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The Nation’s Number Two Tight Oil Play After a Year of Low Oil Prices

The Bakken Play, located in North Dakota and Montana, is the birthplace of tight (shale) oil and in many ways the poster child of the so-called “shale revolution.” Between 2010 and 2014, oil production in North Dakota grew nearly five-fold, from 236,000 barrels/day in January 2010 to over 1,167,000 barrels/day in January 2015, according to the U.S. Department of Energy’s Energy Information Administration (EIA), which every year publishes its Annual Energy Outlook (AEO).

The EIA forecast this production growth to continue and — despite thousands of wells having already been drilled in the most productive areas of the play, and the steep decline in oil prices in 2014 — even raised its projection in 2015 for the total amount of tight oil produced in the Bakken through 2040 by 85% over the previous year’s forecast.

But a new report throws cold water on the thinking that U.S. shale production will be around for the long haul. The Post Carbon Institute conducted an analysis of the top seven oil and top seven natural gas plays, which together account for 89 percent of current shale oil production and 88 percent of shale gas production.

In Bakken Reality Check, David Hughes, author of Drilling Deeper (which likely remains the most thorough independent analysis of U.S. shale gas and tight oil production ever conducted) and a number of other reports on North American shale gas and tight oil production, looks at how production in the Bakken has changed after a year of low oil prices.

Predicting what oil production will be in 25 years is difficult, to say the least, but the Post Carbon report projects that oil production from the Bakken and Eagle Ford will be just one-tenth of the level that EIA is forecasting. The EIA predicts that the Bakken and the Eagle Ford will be producing a combined 1 million bpd in 2040. Hughes thinks it will be just a small fraction of that amount – a mere 73,000 bpd.

Oil production in the Bakken Play is now falling after more than a year of low oil prices—but it has proven more resilient than many observers expected. This paper reviews the latest developments in the Bakken Play and provides an update of the assessment in Drilling Deeper, which was published in October 2014 just as the turmoil in the oil markets began.

The report found that both shale oil and shale gas production will peak before 2020. More importantly, the report’s author, David Hughes, says oil production will decline much more quickly than the EIA has predicted.

That’s largely because of high decline rates at shale wells across the country. Unlike conventional wells, which can produce relatively stable rates for a long period of time, shale oil and gas wells experience an initial burst of production in the first few years, followed by a precipitous decline thereafter.

Hughes estimates that the average shale oil well declines at a rate of between 60 and 91 percent over three years. Wells in the Bakken decline by 45 percent per year, which stands in stark contrast to the 5 percent annual decline for an average conventional well.

Or put another way, oil and gas companies will have to keep drilling at a feverish pace just to stand still. This means the industry is on a “drilling treadmill” that will be unsustainable over the long-term.

This is not the first time that David Hughes has taken aim at EIA data. In a December 2013 report, he skewered the high estimates for the potential of the Monterrey Shale in California, calling the EIA’s numbers “simplistic and highly overstated.” Several months later, the EIA was forced to back track on its figures, downgrading the recoverable oil estimates in the Monterrey by 96 percent.

Hughes says the implications of getting it wrong are “profound,” since so many companies are basing very large investments on incorrect projections. He says rosy estimates have cut into investment for renewables, while steering capital towards expensive oil and gas export terminals that should now be called into question.

An article in CleanTechnica points to the possibility of boom towns turning into “ghost towns” if the pace of drilling drops off. If David Hughes and The Post Carbon Institute are correct, there could be quite a few ghost towns popping up in the coming years as the shale revolution begins to fizzle.

 


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Old News ;-)

[Apr 17, 2017] 04/15/2017 at 9:35 am

Notable quotes:
"... Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again. ..."
"... Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. ..."
"... Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out. ..."
"... A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices. ..."
Apr 17, 2017 | peakoilbarrel.com
Mike 04/15/2017 at 9:35 am
Hopefully everyone involved in defending Bakken production upswings will not disappear into the woodwork next month, or the month after, when production drops again.

Of course marginal shale oil wells that are at or below economic limits get shut in during winter, or get shut in and stay shut in because workover costs to restore production simply do not make economic sense. There are gazillions of those kinds of well in all three of America's shale oil basins. There need not be a flush 'uptick' of production when those wells come back on line (that's investor presentation dribble), in fact it can be just the opposite because of bubble point/higher water saturations.

Re-frac's cost more money. At $20.00 per barrel net back prices a $2.5-3.0M re-frac requires ANOTHER 137,000 BO to payout. Productivity should never be confused with profitability (or lack thereof); in the end the latter always wins out.

And this SPE paper pretty much shoots the hell out of all that "halo" bunk: https://www.spe.org/en/jpt/jpt-article-detail/?art=2819 .

Imagine a situation where you are drilling these $6.5M wells so close together (Marathon at 330 feet, toe to toe) that you have to "protect" them by shutting them in for prolonged periods of time while you frac a new well 3000 feet away. That makes a lot of sense, doesn't it?

A little more time and realized production data will prove that downsizing actually reduced UR per incremental well and was yet another economic disaster in a string of economic disasters for the shale oil industry, the biggest being oversupply and an ensuing 70% drop in product prices.

People do really stupid things with OPM.

George Kaplan 04/14/2017 at 10:31 am
Dennis,

... ... ...

The actual reserve that is being produced in the Bakken was "discovered, undeveloped and developed" in 2013, and not covered by the USGS. It's difficult to find break out information for individual areas in most companies reports but I don't think there was more than about 5 Gb developed and undeveloped reserves in 2013, and it might have declined a bit since then, even including actual production.

[Feb 21, 2017] Is The Bakken a Bust

Feb 21, 2017 | peakoilbarrel.com

Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production down 92,029 bpd to 942,455 bpd. It was noted that this the largest decline ever in North Dakota production. But it should not be overlooked that the October in crease in production was also the largest ever increase in North Dakota production.

Guy M says: 02/16/2017 at 11:37 am
EIA wildly optimistic in Bakken, Gulf and Texas. Their current numbers have to be way high in relation to what is actually happening. Even Texas RRC site is not predicting an upturn until current permits and completions get a lot higher. At $53 oil, it is not happening, or going to happen.
Heinrich Leopold says: 02/17/2017 at 5:23 am
George Kaplan,

In my view there is simply a cost issue here. If a well goes from 100 barrels to 20 barrels per day, the mainenance, operating and transport costs go up fivefold per barrel, even if they are the same for the well. So, it might not pay off to send a crew there and pay for transport. Unless, the oil price does not go up, these wells and many more wells are likely to shut down for a while.

GreenPeople's Media says: 02/16/2017 at 8:20 pm
I saw a recent story about the rise in the cost of fracking to completion for these DUC wells. Costs are said to have risen to something like $3.2 million in some of the areas where wells need completion. I believe the Director's Cut said last month there were 86o wells awaiting completion. If the story I read was true, then it will be around $2.8 billion to frack those 860 wells. I don't know what the cost of getting a well to the DUC stage is, but it sure seems a lot of money to have sunk in the ground for wells that will be outputting just 100 barrel a day after their first 24 months.

Is my thinking fuzzy on this?

Phil Harris says: 02/16/2017 at 12:13 pm
Bruno Verwimp wrote back in 2016, September 16th, " .Hold your breath for the next winter. It might bring severe decline in oil production in ND Bakken ."

I wrote at the same time: " FWIW my 'money' is on Verwimp's observation and model for the Bakken. I for one will be interested to see your chart next spring!"

Another 3 months will be interesting. By the look of it, it might well be down to 700,000 bpd in a year if the uncanny accuracy continues. As I understand it, his chart has nothing in it derived from price.

Javier says: 02/17/2017 at 6:31 am
That is correct. Verwimp's model has no oil price input. This is a serious problem since everybody recognizes that oil price has been determinant in the current oil situation. Therefore one can only conclude that Verwimp's model is accurate due to chance, and therefore has no predicting capability. It will continue to be accurate until it doesn't. It probably represents oil production decay in the absence of sufficient economical incentive.
Dennis Coyne says: 02/20/2017 at 3:22 pm
Hi Verwimp,

Geology absolutely plays a role, especially when oil prices are relatively high it is clear which fields are constrained by geology. When oil prices fall by a factor of 3 or 4 fields that are not constrained by geology will decline due to economic constraints (poor profitability.) The Bakken only increased in output due to high oil prices and a high well completion rate. Eventually geology will be the reason for Bakken decline, low oil prices clearly are the reason at present.

In Jan 2018 your model predicts about 680 kb/d for ND Bakken/TF output. My 61 well model predicts about 818 kb/d in Jan 2018 and the 85 well model predicts 900 kb/d in Jan 2018, I expect ND Bakken/Three Forks output will be around 825 to 900 kb/d in Jan 2018, with a best guess of 866 kb/d (847 kb/d in Dec 2018). This corresponds to a 75 well model, chart below.

djtxyz says: 02/16/2017 at 1:44 pm
A big contributor to the legacy oil decline is the unrelenting physics of fluid phase behavior, with gas becoming more prevalent in the production stream. Statewide GOR increased from 1200 to 1500:1 cuft/bo in 2015. The legacy wells will be worse (i.e. the newer wells dampen the effect, which have an initial GOR of ~ 1000:1). For reference, generally a GOR> 2000:1 is considered a "gas" well or field.

Most of these LTO fields will eventually be abandoned as gas fields.

note – I tried to post a *.png graph, but the reply tool failed.

Fernando Leanme says: 02/16/2017 at 4:20 pm
Is the 2000 GOR a North Dakota convention? There's no reservoir engineering reason to designate a depleted well as a gas well when GOR increases to 2000 scf/bo. Depleted oil wells under depletion drive do experience very high GORs, but they remain oil wells.
Boomer II says: 02/16/2017 at 4:51 pm
Here's a link that says in Texas there are tax advantages in reclassifying an oil well as a gas well.

http://fuelfix.com/blog/2016/11/22/pioneer-denied-request-to-reclassify-oil-wells/

Watcher says: 02/17/2017 at 1:11 pm
My recall is there's a regulation in Texas that classifies liquids from a gas well as condensate vs oil from an oil well. Almost certainly has some tax consequence.
Boomer II says: 02/17/2017 at 1:37 pm
This has been my philosophy for decades. Preserve our own resources and use up everyone else's until they run out.

Berkshire's Charlie Munger Has A Much Different Energy Plan For America Than Donald Trump | Seeking Alpha : "Munger believes that the United States should have an energy strategy that involves preserving these shale resources until some point in the future when they are much more valuable. This would be a point in time after the OPEC nations have exhausted their oil and gas reserves.

Munger would have us import oil and gas now from OPEC so that we can save our oil and gas for the future when the world is going to have major shortages."

Watcher says: 02/18/2017 at 12:59 pm
Sigh.

People Are Not Stupid.

The day comes when a firebrand is in control and dares to rock the societal systemic boat by declaring the price of oil will be non monetary. You want oil from Russia, America? Disarm. You want oil from KSA, America? Convert to Islam.

"We have enough of your dollars created from thin air. Let's have something of real value to us before we send you oil. The price is described above."

[Feb 21, 2017] To reach pay out for the wells started in 2009-2016 requires an estimated oil price of 65 dollars bbl WTI starting Jan-17. To get a return of 2.5% which can be called an inflation hedge) on the $36B requires an estimated oil price of $77 dollars bbl WTI

Notable quotes:
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
Feb 21, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require the addition of an average of about 95 wells/month (61 wells/month were added through 2016).

In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent. This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus a steeper decline in production.

Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI).

To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return.

Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B.

Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets.

At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells.

For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations.

shallow sand says: 02/19/2017 at 4:33 pm
Rune, thank you for this post.

[Feb 20, 2017] To reach pay out for the wells started in 2009-2016 requires an estimated oil price of 65 dollars bbl WTI starting Jan-17. To get a return of two and a half percent they need 77 dollars

Notable quotes:
"... Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI). ..."
"... To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return. ..."
"... Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B. ..."
"... Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets. ..."
"... At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells. ..."
"... For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations. ..."
Feb 20, 2017 | peakoilbarrel.com
Rune Likvern says: 02/19/2017 at 1:04 pm
To keep the Dec-15 output level from Bakken(ND) through 2016, I estimated this would require the addition of an average of about 95 wells/month (61 wells/month were added through 2016).

In 2016 an estimated $2.0 – $2.5Billion more than (net) cash flow from operations was spent. This is about 300 – 350 new wells (spud to flow).
Without this external capital infusion fewer wells would have been brought to flow and thus a steeper decline in production.

Looking at Bakken(ND) as one big project, it has now spent an estimated total of about $36Billion more than generated from net operational cash flows (Jan-09 – Dec-16). To reach pay out for the wells started in 2009-2016 requires an estimated oil price of $65/bo (WTI) starting Jan-17. To get a return of 2.5% (which is, call it, an inflation hedge) on the $36B requires an estimated oil price of $77/bo (WTI).

To enable a debt reduction requires a net positive cash flow from operations and the longer it takes before positive cash flow happens, the higher the required oil price becomes to earn some return.

Some of this $36B debt has already been written down (also through bankruptcies (Chapter 11s), the business model is not sustainable with low oil prices!), which means that the companies now needs to recover less than the $36B.

Write downs/impairments shrinks the affected companies' assets/equities and thus debt carrying capacities. Some make forecasts about future developments without considering the companies' balance sheets.

At present oil pries (low/mid 50's) the companies may add an average of 60-70 wells/month from cash from operations, this will likely be a mixture of DUCs and "new" wells.

For 2017 I expect companies in Bakken(ND) will continue to spend above what is generated from operations.

shallow sand says: 02/19/2017 at 4:33 pm
Rune, thank you for this post.

[Feb 20, 2017] Is The Bakken a Bust

Feb 20, 2017 | peakoilbarrel.com

Bakken production down 86,150 barrels per day to 895,330 bpd. North Dakota production down 92,029 bpd to 942,455 bpd. It was noted that this the largest decline ever in North Dakota production. But it should not be overlooked that the October in crease in production was also the largest ever increase in North Dakota production.

[Feb 20, 2017] it looks likely that the moment Dakota Access is built, there will be a pipeline capacity glut.

Feb 20, 2017 | peakoilbarrel.com
Nathanael says: 02/15/2017 at 1:15 pm
If I'm not mistaken, this means that the North Dakota production (BPD) is now only slightly more than than the existing pipeline capacity leading out of North Dakota (BPD), which is 851,000 at the end of 2016. Production will probably be down to the existing pipeline capacity by March.

https://ndpipelines.files.wordpress.com/2012/04/williston-basin-transportation-table-nov-2016.jpg

Now this isn't quite comparable because part of the Williston isn't in North Dakota, so I'd have to look at the Montana numbers. But still, it looks likely that the moment Dakota Access is built, there will be a pipeline capacity glut.

So is the Dakota Access Pipeline going to be half-empty, or will some of the other pipelines be empty and go bankrupt? They're fighting over market share in a surplus-capacity environment.

[Feb 20, 2017] EUR for Bakken for new investments is assumed to be at unrealistic 980K Boe per well

Feb 20, 2017 | peakoilbarrel.com
HVACman says: 02/16/2017 at 2:04 pm
"The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%"

The estimated EUR's appear VERY high for Bakken wells by my untrained eye. Any thoughts from the resident experts?

George Kaplan says: 02/16/2017 at 3:21 pm
I am certainly not an expert on tight oil but see above. If they get 30 to 40% extra from gas I think they might make it (GOR of 1500 adds 25% I think, and it looks like it will be more than that for most wells). What I don't get is a 'previous average' of 850,000. There's not even one well that looks like that at the moment, based on Enno Peters' charts.
AlexS says: 02/15/2017 at 5:41 pm
Even more striking declines in drilling/completion activity for individual operators.

In December 2016, Continental had only 21 producing wells that started production in 2016, with combined output of 8.6 kb/d

In December 2015, it had 152 producing wells that were started in 2015,
with combined output of 45.1 kb/d.

In December 2014, it had 253 producing wells that were started in 2014,
with combined output of 58.9 kb/d.

So, the number of new producing wells for CLR in 2016 was 12 times less than in 2014.

AlexS says: 02/15/2017 at 6:58 pm
CLR guidance for 2017:

"The Company plans to complete 131 gross (100 net) operated wells out of its Bakken uncompleted well inventory with first production commencing by year end. In addition, Continental plans to complete with first production approximately 17 gross (8 net) newly drilled Bakken wells in 2017. At year-end 2017, the Company expects to have 140 Bakken wells in inventory, of which 72 gross (40 net) wells will have been completed but waiting on first sales and 68 gross (47 net) operated wells will be waiting on completion.

The Company also plans to participate in completing 40 net non-operated wells in 2017, 35 of which will be in the Bakken.

Continental expects to grow Bakken production by approximately 26% in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.

Approximately $550 million, or 70%, of the operated Bakken capital investment in 2017 will be focused on completing wells from the Company's uncompleted well inventory. The Company has five stimulation crews working currently and plans to average seven crews for 2017 as a whole.

Continental plans to apply various enhanced stimulation techniques on all Bakken completions in 2017 to define the optimum designs for future completions. This includes larger proppant loads, diverter technology, shorter stage lengths and shorter cluster spacing. The Company is also applying high-rate production lift technology to accelerate fluid recovery and early production rates. Combined, these techniques add an average of approximately $1.4 million to the previous standard enhanced completion cost of $3.5 million.

For the uncompleted well inventory, the average budgeted completion cost for the larger enhanced completion is approximately $4.9 million per well. The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of 980,000 Boe per well, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%.

The Company also plans to maintain four operated drilling rigs in the Bakken throughout 2017 and drill 101 gross (57 net) operated wells, with 17 gross (8 net) of these wells completed in 2017 with first production. The 17 gross wells will have an average budgeted well cost of approximately $7.0 million. The average EUR for wells drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price of $55 per barrel, these wells should generate over a 40% rate of return."

http://nocache-phx.corporate-ir.net/phoenix.zhtml?c=197380&p=irol-newsArticle&ID=2239817

Eulenspiegel says: 02/16/2017 at 5:39 am
Are they producing mainly gas?

According to Enno, an average Bakken well gives about 200k+ of oil, not 900k. It looks like it's much more gas than oil, or the numbers are completely bogus. Or they have bought the sweetest center of all sweet spots in Bakken?

Questions over questions

AlexS says: 02/16/2017 at 8:21 am
As of 3Q16, oil accounted for 61% of total CLR output.
Apparently, oil's share in CLR production in the Bakken is higher.

According to Enno, CLR Bakken wells with the first flow in 2014 have on average already produced > 200kb of oil. Their average EUR may exceed 400 kb and probably reach 500 kb.
Wells with first flow in 2015 and 2016 perform better.

That said, even including gas, EURs of 900 kboe look unrealistic

shallow sand says: 02/16/2017 at 9:19 am
AlexS.

I have mentioned company proved reserves and PV10 quite a bit here in the past two years.

I am coming to the opinion that these numbers, required by the SEC, have too many uncertainties to make them worthwhile, at least as to PUD. PDP may be useful.

AlexS says: 02/16/2017 at 9:24 am
shallow sand,

I agree. I think PUD estimates for tight oil formations are much more uncertain compared with conventional fields.

George Kaplan says: 02/16/2017 at 11:14 am
They appear to have been increasing well performance since 2014, maybe getting above 400k for oil if the curves continue (as below). It looks like they recomplete after some time. It will be interesting to see how the two 2016 curves go – started high and then the first took a dive. The late 2015 wells did the same and then jumped up, which looks like a re-completion. How much area does one of their new wells drain? Presumably the savings must mostly be on reduced drilling and completions cost, and maybe front loading the returns with higher initial production, not overall additional recovery.

Marathon announced today they'd have six rigs average this year – up one – not sure if that is enough to hold the decline near present levels, mostly that depends on completions rather than rigs though, but they are going for "multiple enhanced completion trials" and expect to increase overall USA production by up to 20% (also six rigs in Eagle Ford).

http://www.marathonoil.com/News/Press_Releases/Press_Release/?id=1012103

[Feb 20, 2017] Bakken steep drop of production

Feb 20, 2017 | peakoilbarrel.com
Heinrich Leopold says: 02/16/2017 at 5:19 am
Bakken data were out yesterday and we have seen a steep drop below 900 000 bbl/d nearly 300 000 bbl/d below its peak of 1.164 mill bbl/d in December (see below chart). Well performance (new and existing wells) is down to a five year low of 83 bbl per well and falling -20% year over year. This means a cost increase per produced barrel of 20%, even if new wells are performing better and costs per rig are down.

Since the well production declines by -20% over two years now, costs per produced barrel are up 40% and rising fast. No wonder companies seem to abandon Bakken for less mature fields such as the Permian. New permits are at five year low and rig count is also grinding down slowly. Inerestingly, number of wells are also falling – down 100 wells in December – which has been deemed as impossible in some forecasting models.

[Feb 09, 2017] Comparing well performance in the Permian and the Eagle Ford, it seems that average IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month of production), but declines in the EFS are much steeper

Notable quotes:
"... Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines. ..."
"... By contrast, new wells in the Permian continue to perform better than older wells. ..."
"... That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays. ..."
Feb 09, 2017 | peakoilbarrel.com
Enno Peters says: 02/07/2017 at 8:40 am
Alex,

"There is no data on average well quality for the wells that started production in 2016. Is that because the data for last year is incomplete?"

If you go to the "Well quality" tab in the first presentation, you'll see 2016 profiles as well.

The "Ultimate Recovery" overview only supports displaying production histories for wells of the same age. As there are still 2016 vintage wells on which I have no data (the ones that started in Nov/Dec), 2016 is not yet shown if you display it by "Year of first flow".

However, if you change the selection to "Quarter of first flow", or "Month of first flow", then you will see more recent data as well, incl 2016.

You may remember past discussions here where we discussed displaying or omitting incomplete tails in the well profile graphs. The Well Quality tab can show incomplete tails, while the Ultimate Recover tab can't.

AlexS says: 02/07/2017 at 10:34 am
Thanks Enno,

I just found that the number 2016 in the legend was hidden.

Comparing well performance in the Permian and the Eagle Ford, it seems that average IP rates are not that different (582 b/d and 510 b/d, respectively, in the second month of production), but declines in the EFS are much steeper.

As a result, by the tenth month, average well in the Permian produces 210.7 b/d, and in the EFS only 122.6 b/d.

Furthermore, well productivity in the Eagle Ford is detereorating over time compared to the wells drilled in previous years, which may suggest that
longer laterals and bigger fracs result in only slightly higher IPs but much steeper declines.

By contrast, new wells in the Permian continue to perform better than older wells.

That may explain why drilling/completion activity and LTO production in the Permian have remained more resilient and are quickly recovering; while EFS has seen the biggest decline in production among the key LTO plays.

[Jan 11, 2017] Cumulative total of Bakken Formation oil production.

Jan 11, 2017 | peakoilbarrel.com
R Walter says: 01/08/2017 at 11:20 pm
1,590,525,938

Cumulative total of Bakken Formation oil production.

One billion of those barrels produced in the past five years, four billion barrels to go with the projected 5.7 billion recoverable, another 20 years of production in the pipeline to go.

https://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp

Click on cumulative totals by formation.

By 2035, the Bakken oil will be about done, can't get anymore.

75 new wells per month, 12×20, 240×75=18,000 more wells over twenty years time.

The price of oil at 50, 4.5 billion barrels of oil, 225 billion dollars.

5,000,000 dollars of cost per well, 90,000,000,000 dollars invested in drilling those 18,000 new wells, 400,000,000 barrels for the extraction taxes, money for the state, 20% for royalties, 80,000,000 barrels for mineral owners, 480,000,000 barrels to keep everyone happy all of those years.

The oil companies can keep 3.52 billion barrels to sell to get them some money.

