Absent those prodigious volumes spewing forth from the thick shale plate (very small in area) of the Marcellus, there is no way for oil prices to shoot upward in the face of $1 NG. Absent these dry gas fields (and I'll admit that the Haynesville has the potential for much more, especially with Jerry Jones at the helm of Comstock production), LTO and NG will once again couple. My prediction is that it won't ever make it back to that cozy 11:1, but maybe 20:1, so at $100 oil, NG would be $5. I respect your modeling, Dennis, but into the mix is thrown a divergence (huge surge in NG from Marcellus). Into the mix is also thrown another divergence: LNG is much more profitable than LTO. I'm saying that when these two influences are mitigated, the models are thrown off.   

What are you three talking about. Are you high.

See. .  .  .  .  .   This is what happens when U.S. legalises pot.  Unattended consequences.

Gerry, the price of gas to oil was locked into approx 1 : 11 because that's how ALL the gas longterm contracts were written.  It was a fixed % of the Brent oil benchmark. That's how Qatar did it. Then the world found an abundance of natural gas.  As contracts expired the new contracts were not "factored" any longer.  No more fixed ratios. 

Too much Natural Gas. 

CVX sees writing on the wall. Much better ROI with oil.

If you think CVX $11 Billion impairment was high .   .  .  .  Exxon paid $42 Billion for XTO , which was predominantly Marcellous natural gas. This after their large impairment to their Tar Sands investment. 

Also , CVX is involved in the new 500k barrels/day Saudi/Kuwait project. They were before the dispute and will be going forward.

Edited December 25, 2019 by Jabbar

[James Gautreau + 86]

1 minute ago, Jabbar said:

What are you three talking about. Are you high.

See. .  .  .  .  .   This is what happens when U.S. legalises pot.  Unattended consequences.

Gerry, the price of gas to oil was locked into approx 1 : 11 because that's how ALL the gas longterm contracts were written.  It was a fixed % of the Brent oil benchmark. That's how Qatar did it. Then the world found an abundance of natural gas.  As contracts expired the new contracts were not "factored" any longer.  No more fixed ratios. 

Too much Natural Gas. 

Art Berman has never been right. I don't think he'll start now. 

[Gerry Maddoux + 3,627]

28 minutes ago, Jabbar said:

What are you three talking about. Are you high.

See. .  .  .  .  .   This is what happens when U.S. legalises pot.  Unattended consequences.

HaHa. You may be right. 

[Gerry Maddoux + 3,627]

31 minutes ago, Jabbar said:

Gerry, the price of gas to oil was locked into approx 1 : 11 because that's how ALL the gas longterm contracts were written.  It was a fixed % of the Brent oil benchmark. That's how Qatar did it. Then the world found an abundance of natural gas.  As contracts expired the new contracts were not "factored" any longer.  No more fixed ratios. 

Maybe in your universe, not in mine. In 1986 oil hovered between $10-16/bl.  We were selling DEEP natural gas--deeper than either 10,000 or 15,000 feet, I can't recall which--for between $10-12/tcf. We had a well that peaked out at 29,600 feet, the deepest well at that time. About that time, Mr. Reagan discontinued the platform beneath deep natural gas. It careened down to about $4 overnight. But even at that, the ratio couldn't have been more than 4:1--the world was just that starved for NG. 

Then it stabilized. Up until about 2008, '09, the ratio was--except for wild divergences--about 11:1. 

I was unaware that long-term gas contracts were ever locked in a ratio, relative to Brent. Thanks for the info. 

[Gerry Maddoux + 3,627]

6 hours ago, James Gautreau said:

Do you know how to invest directly in the Bakken or Eagle Ford? If I make any real money next year I want to put it in oil wells.

Email me personally at glmaddoux@comcast.net and I'll tell you the name of the broker I use to buy properties HBP, with good current income, and with the potential for a substantial upside. The man is honest, which is something in this business. I can also give you the name of the petroleum engineer who collated my property and rendered an independent opinion of its worth. I can help you avoid some pitfalls, but not all. Oil properties are like women: sometimes the plainest ones have the best heart.

[D Coyne + 305]

21 hours ago, Gerry Maddoux said:

 

With respect to you both, I see this somewhat differently: oil and gas pricing used to move hand in glove (11:1), but that decoupled dramatically, and now, at long last, it's going to recouple. Why? Supply/Demand.

NG: The Marcellus, which now produces nearly 40% of US natural gas, is pretty much going to wither on the vine--nobody can make a profit at these NG prices. It'll take a few months, but not many. Chevron's 10B impairment was about the last gasp. Forty-percent is huge: there's going to be a massive hole in the supply chain at the exact time LNG is surging like nothing else I've ever seen in my long life. 

Oil: LTO from shale is going to decline too, for the same reasons. Especially if Mr. Berman is right, and we're going back down to $52 oil--that will be the fatal blow to an awful lot of companies. With a decline in the shale-drilling frenzy for LTO, there goes another very large volume of by-product NG. 

Unless I'm mistaken, we're setting the stage for a very tight market--about this time next year--in both domestic LTO and NG. Absent those prodigious volumes spewing forth from the thick shale plate (very small in area) of the Marcellus, there is no way for oil prices to shoot upward in the face of $1 NG. Absent these dry gas fields (and I'll admit that the Haynesville has the potential for much more, especially with Jerry Jones at the helm of Comstock production), LTO and NG will once again couple. My prediction is that it won't ever make it back to that cozy 11:1, but maybe 20:1, so at $100 oil, NG would be $5. I respect your modeling, Dennis, but into the mix is thrown a divergence (huge surge in NG from Marcellus). Into the mix is also thrown another divergence: LNG is much more profitable than LTO. I'm saying that when these two influences are mitigated, the models are thrown off.   

Gerry,

I have no doubt that my price assumptions may prove either too low or too high.  Both oil and natural gas prices will fluctuate as they always have in ways that are impossible to predict.

I don't follow Natural gas as closely as I do tight oil.  In general I expect low natural gas prices will reduce profits, reduce the number of completions and reduce the growth in natural gas supply in the Marcellus and Utica plays (where most of the NG focused growth has occurred).  Eventually the market will balance out, pipelines will be built so the natural gas in West Texas can get to consumers and not be flared or vented and eventually things will settle out so that prices will reflect a balance of supply and demand.  No idea what that price will be for natural gas, I have guessed $1.50 to $2.50 per thousand cubic feet (MCF) at the well head, perhaps it will be $1 to $4.  The oil market is likely to tighten and I see $70 to$100/bo over the 2020 to 2025 period for Brent (all prices in 2018 US$ for both oil and natural gas).  Note that for pricing in BOE we need to multiply NG price by 6 so we have 2.5*6=$15/BOE for NG at wellhead and assuming $5/bo transport cost for Permian basin tight oil we would have about $80/bo at wellhead for Permian tight oil which is about a 5.3:1 ratio in energy terms but if we mean Brent oil price in $/bo divided by HH price in $/NCF the ratio is 32:1 for my price assumptions (taking mean values).  The 20:1 pricing ratio at my mean oil price assumption suggests $4/MCF at wellhead.  I doubt we get there before 2025, and I also doubt that natural gas prices fall to $1/MCF as nobody will bother to produce the stuff at that price and the shortage in Natural gas will drive prices back up.

From what I have read more natural gas pipelines are set to come online in 2020 and 2021, that will raise the WAHA price back in line with Henry Hub pricing in my opinion.

 

[D Coyne + 305]

18 hours ago, James Gautreau said:

The way I understand it is they are projections or models and the hard data is the monthly EIA that has a 2-3 month lag to assemble the data. Do you know how to invest directly in the Bakken or Eagle Ford? If I make any real money next year I want to put it in oil wells.

The DPR is a model based projection and in my opinion the model is not very good.

Best tight oil data is at link below (spreadsheet with the official EIA tight oil estimates) in my opinion

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

[D Coyne + 305]

22 hours ago, James Gautreau said:

Well now let's think about that. If the focus in the shale patch becomes the gas and not the oil. What sort of market dynamics would that create? Since the gas can now get to the coast, and in a less expensive manner, that means the price will remain low. And if oil becomes scarce as I predict, there will be more and more wells drilled, and thus more and more gas, which means even lower prices. The oil to gas ratio could surge to a record. Typically 10 to 1, I think the record is 45 to 1. If oil goes to $200 and gas drops to $1, that would mean an oil to gas ratio of 200 to 1. Demand for gas would surge, demand growth might surge to over 1%. After awhile oil price would collapse, the drilling would begin to slow and then and only then would gas price start to move higher. 