Times 50 USD per barrel to assess a value, 160,000,000,000 dollars in future income to pay the 90,000,000,000 dollars owed for oil wells drilled. After twenty years of production you will have 70,000,000,000 dollars left over for the buzzards to pick clean.

A measly 3,500,000,000 dollars per year for the oil companies to share. 350 oil companies working, ten million dollars to share amongst stockholders and employees.

The price of oil has to be more or the Bakken will slow to a crawl, then an end.

R Walter says: 01/09/2017 at 7:08 am
Made a mistake by a factor of ten. The 20% for royalties, it is 800,000,000 barrels for royalties, not 80,000,000.

2.8 billion barrels for the oil companies, not 3.52 billion.

[Jan 08, 2017] Dirty games around free cashflow and profitability of shale compnaies

Jan 08, 2017 | peakoilbarrel.com
AlexS says: 01/03/2017 at 12:23 pm
U.S. independent shale oil and gas producers are now cash flow neutral

From the IEA Oil Market Report:

"So far, the shale and tight oil industry has always been characterized by spending levels exceeding cash flow generated. Benefitting from the improved price environment (including a 50% natural gas price increase over the last six months), increased activity and enhanced cost efficiency, the US shale industry is now closer to being able to fund capex programs within operational cash flows. During 3Q16, for the first time in its history, the sector reached free cash flow neutrality. In other words, after more two years of very difficult times, the US shale business model seems on a much more sustainable path. Nonetheless, it remains to be seen whether companies can remain cash flow positive when the industry scales up activity and capital spending and as upward pressure on costs once again takes hold."

Free Cash FLow for US Independents* (USD billion)

* / Free Cash Flow has been calculated analyzing balance sheets of about 50 US shale operators, having more than 80% of their revenues coming from shale activities and covering over 60% of US tight oil and shale gas production

Watcher says: 01/03/2017 at 3:07 pm
What does independent mean?
AlexS says: 01/03/2017 at 4:04 pm
non vertically-integrated
shallow sand says: 01/03/2017 at 7:30 pm
Is interest expense included in these calculations? I am sure reduction of debt principal is not.
AlexS says: 01/03/2017 at 8:23 pm
Free cash flow = operating cash flow – capex.

Operating cashflow = net income excluding all non-cash items: depreciation and amortization; asset writedowns; gains and losses on asset sales, etc.
Operating cashflow includes only those interest expenses and taxes that were actually paid during a certain period and differ from "nominal" interest expenses and taxes that are shown in income statement (as interest can be capitalized, tax payments can be delayed, etc.).

In my view, operating cashflow is a better metric of oil and gas companies' operating results than net income.

Free cashflow shows what is left in a company's coffer after it has spent part of its cash on organic (non-acquisition) capex.
Negative free cashflow means that the company has to borrow money to cover its expenses.
Positive free cashflow means that the company can pay down part of its debt or keep free cash on its accounts.

Free cash flow after dividends = operating cash flow – capex – dividends.

Unlike oil majors, which tend to spend a significant part of their cash on dividends and repurchase of their own shares, U.S. E&Ps normally do not pay or pay relatively small dividends.

The above chart from the IEA monthly report shows that the group of 50 largest shale companies have finally achieved free cash flow neutrality in 3Q2016, which means their quarterly operating cashflow is roughly equal to the sum of their capex and dividends.

That was due to a sharp reduction in capex and lower costs.

I came to similar conclusions, as the IEA, after looking at 2Q and 3Q results from a few large U.S. shale companies.(Of course, my sample group was much narrower than 50 companies).

Mike says: 01/03/2017 at 9:31 pm
The shale oil industry has been in positive cash flow situation since prices got above 40 dollars a barrel. Sorry, this is a meaningless assessment of a meaningless article. Positive cash flow basis to what extent, exactly?

"Free cash flow (two words) shows what is left in a company's coffer after it has spent part of its cash on organic (non-acquisition) capex." Negative. This implies that all wells being drilled by the 50 shale oil companies referenced are now being paid for out of positive cash flow. I don't think so. If so, at the expense of deleveraging, so what?

"Negative free cash flow (two words) means that the company has to borrow money to cover its expenses." Define expenses, please. Including developmental CAPEX?

"Positive free cash flow (two words) means that the company can pay down part of its debt or keep free cash on its accounts." Right. Give me a percentage of the total 50 shale companies surveyed that paid down debt in 2016 and to what extent, please. Last I looked even EOG did not have COH to cover this years maturities.

"The above chart from the IEA monthly report shows that the group of 50 largest shale companies have finally achieved free cash flow neutrality in 3Q2016, which means their quarterly operating cash flow (two words) is roughly equal to the sum of their capex and dividends." How many of these stinking shale oil companies even pay dividends? Come on, Alex. That's BS and you know it. List the 50 and show their losses for 3Q16.

Shallow is right, positive cash flow fills the coke machine down the hall, for the first time in 25 months, that's it. If these shale guys are using cash flow to drill more stinking wells, they are doing so at the expense of deleveraging legacy debt. The marginal price per barrel of shale oil is a meaningless metric now. All of these guys are up to their asses in debt. Folks have got to let this ridiculous IEA, EIA, SPCA and NCAA bunk go and get planted on earth about this shale oil stuff. Nothing has changed in the past 5 months except that OPEC added 5 dollars a barrel to the bottom line. Temporarily.

shallow sand says: 01/03/2017 at 11:38 pm
I guess our goal every time we have borrowed money to buy an asset, be it an oil lease or otherwise, was to pay down the loan principal to zero.

Further, we have not borrowed money to drill or work over wells.

Currently, in the commodity spaces I am familiar with, most asset values are still high, despite much lower commodity prices (grains, oil and natural gas).

I assume increasing interest rates may change this, but maybe not?

We looked at a small oil lease recently. It was priced as if the price of oil was a steady $80. It sold for the asking price. In the first quarter of 2016 the lease lost money on an operating basis. It was barely cash flow positive for 2016. Fifteen years ago, the same lease, being also barely cash flow positive in 2001, would have sold for 1/10 of the current sale price, IMO.

Witness record acreage prices paid in the Permian earlier this year.

Farmland is the same. Grain prices are down for the third year, yet land is barely off highs. Net cash rental income, after payment of real estate taxes, is 2.5% or less. This is pre-income tax returns.

I am not smart enough to know what this means, or what one should do in this situation, unfortunately.

I will say, however, I believe few now have the goal of buying assets and paying the debt down to zero. It appears commodity assets are now about leverage, churn and other ways to make money from them, besides from the income produced by the assets themselves.

One area that I think will only get worse is commodity price volatility. I read a long article recently about this with regard to grain prices, written by a large, well respected farm management company. They have really put an emphasis on marketing, they say farmers that don't aggressively hedge will have a tough time.

This I believe is true for oil and gas too. Unfortunately, the cost to hedge has risen dramatically. I recall buying put options near the market for under a buck a barrel around 12-14 years ago. Those now go for $4+.

AlexS, I do not think operating cash flow is the only metric to look at. If we had paid $150K per barrel in 2013 with borrowed funds, the fact that we have had positive operating cash flow in 2016 would be of little solace.

I contend there is mucho debt in the industry that will continue to be "rolled", little will be paid through net operating income. However, much may be paid through equity issuance.

I sure hope the upstream oil and gas industry is not a microcosm for the whole economy. I'm not smart enough to know that either.

Nathanael says: 01/05/2017 at 10:09 pm
"I am not smart enough to know what this means, or what one should do in this situation, unfortunately."

That's fascinating data, "shallow sand". This is the sort of information I love to get so that I can analyze it, so I'll give it a shot. This is first pass.

I think we're watching a bubble. This smells like bubble.

(1) There is too much money among very rich people chasing too few good investments. Accordingly, the prices of investment products are getting bid up in a bubble.
(2) The bubble in oil, in particular, will burst as they see how terrible the rates of return are.
(3) The middlemen and speculators are of course exacerbating the bubble; they always do.
(4) When the bubble bursts, a lot of wealth will "vanish" overnight. It is best to be out of it before it bursts - sell at the top of the bubble if you can, and switch to something which is selling with less inflated prices.
(5) Farmland might be the same sort of bubble. The other possibility is that it might not have the same bubble behavior: its value might increase - if you get the right farmland, farmland which is likely to continue to do well despite climate change - as there are definitely predictions of droughts and crop failures coming in the next few years.
(6) Because of the excess of investment money, it may be impossible to find anything you're comfortable with which isn't selling at inflated prices, sadly. Paying off debt is an option if you have debt. Or insuring yourself against liabilities (are all your well capping and clean-shutdown costs prepaid?). That sort of thing.

Watcher says: 01/04/2017 at 11:53 am
Clueless should weigh in. I've seen the definition get massaged here and there.

Cash flow is inputs and outputs, and while SS is asking about interest above, that's not the debt focus. New borrowing can be called a cash influx. I've seen it done. New borrowing improves cash flow over a period measured. If you define it that way, you can borrow your way to prosperity.

(Look familiar, OMB?)

clueless says: 01/04/2017 at 12:54 pm
Watcher is mostly right. For example, there are only a small minority of companies that use GAAP earnings as their primary earnings measure. They all must report GAAP earnings, but usually tout some other earnings measure as their earnings that "are more useful for investors to understand the company's financial performance." The GAAP earnings for the most part are standardized. The "more useful" numbers are based upon each company determining for themselves what they will include/exclude. In many cases, totally self-serving. However, they must provide a reconciliation between GAAP earnings and the "more useful" earnings.

With respect to cash flow, each 10-K (annual) report and 10-Q (quarterly) report includes a GAAP standardized statement of cash flow. You may not be able to glean the information that you seek from that report, but it is the only one that I would trust.

Other statements that a company may make in presentations, discussions, etc about "cash flow" I would not trust without a complete detailed discussion of what they were including/excluding in the calculation.

I used the term for GAAP earnings as being "somewhat" standardized. With respect to oil and gas exploration companies, there are 2 different acceptable GAAP standards: successful efforts and full cost. Successful efforts expenses dry holes. Full cost capitalizes them into the pool of depletable costs and expenses them as the reserves are depleted. [Kind of like a manufacturer. Say that quality control finds one out of every 500 circuit boards to be defective. The company does not immediately expense that circuit board. The total manufacturing costs are allocated to the inventory of 499 circuit boards.] But, in the event of significant oil/gas price plunges, the calculation of the amount of write-downs of capitalized/depletable property is also different, depending on which method is used. That becomes a big deal if prices fully recover, because the write-downs are never reinstated.

Not very busy at this moment, so you got a lot of rambling, which I hope is mostly correct.

AlexS says: 01/04/2017 at 3:51 pm
Mike, shallow sand

Free cash flow is a widely used measure of a company's financial performance.
Unlike breakeven price and similar indicators which everyone calculates using its own methodology (and nobody discloses this methodology), free cash flow can be easily calculated using the data from company's SEC fillings.

Below is a definition of free cash flow from investopedia:

Free cash flow (FCF) is a measure of a company's financial performance, calculated as operating cash flow minus capital expenditures. FCF represents the cash that a company is able to generate after spending the money required to maintain or expand its asset base.

FCF is an assessment of the amount of cash a company generates after accounting for all capital expenditures. The excess cash is used to expand production, develop new products, make acquisitions, pay dividends and reduce debt.

Some believe that Wall Street focuses only on earnings while ignoring the real cash that a firm generates. Earnings can often be adjusted by various accounting practices, but it's tougher to fake cash flow. For this reason, some investors believe that FCF gives a much clearer view of a company's ability to generate cash and profits.
However, it is important to note that negative free cash flow is not bad in itself. If free cash flow is negative, it could be a sign that a company is making large investments. If these investments earn a high return, the strategy has the potential to pay off in the long run. FCF is also better indicator than the P/E ratio.

FCF is a good indicator of the performance of a public company. Many investors base their investment decisions on the free cash generated by a company or its equity price to FCF ratio.

http://www.investopedia.com/terms/f/freecashflow.asp

AlexS says: 01/04/2017 at 5:24 pm
It may seem strange that shale companies had negative free cash flow when oil prices were around $100, but achieved FCF neutrality in 3Q16 when WTI averaged only about $45.

The explanation is very simple. In 2010-14, shale companies were heavily investing, which helped them to achieve double-digit growth in production and to increase overall U.S. LTO output by ~1 mb/d each year in 2012-14.

While negative FCF is not necessarily negative, in this particular case, shale companies' strategies proved self-destroying.

1) Negative FCF led to accumulation of very high debt;
2) High demand from shale companies resulted in a sharp increase in unit costs for oil services and other inputs;
3) Rapid growth in LTO production caused the glut in the the global oil market and consequent drop in oil prices.

Lower oil prices led to a sharp reduction in shale companies' operating cash flows. But these companies even more sharply reduced their capex.
Finally, in 3Q2016 their combined capex was roughly equal to combined operating cash flow.

The above chart from the IEA Oil Market Report shows it very clearly.

shallow sand says: 01/04/2017 at 9:44 pm
AlexS. I do not disagree with you that the metrics you are explaining (very well, I might add) are very important.

However, I assume you agree that balance sheets and estimates of future cash flows are also important to look at.

In reality, all can be reviewed in SEC filings, which are the only numbers that are reliable. Company power point presentations are meant to be promotional material.

AlexS says: 01/05/2017 at 5:40 am
shallow sand,

FCF is a good shapshot of a company's financial performance in a particular period. Of course, it is not sufficient for understanding of this company's whole financial situation and its future prospects.

FCF neutrality in 3Q2016 means that the group of 50 companies didn't have to increase their debt, but debt accumulated over the previous years remains on their balance sheets and is a heavy burden for future development.

Furthermore, FCF neutrality was achieved thanks to lower capex which resulted in declining oil production.

Higher oil and gas prices expected for 2017 should improve oil companies' operating cash flows. A number of shale players have already announced planned increases in capex of 10-50% for next year. That will likely reverse the decline in LTO output. But higher capex will not allow shale companies to achieve significant positive FCF, and hence to start repaying their debt.

At $55-60 they will be able to only slightly increase output by year-end 2017 vs. year-end 2016, while maintaining FCF neutrality. A more aggressive increase in capex would result again in negative FCF and increase in debt.

Furthermore, increase in shale companies' spending will reverse oil service cost deflation, which was the main contributor to declining unit costs in 2015-16.

In my view, a conservative financial and operational strategy, with gradual and modest increases in capex, should allow a moderate growth in LTO production over the next few years without significant increase in debt levels.

But a return to previous growth rates of 1 mb/d p.a. anticipated by some experts (including Rystad Energy) from 2018, would result in further deterioration of shale companies' financial situation. And it would have a negative impact on oil prices.

Nathanael says: 01/05/2017 at 10:13 pm
Yeah, something critically important in addition to free cash flow is the growth (or, in *this* industry, decline) trajectory. It's great to have free cash flow this year, but if your wells all run out in two years and you haven't drilled more, well, your free cash flow this year and next *is the total value of the company*, because there won't be any free cash flow in year three.

Well, actually, it's not even that good: liabilities also have to be considered.

clueless says: 01/05/2017 at 12:21 am
Easier said than done. Look at the latest 10-Q for CLR. It seems to me that there would be a lot of questions about their results, especially when you look at their operating cash flow and notice the large impairment charge that is added back, thereby not affecting cash flow from operations negatively. But they lost that cash almost as surely as if they drilled a dry hole.
shallow sand says: 01/05/2017 at 12:57 am
clueless. Regarding CLR and SEC filings, I have brought up several times that the company managed to reduce its estimate of future production costs by 60% from 2014 to 2015, while only reducing all categories of proved reserves by just 9% during the same period.

I believe there were some things pulled to keep PV10 above long term debt in 2015 and I expect the same for year end 2016.

CLR was not the only company to do this.

AlexS says: 01/05/2017 at 4:29 am
clueless,

the large property impairment charge in CLR accounts for 3Q2016 ( $57 million for 3Q and $203 million for 9 months of 2016) is the result of negative revaluation of their reserves (due to lower oil price). It is reflected in the balance sheet as lower net property and equipment (compared with previous period) and as lower shareholers equity.
It is also shown in the income statement, but added back in cash flow statement as that's not real cash paid by the company.
It's a paper loss.

Dry hole cost is very small ( $27 thousands for 3Q and $233 thousands for 9 months of 2016). The cost of drilling wells was already accounted as capex. Then the cost of of successful wells was capitalized (and added to PP&E in the balance sheet) and dry hole costs are expensed and appear in the income statement as expenses. But they are added back in cash flow statement as cash paid for both succesful and dry wells was already included in capex.

Mike says: 01/05/2017 at 8:44 am
Alex, thank you for your detailed explanation of free cash flow. After 40 years of operating oil and gas wells I understand the definition very well. It can indeed be used, as you have said, as a snapshot of financial activity within in a brief period of time. As I have said, and Shallow, I believe, it is of little importance in the grand scheme of things. The shale oil industry is in serious financial trouble and 5 dollars a barrel on the "hope" of OPEC cuts has not changed that.

Its curious to me this intense need for some folks to make predictions about the future. Predicting the role shale oil might play in that future over the next decade, or decades, without understanding the financial condition of those companies extracting it, is a big mistake in my opinion. The shale oil phenomena has not been paid for yet, nevertheless you and others are counting on it decades thirty years from now. I do not understand that, sorry. I really don't have much to contribute here, it seems.

Dennis Coyne says: 01/05/2017 at 1:04 pm
Hi Mike,

I agree LTO will contribute very little in the grand scheme.

Lots of agencies and companies provide outlooks of the future. The Chart below shows the BP Outlook 2016 for C+C+NGL and my "medium" scenario for C+C+NGL with URR=3600 Gb for 2015 to 2035.

clueless says: 01/05/2017 at 1:12 pm
AlexS – I did not do a good job of trying to point out that I think that you have to look at more info.

If you read metric number 3 in this short article, it might be clearer.
http://www.oldschoolvalue.com/blog/investing-perspective/useless-stock-metrics/

AlexS says: 01/05/2017 at 9:26 pm
clueless,

I don't know who is the author of that article, but the very first phrase about operating cash flow is a complete nonsense:

"The way Cash Flow from Operations is calculated is by starting with net income (equity earnings) which doesn't include interest paid to debt holders."

Of course, net income includes "Interest expense".
See CLR's 3Q accounts; income statement.
Net interest expense for the quarter was $82 million.

[Nov 21, 2016] Bigger fracs which cost more money result in higher IPs and higher ensuing 90 day production results. That generates more cash flow and allows for higher EURs that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that.

Notable quotes:
"... This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet. ..."
"... It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices. ..."
"... Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. ..."
peakoilbarrel.com
Hi,

Here are my updates as usual. GOR declined or stayed flat for all years except 2010 in September. Is it the beginning of a new trend?

FreddyW says: 11/16/2016 at 3:50 pm
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009 on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few months?

Watcher says: 11/16/2016 at 10:34 pm
Freddy, these latest years, the IP months are chopped at the top. Any chance of showing those?

The motivation would be to get a look at the alleged spectacular technology advances in the past, oh, 2 yrs.

FreddyW says: 11/17/2016 at 2:10 pm
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so for the method I used above is not very usable. Bellow is the production profile which is better for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the production profile graph.

Watcher says: 11/17/2016 at 2:40 pm
Excellent.

And I guess we can all see no technological breakthru. 2014's green line looks superior to first 3 mos 2015.

2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper decline at that point and is likely going to intersect 2014's line probably within the year.

There is zero evidence on that compilation of any technological breakthrough surging output per well in the past 2-3 yrs.

In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR improvement.

And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also no evidence of sweetspots first.

I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with inferior technology, and then as they became less sweet the technological breakthroughs brought output up to look the same.

Too
Much
Coincidence.

It's all bogus.

Watcher says: 11/17/2016 at 8:12 pm
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.

And it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.

This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.

Mike says: 11/17/2016 at 8:59 pm
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.

Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that.

Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.

Watcher says: 11/18/2016 at 12:03 am
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?

I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This should kill the profitability on those later wells because 30 stages must cost more.

But profit is not required when you MUST have oil.

Watcher says: 11/18/2016 at 12:14 am
You know, that is absolutely insane.

Freddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?

FreddyW says: 11/18/2016 at 2:55 pm
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.
FreddyW says: 11/16/2016 at 3:57 pm
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I suspected. The curves are currently gathering in the 15%-20% range.

Dennis Coyne says: 11/16/2016 at 5:33 pm
Hi FreddyW,

What is the annual decline rate of the 2007 wells from month 98 to month 117 and how many wells in that sample (it may be too low to tell us much)?

FreddyW says: 11/16/2016 at 6:02 pm
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above. Current yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would translate to a 10,3% yearly decline rate. The 2007 curve look quite different from the other curves, so thats why I did not include it.
Dennis Coyne says: 11/16/2016 at 9:27 pm
Hi Freddy W,

Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.

FreddyW says: 11/17/2016 at 3:37 pm
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.

Regarding natural log plots. Yes it could be good if you want to find a constant exponential decline. But we are not there yet as you can see in above graph.

One good reason why decline rates are increasing is because of the GOR increase. When they pump up the oil so fast that GOR is increasing, then it's expected that there are some production increases first but higher decline rates later. Perhaps completion techniques have something to do with it also. Well spacing is getting closer and closer also and is definitely close enough in some areas to cause reductions in UR. But I would expect lower inital production rather than higher decline rates from that. But maybe I´m wrong.

Dennis Coyne says: 11/17/2016 at 8:42 am
Hi FreddyW,

Do you have an estimate of the number of wells completed in North Dakota in September? Does the 71 wells completed estimate by Helms seem correct?

Dennis Coyne says: 11/17/2016 at 12:40 pm
Hi FreddyW,

Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.

FreddyW says: 11/17/2016 at 2:19 pm
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.
Pete Mason says: 11/16/2016 at 3:49 pm
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Dennis Coyne says: 11/16/2016 at 5:28 pm
Hi Pete,

Even though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).

Guy Minton says: 11/16/2016 at 8:41 pm
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle Ford. They ran those projections for a well for over 22 years. Not sure which planet we are talking about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to an Eagle Ford producing half of what they will in the first two years. In most areas, I would say that it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil price reaches a certain level. If it was at a hundred now, it would still take about two years to significantly increase production, if it ever happens. I am not a big believer that US shale is the new spigot for supply.
Dennis Coyne says: 11/16/2016 at 10:03 pm
Hi Guy,

The wells being shut in are not nearly as important as the number of wells completed because the output volume is so different. So the average well in the Eagle Ford in its second month of production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So about 37 average wells need to be shut in to offset one average new well completion.

Point is that total well counts are not so important, it is well completions that drive output higher.

Output is falling because fewer wells are being completed. When oil prices rise and profits increase, completions per month will increase and slow the decline rate and eventually raise output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about 79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I expect eventually new well EUR will start to decrease and my model will start to match actual output better by mid 2017 as sweet spots run out of room for new wells.

Guy Minton says: 11/17/2016 at 7:14 am
Guess I will remember that for the future. The number of producing wells is not important. Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels back in early 2015.
Dennis Coyne says: 11/17/2016 at 10:39 am
Hi Guy,

Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those but complete one well the net change in output is zero.

Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells produced 10 b/d on average.

How much do you expect output to fall in the US by Dec 2017?

Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment where you predicted this?

Tell us what it will be in August 2017.

I expected the fall in supply would lead to higher prices, I did not expect World output to be as resilient as it has been and I also did not realize how oversupplied the market was in April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased by 635 kb/d.

If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12 month average peak in August 2015 (centered 12 month average).