James,

The price of gas was low in West Texas because there was too much gas for the pipeline capacity available.  When the pipeline capacity is built to move the natural gas, then natural gas prices increase, what a smart producer does is lock up pipeline capacity and then plan their drilling to produce close to the amount of gas they have contracted to move in pipelines, this is not rocket science, it is the way one maximizes profits.  Oil won't go to $200/bo any time soon and if it did the demand for natural gas would likely increase as people would move to natural gas as an alternative to oil.  We could see $100/bo with gas at $2.50/MCF and eventually natural gas will start to deplete and natural gas prices mat rise to $5/MCF (probably not until after 2027 as a WAG).

[wrs + 893]

Dennis,

According to my latest royalty stubs, XTO got $2.95 at the wellhead for gas and the independent got $2.71.  Those were in October after the new 2.2bcf/day gulf coast express pipeline had come on line.  Those prices are for the residual gas after taking out the liquids.

[James Gautreau + 86]

31 minutes ago, wrs said:

Dennis,

According to my latest royalty stubs, XTO got $2.95 at the wellhead for gas and the independent got $2.71.  Those were in October after the new 2.2bcf/day gulf coast express pipeline had come on line.  Those prices are for the residual gas after taking out the liquids.

The spot price of nat gas is 2.25 today.

Energy

INDEX	UNITS	PRICE	CHANGE	%CHANGE	CONTRACT	TIME (EST)
CL1:COM WTI Crude Oil (Nymex)	USD/bbl.	61.60	+0.49	+0.80%	Feb 2020	10:11 AM
CO1:COM Brent Crude (ICE)	USD/bbl.	67.67	+0.47	+0.70%	Feb 2020	10:12 AM
XB1:COM RBOB Gasoline (Nymex)	USd/gal.	174.87	+2.17	+1.26%	Jan 2020	10:10 AM
NG1:COM Natural Gas (Nymex)	USD/MMBtu	2.25	+0.08	+3.73%	Jan 2020	10:11 AM
HO1:COM Heating Oil (Nymex)	USd/gal.	204.94	+1.31	+0.64%	Jan 2020	10:11 AM

[Gerry Maddoux + 3,627]

52 minutes ago, D Coyne said:

The 20:1 pricing ratio at my mean oil price assumption suggests $4/MCF at wellhead.  I doubt we get there before 2025, and I also doubt that natural gas prices fall to $1/MCF as nobody will bother to produce the stuff at that price and the shortage in Natural gas will drive prices back up.

Your models and formulation jive identically with my scribblings, in theory. Gas prices are a guessing game. If NG at the wellhead can assume the Henry Hub index, and hold it, there will be continued activity in the dry gas fields: Utica, Haynesville, Marcellus. Enough to keep the price range bound. The Marcellus is currently throwing everything out of whack with these wildly prolific wells that spurt out in three or four months. And as Chevron and Exxon discovered, the Marcellus drilling pad is quite small. So small, indeed, that I believe that area can't remain commercially viable for much longer, even if NG prices stabilize. The Utica is almost as limited. The Haynesville is another story: room to run. 

Assuming that the Marcellus and Utica are in real trouble; ergo, massive volumes of dry gas will come off the market supply soon, I have two scenarios: 1) The price of oil goes up steadily, which will increase shale drilling and keep the NG supply more or less satisfied. 2) Oil pricing remains range-bound, which will cause a dramatic decline in LTO-related NG.

This all takes time, so your predictions for a 2025 inflection point make statistical sense. The monkey wrench in the gear-works could be LNG, which I personally believe will grow at an astronomical rate. Liquifaction removes almost all the parent molecules for acid oxides, hence making it very close to as clean as wind or solar when you factor in the petchem for production of those instruments. 