Guy Minton says: 11/18/2016 at 4:50 am
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but from those producing greater than 10, but less than 100. The ones producing greater than 100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the US shale only. It is your site, you can search it better than I can,
Guy Minton says: 11/18/2016 at 6:20 am
But then don't take my word for it. You can find the same information under the Texas RRC site under oil and gas/research and statistics/well distribution tables. Current production for Sep can be found at online research queries/statewide. It is still dropping, and will long term at the current activity level. Production drop for oil, only, is a little over 40k per day barrels, and condensate is lower for September. Proofs in the pudding.
My guess is that you would see a lot more plugging reports, if it were not so expensive to plug a well. At net income levels where they are, I expect they would put that off as long as they could.
AlexS says: 11/16/2016 at 8:51 pm
Statistics for North Dakota and the Bakken oil production are perfect, but not for well completions.

From the Director's Cut:

"The number of well completions rose from 63(final) in August to 71(preliminary) in September"
(North Dakota total)

From the EIA DPR:

The number of well completions declined from 71 in August to 52 in September and rose to 58 in October
(Bakken North Dakota and Montana).

Wells drilled, completed, and DUCs in the Bakken.
Source: EIA DPR, November 2016

Dennis Coyne says: 11/16/2016 at 9:36 pm
Hi Alex S,

I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.

shallow sand says: 11/17/2016 at 8:36 am
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.

It appears this was because another 13 wells in the field were recently completed.

It appears that when all 29 wells are returned to full production, this field will be very prolific initially. Therefore, on this one field alone, we could see some impact for the entire state.

Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on these strong wells. Bakken just not close to economic.

I also note that average production days per well in for EOG in Parshall was 24. I haven't looked at some of the other "older" large fields yet, but assume the numbers are similar.

shallow sand says: 11/17/2016 at 8:58 am
Also, over 3000 Hz wells in ND produced less than 1000 BO in 9/16.

This is just for wells with first production 1/1/07 or later.

Dennis Coyne says: 11/17/2016 at 10:57 am
Hi Shallow sand,

I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk costs in wells drilled but not completed and running the numbers based on whether they can pay back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay the bills as best they can, not sure if just stopping altogether is the best strategy.

There is the old adage that when your in a hole, more digging doesn't help much. 🙂

So my model just assumes continued completions at the August rate for about 12 months with gradually rising prices as the market starts to balance, then a gradual increase in completions as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90 completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level for 40 years (not likely, but the model is simplistic).

I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?

shallow sand says: 11/18/2016 at 8:20 am
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding the oil price.

I continue to contend that there will be no quick price recovery without an OPEC cut. Further, the US dollar is very important too, as are interest rates.

Dennis Coyne says: 11/18/2016 at 10:03 am
Hi Shallow sand,

At some point OPEC may not be able to increase output much more and overall World supply will increase less than demand. My guess is that this will occur by mid 2017 and oil prices will rise. OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe another 1 Mb/d at most. I don't expect any big increases from other OPEC nations in the near term.

A big guess as to oil prices has to be made to do a model.

I believe my guess is conservative, but maybe oil prices will remain where they are now beyond mid 2017.

I expected World supply to have fallen much more quickly than has been the case at oil prices of $50/b.

George Kaplan says: 11/17/2016 at 3:31 am
Probably to do with how confidential wells are included.
AlexS says: 11/17/2016 at 4:42 am
RBN explains EIA methodology:

"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical registry-to identify the completion phase, marked by the first fracking. If a well shows up on the registry, it's considered completed "

Sydney Mike says: 11/17/2016 at 2:19 am
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a weekly English business paper called Capital Ethiopia. The latest editorial is again putting an excellent perspective on world events. http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600

For the record, I have no interest or connection to this publication other than that of a paying reader.

Wouldn't it be nice if mainstream publications would sound a bit more like this.

Watcher says: 11/17/2016 at 11:34 am
the word oil does not appear anywhere on that.
Pete Mason says: 11/17/2016 at 4:56 am
Thanks all. I thought that the red queen concept meant that there had to be an increase in the rate of completions. So that 71 year-on-year in north Dakota would only stabilise temporarily. Perhaps the loss of sweet spots are being counteracted by the improvements in technology? I'm assuming that even with difficulties of financing there will be a swift increase in completions should the oil price take off, but not sure how sustainable this would be
Oldfarmermac says: 11/17/2016 at 6:03 am
Hi Pete,

Sometimes I think that once the price of oil is up enough that sellers can hedge the their selling price for two or three years at a profitable level, it will hardly matter what the banks have to say about financing new wells.

At five to ten million apiece, there will probably be plenty of money coming out of various deep pockets to get the well drilling ball rolling again, if the profits look good.

Sometimes the folks who think the industry will not be able to raise money forget that it's not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases, etc are already in place, meaning all it takes to get the oil started now is a drill and frack rig.

I don't know what the price will have to be, but considering that a lot of lease and other money is a sunk cost that can't be recovered, and will have to be written off, along with the mountain of debts accumulated so far, the price might be lower than a lot of people estimate.

Bankruptcy of old owners results in lowering the price at which an old business makes money for its new owners.

Dennis Coyne says: 11/17/2016 at 8:32 am
Hi Pete,

The Red Queen effect is that more and more wells need to be completed to increase output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain output.

Heinrich Leopold says: 11/17/2016 at 8:11 am
The FED oil production number for October came out yesterday. In below chart the production decline (blue line) is the same as in the previous month, yet the trend is still a massive decline year over year. In my view year over year comparison can show the dynamic of a trend. And it shows clearly that in the current cycle the oil price recovery is – in contrast to the cycle in 2008/9 – very slow and tentative.

The year over year oil price (green line in below chart) actually decreased again year over year and the risk of a double dip in the oil price is growing by the day. Drilling follows very cautiously the oil price in a parallel line (red line in below chart). If there would be really a technological advantage for shale, the red and the green line would not be paralell, but the red line for drilling would rise much stronger. This is actually the case for Middle East drilling, which barely fell during this cycle. This indicates that most Middle East producers still have high margins at the current oil price. Middle East producers – and also Russia – can quite easily cope with an oil price of 40 +/- 10 USD per barrel. This is why I think that the oil price will bounce at the bottom of the barrel within above range for a few years.

There is also something interesting going on with the world economy. The shippers rose exponentionally over the last few days (DRYS up over 1000%). Also the baltic Dry index is up 600% since the beginning of this year. House prices here in London fell – mostly at the high end. Rents for expensives homes are down by up to 36%. Donald Trump has clearly changed something already as it becomes increasingly clear that the dollar hoarders are paying for the infrastructure spending. I am not sure if he understands that he is doing a lot of harm to his own business empire as well.

Wake says: 11/17/2016 at 3:30 pm
I expect if that depressing old banker were here he would note that instability is dangerous, and that all the moves in treasuries currency and possibly trade flow create changes of which the results are difficult or impossible to predict
Oldfarmermac says: 11/18/2016 at 7:55 am
Hi Heinrich,

I can easily understand your assertion that Middle Eastern and Russian oil is profitable at forty bucks.

But if the price is to stay around forty, then it follows that you think that between them, the producers in the Middle East and Russia will be able to supply all the oil the world wants for the next few years.

Am I correct in saying this?

Do you think western producers will continue to pump enough at a loss ( most of them are apparently losing money at forty bucks ) to make up the difference?

If you are willing to venture a guess, when do you think the price will get back into the sixty dollar and up range?

If you think it won't for a lot of years, is that because you believe the economy is will be that anemic, or because electric cars will substantially reduce demand, or both ? Or maybe you have other reasons ?

Heinrich Leopold says: 11/18/2016 at 9:49 am
oldfarmermac,

The US has thrown the gauntlet to OPEC by claiming to becoming an oil net exporter. This has brought OPEC in a very difficult situation. If they cut – and oil gets to 70 USD per barrel – shale will pick up the slack and produce the amount OPEC has cut within a short period of time. So, OPEC is forced to cut again, until it has lost a lot of market share – and thus also a lot of revenue.

In my view OPEC has no other choice than to produce come hell and water – until something breaks. This could be that many shale companies give up or that for instance Iran is not allowed to export as much as they do, or there is a major conflict in the Middle East, or Saudi Arabia is running out of cash ..

He who has the market share now, will cash in when the oil price rises. And it will rise, yet not until something breaks. This is how business works. This is how Microsoft crushed Apple in the nineties in the PC market – and Apple then crushed Nokia in the smart phone market .

I do not think that Saudi Arabia has the freedom to compromise here – even if they want. If they blink they will be crushed by shale producers. So, the stand-off will go on for a while, at a loose-loose situation for both parties. However this is great luck for consumers as they can enjoy low energy prices for 2 to 3 years.

Enno Peters says: 11/17/2016 at 11:48 am
I've also a new post on ND, here .
George Kaplan says: 11/18/2016 at 8:28 am
Do you know why you show a significantly higher number of DUCs than Bloomberg do – as reported here?

http://www.oilandgas360.com/ducs-havent-flown-fast-since-april/

I think your numbers reflect numbers reported from ND DMR but Bloomberg might be closer to reality for wells that will actually ever be completed (just a guess by me though). How do Bloomberg get their numbers (e.g. removing Tight Holes, or removing old wells, not counting non-completed waivers etc.)?

Enno says: 11/18/2016 at 10:56 am
George,

Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old wells for example, and already include those that were spud last month (even though maybe casing has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs method exactly, so I can't comment on that.

Oldfarmermac says: 11/18/2016 at 7:57 am
Discussion of Venezuelan politics should be in the open thread, but politics are going to determine how much oil is produced there for the next few years, and the situation looks iffy indeed.

https://www.theguardian.com/commentisfree/2016/nov/17/venezuela-nicolas-maduro-dictatorship-elections-jeremy-corbyn

Watcher says: 11/18/2016 at 2:09 pm
Concerning Freddy's chart of production profile of wells drilled in various years.

They all line up by about month 18 of production. This should not be possible. The later wells have many more stages of frack. They are longer, draining more volume of rock. But the chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the curve can be the same, but it should be offset higher.

Explanation?

How about above ground issues . . . older wells get pipelines and can flow more oil . . . nah, that's absurd.

There needs to be a physical explanation for this.

AlexS says: 11/18/2016 at 4:36 pm
These new wells have higher IPs, but also higher decline rates.
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact production curves and EURs.
Watcher says: 11/18/2016 at 6:02 pm
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into production?

Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as the shorter laterals did at the same month number of production. Higher IP and higher decline rate will affect the shape, but There Is Twice The Length..

Dennis Coyne says: 11/18/2016 at 8:15 pm
Hi Watcher,

I don't think we have information on the length of the wells, since 2008 the length of the lateral has not changed, just the number of frack stages and amount of proppant. This seems to primarily affect the output in the first 12 to 18 months, and well spacing and room in the sweet spots no doubt has some effect (offsetting the greater number of frack stages etc.).

Listen to Mike, he knows this stuff.

Watcher says: 11/18/2016 at 8:31 pm
From http://www.dtcenergygroup.com/bakken-5-year-drilling-completion-trends/

STATISTICS

The combination of longer lateral lengths and advancements in completion technology has allowed operators to increase the number of frac stages during completions and space them closer together. The result has been a higher completion cost per well but with increased production and more emphasis on profitability.

In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs have been achieved.

One of the main reasons for this is the longer lateral lengths – operators now have twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008, as experienced by DTC supervisors.

By placing more fracture stages closer together, over a longer lateral length, operators have successfully been able to improve initial production (IP) rates, as well as increase EURs over the life of the well.

blah blah, but they make clear the years have increased length. Freddy was talking about well spacing, this text is about stage spacing, but that is achieved because of lateral length.

Freddy can you revisit your graph code? It's just bizarre that different length wells have the same flow rate 2 yrs out, and later.

FreddyW says: 11/19/2016 at 7:22 am
Take a look at Enno´s graphs at https://shaleprofile.com/ . They look the same as my graphs and we have collected and processed the data independently from each other.
George Kaplan says: 11/19/2016 at 1:39 am
If the wells have the same wellbore riser design irrespective of lateral length (i.e. same depth, which is a given, same bore, same downhole pump) then that section might become the main bottleneck later in life and not the reservoir rock. With a long fat tail that seems more likely somehow compared to the faster falling Eagle Ford wells say (but that is just a guess really). But there may be lots of other nuances, we just don't have enough data in enough detail especially on the late life performance for all different well designs – it looks like the early ones are just reaching shut off stage in numbers now. I doubt if the E&Ps concentrated on later life when the wells were planned – they wanted early production, and still do, to pay their creditors and company officers bonuses (not necessarily in that order).
Watcher says: 11/19/2016 at 3:31 am
Hmmm. I know it is speculation, but can you flesh that out?

If some bottleneck physically exists that defines a flow rate for all wells from all years then that does indeed explain the graphs, but what such thing could exist that has a new number each year past year 2?

We certainly have discussed chokes for reservoir/EUR management, but the same setting to define flow regardless of length?

Hmmm.

George Kaplan says: 11/19/2016 at 4:01 am
The flow depends on the available pressure drop, which is made up of friction through the rock and up the well bore (plus maybe some through the choke but not much), plus the head of the well, plus a negative number if there is a pump. The frictional and pump numbers depend on the flow and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the rock because of the high flow, then not so much. Once the flow drops the pressure at base of the well bore just falls as a result of depletion over time, the effect of the completion design is a lot less and lost in the noise, so all the wells behave similarly. That's just a guess – I have never seen a shale well and never run a well with 10 bpd production, conventional or anything else.

A question might be if the flow is the same why doesn't the longer well with the bigger volume deplete more slowly, and I don't know the answer. It may be too small to notice and lost in the noise, or to do with gas breakout dominating the pressure balance, or just the way the the physics plays out as the fluids permeate through the rock, or we don't have long enough history to see the differences yet.

clueless says: 11/18/2016 at 2:30 pm
Permian rig count now greater than same time last year.
Watcher says: 11/18/2016 at 3:27 pm
http://www.fool.ca/2016/11/16/buffett-sells-suncor-energy-inc-what-does-this-mean-for-the-canadian-oil-patch/
AlexS says: 11/18/2016 at 4:55 pm
Suncor's forecast for production [in 2017] is 680,000-720,000 boe/d. A midpoint would represent a 13% increase over 2016.

http://www.ogj.com/articles/2016/11/suncor-provides-capital-spending-production-outlook-for-2017.html

Solid growth

R Walter says: 11/18/2016 at 5:47 pm
The only oil investment that has any feck is turmoil.

Or, Term Oil Corporation.

Also known as Peak Oil.

http://www.bnsf.com/about-bnsf/financial-information/weekly-carload-reports/

The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400 petroleum cars hauled each week for a good six months now.

Seems as though petroleum by rail is more of a necessity than a choice.

The volume is down a good thirty percent since about 2013 when over 10,000 cars were hauled per week.

Demand decreases, contracts expire, better modes of transport emerge and cost less. not as much call for Bakken oil. Plenty of the stuff somewhere else in this world.

The trend is down, not up for petroleum hauled by rail.

If there were orders for Bakken oil for one million bpd, the production would be one million bpd.

Bakken oil lost marketshare due to price drop.

Buyers can buy oil from anywhere.

GoneFishing says: 11/18/2016 at 6:34 pm
More Bakken petroleum is being moved by pipeline.

Over the whole rail system, petroleum and petroleum product rail car loadings were down to 10.5 thousand in September. That compares to a high point of 16.3 thousand railcars in Sept of 2014.

Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept. Coal was running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.

AlexS says: 11/18/2016 at 6:57 pm
The chart below from RBN shows that Bakken pipeline capacity did not increase since early 2015. But production dropped, and this primarily affected volumes of Bakken oil transported by rail.

Given the higher percentage of oil transported by pipelines, the average transporation cost for Bakken crude should have decreased. Interesting, however, that the price differential between the well-head Bakken sweet crude and WTI has remained within the $10-12/bbl range.

Bakken Crude Production and Takeaway Capacity
Source: RBN

AlexS says: 11/18/2016 at 7:06 pm
This article from Platts explains better than me:

Analysis: Bakken discounts deepen as competition heats up

Houston (Platts)–16 Nov 2016
http://www.platts.com/latest-news/oil/houston/analysis-bakken-discounts-deepen-as-competition-27711340

Bakken Blend differentials at terminals close to North Dakota wellheads held their lowest assessment since December Tuesday, closing at the calendar-month average of the NYMEX light sweet crude oil contract (WTI CMA) minus $6.25/b.
While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI spread - trading around 42 cents/b Tuesday, well in from the steady $2/b seen this summer - the return of Louisiana Light Sweet to the Midwest market may also be having an impact, according to traders.
One trader said there was an increase in volumes heading up the Capline pipeline, however, differentials suggest LLS is still too expensive, at least compared to Bakken. Platts assessed LLS at WTI plus $1.15/b Tuesday.
Considered by some to be the "champagne of crudes," it is unclear what appeal LLS still has for a Midwest refiner as margins for LLS actually - and unusually - lag those for Bakken.
S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b Monday, compared to Bakken cracking margins of $6.37/b. In fact, the advantage of cracking Bakken has grown steadily since August.
Platts margin data reflects the difference between a crude's netback and its spot price.
Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.
What is clear however, is that the steeper discounts available for Bakken provide the biggest incentive for a Midwest refiner.
The cost of getting Bakken to this market is around $3.48/b, according to Platts netback calculations, compared to just $1.02/b for LLS.
These costs make up a significant portion of the Bakken discount.
Further, LLS moving up the Capline after many years of relative inactivity does not necessarily suggest a new trend is in the making. However, recent pipeline reversals between Texas and Louisiana mean more Permian crudes are capable of reaching Louisiana refineries, and thus, if priced accordingly, could displace incremental volumes of LLS from its home market.
With current pipeline capacity out of North Dakota typically full, the marginal Bakken barrel often gets to market via rail, and this cost has traditionally sets the floor to Bakken's discount to WTI. And part of the recent downturn in Bakken could be chalked up to an increase in railed volumes to the US Atlantic Coast, as Bakken cracking margins there are again in the black.
In fact, Association of American Railroad's latest monthly and weekly data shows crude and refined product rail movements appear to have bottomed, having grown in September from August.
Weekly data bears this out as well, showing increases in three of the last four weeks.
It remains to be seen how long this will last, however, should Energy Transfer Partners Dakota Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the grade too expensive to rail east. However, the devil is in the details.
Traders and analysts have pegged Dakota Access pipeline tariffs between $4.50-$5.50/b for uncommitted shippers between North Dakota and Patoka, Illinois. A further $6.50/b would be needed to bring the crude south from Patoka to Nederland, Texas, sources have said.
If this $11-$12/b combined pipeline estimated cost were to pan out, it would be more expensive than the $10.20/b Platts assumes in its Bakken USAC rail-based netback calculation.

AlexS says: 11/18/2016 at 8:59 pm
U.S.oil rig count was up 19 units last week, the largest weekly gain in 16 months.
Gas rig count is up 1 unit.

Permian basin: + 11 oil rigs
Bakken: -1
Eagle Ford: -1
Niobrara: +2
Cana Woodford: unchanged
Other shale plays: +2
Conventional basins: +6

Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase among all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and especially the Eagle Ford where drilling activity remains depressed.

AlexS says: 11/18/2016 at 9:30 pm
The number of horizontal rigs drilling for oil in the Permian is now 54% of the 2014 peak.

Oil rig count in the Permian basin
source: Baker Hughes

AlexS says: 11/18/2016 at 9:42 pm
Weak drilling activity in the Bakken and the Eagle Ford helps to explain continued declines in their oil production

Oil rig count in 4 other tight oil plays

Roger Blanchard says: 11/19/2016 at 8:17 am
Alex,

As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state.

Based upon state data, the number of producing wells/square mile is 1.29 in Mountrail County, 1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn County. How high can the number of producing wells/square mile go?

Is there something more than reduced drilling to explain the drop in production?

George Kaplan says: 11/19/2016 at 8:35 am
This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated.

AlexS says: 11/18/2016 at 9:53 pm
From a recent EIA report:

"U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month."

AlexS says: 11/18/2016 at 9:58 pm
The EIA DPR production volume estimates for the Permian include both LTO and conventional C+C

AlexS says: 11/18/2016 at 10:06 pm
Permian Basin also dominates M&A activity in the US E&P sector.

From the same EIA report:

"Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value."

http://www.eia.gov/todayinenergy/detail.php?id=28772

Heinrich Leopold says: 11/19/2016 at 6:09 am
RRC Texas for September came out recently. As others will probably elaborate more on the data, I just want to show if year over year changes in production could be use as a predictive tool for future production (see below chart).

It is obvious that year over year changes (green line) beautifully predicted oil production (red line) at a time lag of about 15 month. Even when production was still growing, the steep decline of growth rate indicated already the current steep decline.

The interesting thing is that the year over year change is a summary indicator. It does not tell why production declines or rises. It can be the oil price, interest rates or just depletion – even seasonal factors are eliminated. It just shows the strength of a trend.

I am curious myself how this works out. The yoy% indicator predicts that Texas will have lost another million bbl per day by end next year. That sounds quite like a big plunge. One explanation could be the fact that we have now low oil prices and high interest rates. In all other cycles it has been the other way around: low oil prices came hand in hand with low interest rates. This could be now a major obstacle for companies to grow production.

This concept of following year over year changes works of course just for big trends, yet for investment timing it seems exactly the right tool. Another huge wave is coming in electric vehicles which are growing in China by 120% year over year. Here we have the same situation as for shale 7 years ago: Although current EV sales are barely 1 million per year worldwide, the growth rate reveals already an huge wave coming. So as an investor it is always necessary to stay ahead of the trend and I think this can be done by observing the year over year% change.

[Nov 19, 2016] The bakken core is getting saturated and average production per well drops. Often dramatically as you go out of 50 km sweet spot zone.

Notable quotes:
"... As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state. ..."
"... This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated. ..."
"... "U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month." ..."
"... "Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase. Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value." ..."
Nov 19, 2016 | peakoilbarrel.com

R Walter says: 11/18/2016 at 5:47 pm

The only oil investment that has any feck is turmoil.

Or, Term Oil Corporation.

Also known as Peak Oil.

http://www.bnsf.com/about-bnsf/financial-information/weekly-carload-reports/

The number of rail cars hauling petroleum is a constant in the range of 7,200 to 7,400 petroleum cars hauled each week for a good six months now.

Seems as though petroleum by rail is more of a necessity than a choice.

The volume is down a good thirty percent since about 2013 when over 10,000 cars were hauled per week.

Demand decreases, contracts expire, better modes of transport emerge and cost less. not as much call for Bakken oil. Plenty of the stuff somewhere else in this world.

The trend is down, not up for petroleum hauled by rail.

If there were orders for Bakken oil for one million bpd, the production would be one million bpd. Bakken oil lost marketshare due to price drop. Buyers can buy oil from anywhere.

GoneFishing says: 11/18/2016 at 6:34 pm
More Bakken petroleum is being moved by pipeline. Over the whole rail system, petroleum and petroleum product rail car loadings were down to 10.5 thousand in September. That compares to a high point of 16.3 thousand railcars in Sept of 2014.

Coal car loadings are on the rise, from a low of 61,000 in April to 86,000 in Sept. Coal was running a near steady 105,00 to 110,000 railcars every month in 2013 and 2014.

AlexS says: 11/18/2016 at 6:57 pm
The chart below from RBN shows that Bakken pipeline capacity did not increase since early 2015. But production dropped, and this primarily affected volumes of Bakken oil transported by rail.

Given the higher percentage of oil transported by pipelines, the average transportation cost for Bakken crude should have decreased. Interesting, however, that the price differential between the well-head Bakken sweet crude and WTI has remained within the $10-12/bbl range.

Bakken Crude Production and Takeaway Capacity
Source: RBN

AlexS says: 11/18/2016 at 7:06 pm
This article from Platts explains better than me:

Analysis: Bakken discounts deepen as competition heats up

Houston (Platts)–16 Nov 2016
http://www.platts.com/latest-news/oil/houston/analysis-bakken-discounts-deepen-as-competition-27711340

Bakken Blend differentials at terminals close to North Dakota wellheads held their lowest assessment since December Tuesday, closing at the calendar-month average of the NYMEX light sweet crude oil contract (WTI CMA) minus $6.25/b.

While one factor dragging on Bakken differentials has clearly been a tight Brent/WTI spread - trading around 42 cents/b Tuesday, well in from the steady $2/b seen this summer - the return of Louisiana Light Sweet to the Midwest market may also be having an impact, according to traders.

One trader said there was an increase in volumes heading up the Capline pipeline, however, differentials suggest LLS is still too expensive, at least compared to Bakken. Platts assessed LLS at WTI plus $1.15/b Tuesday.

Considered by some to be the "champagne of crudes," it is unclear what appeal LLS still has for a Midwest refiner as margins for LLS actually - and unusually - lag those for Bakken.

S&P Global Platts data shows LLS cracking margins in the Midwest closed at $3.30/b Monday, compared to Bakken cracking margins of $6.37/b. In fact, the advantage of cracking Bakken has grown steadily since August.

Platts margin data reflects the difference between a crude's netback and its spot price.

Netbacks are based on crude yields, which are calculated by applying Platts product price assessments to yield formulas designed by Turner, Mason & Co.

What is clear however, is that the steeper discounts available for Bakken provide the biggest incentive for a Midwest refiner.

The cost of getting Bakken to this market is around $3.48/b, according to Platts netback calculations, compared to just $1.02/b for LLS.

These costs make up a significant portion of the Bakken discount.

Further, LLS moving up the Capline after many years of relative inactivity does not necessarily suggest a new trend is in the making. However, recent pipeline reversals between Texas and Louisiana mean more Permian crudes are capable of reaching Louisiana refineries, and thus, if priced accordingly, could displace incremental volumes of LLS from its home market.

With current pipeline capacity out of North Dakota typically full, the marginal Bakken barrel often gets to market via rail, and this cost has traditionally sets the floor to Bakken's discount to WTI. And part of the recent downturn in Bakken could be chalked up to an increase in railed volumes to the US Atlantic Coast, as Bakken cracking margins there are again in the black.

In fact, Association of American Railroad's latest monthly and weekly data shows crude and refined product rail movements appear to have bottomed, having grown in September from August.

Weekly data bears this out as well, showing increases in three of the last four weeks.

It remains to be seen how long this will last, however, should Energy Transfer Partners Dakota Access Pipeline go ahead as planned.
Linefill for the pipeline could boost Bakken differentials, potentially making the grade too expensive to rail east. However, the devil is in the details.

Traders and analysts have pegged Dakota Access pipeline tariffs between $4.50-$5.50/b for uncommitted shippers between North Dakota and Patoka, Illinois. A further $6.50/b would be needed to bring the crude south from Patoka to Nederland, Texas, sources have said.

If this $11-$12/b combined pipeline estimated cost were to pan out, it would be more expensive than the $10.20/b Platts assumes in its Bakken USAC rail-based netback calculation.

AlexS says: 11/18/2016 at 8:59 pm
U.S.oil rig count was up 19 units last week, the largest weekly gain in 16 months.
Gas rig count is up 1 unit.

Permian basin: + 11 oil rigs
Bakken: -1
Eagle Ford: -1
Niobrara: +2
Cana Woodford: unchanged
Other shale plays: +2
Conventional basins: +6

Oil rig count in the Permian is up 73.5% from this year's low – the biggest increase among all US basins.
It is still only 41% of October 2014 peak, but this is much better than the Bakken and especially the Eagle Ford where drilling activity remains depressed.

AlexS says: 11/18/2016 at 9:30 pm
The number of horizontal rigs drilling for oil in the Permian is now 54% of the 2014 peak.

Oil rig count in the Permian basin
source: Baker Hughes

AlexS says: 11/18/2016 at 9:42 pm
Weak drilling activity in the Bakken and the Eagle Ford helps to explain continued declines in their oil production

Oil rig count in 4 other tight oil plays

Roger Blanchard says: 11/19/2016 at 8:17 am
Alex,

As of September 2016, 4 counties produced 90.1% of all the Bakken/Three Forks oil production in North Dakota: McKenzie, Mountrail, Williams and Dunn. Relative to December 2014, North Dakota Bakken/Three Forks oil production is off 243,098 b/d relative to December 2014 while the number of producing wells is up 1861 based upon data from the state.

Based upon state data, the number of producing wells/square mile is 1.29 in Mountrail County, 1.22 in McKenzie County, 1.02 in Willams County, and 0.86 in Dunn County. How high can the number of producing wells/square mile go?

Is there something more than reduced drilling to explain the drop in production?

George Kaplan says: 11/19/2016 at 8:35 am
This shows well density and production from last September. The distance is concentric from a "production centre of gravity" – i.e. weighted average by production for all wells. The core area ("sweet spot") is a circle of about 50 to 60 kms only (it's squashed out a bit to the west and missing a bite in the SW). Maximum well density (and with the best wells is 120 to 160 acres, and falls off quickly outside the core. The core is getting saturated.

AlexS says: 11/18/2016 at 9:53 pm
From a recent EIA report:

"U.S. drilling activity is increasingly concentrated in the Permian Basin . The Permian now holds nearly as many active oil rigs as the rest of the United States combined, including both onshore and offshore rigs, and it is the only region in EIA's Drilling Productivity Report where crude oil production is expected to increase for the third consecutive month."

AlexS says: 11/18/2016 at 9:58 pm
The EIA DPR production volume estimates for the Permian include both LTO and conventional C+C

AlexS says: 11/18/2016 at 10:06 pm
Permian Basin also dominates M&A activity in the US E&P sector.

From the same EIA report:

"Several of the larger M&A deals involved Permian Basin assets, where drilling and production is beginning to increase.
Based on data through November 10, the second half of 2016 already has more M&A spending than the first half of 2016, but on fewer deals. The 93 M&A announcements in the third quarter of 2016 totaled $16.6 billion, for an average of $179 million per deal, the largest per deal average since the third quarter of 2014. Although only 11 of the 49 deals so far in the fourth quarter of 2016 are in the Permian Basin, they accounted for more than half of total deal value."

http://www.eia.gov/todayinenergy/detail.php?id=28772

[Nov 19, 2016] Reply

Nov 19, 2016 | peakoilbarrel.com
Dennis Coyne says: 11/17/2016 at 8:49 am
Hi Mike,

The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis.

It would be better if the USGS did an economic analysis as they do with coal for the Powder River Basin. They could develop a supply curve based on current costs, but they don't.

Do you have any idea of the capital cost of the wells (ballpark guess) for a horizontal multifracked well in the Wolfcamp? Would $7 million be about right (a WAG by me)?

On ignoring economics, I show my oil price assumptions. Other financial assumptions for the Bakken are $8 million for capital cost of the well (2016$). OPEX=$9/b, other costs=$5/b, royalty and taxes=29% of gross revenue, $10/b transport cost, and a real discount rate of 7% (10% nominal discount rate assuming 3% inflation).

I do a DCF based on my assumed real oil price curve. Brent oil price rises to $77/b (2016$) by June 2017 and continue to rise at 17% per year until Oct 2020 when the oil price reaches $130/b, it is assumed that average oil prices remain at that level until Dec 2060. The last well is drilled in Dec 2035 and stops producing 25 years later in Dec 2060.

EUR of wells today is assumed to be 321 kb and EUR falls to 160 kb by 2035. The last well drilled only makes $243,000 over the 7% real rate of return, so the 9 Gb scenario is probably too optimistic, it is assumed that any gas sales are used to offset OPEX and other costs, though no natural gas price assumptions have been made to simplify the analysis.

This analysis is based on the analyses that Rune Likvern has done in the past, though his analyses are far superior to my own.

shallow sand says: 11/17/2016 at 9:00 am
I think when seismic, land, surface and down hole equipment is included, the number is much higher.

With $20-60K per acre being paid, land definitely has to be factored in. Depending on spacing, $1-5 million per well?

Dennis Coyne says: 11/17/2016 at 10:07 am
Hi Shallow sand,

I am doing the analysis for the Bakken. A lot of the leases are already held and I don't know that those were the prices paid. Give me a number for total capital cost that makes sense, are you suggesting $10.5 million per well, rather than $8 million? Not hard to do, but all the different assumptions you would like to change would be good so I don't redo it 5 times.

Mostly I would like to clear up "the number".

I threw out more than one number, OPEX, other costs, transport costs, royalties and taxes, real discount rate (adjusted for inflation), well cost.

I think you a re talking about well cost as "the number". I include down hole costs as part of OPEX (think of it as OPEX plus maintenance maybe).

shallow sand says: 11/17/2016 at 11:19 am
Dennis. The very high acreage numbers are for recent sales in the Permian Basin.

In reading company reports, it seems they state a cost to drill and case the hole, another to complete the well, then add the two for well cost.

This does not include costs incurred prior to the well being drilled, which are not insignificant. Nor does it include costs of down hole and surface equipment, which also are not insignificant.

Land costs are all over the map, and I think Bakken land costs overall are the lowest, because much of the leasing occurred prior to US shale production boom. I think a lot of acreage early on cost in the hundreds per acre. Of course, there was quite a bit of trading around since, so we have to look project by project, unfortunately. For purposes of a model, I think $8 million is probably in the ballpark.

I would not include equipment for the well, initially, as OPEX (LOE is what I prefer to stick with, being US based). The companies do not do that, those costs are included in depreciation, depletion and amortization expense.

Once the well is in production, and failures occur, I include the cost of repairs, including replacement equipment, in LOE. I am not sure that the companies do that, however.

I think the Permian is going to be much tougher to estimate, as there are different producing formations at different depths, whereas the Bakken primarily has two, and the Eagle Ford has 1 or 2.

An example:

QEP paid roughly $60,000 per acre for land in Martin Co., TX. If we assume one drilling unit is 1280 acres (two sections), how many two mile laterals will be drilled in the unit?

1280 acres x $60,000 = $76,800,000.

Assume 440′ spacing, 12 wells per unit.

$76,800,000/12 = $6,400,000 per well.

However, there are claims of up to 8 producing zones in the Permian.

So, 12 x 8 = 96 wells.

$76,800,000 / 96 = $800,000 per well.

Even assuming 96 wells, the cost per well is still significant.

If we assume 96 wells x $7 million to drill, complete and equip, total cost to develop is $.75 BILLION. That is a lot of money for one 1280 acre unit, need to recover a lot of oil and gas to get that to payout.

Dennis Coyne says: 11/17/2016 at 1:22 pm
Hi Shallow sands,

I am neither an oil man nor an accountant, so regardless of what we call it I am assuming natural gas sales (maybe about $3/barrel on average) are used to offset the ongoing costs to operate the well (LOE, OPEX, financial costs, etc), we could add another million to the cost of the well for surface and downhole equipment and land costs. Does an average operating cost over the life of a well of about $17/b ($14/b plus natural gas sales of $3/b of oil produced)seem reasonable? That would be about $5.4 million spent on LOE etc. over the life of the well (assuming 320 kbo produced). Also does the 10% nominal rate of return sound high enough, what number would you use as a cutoff? You use a different method than a DCF and want the well to pay out in 60 months. This would correspond to about a 14% nominal rate of return and an 11% real rate of return (assuming a 3% annual inflation rate.)

AlexS says: 11/17/2016 at 9:05 am
"The Monterrey shale estimate was by the EIA not the USGS. The EIA had a private consultant do the analysis and it was mostly based on investor presentations, very little geological analysis."

Exactly.
USGS' estimate as of October 2015 is very conservative:

"The Monterey Formation in the deepest parts of California's San Joaquin Basin contains an estimated mean volumes of 21 million barrels of oil, 27 billion cubic feet of gas, and 1 million barrels of natural gas liquids, according to the first USGS assessment of continuous (unconventional), technically recoverable resources in the Monterey Formation."

"The volume estimated in the new study is small, compared to previous USGS estimates of conventionally trapped recoverable oil in the Monterey Formation in the San Joaquin Basin. Those earlier estimates were for oil that could come either from producing more Monterey oil from existing fields, or from discovering new conventional resources in the Monterey Formation."

Previous USGS estimates were for conventional oil:

"In 2003, USGS conducted an assessment of conventional oil and gas in the San Joaquin Basin, estimating a mean of 121 million barrels of oil recoverable from the Monterey. In addition, in 2012, USGS assessed the potential volume of oil that could be added to reserves in the San Joaquin Basin from increasing recovery in existing fields. The results of that study suggested that a mean of about 3 billion barrels of oil might eventually be added to reserves from Monterey reservoirs in conventional traps, mostly from a type of rock in the Monterey called diatomite, which has recently been producing over 20 million barrels of oil per year."

https://www.usgs.gov/news/usgs-estimates-21-million-barrels-oil-and-27-billion-cubic-feet-gas-monterey-formation-san

Mike says: 11/17/2016 at 1:24 pm
I am corrected, RE; USGS and Monterrey. I still don't believe there is 20G BO in the Wolfcamp. Most increases in PB DUC's are not wells awaiting frac's but lower Wolfcamp wells that are TA and awaiting re-drills; that should tell you something. With acreage, infrastructure and water costs in W. Texas, wells cost $8.5-9.0M each. The shale industry won't admit that, but that's what I think. What happens to EUR's and oil prices after April of 2017 is a guess and a waste of time, sorry.
Dennis Coyne says: 11/17/2016 at 8:54 am
Hi JG,

What is the average cost of drilling and completion (including fracking) for a horizontal Wolfcamp well?

Does the F95 estimate of 11 Gb seem reasonable if oil prices go up to over $80/b (2016 $) and remain above that level on average from 2018 to 2025?

Boomer II says: 11/17/2016 at 3:25 pm
What most interests me are suggestions that there is so much available oil in Wolfcamp and what that will do to oil prices and national policy.

Seems like any announcement of more oil will likely keep prices low. And if they stay low, there's little reason to open up more areas for oil drilling.

AlexS says: 11/16/2016 at 3:53 pm
"Their assessment method for Bakken was pretty simple – pick a well EUR, pick a well spacing, pick total acreage, pick a factor for dry holes – multiply a by c by d and divide by b."

The EIA and others use the same methodology

AlexS says: 11/16/2016 at 4:09 pm
USGS estimates for average well EUR in Wolfcamp shale look reasonable: 167,ooo barrels in the core areas and much lower in other parts of the formation.

I do not know if the estimated potential production area is too big, or assumed well spacing is too tight.

The key question is what part of these estimated technically recoverable resources are economically viable at $50; $60; $70; $80; $90, $100, etc.

Significant part of resources may never be developed, even if they are technically recoverable.

Dennis Coyne says: 11/16/2016 at 5:17 pm
Keep in mind these USGS estimates are for undiscovered TRR, one needs to add proved reserves times 1.5 to get 2 P reserves and that should be added to UTRR to get TRR. There are roughly 3 Gb of 2P reserves that have been added to Permian reserves since 2011, if we assume most of these are from the Wolfcamp shale (not known) then the TRR would be about 23 Gb. Note that total proved plus probable reserves at the end of 2014 in the Permian was 10.5 Gb (7 Gb proved plus 3.5 GB probable with the assumption that probable=proved/2). I have assumed about 30% of total Permian 2P reserves is in the Wolfcamp shale. That is a WAG.

Note the median estimate is a UTRR of 19 Gb with F95=11.4 Gb and F5=31.4 Gb. So a conservative guess would be a TRR of 13.4 Gb= proved reserves plus F95 estimate. If prices go to $85/b and remain at that level the F95 estimate may become ERR, at $100/b maybe the median is potentially ERR. It will depend how long prices can remain at $100/b before an economic crash, prices are Brent Crude price in 2016$ with various crude spreads assumed to be about where they are now.

AlexS says: 11/16/2016 at 7:01 pm
Dennis,
where your number for proven reserves in the Permian comes from?
In November 2015, the EIA estimated proven reserves of tight oil in Wolfcamp and Bone Spring formations as of end 2014 at just 722 million barrels.

http://www.eia.gov/naturalgas/crudeoilreserves/

AlexS says: 11/16/2016 at 7:16 pm
US proved reserves of LTO

Dennis Coyne says: 11/16/2016 at 9:11 pm
Hi Alex S,

I just looked at Permian Basin crude reserves (Districts 7C, 8 and 8A) and assumed the change in reserves from 2011 to 2014 was from the Wolfcamp. I didn't know about that page for reserves. It is surprising it is that low.

In any case the difference is small relative to the UTRR, it will be interesting to see what the reserves are for year end 2015.

Based on this I would revise my estimate to 20 Gb for URR with a conservative estimate of 12 Gb until we have the data for year end 2015 to be released later this month.

My guess is that the USGS probably already has the 2015 year end reserve data.

AlexS says: 11/16/2016 at 9:26 pm
Dennis,

The EIA proved reserves estimate for 2015 will be issued this month. I think we will see a significant increase in the number for the Permian basin LTO.

Also note that USGS TRR estimate is only for Wolfcamp.
I can only guess what could be their estimate for the whole Permian tight oil reserves.
But the share of Wolfcamp in the Permian LTO output is only 24% (according to the EIA/DrillingInfo report).

Dennis Coyne says: 11/16/2016 at 10:09 pm
Hi Alex S,

http://www.beg.utexas.edu/resprog/permianbasin/index.htm

At link above they say Permian basin has 30 Gb of oil, so if both estimates are correct the Wolfcamp has 2/3 of remaining resources.

AlexS says: 11/17/2016 at 4:32 am
Dennis,

Wolfcamp is a newer play than Bone Spring and Spraberry. That's why its share in the Permian LTO production is less than in TRR.

Dennis Coyne says: 11/17/2016 at 8:21 am
Hi AlexS,

That makes sense. I also imagine the USGS focused on the formation with the bulk of the remaining resources. It is conceivable that the 30 Gb estimate is closer to the remaining oil in place and that more like 90% of the TRR is in the Wolfcamp, considering that the F5 estimate is about 30 Gb. That older study from 2005 may be an under estimate of TRR for the Permian, likewise the USGS might have overestimated the UTRR.

shallow sand says: 11/16/2016 at 5:18 pm
AlexS. Another key question, which is price dependent, is how many years will it take to fully develop the reserves?
Dennis Coyne says: 11/16/2016 at 5:38 pm
Hi Shallow sand,

If oil prices go back to $100/b in 2018 as the IEA seems to be concerned about, it could ramp up at the speed of the Eagle Ford (say 2 to 3 years). It will be oil price dependent and perhaps they won't over do it like in 2011-2014, but who knows, some people don't learn from past mistakes. If you or Mike were running things it would be done right, but the LTO guys, I don't know.

AlexS says: 11/16/2016 at 7:08 pm
shallow sand,

Yes, you are correct. And there are multiple potential production scenarios, depending on the oil prices.

Boomer II says: 11/16/2016 at 3:39 pm
From the USGS press release.

USGS Estimates 20 Billion Barrels of Oil in Texas' Wolfcamp Shale Formation

"This estimate is for continuous (unconventional) oil, and consists of undiscovered, technically recoverable resources.

Undiscovered resources are those that are estimated to exist based on geologic knowledge and theory, while technically recoverable resources are those that can be produced using currently available technology and industry practices. Whether or not it is profitable to produce these resources has not been evaluated."

Watcher says: 11/16/2016 at 4:11 pm
This is an important way to assess.

If it requires slave labor at gunpoint to get the oil out, then that's what will happen because you MUST have oil, and a day will soon come when that sort of thing is reqd.

Fred Magyar says: 11/17/2016 at 11:18 am
Nice apocalyptic vision of the future you've got there!

Whatever happened to the ideals of democracy, capitalism, business, profits, free markets etc ? Don't worry, no need to answer, that was purely a rhetorical question. I'm quite aware of the realities of the world!

However, not to pour too much sand on your vision, But I have to wonder? Since your potential slaves in 21st century America are already armed to the teeth, they might decide not to just go with the flow. (pun intended) 🙂

Anyways slaves don't buy cars or too many consumer goods so that might, in and of itself, put a bit of a damper on the raison d'etre, excuse my french, of the oil companies and the very existence of these future slave owners.

because you MUST have oil

Really now?! You know, as time goes by, I'm less and less convinced of that!

Cheers!

George Kaplan says: 11/16/2016 at 3:16 pm
This follows on from reserve post above (two a couple of comments). In terms of changes over the last three years – there really weren't anything much dramatic. We'll see what 2016 brings, especially for ExxonMobil, but it looks like they already knocked a big chunk off of their Bitumen numbers already in 2015.

Note I went through a lot of 20-F and 10-K reports watching the rain fall this morning and copied out the numbers, I'm not guaranteeing I got everything 100%, but I think the general trends are shown.

Note the figures are totals for all nine companies I looked at.

Jeff says: 11/16/2016 at 3:20 pm
IEA WEO is out: http://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html presentation slides, fact sheet and summary are available online (report can be purchased). IEA seems to be _very_ concerned about underinvestment in upstream oil production. Several pages of the report is devoted to this, the title of that section is "mind the gap". More or less all of the content has been discussed on this website, including the issue with high levels of debt and that this can affect suppliers' capacity to rebound, and how much demand can be reduced as a result of a stringent carbon cap.

From the fact sheet (available free of charge):
"Another year of low upstream oil investment in 2017 would risk a shortfall in oil production in a few years' time. The conventional crude oil resources (e.g. excluding tight oil and oil sands) approved for development in 2015 sank to the lowest level since the 1950s, with no sign of a rebound in 2016. If there is no pick-up in 2017, then it becomes increasingly unlikely that demand (as projected in our main scenario) and supply can be matched in the early 2020s without the start of a new boom/bust cycle for the industry"

Presentation 1:09 – Dr. Birol gives his view: "depletion never sleeps"

George Kaplan says: 11/17/2016 at 3:42 am
I wonder who that paragraph is aimed at. As I indicated above the companies that would be investing in long term conventional projects don't have a very large inventory of undeveloped reserves (17 Gb as of end of 2015, some of this has gone already this year and more is in development and will come on stream in 2017 and 2018 (and a small amount in later years for approved projects). I'd guess there might only be less than 10 Gb (and this the most expensive to develop) that is currently under appraisal among the major western IOCs and larger independents; allowing for their partnerships with NOCs in a lot of the available projects that could represent 20 to 30 Gb total. That really isn't very much new supply available, and a large proportion is in complex deep water projects that wouldn't be ramped up fully until 6 to 7 years after FID (i.e. already too late for 2020). Really the main players need to find new fields with easy developments, but they obviously aren't, probably never will, and actually aren't looking very hard at the moment.
Jeff says: 11/17/2016 at 7:24 am
My interpretation is that this is IEAs way of saying that it does not look good. Those who can read between the lines get the message. Also, a few years from they will be able to say "see we told you so".

It's impossible for IEA to make statements like: "the end of low cost oil will negatively affect economic growth", "geology is about to beat human ingenuity" etc.

WEO have become more and more bizarre over the years. On the one hand they contain quantitative projections which tell the story politicians wants to hear. On the other hand, the text describes all sorts of reason of why the assumptions are unlikely to hold. Normally, if you don't believe in your own assumptions you would change them.

FreddyW says: 11/16/2016 at 3:43 pm
Hi,

Here are my updates as usual. GOR declined or stayed flat for all years except 2010 in September. Is it the beginning of a new trend?

FreddyW says: 11/16/2016 at 3:50 pm
Here is the production graph. Not that much has happened. There was a big drop for 2011. 2009 on the other hand saw an increase. Up to the left, which is very hard to see, 2015 continues to follow 2014 which follows 2013 which follows 2012. Will we see 2013 reach 2007 the next few months?

Watcher says: 11/16/2016 at 10:34 pm
Freddy, these latest years, the IP months are chopped at the top. Any chance of showing those?

The motivation would be to get a look at the alleged spectacular technology advances in the past, oh, 2 yrs.