[Mike Shellman + 548]

deleted

 

Edited January 1, 2020 by Mike Shellman

[Gerry Maddoux + 3,627]

15 minutes ago, Mike Shellman said:

Additional takeaway out of the Permian is actually causing the price of associated gas to go down, not up. Flaring is on the rise in all shale oil basins, accordingly. Gas to oil ratios. a precursor to depletion, are increasing dramatically in the Permian

HaHa, yes, we're out here. And you're exactly right in everything you just pointed out. Your eyes may be too close together in your photo but you're a good observer of events in the oil field. 

You point out a VERY relevant point about the gas/oil ratios. This is a bad harbinger. Anyone who doesn't believe it can scroll up to the chart that James inserted, showing the massive gas/oil ratio up in the SCOOP/STACK. This is something that even I--generally a skeptic about the Permian--hadn't factored in. 

There are too many moving parts in this thing! And each one of them produces unpredictable circumstances. 

I tell you, these features make me love the Bakken even more: low gas/oil, relatively; negligible parent-child interaction (due to lower porosity), good IP, steady-eddy. Big Negative: far north location really slows production in the winter. 

[James Gautreau + 86]

The Bakken is the best fracking out there. You can expect income out of there for probably 20 years. I think it's the only one. 

[Gerry Maddoux + 3,627]

So . . . . . .

Frankly, I had no idea that the Delaware was gassier than the eastern Permian, and that it gets gassier fast. Or that it was worst of all in the mighty Wolfcamp play. Mike, your post is illuminating to me. Thanks! 

Well, if Chevron, Exxon and Occidental decide to stick it out in the Delaware--and they will--we're going to continue to see NG price suppression as a necessary by-product of their immense drilling program. 

I don't know, if I were Chevron I'd be moving toward acquiring an LNG business, probably Cheniere. I just don't see any other way they can salvage their business model in the Delaware. 

And I don't want to see this happen, but the underground features in the Delaware are eerily similar to the SCOOP/STACK. Namely, limestone caverns held in place by tangential wall stress exerted by water and gas. In Oklahoma removal of vast quantities of this resulted in seismic activity. Now, the drillers in the Delaware are reusing more of their water cut, but there are still huge numbers of disposal wells. With that kind of structure, there is evident danger of repeating the Oklahoma experience. 

[D Coyne + 305]

22 hours ago, Gerry Maddoux said:

Dennis? What do your models say?

I agree with the tall order: that's 2,000 new wells producing an IP of 1,500 each.

Tall order indeed: That's 3,000 wells with an IP of 1,500.

Factor in that the offshore subset is cranking up awfully fast . . . much faster than in the past where there was a five-year lag. In fact, this looks like the after-party for shale, and the pre-party for offshore. 

BUT!!!!!!!!     Dadgum it, look at this in perspective of increasing scarcity. 

There are quite a few shale drilling sites that will produce an EUR of 300,000 barrels. It costs about $5M, these days, to drill one of those. At just $100 oil, that's a payout of . . . $30,000,000. And, like the old days, I think we can reasonably assume that the price of oil will go up linearly at some point--Dennis says about year 2025--and then logarithmically. That's a pretty good investment payout where I come from. 

Compare it to the old conventional wells. I know of tens of thousands of these that were drilled back in the fifties--take the old Hugoton Field, for example (coincidentally, the first field where fracking was used, jazzed gasoline--napalm--mixed with water from the creek). Many of those wells are still chugging along at ten barrels a day: $15,000/month or $180,000/year. 

My point? When oil prices go up to $100, an awful lot of disrespected shale zones are suddenly going to go from trash to treasure. In Divide County North Dakota the whole county is comprised of thin shale that is as oil-soaked as anything out there, yet it has been dissed as only having an EUR of 200-300,000. But it's shallow, so takes less money to get down there. Let's take the low end: 200,000 barrels at $100 per is $20,000,000 payout for a well that cost $3-4M to drill. Eighty-five percent of that comes back the first year, right? Then, as it declines to a paltry 200 blls/d, then 100, and finally a miserly 50, it's still paying out pretty good money, because by the time it gets to 50 blls/d, the price of oil is up to say $150 a barrel and the yearly income from that crappy little well is . . . $2,737,500/year. I'll take a batch of those!

 

 

Gerry,

At higher oil prices and higher tight oil well completion rates, my models suggest tight oil output will increase, a high completion rate and high oil price scenario (prices rising to $170/b by 2050) we would see a US tight oil peak by 2027 at about 12 Mb/d, this assumes USGS TRR mean estimates are approximately correct and also assumes well costs in constant dollars per lateral foot remain unchanged from today's levels.  The URR of this optimistic scenario (as oil prices are very high) is 110 Gb, with cumulative production through Nov 2019 at 15 Gb and about 95 Gb left to produce.

Edited December 26, 2019 by D Coyne

[D Coyne + 305]

For the US Tight oil scenario longer term (to 2050) we have the chart below, steep decline from 2027 to 2050 with US tight oil output falling from 12 Mb/d to 2 Mb/d.

[Gerry Maddoux + 3,627]

2 minutes ago, D Coyne said:

The URR of this optimistic scenario (as oil prices are very high)

Dennis, I would (selfishly) argue that oil prices are not "very high," at least when measured against other commodities . . . and especially when compared to frivolous commodities that are not necessary to sustain life. I have used this so much someone will put in an emoji of gagging, but here goes. If you were to roll a new oil barrel into a Starbucks and fill it with latte, it would cost you $3700. No one has indexed oil to the stealth inflation that's all around us: cost of food, coffee, liquor, bottled water, hotel rooms, airline tickets, on and on.

Further, the production of a barrel of oil used to be a low-cost thing: drill a vertical well, let it flow. These days, every time I venture out into the oil field I am amazed at what's going on: drill bit sensors, computers massaging the data, this new e-fracking. We're not talking picking coffee beans in the sunshine; the cost of producing a barrel of LTO is staggering. 

In Saudi Arabia, the cost to produce a barrel of oil is not staggering. It's about $11, maybe add on another couple of bucks for sea-water flooding. But their social cost is high. Same for a lot of other large oil pool countries. 

In 1993 the price of oil was $10 and the cost of lifting WTI was $12. Nobody could make a buck. Lots of people shut in wells or just plugged them (you could do that back then for $1500). Plugging a well to Texas Railroad Commission standards now costs $30,000. At these current oil and gas prices, there are going to be quite a lot of wells that get plugged early. Enough that it's going to spur cottage industries in that field. 

 

[Old-Ruffneck + 1,177]

10 minutes ago, D Coyne said:

At higher oil prices and higher tight oil well completion rates, my models suggest tight oil output will increase, a high completion rate and high oil price scenario (prices rising to $170/b by 2050) we would see a US tight oil peak by 2027 at about 12 Mb/d, this assumes USGS TRR mean estimates are approximately correct and also assumes well costs in constant dollars per lateral foot remain unchanged from today's levels.

Not trying to throw a spoiler there but they USGS and TRR can't guesstimate that far into the future/ie: 7 to 30 years. Remember as US Tight oil production curve starts its downward trend, other nations are ramping up big time. Guyana and Brazil in 7 years will fulfill our losses, thus keeping a check on price inflation. More oil will be discovered to be sure. And by 2050 we will all be "Green" lol.

[D Coyne + 305]

58 minutes ago, Mike Shellman said:

"Spot" gas at Henry is only applicable to a limited few shale oil producers in any basin; free royalty on this gas is not subject to any processing or marketing costs and therefore has nothing whatsoever to do with current well economics are wild ass guesses about the future. Additional takeaway out of the Permian is actually causing the price of associated gas to go down, not up. Flaring is on the rise in all shale oil basins, accordingly. Gas to oil ratios. a precursor to depletion, are increasing dramatically in the Permian: https://www.bloomberg.com/news/articles/2019-12-24/permian-gas-problem-just-gets-worse-as-shale-drilling-slows-down. 

Sent from planet Earth 12.26.19 @ 09:40. Is anybody out there? 

Hi Mike,

When I do the well economics, I take out the royalties and taxes and currently assume about $1.50 at the wellhead and deduct about 30% for royalties and taxes, does that seem like a good ballpark estimate?  Also wrs has suggested the NGL sales would bump up the actual revenue by 25%, does that seem a reasonable guess (on average).  I realize that each well is unique, I take averages as analyzing 300,000 invividual wells is beyond my pay grade.