FreddyW says: 11/17/2016 at 2:10 pm
Its on purpose both because I wanted to zoom in and because the data for first 18 months or so for the method I used above is not very usable. Bellow is the production profile which is better for seeing differences the first 18 months. Above graph is roughly 6 months ahead of the production profile graph.

Watcher says: 11/17/2016 at 2:40 pm
Excellent.

And I guess we can all see no technological breakthru. 2014's green line looks superior to first 3 mos 2015.

2016 looks like it declines to the same level about 2.5 mos later, but is clearly a steeper decline at that point and is likely going to intersect 2014's line probably within the year.

There is zero evidence on that compilation of any technological breakthrough surging output per well in the past 2-3 yrs.

In fact, they damn near all overlay within 2 yrs. No way in hell there is any spectacular EUR improvement.

And . . . in the context of the moment, nope, no evidence of techno breakthrough. But also no evidence of sweetspots first.

I suppose you could contort conclusions and say . . . Yes, the sweetspots were first - with inferior technology, and then as they became less sweet the technological breakthroughs brought output up to look the same.

Too
Much
Coincidence.

It's all bogus.

Watcher says: 11/17/2016 at 8:12 pm
clarifying, the techno breakthrus are bogus. They would show in that data if they were real.

And it would be far too much coincidence for techno breakthrus to just happen to increase flow the exact amount lost from exhausting sweet spots.

This suggests the sweetspot theory is also bogus, unless there are 9 years of them, meaning it's ALL been sweetspots so far. 9 yrs of sweetspots might as well be called just normal rather than sweet.

Mike says: 11/17/2016 at 8:59 pm
It is pretty much all bogus, yes, Watcher. With any rudimentary understanding of volumetric calculations of OOIP in a dense shale like the Bakken, there is only X BO along the horizontal lateral that might be "obtained" from stimulation. More sand along a longer lateral does not necessarily translate into greater frac growth (an increase in the radius around the horizontal lateral). Novices in frac technology believe in halo effects, or that more sand equates to higher UR of OOIP per acre foot of exposed reservoir. That is not the case; longer laterals simply expose more acre feet of shale that can be recovered. Recovery factors in shale per acre foot will never exceed 5-6%, IMO, short of any breakthroughs in EOR technology. That will take much higher oil prices.

Its very simple, actually bigger fracs (that cost lots more money!!) over longer laterals result in higher IP's and higher ensuing 90 day production results. That generates more cash flow (imperative at the moment) and allows for higher EUR's that translate into bigger booked reserve assets. More assets means the shale oil industry can borrow more money against those assets. Its a game, and a very obvious one at that. Nobody is breaking new ground or making big strides in greater UR. That's internet dribble. Freddy is right; everyone in the shale biz is pounding their sweet spots, high grading as they call it, and higher GOR's are a sure sign of depletion. Moving off those sweet spots into flank areas will be even less economical (if that is possible) and will result in significantly less UR per well. That is what is ridiculous about modeling the future based on X wells per month and trying to determine how much unconventional shale oil can be produced in the US thru 2035. The term, "past performance is not indicative of future results?" We invented that phrase 120 years ago in the oil business.

Watcher says: 11/18/2016 at 12:03 am
That, sir, is pretty much the point. I see what looks like about 20% IP increase for the extra stages post 2008/9/10. How could there not be going from 15 stages to 30+?

I see NO magic post peak. They all descend exactly the same way and by 18-20 months every drill year is lined up. That's actually astounding - given 15 vs 30 stages. There should be more volume draining on day 1 and year 2, but the flow is the same at month 20+ for all drill years. This should kill the profitability on those later wells because 30 stages must cost more.

But profit is not required when you MUST have oil.

Watcher says: 11/18/2016 at 12:14 am
You know, that is absolutely insane.

Freddy, is there something going on in the data? How can 30 stage long laterals flow the same at production month 24 as the earlier dated wells at their production month 24 –whose lengths of well were MUCH shorter?

FreddyW says: 11/18/2016 at 2:55 pm
I can only speculate why the curves look like they do. It could be that the newer wells would have produced more than the older wells, but closer well spacing is causing the UR to go down.
FreddyW says: 11/16/2016 at 3:57 pm
Here is the updated yearly decline rate graph. 2010 has seen increased decline rates as I suspected. The curves are currently gathering in the 15%-20% range.

Dennis Coyne says: 11/16/2016 at 5:33 pm
Hi FreddyW,

What is the annual decline rate of the 2007 wells from month 98 to month 117 and how many wells in that sample (it may be too low to tell us much)?

FreddyW says: 11/16/2016 at 6:02 pm
2007 only has 161 wells. So it makes the production curve a bit noisy as you can see above. Current yearly decline rate for 2007 is 7,2% and the average from month 98 to 117 would translate to a 10,3% yearly decline rate. The 2007 curve look quite different from the other curves, so thats why I did not include it.
Dennis Coyne says: 11/16/2016 at 9:27 pm
Hi Freddy W,

Thanks. The 2008 wells were probably refracked so that curve is messed up. If we ignore 2008, 2007 looks fairly similar to the other curves (if we consider the smoothed slope.) I guess one way to do it would be to look at the natural log of monthly output vs month for each year and see where the curve starts to become straight indicating exponential decline. The decline rates of many of the curves look similar through about month 80 (2007, 2009, 2010, 2011) after 2011 (2012, 2013, 2014) decline rates look steeper, maybe poor well quality or super fracking (more frack stages and more proppant) has changed the shape of the decline curve. The shape is definitely different, I am speculating about the possible cause.

FreddyW says: 11/17/2016 at 3:37 pm
2007 had much lower initial production and the long late plateau gives it a low decline rate also. But yes, initial decline rates look similar to the other curves. If you look at the individual 2007 wells then you can see that some of them have similar increases to production as the 2008 wells had during 2014. I have not investigated this in detail, but it could be that those increases are fewer and distributed over a longer time span than 2008 and it is what has caused the plateau. If that is the case, then 2007 may not be different from the others at and we will see increased decline rates in the future.

Regarding natural log plots. Yes it could be good if you want to find a constant exponential decline. But we are not there yet as you can see in above graph.

One good reason why decline rates are increasing is because of the GOR increase. When they pump up the oil so fast that GOR is increasing, then it's expected that there are some production increases first but higher decline rates later. Perhaps completion techniques have something to do with it also. Well spacing is getting closer and closer also and is definitely close enough in some areas to cause reductions in UR. But I would expect lower inital production rather than higher decline rates from that. But maybe I´m wrong.

Dennis Coyne says: 11/17/2016 at 8:42 am
Hi FreddyW,

Do you have an estimate of the number of wells completed in North Dakota in September? Does the 71 wells completed estimate by Helms seem correct?

Dennis Coyne says: 11/17/2016 at 12:40 pm
Hi FreddyW,

Ok Enno's data from NDIC shows 73 well completions in North Dakota in Sept 2016, 33 were confidential wells, if we assume 98% of those were Bakken/TF wells that would be 72 ND Bakken/TF wells completed in Sept 2016.

FreddyW says: 11/17/2016 at 2:19 pm
I have 75 in my data, so about the same. They have increased the number of new wells quite alot the last two months. It looks like the addtional ones mainly comes from the DUC backlog as it increased withouth the rig count going up. But I see that the rig count has gone up now too.
Pete Mason says: 11/16/2016 at 3:49 pm
Ron you say " Bakken production continues to decline though I expect it to level off soon."
A few words of wisdom as to the main reasons why it would level off? Price rise?
Dennis Coyne says: 11/16/2016 at 5:28 pm
Hi Pete,

Even though you asked Ron. He might think that the decline in the number of new wells per month may have stabilized at around 71 new wells per month. If that rate of new completions per month stays the same there will still be decline but the rate of decline will be slower. Scenario below shows what would happen with 71 new wells per month from Sept 2016 to June 2017 and then a 1 well per month increase from July 2017 to Dec 2018 (89 new wells per month in Dec 2018).

Guy Minton says: 11/16/2016 at 8:41 pm
I am not so convinced that either Texas or the Bakken is finished declining at the current level of completions. There was consistent completions of over 1000 wells in Texas until about October of 2015. Then it dropped to less than half of that. The number of producing wells in Texas peaked in June of this year. Since then, through October, it has decreased by roughly 1000 wells a month. The Texas RRC reports are indicating that they are still plugging more than they are completing.
I remember reading one projection recently for what wells will be doing over time in the Eagle Ford. They ran those projections for a well for over 22 years. Not sure which planet we are talking about, but in Texas an Eagle Ford does well to survive 6 years. They keep referring to an Eagle Ford producing half of what they will in the first two years. In most areas, I would say that it is half in the first year.
The EIA, IEA, Opec, and most pundits have the US shale drilling turning on a dime when the oil price reaches a certain level. If it was at a hundred now, it would still take about two years to significantly increase production, if it ever happens. I am not a big believer that US shale is the new spigot for supply.
Dennis Coyne says: 11/16/2016 at 10:03 pm
Hi Guy,

The wells being shut in are not nearly as important as the number of wells completed because the output volume is so different. So the average well in the Eagle Ford in its second month of production produces about 370 b/d, but the average well at 68 months was producing 10 b/d. So about 37 average wells need to be shut in to offset one average new well completion.

Point is that total well counts are not so important, it is well completions that drive output higher.

Output is falling because fewer wells are being completed. When oil prices rise and profits increase, completions per month will increase and slow the decline rate and eventually raise output if completions are high enough. For the Bakken at an output level of 863 kb/d in Dec 2017 about 79 new wells per month is enough to cause a slight increase in output. My model slightly underestimates Bakken output, for Sept 2016 my model has output at 890 kb/d, about 30 kb/d lower than actual output (3% too low), my well profile may be slightly too low, but I expect eventually new well EUR will start to decrease and my model will start to match actual output better by mid 2017 as sweet spots run out of room for new wells.

Guy Minton says: 11/17/2016 at 7:14 am
Guess I will remember that for the future. The number of producing wells is not important. Kinda like I got pooh poohed when I said the production would drop to over 1 million barrels back in early 2015.
Dennis Coyne says: 11/17/2016 at 10:39 am
Hi Guy,

Do you agree that the shut in wells tend to be low output wells? So if I shut down 37 of those but complete one well the net change in output is zero.

Likewise if I complete 1000 wells in a year, I could shut down 20,000 stripper wells and the net change in output would be zero, but there would be 19,000 fewer producing wells, if we assume the average output of the 1000 new wells completed was 200 b/d for the year and the stripper wells produced 10 b/d on average.

How much do you expect output to fall in the US by Dec 2017?

Hindsight is 20/20 and lots of people can make lucky guesses. Output did indeed fall by about 1 million barrels per day from April 2015 to July 2016, can you point me to your comment where you predicted this?

Tell us what it will be in August 2017.

I expected the fall in supply would lead to higher prices, I did not expect World output to be as resilient as it has been and I also did not realize how oversupplied the market was in April 2015. In Jan 2015 I expected output would decrease and it increased by 250 kb/d from Jan to April, so I was too pessimistic, from Jan 2015 (which is early 2015) to August 2016 US output has decreased by 635 kb/d.

If you were suggesting World output would fall from Jan 2015 levels by 1 Mb/d, you would also have been incorrect as World C+C output has increased from Feb 2015 to July 2016 by 400 kb/d. If we consider 12 month average output of World C+C, the decline has been 340 kb/d from the 12 month average peak in August 2015 (centered 12 month average).

Guy Minton says: 11/18/2016 at 4:50 am
The dropping numbers are not as much from the wells that produce less than 10 barrels a day, but from those producing greater than 10, but less than 100. The ones producing greater than 100 are remaining at a consistent level over 9000 to 9500. The prediction on one million was as to the US shale only. It is your site, you can search it better than I can,
Guy Minton says: 11/18/2016 at 6:20 am
But then don't take my word for it. You can find the same information under the Texas RRC site under oil and gas/research and statistics/well distribution tables. Current production for Sep can be found at online research queries/statewide. It is still dropping, and will long term at the current activity level. Production drop for oil, only, is a little over 40k per day barrels, and condensate is lower for September. Proofs in the pudding.
My guess is that you would see a lot more plugging reports, if it were not so expensive to plug a well. At net income levels where they are, I expect they would put that off as long as they could.
AlexS says: 11/16/2016 at 8:51 pm
Statistics for North Dakota and the Bakken oil production are perfect, but not for well completions.

From the Director's Cut:

"The number of well completions rose from 63(final) in August to 71(preliminary) in September"
(North Dakota total)

From the EIA DPR:

The number of well completions declined from 71 in August to 52 in September and rose to 58 in October
(Bakken North Dakota and Montana).

Wells drilled, completed, and DUCs in the Bakken.
Source: EIA DPR, November 2016

Dennis Coyne says: 11/16/2016 at 9:36 pm
Hi Alex S,

I trust the NDIC numbers much more than the EIA numbers which are based on a model. Enno Peters data has 66 completions in August 2016, he has not put up his post for the Sept data yet so I am using the Director's estimate for now. I agree his estimate is usually off a bit, Enno tends to be spot on for the Bakken data, for Texas he relies on RRC data which is not very good.

shallow sand says: 11/17/2016 at 8:36 am
Dennis. Someone pointed out Whiting's Twin Valley field wells being shut in for August.

It appears this was because another 13 wells in the field were recently completed.

It appears that when all 29 wells are returned to full production, this field will be very prolific initially. Therefore, on this one field alone, we could see some impact for the entire state.

Does anyone know if these wells are part of Whiting's JV? Telling if they had to do that on these strong wells. Bakken just not close to economic.

I also note that average production days per well in for EOG in Parshall was 24. I haven't looked at some of the other "older" large fields yet, but assume the numbers are similar.

shallow sand says: 11/17/2016 at 8:58 am
Also, over 3000 Hz wells in ND produced less than 1000 BO in 9/16.

This is just for wells with first production 1/1/07 or later.

Dennis Coyne says: 11/17/2016 at 10:57 am
Hi Shallow sand,

I agree higher prices will be needed in the Bakken, probably $75/b or more. To be honest I don't know why they continue to complete wells, but maybe it is a matter of ignoring the sunk costs in wells drilled but not completed and running the numbers based on whether they can pay back the completion costs. Everyone may be hoping the other guys fail and are just trying to pay the bills as best they can, not sure if just stopping altogether is the best strategy.

There is the old adage that when your in a hole, more digging doesn't help much. 🙂

So my model just assumes continued completions at the August rate for about 12 months with gradually rising prices as the market starts to balance, then a gradual increase in completions as prices continue to rise from July 2017($78/b) to Dec 2018 (from 72 completions to about 90 completions per month 18 months later). At that point oil prices have risen to $97/b and LTO companies are making money. Prices continue to rise to $130/b by Oct 2020 and then remain at that level for 40 years (not likely, but the model is simplistic).

I could easily do a model with no wells completed, but I doubt that will be correct. Suggestions?

shallow sand says: 11/18/2016 at 8:20 am
Dennis. As we have discussed before, tough to model when there is no way to be accurate regarding the oil price.

I continue to contend that there will be no quick price recovery without an OPEC cut. Further, the US dollar is very important too, as are interest rates.

Dennis Coyne says: 11/18/2016 at 10:03 am
Hi Shallow sand,

At some point OPEC may not be able to increase output much more and overall World supply will increase less than demand. My guess is that this will occur by mid 2017 and oil prices will rise. OPEC output from Libya an Nigeria has recovered, but this can only go so far, maybe another 1 Mb/d at most. I don't expect any big increases from other OPEC nations in the near term.

A big guess as to oil prices has to be made to do a model.

I believe my guess is conservative, but maybe oil prices will remain where they are now beyond mid 2017.

I expected World supply to have fallen much more quickly than has been the case at oil prices of $50/b.

George Kaplan says: 11/17/2016 at 3:31 am
Probably to do with how confidential wells are included.
AlexS says: 11/17/2016 at 4:42 am
RBN explains EIA methodology:

"EIA does this by using a relatively new dataset-FracFocus.org's national fracking chemical registry-to identify the completion phase, marked by the first fracking. If a well shows up on the registry, it's considered completed "

Sydney Mike says: 11/17/2016 at 2:19 am
There is an unlikely peak oil related editorial writer hiding in the most unlikely place: a weekly English business paper called Capital Ethiopia. The latest editorial is again putting an excellent perspective on world events. http://capitalethiopia.com/2016/11/15/system-failure/#.WC1ZCvl9600

For the record, I have no interest or connection to this publication other than that of a paying reader.

Wouldn't it be nice if mainstream publications would sound a bit more like this.

Watcher says: 11/17/2016 at 11:34 am
the word oil does not appear anywhere on that.
Pete Mason says: 11/17/2016 at 4:56 am
Thanks all. I thought that the red queen concept meant that there had to be an increase in the rate of completions. So that 71 year-on-year in north Dakota would only stabilise temporarily. Perhaps the loss of sweet spots are being counteracted by the improvements in technology? I'm assuming that even with difficulties of financing there will be a swift increase in completions should the oil price take off, but not sure how sustainable this would be
Oldfarmermac says: 11/17/2016 at 6:03 am
Hi Pete,

Sometimes I think that once the price of oil is up enough that sellers can hedge the their selling price for two or three years at a profitable level, it will hardly matter what the banks have to say about financing new wells.

At five to ten million apiece, there will probably be plenty of money coming out of various deep pockets to get the well drilling ball rolling again, if the profits look good.

Sometimes the folks who think the industry will not be able to raise money forget that it's not a scratch job anymore. The land surveys, roads, a good bit of pipeline, housing, leases, etc are already in place, meaning all it takes to get the oil started now is a drill and frack rig.

I don't know what the price will have to be, but considering that a lot of lease and other money is a sunk cost that can't be recovered, and will have to be written off, along with the mountain of debts accumulated so far, the price might be lower than a lot of people estimate.

Bankruptcy of old owners results in lowering the price at which an old business makes money for its new owners.

Dennis Coyne says: 11/17/2016 at 8:32 am
Hi Pete,

The Red Queen effect is that more and more wells need to be completed to increase output. As output decreases fewer wells are needed to maintain output. So at 1000 kb/d output it might require 120 wells to be completed to maintain output (if new well EUR did not eventually decrease), but at 850 kb/d it might require about 78 new wells per month to maintain output.

Enno Peters says: 11/17/2016 at 11:48 am
I've also a new post on ND, here .
George Kaplan says: 11/18/2016 at 8:28 am
Do you know why you show a significantly higher number of DUCs than Bloomberg do – as reported here?

http://www.oilandgas360.com/ducs-havent-flown-fast-since-april/

I think your numbers reflect numbers reported from ND DMR but Bloomberg might be closer to reality for wells that will actually ever be completed (just a guess by me though). How do Bloomberg get their numbers (e.g. removing Tight Holes, or removing old wells, not counting non-completed waivers etc.)?

Enno says: 11/18/2016 at 10:56 am
George,

Yes indeed. The difficulty with DUCs is always, which wells do you count. I don't filter old wells for example, and already include those that were spud last month (even though maybe casing has not been set). I don't do a lot of filtering, so the actual # wells that really can be completed is likely quite a bit lower. I see my DUC numbers as the upper bound. I don't know Bloombergs method exactly, so I can't comment on that.

Watcher says: 11/18/2016 at 2:09 pm
Concerning Freddy's chart of production profile of wells drilled in various years.

They all line up by about month 18 of production. This should not be possible. The later wells have many more stages of frack. They are longer, draining more volume of rock. But the chart says what it says. At month about 18 the 2014 wells are flowing the same rate as 2008 wells. We know stage count has risen over those 6 yrs. 2014 wells should flow a higher rate. The shape of the curve can be the same, but it should be offset higher.

Explanation?

How about above ground issues . . . older wells get pipelines and can flow more oil . . . nah, that's absurd.

There needs to be a physical explanation for this.

AlexS says: 11/18/2016 at 4:36 pm
These new wells have higher IPs, but also higher decline rates.
Closer spacing (see Freddy's comment above) and depletion of the sweet spots may also impact production curves and EURs.
Watcher says: 11/18/2016 at 6:02 pm
That doesn't make sense. They are longer. By a factor of 2ish. How can a 6000 foot lateral flow exactly the same amount 2 yrs into production as a 3000 foot lateral flows 2 yrs into production?

Look at the lines. At 18 months AND BEYOND, these longer laterals flow the same oil rate as the shorter laterals did at the same month number of production. Higher IP and higher decline rate will affect the shape, but There Is Twice The Length..

Dennis Coyne says: 11/18/2016 at 8:15 pm
Hi Watcher,

I don't think we have information on the length of the wells, since 2008 the length of the lateral has not changed, just the number of frack stages and amount of proppant. This seems to primarily affect the output in the first 12 to 18 months, and well spacing and room in the sweet spots no doubt has some effect (offsetting the greater number of frack stages etc.).

Listen to Mike, he knows this stuff.

Watcher says: 11/18/2016 at 8:31 pm
From http://www.dtcenergygroup.com/bakken-5-year-drilling-completion-trends/

STATISTICS

The combination of longer lateral lengths and advancements in completion technology has allowed operators to increase the number of frac stages during completions and space them closer together. The result has been a higher completion cost per well but with increased production and more emphasis on profitability.

In the past five years, DTC Energy Group completion supervisors in the Bakken have helped oversee a dramatic increase from an average of 10 stages in 2008 to 32 stages in 2013. Even 40-stage fracs have been achieved.

One of the main reasons for this is the longer lateral lengths – operators now have twice as much space to work with (10,000 versus 5,000 feet along the lateral). Frac stages are also being spaced closer together, roughly 300 feet apart as compared to spacing up to 800 feet in 2008, as experienced by DTC supervisors.

By placing more fracture stages closer together, over a longer lateral length, operators have successfully been able to improve initial production (IP) rates, as well as increase EURs over the life of the well.

blah blah, but they make clear the years have increased length. Freddy was talking about well spacing, this text is about stage spacing, but that is achieved because of lateral length.

Freddy can you revisit your graph code? It's just bizarre that different length wells have the same flow rate 2 yrs out, and later.

FreddyW says: 11/19/2016 at 7:22 am
Take a look at Enno´s graphs at https://shaleprofile.com/ . They look the same as my graphs and we have collected and processed the data independently from each other.
George Kaplan says: 11/19/2016 at 1:39 am
If the wells have the same wellbore riser design irrespective of lateral length (i.e. same depth, which is a given, same bore, same downhole pump) then that section might become the main bottleneck later in life and not the reservoir rock. With a long fat tail that seems more likely somehow compared to the faster falling Eagle Ford wells say (but that is just a guess really). But there may be lots of other nuances, we just don't have enough data in enough detail especially on the late life performance for all different well designs – it looks like the early ones are just reaching shut off stage in numbers now. I doubt if the E&Ps concentrated on later life when the wells were planned – they wanted early production, and still do, to pay their creditors and company officers bonuses (not necessarily in that order).
Watcher says: 11/19/2016 at 3:31 am
Hmmm. I know it is speculation, but can you flesh that out?

If some bottleneck physically exists that defines a flow rate for all wells from all years then that does indeed explain the graphs, but what such thing could exist that has a new number each year past year 2?

We certainly have discussed chokes for reservoir/EUR management, but the same setting to define flow regardless of length?

Hmmm.

George Kaplan says: 11/19/2016 at 4:01 am
The flow depends on the available pressure drop, which is made up of friction through the rock and up the well bore (plus maybe some through the choke but not much), plus the head of the well, plus a negative number if there is a pump. The frictional and pump numbers depend on the flow and all the numbers depend on gas-oil ratio. Initially there is a big pressure drop in the rock because of the high flow, then not so much. Once the flow drops the pressure at base of the well bore just falls as a result of depletion over time, the effect of the completion design is a lot less and lost in the noise, so all the wells behave similarly. That's just a guess – I have never seen a shale well and never run a well with 10 bpd production, conventional or anything else.

A question might be if the flow is the same why doesn't the longer well with the bigger volume deplete more slowly, and I don't know the answer. It may be too small to notice and lost in the noise, or to do with gas breakout dominating the pressure balance, or just the way the the physics plays out as the fluids permeate through the rock, or we don't have long enough history to see the differences yet.

clueless says: 11/18/2016 at 2:30 pm
Permian rig count now greater than same time last year.
Watcher says: 11/18/2016 at 3:27 pm
http://www.fool.ca/2016/11/16/buffett-sells-suncor-energy-inc-what-does-this-mean-for-the-canadian-oil-patch/
AlexS says: 11/18/2016 at 4:55 pm
Suncor's forecast for production [in 2017] is 680,000-720,000 boe/d. A midpoint would represent a 13% increase over 2016.

http://www.ogj.com/articles/2016/11/suncor-provides-capital-spending-production-outlook-for-2017.html

Solid growth

Heinrich Leopold says: 11/19/2016 at 6:09 am
RRC Texas for September came out recently. As others will probably elaborate more on the data, I just want to show if year over year changes in production could be use as a predictive tool for future production (see below chart).

It is obvious that year over year changes (green line) beautifully predicted oil production (red line) at a time lag of about 15 month. Even when production was still growing, the steep decline of growth rate indicated already the current steep decline.

The interesting thing is that the year over year change is a summary indicator. It does not tell why production declines or rises. It can be the oil price, interest rates or just depletion – even seasonal factors are eliminated. It just shows the strength of a trend.

I am curious myself how this works out. The yoy% indicator predicts that Texas will have lost another million bbl per day by end next year. That sounds quite like a big plunge. One explanation could be the fact that we have now low oil prices and high interest rates. In all other cycles it has been the other way around: low oil prices came hand in hand with low interest rates. This could be now a major obstacle for companies to grow production.

This concept of following year over year changes works of course just for big trends, yet for investment timing it seems exactly the right tool. Another huge wave is coming in electric vehicles which are growing in China by 120% year over year. Here we have the same situation as for shale 7 years ago: Although current EV sales are barely 1 million per year worldwide, the growth rate reveals already an huge wave coming. So as an investor it is always necessary to stay ahead of the trend and I think this can be done by observing the year over year% change.

[Aug 16, 2016] US shale oil production is expected to fall for a tenth consecutive month in September

peakoilbarrel.com
From Reuters and EIA

"U.S. shale oil production is expected to fall for a tenth consecutive month in September, according to a U.S. government forecast released on Monday, as low oil prices continue to weigh on production.

"Total output is expected to drop 85,000 bpd to 4.47 million bpd, according to the U.S. Energy Information Administration's drilling productivity report. That is the lowest output number since April 2014.

"The EIA's previous forecast calling for an output decline in August of 99,000 bpd was revised up to nearly 112,000 bpd, data shows.

"Bakken production from North Dakota is expected to fall 26,000 bpd, while production from the Eagle Ford formation is expected to drop 53,000 bpd. Production from the Permian Basin in West Texas is expected to rise 3,000 bpd, according to the data."

Ron's graphs summarised this better but I don't have the previous history to show it. Has anybody here explained why Eagle Ford drops are so much more than Bakken?

Dennis Coyne , 08/16/2016 at 3:29 pm
Hi George,

The DPR tends to overestimate the decline in the Eagle Ford.

Enno Peters uses Texas RRC data to estimate Eagle Ford output and that also underestimates output for the same reason that Texas data in general is too low because it is incomplete.

I have estimated Eagle Ford output by finding the percentage of total Texas C+C output from the Eagle Ford for each of the most recent 24 reported months and than multiplied this percentage by Dean Fantazzini's estimate of Texas C+C output (which is better than any other estimate in my opinion).

The Chart below compares this method using Dean's estimate (DC estimate) and the EIA estimate for Texas C+C output, to find Eagle Ford output through June 2016.

The reason Eagle Ford output has decreased more rapidly is because the wells decline more rapidly and because the ramp up in the Eagle Ford was more rapid than in the Bakken/Three Forks so that a lot more wells are declining at once.

Dennis Coyne , 08/16/2016 at 3:33 pm
The Chart below is from Enno Peter's excellent website

https://shaleprofile.com/index.php/2016/06/24/eagle-ford-update-until-2016-03/

It shows the number of new wells completed in the Eagle Ford (he calls these wells "first flow" as in the month that the well started producing oil). Compare this chart to the Bakken chart in the post.

George Kaplan , 08/16/2016 at 3:36 pm
Dennis, Thanks – would that mean it could ramp up faster if conditions became more favourable?
Dennis Coyne , 08/16/2016 at 3:47 pm
Hi George,

I don't know if they might have reached saturation in the sweet spots in the Eagle Ford, they seem to have an advantage in Texas with infrastructure and pipeline capacity, but a lot of that has now been established in North Dakota so going forward the main advantage for Texas is lower transportation costs to refineries.

Take a look at http://www.shaleprofile.com there is a ton of information there.

Enno Peters , 08/16/2016 at 3:34 pm
George,

> Has anybody here explained why Eagle Ford drops are so much more than Bakken?

Although the number of new wells producing dropped very similarly (relatively) in these two basins, Eagle Ford wells decline faster after initial production. You can see this most clearly by:

1. Going to my latest US presentation here .
2. Go to the "Well quality" tab.
3. Group wells by "Basin".

=> You can see the profiles of the average well in each of the basins, and that Bakken wells in general have a longer production life. Note that there is some distortion as especially the early 2007-2008 Bakken wells (Sanish & Parshall) were exceptionally good.

You can play with the "first flow" filter to see this for wells starting in different years.

Dennis Coyne , 08/16/2016 at 4:05 pm
Hi Enno,

Thanks. Using your link above I created the following chart from your website.

I compare only wells with first flow from 2012 to 2016 because the Eagle Ford play did not really start being developed as an oil basin until late 2010 and they probably hadn't really figured out optimal well spacing and frack setup until 2012.

This demonstrates the steeper decline for the Eagle Ford that you refer to.

Dennis Coyne , 08/16/2016 at 4:08 pm
Cumulative well profile that goes with chart above, color scheme is the same, Bakken red, Eagle Ford green, etc.

Enno Peters , 08/16/2016 at 4:25 pm
Exactly, thanks Dennis.
George Kaplan , 08/16/2016 at 4:42 pm
So 'other' would represent the 130 Gb of undiscovered resource that Rystad reckons exists in the USA? That's going to need a lot of wells.
Enno Peters , 08/16/2016 at 5:13 pm
George,

No, the "other" represents other horizontal wells that were drilled in Texas in the last couple of years, outside the Eagle Ford & Permian area, e.g. in the Barnett, Granite Wash, etc.

AlexS , 08/16/2016 at 4:29 pm
Thanks Enno,

These charts from the EIA confirm your conclusions.
They show that, while IP rates in the Bakken and the Eagle Ford are similar, EFS production rates are declining much faster.
Would be interesting to know if this is due to more rapidly falling reservoir pressures, different completion techniques, or something else.

AlexS , 08/16/2016 at 4:30 pm
Eagle Ford

AlexS , 08/16/2016 at 6:29 pm
New-well oil production per rig is higher in the Eagle Ford.
Apparently, this is because EFS is shallower and it takes less time to drill a well than in the Bakken.
As a result, more wells can be drilled by 1 rig in the same period of time.

Source: EIA DPR August 2016

AlexS , 08/16/2016 at 6:31 pm
But legacy oil production declines in the EFS are much steeper

Verwimp , 08/16/2016 at 5:27 pm
To put Enno's "relatively" into perspective: Peak output of Eagle Ford used to be bigger than peak output of Bakken. The more you have, the more you can lose.
AlexS , 08/16/2016 at 5:58 pm
The trend in rig count and the absolute number of active oil rigs are quite similar in the Bakken and EFS.

AlexS , 08/16/2016 at 7:02 pm
The number of drilled but uncompleted wells is bigger in the Eagle Ford.
According to Rystad Energy, it was 1000 as of May 2016 in EFS vs. 850 in the Bakken.

.

AlexS , 08/16/2016 at 7:09 pm
The intentionally postponed (abnormal) part of the DUC inventory has been growing much faster in the Eagle Ford than in the Bakken since mid-2015.
That could also explain steeper declines in EFS oil production vs. the Bakken.

AlexS , 08/16/2016 at 7:16 pm
Bloomberg shows a different trend in DUCs inventory: a decline in the Eagle Ford vs. continued growth in the Bakken. That would suggest more resilient production volumes in EFS.
But I think that Rystad's estimate is more reliable.

[Jul 19, 2016] Bakken is trending towards the less spectacular wells with a lots of sub 1K, and more than a few sub 500 BO IP

Notable quotes:
"... it seem that the IP's out of the Bakken in the Daily reports are trending towards the "less spectacular"? Lots of sub 1,000, and more than a few sub 500 BO IP. ..."
"... I always thought that EOG was the "darling" of the group. But, they having the lowest % of remaining – 36% (64% produced). In that regard, with respect to the production remaining, can you advise "about" how many years of production is represented for an average producer that you note? ..."
peakoilbarrel.com

shallow sand , 07/13/2016 at 1:06 pm

This comment is without me doing any analysis, but does it seem that the IP's out of the Bakken in the Daily reports are trending towards the "less spectacular"? Lots of sub 1,000, and more than a few sub 500 BO IP.
Enno Peters , 07/13/2016 at 1:33 pm
I created a presentation where I show where oil production from existing shale US wells is heading in the coming years. It only includes the actual & projected production of horizontal wells that started production before 2016.
GoneFishing , 07/13/2016 at 1:52 pm
Excellent work Eno, thanks. I notice that the cumulative production of 2008 and 2009 wells is much higher than other years. Any explanation?
Enno , 07/14/2016 at 5:24 am
Thanks, the main reason for that is that those were mostly Bakken wells, and Bakken wells are more productive than the ones in other basins.
clueless , 07/13/2016 at 2:40 pm
Enno – Excellent information! I always thought that EOG was the "darling" of the group. But, they having the lowest % of remaining – 36% (64% produced). In that regard, with respect to the production remaining, can you advise "about" how many years of production is represented for an average producer that you note?
Enno , 07/14/2016 at 6:08 am
Thanks Clueless,

I don't get your question exactly, can you rephrase? The remaining production is all the production that is still expected from the legacy wells, in the coming 20 years, although most of it will of course be produced early on.

clueless , 07/14/2016 at 10:49 am
You answered it. Everything in the next 20 years. I was wondering if it was a truncated number of years, like next 5, etc.
Thanks.

[Jul 17, 2016] 07/16/2016 at 8:52 am

Notable quotes:
"... It looks like the increase in GOR has finally stopped, at least for wells earlier than 2015. GOR for 2015 is still increasing fast. 2008 and 2009 are on the other hand decreasing. ..."
"... Here we can see that for 2009 there is a huge drop, about 6%. As a comparison it would translate into more than 50% in one year. ..."
"... This graph looks like a mess, I know. I hope you can make something out if though. It shows the percentage of wells that are producing in a certain month. There is a downward trend over time, but the oil price is not affecting it much at all. ..."
peakoilbarrel.com
Hello guys. Here is my updated Bakken GOR graph. It looks like the increase in GOR has finally stopped, at least for wells earlier than 2015. GOR for 2015 is still increasing fast. 2008 and 2009 are on the other hand decreasing. So what does this mean for production? Lets see in my next graph bellow.

FreddyW , 07/16/2016 at 9:07 am
Here we can see that for 2009 there is a huge drop, about 6%. As a comparison it would translate into more than 50% in one year. But of course you should not extrapolate from a (cherry picked) single month like that. For 2008 there is instead a slight increase. At least some of that can be explained by that some wells that were previously not producing, are now back online. I don´t know how much of an effect that has though. I´ll show more about that in my next graph. 2013 has slowed down the decline since last month, but is still bellow 2012. So overall nothing dramatic except for 2009.

FreddyW , 07/16/2016 at 9:22 am
This graph looks like a mess, I know. I hope you can make something out if though. It shows the percentage of wells that are producing in a certain month. There is a downward trend over time, but the oil price is not affecting it much at all. It´s only this spring when the oil price was in the 30s that you can notice some decline. But it´s not more than 1-2% of the wells that were put offline. Never the less, there were some wells that were put back on production in May which should have a positive effect on production. Also ,the total producing "days" for all wells combined has increased by about 5% since last month (which I don´t show in any graph here).

[Jun 19, 2016] the inaccurate idea about shale company financing and the role of oil price on that

Notable quotes:
"... You and SS (and others) have quite the inaccurate idea about shale company financing and the role of oil price on that. This type of linear/classical thinking (i.e.: "…price rose, so the banks must lent to the drillers now…") does not represent the reality today when loans to the drillers are used as futures' derivatives' bets and far, far, far exceed the ability of some of these companies to pay back their debt even if oil was to be $1.000/brl for the next 20 years. ..."
"... Much higher oil prices would give the shale folks the ABILITY to pay debt. Question is, wouldn't they drill more wells instead, and roll over the debt? So, what would happen if US, Europe and Japan just coordinated .25 rate hikes each quarter for the next three years? Would that result in a catastrophe? Rune Likvern , 06/16/2016 at 10:07 pm Shallow, What most oil companies [other companies/entities as well] did as they assumed more debt was in reality to enter into a bet that consumers would be able to access more credit/go deeper into debt to enable the oil companies to retire their debts which was assumed to pay for development of costlier oil. [Rollovers are not retirement.] ..."
"... Debt is borrowing from the future. ..."
"... "Some describes this process as transforming wealth into income." Or perhaps it's just transforming billionaires into trillionaires and leaving the rest where they are (or worse). ..."
"... If oil went to $100 WTI, and stayed there for 5 years, and gas went to $6 per mcf, and stayed there for five years, and if the shale companies determined to only spend enough CAPEX to maintain flat production, I think they could generally pay off, or at least substantially pay down debt, in that 5 year period. Some are better off than others. ..."
peakoilbarrel.com

Petro , 06/16/2016 at 6:19 pm

Dennis,

you get entangled so much in numbers, data and lines that you miss and/or confuse the logical big picture.

-Before we enter price/brl/oil and financing of drillers into the equation and, well before we then discuss if your's or somebodyelse's (i.e.: virwimp's) are the more plausible scenarios and more likely to materialize, we have to see if your chart stands logically and mathematically.

And looking at it, that can be only if the following conditions are met:

  1. The "sweet spot/s" of Bakken has not yet been found and it will be in 2019-2020.
  2. The "i-gadgets" of fracking technology have gotten so advanced by 2019-2020 that we can expects wells then to have 30-50-70% more output/day than the comparable well of 2014-2015 (% are for illustration only, I have not crunched the numbers to be precise).
  3. Judging by that almost plateau-ish curb top you have on your production line 2020-2025, the decline rates of wells in 2020-2025 are far, far. far less than those of comparable wells of 2014-2015.
  4. All of the above

Now, can you (or anyone who knows a thing, or two about oil and mathematics for that matter) explain and defend the above scenario logically and scientifically?
Don't you see to much magic and wishful thinking?

If you can do that (explain logically and scientifically), then and only then I will engage in the price/financing debate with you and after that, in the one that discusses which is the most plausible to represent reality 10-20-30 years in the future.

Be well,

Petro

P.S.: You and SS (and others) have quite the inaccurate idea about shale company financing and the role of oil price on that.
This type of linear/classical thinking (i.e.: "…price rose, so the banks must lent to the drillers now…") does not represent the reality today when loans to the drillers are used as futures' derivatives' bets and far, far, far exceed the ability of some of these companies to pay back their debt even if oil was to be $1.000/brl for the next 20 years.

But that is a very complex matter which you (and I am not being offensive here…believe me!) and almost all here cannot understand easily, so I will leave that for another day.

shallow sand , 06/16/2016 at 8:48 pm
Much higher oil prices would give the shale folks the ABILITY to pay debt. Question is, wouldn't they drill more wells instead, and roll over the debt?

So, what would happen if US, Europe and Japan just coordinated .25 rate hikes each quarter for the next three years?

Would that result in a catastrophe?

Rune Likvern , 06/16/2016 at 10:07 pm
Shallow,

What most oil companies [other companies/entities as well] did as they assumed more debt was in reality to enter into a bet that consumers would be able to access more credit/go deeper into debt to enable the oil companies to retire their debts which was assumed to pay for development of costlier oil. [Rollovers are not retirement.]

Central banks lowering the interest rate [described as interest suppression by many] served several purposes like easing services of existing debt overhang and allow for further debt expansion in an effort to bring our economies back on the [economic] growth trajectory.

Debt is borrowing from the future.

Increasing the interest rate as described by a quarter percent over 3 years would introduce severe strain on the system as it becomes harder to service the present huge debt overhang and make it hard for anyone to assume more debt [it would likely blow out many balance sheets].

The Fed now keeps deferring further increases to the feds funds rate. The Fed is worried about what an increase could entail.
In short a higher interest rate would bring the oil price down as more income becomes diverted to servicing debts and thus less available to pay for amongst other things higher priced oil.

shallow sand , 06/16/2016 at 11:43 pm
Rune: I am not so sure.

There is a very sizable population of retired individuals in both US and Europe who are spending much less because they have less income.

Ultra low rates have caused a lot of misplaced investments, leading to capital destruction.

hightrekker23 , 06/17/2016 at 12:01 am
Well said, and true from my observations.
Rune Likvern , 06/17/2016 at 11:01 am
Shallow, thanks

First you described the interest rate with raising it a quarter percent each quarter over 3 years. (Something became omitted in my reply, but it looks like the objective of the discussion was sustained.)

What you describe about those who live on income from their own savings or pension funds I agree with, lower interest rates now wreaks havoc with many pension plans and also the insurance industry.

I also agree that ultra low rates have caused misallocation of capital. Yield starved investors started chasing riskier projects/investments.

To me this illustrates that there is no easy fix to the interest dilemma.
Damned if interest rates are raised and damned if they are not.

Low rates have led to capital destruction, I agree.
Some describes this process as transforming wealth into income.

Doug Leighton , 06/17/2016 at 11:08 am
"Some describes this process as transforming wealth into income." Or perhaps it's just transforming billionaires into trillionaires and leaving the rest where they are (or worse).
Nick G , 06/17/2016 at 11:19 am
Or, perhaps we simply have too many wealthy investors, who save rather than consume.

If the income and wealth were in the hands of middle or lower income people, we wouldn't have so much excess capital pursuing unrealistic returns.

Petro , 06/17/2016 at 12:30 pm
"Much higher oil prices would give the shale folks the ABILITY to pay debt."

-NO.
Debt is at unsustainable levels. You seem to have missed the P.S. section of the comment of mine you replied to. I suggest you revisit it.

"Question is, wouldn't they drill more wells instead, and roll over the debt?"

-That is NOT the question. That is the ONLY thing they can do with higher oil prices at this point.

"So, what would happen if US, Europe and Japan just coordinated .25 rate hikes each quarter for the next three years?

Would that result in a catastrophe?"

Folks who say: "ahh, what's a .25% increase to our economy? Nothing…let the FED do that…" know nothing about the economy and finance. Do not waste your time listening to them.
As I said this is a very complex matter, but for now let me tell you that the economy and finance work NOT on nominal rates (the famous FED rate, or BOJ rate or ECB rate you hear about on TV and how they manipulate it…ha, ha, ha…), but on REAL interest rates …which are totally a different beast.

If the FED, BOJ and ECB did what you suggest and in a coordinated matter increased the nominal rate .25% every quarter we would literally plunge into the dark ages in short, very short order!!!!
Who tells you otherwise is an idiot.
Forget about the "PONZI FIAT money scheme" and the "FED MANIPULATION" you hear from obviously "experts" on the matter here and elsewhere….

FED, BOJ and ECB have NO choice but to lower the rates and print digits/money.

Again, I cannot stress this enough:
who tells you otherwise, and who tells you that (at this point in time) we can go to a gold standard, or some kind responsible debt reduction economy knows nothing of today's economy and finance and is an idiot.
And NO, this has nothing to do with some kind of Marxist redistribution of wealth.
Even if we somehow did that, we would still be in the same place in the near future.
It is human nature and the behavior of our inner human animal.

That is why a while back – when everybody was saying that FED is increasing rates and rates will go up – I told you: " 10year note is going to 1% BEFORE going to 3% like everybody says…."
….and perhaps is going to 0% soon.
Expect no more rate increases and going back to QE (with other names perhaps) – NOT because the FED is evil (as you hear here all the time) but because there is NO other choice!

Rates shall spike up in the future, but when they do is time to go underground with our loved ones, a loaf of bread, a gun and pray….if you believe that is'

Pay, pray, pray that Yellen, Kuroda and Draghi go each month on TV and bullshit us some more, for if they do not …..well let's just say that we will not have computers to reply to each other anymore…..

Be well,

Petro

texas tea , 06/17/2016 at 1:36 pm
"Rates shall spike up in the future, but when they do is time to go underground with our loved ones, a loaf of bread, a gun and pray….if you believe that is'"

Petro ….'a' gun come now. all things being equal i think I will have a couple of semi auto, as well as revolvers, pump action and double barrels. Ironic so many here can make a reasoned case for civil breakdown and at the same time want to restrict guns of law abiding citizens. I suspect your analysis posted here is more realistic than many others, the timing issue is the real question. Next up more QE and then helicopter money!

houtskool , 06/17/2016 at 2:46 pm
Agreed 100% Petro. Awesome comment, a few more years of monetizing and 'whatever it takes' comments. We're in trouble.
shallow sand , 06/17/2016 at 7:19 pm
Petro.

If oil went to $100 WTI, and stayed there for 5 years, and gas went to $6 per mcf, and stayed there for five years, and if the shale companies determined to only spend enough CAPEX to maintain flat production, I think they could generally pay off, or at least substantially pay down debt, in that 5 year period. Some are better off than others.

I suspect costs would rise, both LOE and CAPEX, but I will do an example.

Shale R Us has 200,000 BOE per day, 80% oil 20% gas. So, lets say after well head discounts, they get $85 per BOE. LOE is $8. G & A is $3. They have to spend $20 per BOE in CAPEX to keep production at 200,000 BOE per day ($1.46 billion per year). Severance tax is 10%. They have $3 billion of debt, interest rate is 6%.

By my calculations, over five years, Shale R Us generates $16.6075 billion of pre-tax and pre-interest cash flow in this scenario. There is $900 million of interest that has to be paid, plus the $3 billion of principal. Assuming income tax of 35%, subtract about $5.5 billion for income tax.

I come up with Shale R Us having $7.2 billion left in this scenario, at the end of five years after payment of income tax, principal and interest.

I did this quickly, so if there are computational errors, let me know and I will correct them.

Now, my example is of a strong company. Most wont work out that well, but they can pay the debt off at $100 WTI plus $6 gas.

Petro, you are either talking over my head and/or we are talking past each other. I am not considering what those prices do to the world economy, demand, etc., only whether Shale R Us can eliminate their debt.

Sorry if I am too dense to follow how $1,000 oil for 20 years would not cause all the LTO companies to mint money. Again, not talking about the economy, etc. Just doing math, really.

Petro , 06/17/2016 at 8:07 pm
Dear Shallow,

you are falling in the same trap as Dennis: getting entangled in too much data.

Yes indeed, as you say, I am talking way above your head here.
Now before you hate me, trust me I mean no disrespect.
But the subject is such….so please stay with me.

What you are asking me is another difficult and long answer.
I either have to do that post I mentioned about debt and money, or stop answering and replying.

First of, you have the wrong idea as to how the financing of shale drillers happens.
The way you think it happens (i.e.: they go to bank, present their business model and oil price expectations and blah, blah , blah and bingo….Goldman gives them the money!) does not exist anymore.
It indeed happened that way (more or less, of course I am simplifying) PRIOR to 2000 – not today.

Goldman (or any bank…put the name you like here) uses the oil price and business model of the sale player ONLY to bullshit the shareholders into voting it…..it does not give a crap what the company does and how it does it and at what price.

Here where the "beauty" starts:
that loan then, which on bank's balance sheet is considered an asset, is re-hypothecated dozens, upon dozens, upon dozens of times as a futures' OTC derivatives' bet with businesses that have nothing to do with shale players and are half a world away – china let's say.
So, if one too many of them fail, driven out of business by responsible guys like you – even though their combined debt size is nothing compared to….oh, lets say JP Morgans' assets, the avalanche it starts buries us all.

You are thinking in terms of only one good company – that my friend is linear/classical thinking.
Is like this: the risk increased by 2 times so the outcome shall be 2 times worse or maybe 4.
That to you (and most) is manageable if you tighten your belt and plan well.
-But our economy and our energy/finance system is a COMPLEX INTERCONNECTED SYSTEM.
That means that small stimuli, bring about exponentially worse and uncontrollable outcomes.
Its like Lehman Bros. in 2008.
Their assets and liabilities were nothing compared to the whole economy…..but the cascade they would have started would have plunged the entire global finance/economy into dark ages within hours…literally.

So, contrary to what you have learned by "experts" here that: "…the Evil FED helped their crony bodies and destroyed the economy…ha, ha , ha…", if the 1st QE aka TARP did not happened, we literally would have eaten each other as food by now (walking dead type thing….ish).

DEBT cannot be eliminated.
It has to increase more and more if you would like to continue the life you have.
If we eliminate debt, we eliminate money including that $100 that you like to get per barrel of your own oil…………it cannot be!
Stick that in your head.

Be well,

Petro

shallow sand , 06/17/2016 at 10:41 pm
Petro. I'd like to see a post from you. I doubt you'd get blasted, and if you do, so what? If anything, I kind of enjoy debating this stuff with someone on the other side.

Couple of questions.

First, you talk about shareholders approving loans. I am assuming you just misspoke, as shareholders of banks do not approve of anything, except voting on directors, some compensation issues, and sometimes stuff put on proxy cards by activists (i.e. divest of fossil fuel loans LOL!)

Second, I did not think that reserve based energy loans were being packaged and sold in derivative markets, at least not like home mortgages were. I also was unaware banks were insuring them to a large extent with CDS's.

My understanding is there is a consortium of banks on most of these, with one bank as lead, the others each taking a participating percentage. The note is secured by a first lien on the shale company assets. The size of the loan is based on the PV10 (or PV9) of the assets, with PDP valued at 100% and with PDNP, PDBP and PUD possibly being given some collateral value, but being greatly discounted, say for PUD, maybe assigned only 20-30% of PV10.

The maximum amount that may be extended should be no more than 65% of PV10 or PV9. If the value of the reserves drops, the borrowing base is cut.

Petro, you probably know all this stuff, maybe more in depth than me. I'm posting this for other's benefit.

The game the shale guys played in 2010-2014 was to fill up the first lien bank line, then float an unsecured bond to pay it off. Most shale guys did this several times. I assume it is on these unsecured bonds, where credit default swaps (insurance) was likely sold, where you think there will be a black swan event? My understanding is this junk is a small fraction of what the mortgage derivative market was and still is. Many of these bonds have defaulted, or are at extreme stress levels already.

Would seem to me, given oil cratered to the $20s in early 2016, we would have seen signs of the black swan, maybe we did, as the markets fell, almost perfect correlation with oil, which has now, somewhat broken.

However, if we take my hypothetical $100 WTI and $6 HH per mcf, how do those CDS on shale bonds cause any problems?

Also, back to the horse and pony show with regard to bank loans, I am not so sure how much puffery there has been. It really depends on how the engineering firm did the reserve report, and if the bank's price deck utilized was realistic.

I will say, unlike the mortgage meltdown, where there were fraudulent appraisals all over the place, there are not a lot of petroleum engineering firms, and they are not fly by night outfits.

I will also say, it seems to me energy lending is pretty specialized, there weren't energy loan brokers setting up shop on every street corner and advertising on late night cable TV. Mostly big banks, or large regionals, in this market.

Finally, these loans are not of the $150K mortgage variety. When the bank examiners come, they look into the big loans much more closely. Easier for OCC to examine 10 billion $ worth of 10 reserve backed energy loans than $10 billion $ of home mortgages, of which there would be 50-100K individual loan files, appraisals, etc.

Where the OCC screwed up was by not figuring in the junior debt when they examined the bank loans. But, they finally are now, and that is a big deal IMO.

The way I see it, if WTI hits $100 2017-2021, and gas is $6 during the same time, and the shale knuckleheads have learned something from the most recent Arab OPEC "good sweating" and don't overdo it, they mostly pay down substantially/payoff debt.

I'm talking Newfield, QEP, OXY, PXD, EGN, EOG, COP, MRO, WPX, SM, HES, APA, APC, XEC, FANG, MTDR, DVN and a few others. CLR and WLL would pay down, but not off. Same with OAS. CHK too. The few MLP that have survived thus far, would also at least pay down, but think they are required to distribute most cash flow.

Oil at $125 for five years, they about all get out of debt IMO.

And, in the event this happens, these guys would be well advised to just issue equity to grow, going forward. Where price wont help them is when the locations run out. Especially the good ones. Better to have little to no debt when that happens, which is probably by 2021, even if these dudes are more sane about development.

Keep in mind, in my example, the pre-tax, pre-interest profit margin is $45.5 per BOE. Right now, and pretty much since Thanksgiving, 2014 unhedged profit margin has been less than zero.

I agree, the world economy is screwed up. But, I think I am going to need some more detail to figure out what you are saying. I also do not think TARP was bad. Clueless described TARP very well recently.

Don't worry about offending me, I'm called a lot of stuff and don't care. Know who I am pretty well. Would really like a post, but understand if you don't. Its kind of daunting.

Petro , 06/17/2016 at 11:52 pm
Shallow,

I am just going to touch a couple of points only.
First, as far as offending you:
yeah, you might have been called names and have a thick skin, but I do not want to go that route to begin with.
Not because you don't care, but because I do not offend people…intentionally that is.
So, I said that to warn you that if it comes out that way, it is not my intention.

Second, I did not misspeak.
I already spent too much time comenting and I went short, obviously way short.
I meant they'd have it on the books in order in case something happened, or somebody inquired, or to present their "strategy" at their shareholders or their newsletters for investors (i.e.: Goldmans' outlook on the oil market….and BS like that)
Most of the big guys repackaged and resold those loand to greater fools way, way before oil price rout started.
They own very little directly……
However – and this is the important part – they are affected by them indirectly by other companies derivatives which have direct exposure to the loans presently.
Think of it as: you fire a gun at a target in front of you, but it makes 10 ricochets at the walls and trees and what not around and comes back and kills you.

Third, as the result of the repeal of Glass_Stegal in 1999 – thank you very much R. Rubin, L. Summers and most importantly our dear B.Clinton who signed it into law
(don't fuss democrats. For me there is NO difference between republicrats and democlicans. Reagan and Bush were as bad, or worse!) – commercial and investment banking became one and all and turned to what's called TRANSACTIONAL banking.
Meaning: everything, without exception is repackaged and resold multiple times to grater fools.

Forth, the task of a post is not daunting!
heck, I have posted here in the last 2-3 years to last me for 3 posts.
It is first that, even knowledgeable, well meaning people have preset concepts that they are not willing to change.
I mean, look at the amount of time I am spending replying to you and you ask me the same things…..does "linear/classical" thinking ring a bell?
You wrote it yourself: "Hard to change long held views".

and second, some people act as experts in things they know nothing about….and they are going to reply to me with stupid: "evil FED" , "Real Gold Money vs. Fiat" and " Rockefeller- Rothchild cospiracy" bull shit…………………………………….
and I am not sure I can handle that politely…………………..
…and then you have Nik Gs and the rest who think that oil and energy are just like any other commodity and we somehow can do without them and so on and so on…..
You get my point….

But, I am thinking about it….
Be well,

Petro

Oldfarmermac , 06/18/2016 at 6:43 am
" repeal of Glass_Stegal in 1999 – thank you very much R. Rubin, L. Summers and most importantly our dear B.Clinton who signed it into law
(don't fuss democrats. For me there is NO difference between republicrats and democlicans."

Petro, you are one heap big smart fella, or else I am a mental midget. I just can't see any way you are wrong.

The key problem with our current two party political set up is that both parties were long ago captured by Wall Street type interests.

Political reform on the grand scale would help immensely, but political reform is not enough to solve the overshoot problem.

shallow sand , 06/18/2016 at 7:46 am
Petro.

I agree with you about Glass Stegal.

Also, I should point out my banking experience is with a small, local bank, privately traded shares, less than 500 shareholders. The stock price barely moves, however it has slowly ground upward over time. Has always paid a dividend which has been 4-5% of share price.

The bank makes fixed rate mortgages, which it sells off to Fannie or Freddie, but retains all servicing. It retains all other loans in house, such as auto, Ag, small business, rental real estate. It has a few larger customers where it has to participate with others, and occasional will participate with other banks on loans the others originate.

The 2008 financial crisis did not affect it. No one sold their shares anymore than usual, the stock price didn't drop.

The only real thing they do which was prohibited by Glass Stegal is they have an in house stock broker, where customers hold brokerage accounts. I don't see that as a problem, and that service ties in well with the primary duty of being a trust officer.

The primary problem in the aftermath of 2008 is the banks cost of compliance went up.

So, you can see, my background in this area is very foreign. I am coming from a totally different view, so yours, or any other serious and on topic views are appreciated. My views are very 1980s, I remember when a bank in one town could not open a branch in the next town over.

I continue to be surprised that interest rates "have not risen on their own".

Rune Likvern , 06/16/2016 at 10:06 pm
Petro,
Thanks for your interesting contributions and viewpoints to this debate.
I believe we are headed for some non linear events and the thing is the human brains are NOT evolved/trained to think in non linear terms. We tend to extrapolate past experiences into the future with some noise around a constructed [wished for] trend line.
Looking forward to your future elaborations on this subject.

[Jun 19, 2016] I wonder if someone fiddled with those chokes just a little to more conservative settings?

Notable quotes:
"... As for damage, that will be the final proof of what has been happening. I will be watching Rune's graphs to see if the recent years start to drop below previous years totals. ..."
"... There was a great summary by somebody else a few posts back. The big issue is that you have condensate get into gasphase inside the reservoir. This in turn will result in more "stranded" oil. I fear we will only see the results later this year/2017. I would expect the production rates to drop of steeper than before and result in lower ultimate recoveries (but i know conventional plays much better). Maybe somebody with more knowledge can chime in? ..."
"... As for damaged wells. We will just have to wait for the data to come in. April's decreasing GOR has given me confidence in my original suspicions of over producing wells. Not sure how keen Shallow will be pumping dead oil from 10,000 ft TVD and 20,000 ft MD. At least there will be plenty of wells to experiment with, until you can make it work! ..."
"... Although it intrigues me, don't worry, we will leave the deep stuff to someone else. Low volume wells that produce little to no water can work even in a low price environment. ..."
"... Besides the costs in the event of a down hole failure being down right frightening, it has not been determined where these wells will settle out in years 10-30+ ..."
peakoilbarrel.com
Toolpush , 06/16/2016 at 4:36 am
Just my monthly 2c worth on GORs.

Oil price up, cash flows more comfortable, Oil production down a whopper, GOR also down and against the trend!

I wonder if someone fiddled with those chokes just a little to more conservative settings?

daniel , 06/16/2016 at 5:13 am
I was thinking exactly the same. I would think the damage is done though
Toolpush , 06/17/2016 at 4:17 am
Daniel,

I believe you are in the patch? Do you have any on the ground experience you can relate? As for damage, that will be the final proof of what has been happening. I will be watching Rune's graphs to see if the recent years start to drop below previous years totals.

daniel , 06/17/2016 at 3:15 pm
There was a great summary by somebody else a few posts back. The big issue is that you have condensate get into gasphase inside the reservoir. This in turn will result in more "stranded" oil. I fear we will only see the results later this year/2017. I would expect the production rates to drop of steeper than before and result in lower ultimate recoveries (but i know conventional plays much better). Maybe somebody with more knowledge can chime in?
Toolpush , 06/18/2016 at 2:17 am
Daniel,

You raised an interesting point. Everybody that bothers to write on these blogs, that have any hands on experience, all seem to be from the conventional oil field. Either the shale players, are not interested, or are keeping a big secret. Smiles.

I would really love to hear some real inside info. I am sure a lot of speculation could be put to rest very quickly.

As for damaged wells. We will just have to wait for the data to come in. April's decreasing GOR has given me confidence in my original suspicions of over producing wells. Not sure how keen Shallow will be pumping dead oil from 10,000 ft TVD and 20,000 ft MD. At least there will be plenty of wells to experiment with, until you can make it work! lol

shallow sand , 06/18/2016 at 7:27 am
Toolpush,

Although it intrigues me, don't worry, we will leave the deep stuff to someone else. Low volume wells that produce little to no water can work even in a low price environment.

Besides the costs in the event of a down hole failure being down right frightening, it has not been determined where these wells will settle out in years 10-30+.

[Jun 19, 2016] Higher borrowing costs and tighter lending standards will act to restrain growth in the Bakken going forward

Notable quotes:
"... Prices however can go substantially higher before restraining U.S. growth than they could in 2008 since the economy has changed. ..."
"... New vehicle efficiency alone increased 25 percent: ..."
peakoilbarrel.com
Higher borrowing costs and tighter lending standards will act to restrain growth in the Bakken going forward and along with continued advances in alternatives may well make it unlikely to peak higher. Prices however can go substantially higher before restraining U.S. growth than they could in 2008 since the economy has changed.

New vehicle efficiency alone increased 25 percent: http://www.umich.edu/~umtriswt/img/EDI_mpg_May-2016.png

[Jun 19, 2016] I was rather surprised by the modest declines those last two months.

peakoilbarrel.com
Verwimp , 06/15/2016 at 2:21 pm
This is only a little surprise. This decline takes away the surplus that was built up during the last two months (Fabruari and March) compared to the Season Effect Model. I was rather surprised by the modest declines those last two months.

I try to attach the graph once more to this comment (or I will ask Ron for support).

You can clearly see the dataset crosses the modelled line for the sixth time now. The first derivative of the model and the change of the data are still within the same error range as prior to the moment the model was built.

Difference between the model and the data is -2.4% now. The age of the model is 29 months now.

 photo Bruno 1_zpsqwt0dc5p.jpg

SRSrocco , 06/15/2016 at 2:47 pm
Verwimp,

Excellent chart. Just wanted to let you know that you were one of the few who presented the CORRECT Bakken chart in this blog. There may have been others, but well done. Jean Laherrere and Tad Patzek both have the same Bakken production profile as yours.

By 2025, the United States will be pumping 75% less oil than it is today. It will be interesting to see how we run the LEECH & SPEND SERVICE ECONOMY on that little amount of oil. Americans who think we will be able to exchange worthless paper dollars or Treasuries for oil at that time, better stop sniffing the glue.

[Jun 19, 2016] The Bakken was down 69,420 barrels per day in April

Notable quotes:
"... Producing Wells ..."
"... March 13,052 ..."
"... April 13,050 (preliminary)(all-time high was Oct 2015 13,190) ..."
"... March 56 drilling and 4 seismic ..."
"... April 66 drilling and 0 seismic ..."
"... May 42 drilling and 0 seismic (all time high was 370 in 10/2012) ..."
"... ND Sweet Crude Price ..."
"... March $26.62/barrel ..."
"... April $30.75/barrel ..."
"... May $33.74/barrel ..."
"... Today $38.25/barrel (all-time high was $136.29 7/3/2008) ..."
"... Today's rig count is 28 (lowest since July 2005 when it was 27)(all-time high was 218 on 5/29/2012) ..."
"... The drilling rig count fell 3 from March to April, 2 from April to May, and increased 1 from May to today. Operators remain committed to running the minimum number of rigs while oil prices remain below $60/barrel WTI. The number of well completions fell from 66 (final) in March to 41 (preliminary) in April. Oil price weakness is the primary reason for the slow-down and is now anticipated to last into at least the third quarter of this year and perhaps into the second quarter of 2017. There was 1 significant precipitation event, 15 days with wind speeds in excess of 35 mph (too high for completion work), and no days with temperatures below -10F. ..."
"... Over 98% of drilling now targets the Bakken and Three Forks formations. ..."
"... Estimated wells waiting on completion services is 892, down 28 from the end of March to the end of April. Estimated inactive well count is 1,590, up 67 from the end of March to the end of April. ..."
"... Crude oil take away capacity remains dependent on rail deliveries to coastal refineries to remain adequate. ..."
"... Low oil price associated with lifting of sanctions on Iran and a weaker economy in China are expected to lead to continued low drilling rig count. Utilization rate for rigs capable of 20,000+ feet is 25-30% and for shallow well rigs (7,000 feet or less) 15-20%. ..."
"... Drilling permit activity increased from March to April then fell back in May as operators continue to position themselves for low 2016 price scenarios. Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months. ..."
peakoilbarrel.com

by Ron Patterson Posted on 06/15/2016 The Bakken and North Dakota production data is out. Big surprise. The Bakken was down 69,420 barrels per day in April while all North Dakota was down 70,414 bpd.

Largest drop ever in North Dakota production. The Bakken is now under one million barrels per day.

Bakken Change

This gives you some idea of the erratic nature of North Dakota production. But as you can see, the decline is accelerating.

The EIA's Drilling Productivity Report gives past Bakken production numbers, which includes the Montana portion, and future estimates for the next couple of months. The average difference between North Dakota production and total Bakken production has been about 27,500 bpd. However for April the difference is almost 63,000 barrels. So it looks like for once the DPR estimate is way too conservative. The DPR estimate is through July while the north Dakota data is only through April.

In April Bakken barrels per day per well fell by 7 to 94, North Dakota bpd per well fell by 5 to 82.

From the Director's Cut

Producing Wells

March 13,052
April 13,050 (preliminary)(all-time high was Oct 2015 13,190)

Permitting

March 56 drilling and 4 seismic
April 66 drilling and 0 seismic
May 42 drilling and 0 seismic (all time high was 370 in 10/2012)

ND Sweet Crude Price

March $26.62/barrel
April $30.75/barrel
May $33.74/barrel
Today $38.25/barrel (all-time high was $136.29 7/3/2008)

Rig Count

March 32
April 29
May 27
Today's rig count is 28 (lowest since July 2005 when it was 27)(all-time high was 218 on 5/29/2012)

Comments:

The drilling rig count fell 3 from March to April, 2 from April to May, and increased 1 from May to today. Operators remain committed to running the minimum number of rigs while oil prices remain below $60/barrel WTI. The number of well completions fell from 66 (final) in March to 41 (preliminary) in April. Oil price weakness is the primary reason for the slow-down and is now anticipated to last into at least the third quarter of this year and perhaps into the second quarter of 2017. There was 1 significant precipitation event, 15 days with wind speeds in excess of 35 mph (too high for completion work), and no days with temperatures below -10F.
Over 98% of drilling now targets the Bakken and Three Forks formations.

Estimated wells waiting on completion services is 892, down 28 from the end of March to the end of April. Estimated inactive well count is 1,590, up 67 from the end of March to the end of April.
Crude oil take away capacity remains dependent on rail deliveries to coastal refineries to remain adequate.
Low oil price associated with lifting of sanctions on Iran and a weaker economy in China are expected to lead to continued low drilling rig count. Utilization rate for rigs capable of 20,000+ feet is 25-30% and for shallow well rigs (7,000 feet or less) 15-20%.
Drilling permit activity increased from March to April then fell back in May as operators continue to position themselves for low 2016 price scenarios. Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months.

... ... ...

New wells added in the Bakken/Three Forks are assumed to drop to 25 new wells in April and remain at that level until Jan 2017. Last month about 64 new wells were added.

[Jun 18, 2016] The E P companies stopped drilling wildcats starting in 2013, and havent applied for such a permit for months, Id suggest that means there are no undiscovered reserves, all wells are in known areas now

Notable quotes:
"... Note that at $90/b at the wellhead, the average 2014-2015 Bakken well pays out in 27 months. ..."
"... Note that 10,000 wells were drilled over an 8 year period from 2008 to 2016. ..."
"... My scenario has another 14,000 wells drilled over 11 years, possibly too optimistic, but similar to past history. ..."
"... 'Rationing' the remaining affordable oil supply will ONLY work as intended if the entire world does it together and the same time simultaneously and harmoniously.. . Not a snowballs chance of that is there. ..."
"... Usually rationing causes more problems than it solves, it usually is best to let the market handle it, high prices will reduce the quantity that people are able to purchase and behaviors will change. More efficient vehicles, car pooling, use of public transportation where available, etc. ..."
"... In june 2010 the average well production was 145 barrels per day, with a total of 1663 wells. Now the average well production is 94 barrels per day with a total of ten thousand five hundred and six wells. That's a lot of wells. All of them declining from day one. There is an enormous amount of inertia built in into the system now. It will take another ten-, twenty- of even fiftythousand wells to make the red queen recover. She will not. In the mean time companies go broke and the whole thing comes to a grinding halt. ..."
"... Dennis. $75 [is Ok to drill shale well] using cash. How many in the Bakken shale are using cash? Also, $75 assumes service companies continue to agree to low to no profit from services provided. Bakken wells were north of $10 million per in 2011-14. Again, CLR $11 million cash, $7.3 billion debt. WLL over $5 billion debt. HRC is bankrupt. From memory QEP, SM, HES, EOG, MRO, etc. All have billions of debt. PDP PV10 is less than long term debt at current prices. ..."
"... One thing, it appears that only equity markets are open to shale drillers. That, of course, is the best approach IMO. Promoters usually make money if investors pay for the well, regardless of whether the well pays out. Issuing gobs of debt turned out to be a big mistake. Think how much $$ shale could have gotten 2011-14 by just issuing shares. Break even would certainly be less. ..."
"... You think perhaps they drilled the worst spots first, saving the sweet spots for last? No, the sweet spots have already been drilled. Future wells will, almost certainly, produce less oil than those already drilled. Drillers just don't think that way Dennis. They would never save the sweet spots for last. ..."
"... Dennis, in the early days of Bakken fracking the wells had short laterals and fewer fracking stages. They got better with much longer laterals. They also got better at locating the sweet spots. But now the laterals and number of stages has maxed out. And the sweet spots are all drilled up. ..."
"... There is no doubt whatsoever that the very best and most productive wells have already been drilled. ..."
"... Low oil prices are forcing operators to focus drilling activity only in the core areas of the Bakken where wells have the greatest production. As oil prices recover and drilling expands to other areas of the Bakken, those high-producing wells will be declining, Helms said. "It's really kind of doubtful that we're going to make that (2 million barrels per day) because we're drilling everything in the core where the best wells are," he said. ..."
peakoilbarrel.com

George Kaplan , 06/16/2016 at 2:52 pm

The E&P companies stopped drilling wildcats starting in 2013, and haven't applied for such a permit for months, I'd suggest that means there are no undiscovered reserves, all wells are in known areas now.
Dennis Coyne , 06/16/2016 at 1:18 pm
Hi Jim,

What do you think will happen to oil prices when oil output decreases?

The scenario is optimistic and assumes high oil prices, note that output does not start to increase until 2019 in this scenario, when oil prices have risen to $88/b (2015$).

The high oil price for this model is $116/b in 2016$ which is reached in late 2020, does that seem unreasonable? The number of wells added is 1800 per year starting in 2021 with a gradual ramp up to that level over a 2.5 year period from mid 2018 to the end of 2020.

I think it likely that if oil prices rise and remain over $100/b for a few years that oil output will expand rapidly.

Note that at $90/b at the wellhead, the average 2014-2015 Bakken well pays out in 27 months.

The net discounted cash flow for that well, a 10% annual discount rate is $12.6 million with a well cost of about $8.5 million that leaves $4.1 million for profit or to be used to pay interest and debt.

I doubt we will be seeing more oil surpluses in the near future. Perhaps if people start to move to EVs in 20 years or so we might see demand fall faster than supply, but it will probably be 30 years or more before we get there so 2045, beyond the scope of my scenario.

At some point there could be a financial crisis, but I will leave it to others to predict when that will occur. In that case demand for oil will fall along with oil prices and supply.

Cracker , 06/16/2016 at 3:56 pm
Dennis,

You asked "What do you think will happen to oil prices when oil output decreases?"

I agree the initial reaction will be higher oil prices, but I don't expect the stability in high prices, oil markets, and free money that existed in the last cycle will ever be repeated. And you need those conditions to ramp up shale again to production levels that can overcome the inertia of decline.

I think the stability expected is the root of our separate views. You foresee (and hope) for it while I don't see it (but hope for it).

I think the only reason the global economy seemed to be able to afford $100 oil is because abundant cheap money (from central banks) reduced interest costs, which were able to help pay for higher energy costs. It bought time, but I'm still seeing its effects, in the form of activities and businesses that just aren't productive enough to continue, and shut down, without being replaced. The effects of the last round of high oil prices are still slowly but surely creeping around in the US economy.

Sure, oil prices will go back up soon enough. But can they go up and stay stable at high enough levels to overcome the memories of shale ponzi financials? And can the rest of the world avoid instability that affects oil demand and supply for that same period?

Seems unlikely from here.

I'm glad I'm not making your models because I would go nuts trying to figure out how to build in some of my variables of instability. It can't be easy or you would have done because I (and others) have suggested it in recent past.

Thanks for putting some numbers and graphics on these things. We may not all agree with you, but you sure make us think. Thank you for that.

Jim

Dennis Coyne , 06/17/2016 at 8:03 am
Hi Jim,

Thanks.

I don't expect the price will be stable, I don't know how the instability will manifest.

When you look at my models just imagine the real values will wiggle above and below the trend line, prices are very hard to predict. Also if we look at the 36 month centered running average of monthly WTI prices since 1986, prices look somewhat less volatile. I expect prices will rise to the 80 to 90 dollar range and perhaps stabilize (if we looked at future 36 month running average). I also don't predict oil prices well so perhaps it will be $60 to $70/b, in that case there will be less LTO wells drilled, or perhaps none.

GoneFishing , 06/15/2016 at 5:41 pm
Wouldn't it be a lot more prudent to just ration oil and move to EV's and renewables as fast as possible?
Putting in another 15,000 wells that are mostly not in sweet spots will make most of the players even more vulnerable to a downturn in oil prices than they were the last time.
Dennis Coyne , 06/15/2016 at 7:17 pm
Hi Gone Fishing,

At high oil prices wells will be drilled. If oil prices stay low because we move quickly to EVs, the scenario will be incorrect. I would love to be wrong, unfortunately this is fairly likely to occur. Note that 10,000 wells were drilled over an 8 year period from 2008 to 2016.

My scenario has another 14,000 wells drilled over 11 years, possibly too optimistic, but similar to past history.

GoneFishing , 06/16/2016 at 4:29 am
Dennis, I don't see any way that low oil prices can occur again for any period of time. We are entering the final descent phase of LTO, exports will be falling worldwide and prices will stay high.

Rationing is just around the corner anyway, so why not be sensible about it and start it sooner. People can put up with being transport limited or they can switch to EV's.
15.000 more wells in the Bakken saturate it and there is no more room. End of story. Probably stop drilling long before that as they will be far off the sweet spots and profits will not be there, even at high oil prices.

Adam Ash , 06/16/2016 at 7:06 am
'Rationing' the remaining affordable oil supply will ONLY work as intended if the entire world does it together and the same time simultaneously and harmoniously.. . Not a snowballs chance of that is there.

So if say UK and USA ration, all it will do is reduce the price (due to reduced demand) which will encourage other unconstrained users to increase their consumption.

In the absence of a One World Govt and its associated Inspired Benevolent Dictator we are screwed either way. The yeast is running our of sugar, we are heading down the back of the resource supply curve, and everybody here knows what a bumpy horrid ride it is going to be.

(That's my cheerful appreciation of our predicament for today! Carry on!)

GoneFishing , 06/16/2016 at 9:50 am
When you have a shortfall, rationing what you do have has no effect on world demand or use. It is merely a way of controlling distribution of product in hand and product you can get hold of. If you can't get more, how does that change anything.

Demand reduction will occur as alternatives and lifestyle changes take over. That is going to happen anyway. Let the ROTFW fight over the last dribbles if they are stupid.

Dennis Coyne , 06/16/2016 at 1:22 pm
Hi Gonefishing,

Usually rationing causes more problems than it solves, it usually is best to let the market handle it, high prices will reduce the quantity that people are able to purchase and behaviors will change. More efficient vehicles, car pooling, use of public transportation where available, etc.

Verwimp , 06/15/2016 at 5:48 pm
Hi Dennis,

Again: Time will tell.

Still, I stick to my model as I have been doing for 29 months now. Especially because price is not a parameter in the model.
In june 2010 the average well production was 145 barrels per day, with a total of 1663 wells. Now the average well production is 94 barrels per day with a total of ten thousand five hundred and six wells. That's a lot of wells. All of them declining from day one. There is an enormous amount of inertia built in into the system now. It will take another ten-, twenty- of even fiftythousand wells to make the red queen recover. She will not. In the mean time companies go broke and the whole thing comes to a grinding halt.
That's my take on it.

Doug Leighton , 06/15/2016 at 6:25 pm
Verwimp,

I like your analyses and, subject to unexpected crises, suspect you've pretty well nailed it. Of course, expired (and expiring) hedges will serve to exacerbate decline as well.

Dennis Coyne , 06/15/2016 at 6:47 pm
Hi Doug,

The average Bakken well pays back drilling and completion costs in 60 months at about $75/b. The resources are there, if oil prices are high enough the oil will be recovered. the F50 technically recoverable resources are about 11 Gb based on USGS estimates and the F95 estimate is about 8 Gb.

I will go with the USGS and the likelihood that as oil output decreases oil prices will increase.

We will see who has the last laugh.

Ves , 06/15/2016 at 7:31 pm
"The average Bakken well pays back drilling and completion costs in 60 months at about $75/b."

That is impossible to happen in short term because business cycle (real economy) has to grow at least the same rate or higher then finance cycle of shale drillers (money that shale borrowed) and that went exponential in the last 8 years.

Petro , 06/16/2016 at 12:19 am
"Again: Time will tell."
~Verwimp

-We can say that about your chart, but for Dennis' there is nothing to tell!

The curbs on that chart cannot coexist together mathematically.
Whether one believes that projections for 2020, 2030 or 2040 and beyond shall materialize, or not is besides the point – we can argue that forever (as we have been).

-Dennis' chart cannot be, both logically and mathematically.

Unless one believes that they used the wrong narrow pipes from 2010 to 2015 and the large correct ones from 2020-2025 to get the oil out of the ground (I am joking, of course!), for that chart to make sense, either production curb 2020-2025 has to come down below the level of that 2014-2015, or the line representing wells during 2020-2025 has to be way above the level of that representing wells from 2012-2015…or both.

Or, here's a third " bright" scenario for you:
one has to believe that some very advanced (not known today) way of fracking will exist by 2020 in order to "squeeze" far more oil than we do today from a, by then – for all practical intents and purposes – totally exhausted oil field (i.e.: Bakken, circa 2025).

I am surprised some of you "well versed on charts guys" did not see that.

Be well,

Petro

Dennis Coyne , 06/16/2016 at 10:38 am
No Petro,

The output has decreased because fewer wells have been added each month, if the number of wells completed per month increases, output also increases.

Do you see a logical reason that the number of wells completed per month cannot increase if oil prices increase to a level which makes wells profitable?

Shallow sand has shown very clearly that $75/b is enough to make an average Bakken well profitable.

Also my scenario has 8 Gb from 24,000 wells, and average EUR per well of about 330 kb. The average well from 2008 to 2015 gas a well profile with a URR of about 350 kb.

The model is very straightforward, but could overestimate the well profile for recent wells.

We do not know what the wells will produce in the future,

I have estimated future well output on the performance of past wells, future well could be worse (or better than I have estimated). The scenario below assumes higher oil prices ($154/b) and fewer wells added per month (a maximum of 130 new wells per month), a more conservative well profile for 2015 and later is used (EUR=369 kb), ERR is 8.5 Gb with 33,000 total wells completed. That is fairly close to the USGS F95 estimate.

shallow sand , 06/16/2016 at 10:57 am
Dennis. $75 [is Ok to drill shale well] using cash. How many in the Bakken shale are using cash? Also, $75 assumes service companies continue to agree to low to no profit from services provided. Bakken wells were north of $10 million per in 2011-14. Again, CLR $11 million cash, $7.3 billion debt. WLL over $5 billion debt. HRC is bankrupt. From memory QEP, SM, HES, EOG, MRO, etc. All have billions of debt. PDP PV10 is less than long term debt at current prices.
Dennis Coyne , 06/17/2016 at 2:58 pm
Hi Shallow sand,

The wells will generate cash at $75/b, if they can be financed at less than the discount rate, net cash flow will be positive.

shallow sand , 06/17/2016 at 6:50 pm
Dennis.

One thing, it appears that only equity markets are open to shale drillers. That, of course, is the best approach IMO. Promoters usually make money if investors pay for the well, regardless of whether the well pays out. Issuing gobs of debt turned out to be a big mistake. Think how much $$ shale could have gotten 2011-14 by just issuing shares. Break even would certainly be less.

Ron Patterson , 06/16/2016 at 11:34 am
I have estimated future well output on the performance of past wells, future well could be worse (or better than I have estimated).

They could be better? Really? You think perhaps they drilled the worst spots first, saving the sweet spots for last? No, the sweet spots have already been drilled. Future wells will, almost certainly, produce less oil than those already drilled. Drillers just don't think that way Dennis. They would never save the sweet spots for last.

Dennis Coyne , 06/16/2016 at 1:33 pm
Hi Ron,

My projection of future output from recent wells has much steeper decline than older wells, so I could have overestimated or underestimated what the future output will be from a well that was drilled in 2015.

In 2005 to 2007 the EUR of the average well was much lower than 2008 to 2013, so it is possible that improved techniques might increase output, the first 12 months of output was higher in 2013 wells and 2014 wells than the earlier 2008 to 2012 average well. At some point this will reverse and my model has new well EUR decreasing after June 2018, this guess could be too early or too late.

So basically I am not assuming anyone is saving the sweet spots, just that my estimate could be low or high, we won't know until we have more data.

Ron Patterson , 06/16/2016 at 2:11 pm
Dennis, in the early days of Bakken fracking the wells had short laterals and fewer fracking stages. They got better with much longer laterals. They also got better at locating the sweet spots. But now the laterals and number of stages has maxed out. And the sweet spots are all drilled up.

There is no doubt whatsoever that the very best and most productive wells have already been drilled.

Dennis Coyne , 06/17/2016 at 8:10 am
Hi Ron,

I will wait for the data that confirms you are correct. So far the productivity of the average well for the first 12 months of output has been increasing, later months we can only guess at for the wells that were recently drilled (wells starting production after May 2015 we don't have data for production beyond month 12).

I thought we would see new well EUR decreasing by 2014, so far the data shows little evidence of that.

Ron Patterson , 06/17/2016 at 10:14 am
Dennis, this is just what Lynn Helms says was happening at a news conference back on May 4th.

Next Round Of ND Oil Production Figures 'going To Be Bad,' Helms Says

Low oil prices are forcing operators to focus drilling activity only in the core areas of the Bakken where wells have the greatest production. As oil prices recover and drilling expands to other areas of the Bakken, those high-producing wells will be declining, Helms said.

"It's really kind of doubtful that we're going to make that (2 million barrels per day) because we're drilling everything in the core where the best wells are," he said.

He said he thinks North Dakota production will eventually reach 1.8 million barrels per day. I wonder if he said that with a straight face, especially after just admitting that all the good spots will soon be gone.

Dennis Coyne , 06/17/2016 at 2:51 pm
Hi Ron,

I repeat, I do not expect the well profile will increase. When I said it may be better or worse than my estimate of the well profile, it simply means that we do not know what the well profile is, we have to estimate and sometimes the "best guess" is too high and other times it is too low, just like any other guess.

When you make an estimate is it always too high? My estimates may be different, about half the time they are too high, and the other half they are too low. :)

That is all that I meant.

Also, my "funny model" uses exactly the same well profile that I have been using since Enno suggested I should correct my model because it consistently was under predicting Bakken output.

Maybe new well EUR will start to decrease sooner than I have predicted (June 2018), but with only 980 new wells completed in the model over a 28 month period and that for the past 2 years the well profile has been increasing, I think the June 2018 guess is reasonable.

The eventual number of wells was 150 per month which is 21% less than the high 12 month rate of 186 wells per month, only 80 wells per month are needed for 1000 kb/d with the current well profile.

dclonghorn , 06/15/2016 at 6:47 pm
If i understand Verwimp's chart correctly, he started it when the price of oil was over 100. So Verwimp, did you know something the rest of us didn't or was this just a good educated guess.

At any rate your chart has nailed it to date. Congrats.

Verwimp , 06/16/2016 at 2:52 pm
You do understand correctly. The model was built before the price collapse. It's a Hubbert analysis basically. The dataset prior to the moment the model was built was a Hubbert poster child and it still is. When linearised according to Hubbert Linearisation, the data is still a straight line. There is no drop in that line. A sudden policy change coinciding with lower prices would have generated a drop in that line. That would also be visible in the change in daily oil shifting away from the first derivative of the model. Both are not occuring. So the only resulting conclusion is: ND Bakken is running out of oil, despite the high USGS EUR estimate.
I may stand corrected in the future. If prices rise and production rises again, I missed something. Until now (today's WTI prices are almost double the WTI price in Februari -- ) that is not the case, as you can see.
ktoś , 06/17/2016 at 7:42 am
So you're confirming that it was a guess. Thanks.
Nick G , 06/17/2016 at 10:36 am
Which only makes sense. A simple Hubbert analysis would never have predicted the surge in LTO production of the last 10 years.
Verwimp , 06/17/2016 at 4:24 pm
A Hubbert analysis only makes sense when a lot of data on the upgoing side of the curve already exists. 10 years ago there was virtually no LTO. So no Hubbert analysis could have been made.
Nick G , 06/17/2016 at 4:29 pm
To the contrary, people have been drilling for oil in N. Dakota, and the Bakken, for many decades. Production grew, peaked, and then declined.

Then…prices rose, and LTO became economic. And we're seeing a second peak.

Hubert Linearization would never, could never have caught that, because it wasn't designed to take price into account.

Prices matter. Ask any oilman.

Verwimp , 06/17/2016 at 4:21 pm
No, it wasn't a guess. It's just the nature of things that what goes up must come down. The Hubbert analysis provides a tool to calculate the altitude and the timing of the top, as well as the steepness of the decline. These calculations are more accurate when the top is closer by (or past). Apparently 29 months after the calculations were done, the reality is still in line with the modelled curve.

(I also added a seasonal correction to the Hubbert Curve, that as proven to be pretty accurate, but that is a minor feature of the curve compared to the underlying Hybbert Curve.)

The only guess was that ND Bakken would stay being the Hubbert poster child it was prior to the calculations. Apparently it still is. That guess was based on the fact Lower48 and Alaska production are also pretty Hubbert-like curves, just like earlier smaller booms in North Dakota. It's in the 'genes' of Americans, I presume, to go for it as soon as possible, as hard as possible and as fast as possible when it comes to earn money extracting a resource, until the show is over. A Hubbert curve is the result then…

Nick G , 06/17/2016 at 4:31 pm
Lower48…also pretty Hubbert-like curves, just like earlier smaller booms in North Dakota

The curve for the lower 48 isn't at all Hubbert-like, unless you arbitrarily subtract LTO.

[Jun 09, 2016] By 2020, most of the 2014 and prior vintage Bakken and TFS wells will be stripper wells making under 20 bopd.

Notable quotes:
"... I hope everyone understands that by 2020, most of the 2014 and prior vintage Bakken and TFS wells will be just like what Oasis sold, 21,000′ well bores making under 20 bopd. ..."
"... There are going to be about 40,000 stripper wells in the US that have a TD in excess of 15,000′ in about 5 years. If those are economic I think we will be very happy. ..."
"... I sure agree, hope this rally isn't a repeat of last year. ..."
"... WPX Energy Inc prices public offering of 49.5 mln shares for total gross proceeds (before estimated expenses) of about $485 mln ..."
"... You know that Permian, break even at $30, 30% IRR at $35. LOL! ..."
"... The Mighty MIGHTY MARKET and the ( near) Invincible Invisible Hand really can work economic miracles, sometimes, not every time, given time enough. ..."
"... The "Invisible Fist" generally just plummets our proletarian friends. ..."
peakoilbarrel.com

shallow sand , 06/08/2016 at 6:56 pm

Article in WSJ about shut in wells in the Bakken and various entities and individuals who are taking their first stab in the oil business by purchasing distressed Bakken production.

Hope they have their eyes wide open, so to speak.

Saw that Oasis sold all of its non Middle Bakken/TFS wells and acreage for $16.5 million to Samson. Not the KKR bankrupt Samson, but the Austrailian penny stock Samson.

780 BOEPD net and over 50K of acreage, but lots of shut in wells.

I hope everyone understands that by 2020, most of the 2014 and prior vintage Bakken and TFS wells will be just like what Oasis sold, 21,000′ well bores making under 20 bopd.

Think we'll stick to the ones that make 1/20th of the oil but are also 1/20th of the depth.

There are going to be about 40,000 stripper wells in the US that have a TD in excess of 15,000′ in about 5 years. If those are economic I think we will be very happy.

texas tea , 06/08/2016 at 7:18 pm
is that "we" meant to be the you oil barrons :-), I think the Nathaniel's and Fred's of the world might have a different perspective, but it may also be a learning experience. For the first time in a year the light at the end of the tunnel might not be the another freakin train.
shallow sand , 06/08/2016 at 11:06 pm
TT.

We means my family, as we own stuff together. We are hardly oil barons, more like mom, pop and the kids, etc.

I sure agree, hope this rally isn't a repeat of last year.

Greenbub , 06/08/2016 at 9:44 pm
shallow, did you see this?

http://www.reuters.com/article/idUSASC08SSX

BRIEF -- WPX Energy Inc prices public offering of 49.5 mln shares for total gross proceeds (before estimated expenses) of about $485 mln

The stock went up with the dilution (?) and they plan to use the money to drill wells:
"WPX says it plans to use the proceeds for general corporate purposes, which may include an acceleration of drilling and completion activities, bolt-on acreage acquisition, and midstream infrastructure in the Delaware Basin."

sorry for repost

shallow sand , 06/08/2016 at 11:02 pm
Greenbub. Yes. Saw that.

You know that Permian, break even at $30, 30% IRR at $35. LOL!

Oldfarmermac , 06/08/2016 at 9:35 pm
The Mighty MIGHTY MARKET and the ( near) Invincible Invisible Hand really can work economic miracles, sometimes, not every time, given time enough.

Here is an example of incremental change that can WORK, NOW. Plug in hybrid trucks aren't going to solve the oil depletion problem. Electric cars won't solve it either. But they will DELAY the day of reckoning- maybe long enough for us to change our ways sufficiently to avoid an economic catastrophe.

http://gas2.org/2016/06/08/wrightspeed-mack-trucks-team/

Twenty four miles on battery power alone is enough to cut substantially into diesel fuel consumption if a truck is running a short route. Ten years from now, fifty miles on battery power alone will probably be feasible.

hightrekker23 , 06/08/2016 at 10:27 pm
The "Invisible Fist" generally just plummets our proletarian friends.

[May 24, 2016] ExxonMobil and Chevron also had large North American losses

Notable quotes:
"... If one assumes that gas stays low priced, WTI will need to pass $55 sustained for 3 months for most US LTO producers to not show losses for GAAP purposes. This, of course, does not include hedges. ..."
peakoilbarrel.com
shallow sand , 05/24/2016 at 7:53 am
ExxonMobil and Chevron also had large North American losses.

Due to the high CAPEX spent 2011-14, and given depreciation, depletion and amortization methods selected by US producers, expect $20-$25 per BOE in D,D & A for US oil weighted LTO producers for at least the next 3 years. Then add in $8 or more of LOE, $3-5 G & A, and $4-$7 in interest, all in BOE terms. Also, some monetized gathering, so there could be expenses there. Also include severance taxes of 6-10% of $ per BOE sold.

If one assumes that gas stays low priced, WTI will need to pass $55 sustained for 3 months for most US LTO producers to not show losses for GAAP purposes. This, of course, does not include hedges.

[May 19, 2016] Decline curve of Bakken LTO wells

Notable quotes:
"... So at $35/b at the wellhead you get $31.85/b after taxes, then if we deduct OPEX we get $23.85/b, so net revenue would be 1.67 million the first year. Also remember the future revenue should be discounted at 10% per year. With no discount shallow sands wants the net revenue to pay for the well after 5 years. In this case the net revenue is $3.737 million after 5 years and the well is a failure (it loses money). Even after 14 years net revenue is only $5.25 million. I have ignored interest in this example and have assumed the well has been paid for out of cash flow. If the well head price were between 50 and 51 per barrel the well would be paid for after 5 years. ..."
"... I quickly checked the same analysis for the recent Bakken well profile, which has a higher 60 month EUR (266 kb vs 196 kb for the 2013 well). The well is paid for in 60 months at a wellhead price of $40/b using the same assumptions I used in the previous example. ..."
"... Of course, as you mention, none of the companies are able to pay for wells right now out of cash flow. All have interest expense, many have interest expense in excess of $5 per barrel. ..."
"... Also, another expense I have noticed with more frequency are gathering expenses. Many of the LTO companies sold their gathering and/or produced water disposal infrastructure in order to raise cash. They now are required to pay $X per barrel or mcf of gas in order to get their products to market. ..."
"... I would also note, 20% is a "base case" for Bakken royalties. The actual figures can range from 12.5% (1/8) to over 25% (1/4). If one is looking at the EFS or Permian, I suggest using a "base case" royalty of 25% (1/4). However, taxes in TX are less than ND. ..."
"... "We are slowly technologizing ourselves into extinction. Technology is seductive. Is it the power? Is it the comfort? Or is it some internal particularly human attribute that drives it? Technology surrounds us and becomes part of our story and myths. Technology tantalizes the human mind to make, combine, invent. There are always unintended consequences with technology. It affects how we experience the world in time and space. It affects how we feel about the world. If all the externalities were included in the prices and cost to nature, we would be very, very wary of technology. ..."
"... We will do more of the same, business as usual until there are no more holes in the ground to dig, no more water above and below to contaminate, no humans to wage slave, no other lifeforms to eliminate. Yes, we are building Trojan horses in our hearts, minds and spirits. It will be elitist and entitlement and hubris – it will end with both a bang and a whimper." ~ John Weber ..."
peakoilbarrel.com
Dennis Coyne , 05/16/2016 at 1:27 pm
Hi Islandboy,

The wells never stop declining so for your final three years each year should be 93% of the previous year, this doesn't really happen for about 10 to 15 years. Below are annual decline rates for an average new Bakken well in 2013. The first year's average output is 2.9 kb/d and the decline rates are year 1 to 2, 2 to 3, …, 9 to 10.

51.91%
32.53%
26.51%
20.41%
17.02%
14.59%
12.78%
11.36%

Output in barrels per year
87696
42170
28453
20911
16643
13811
11796
10289
9120
8187
7425
6792
6252
5763

Hope that helps. The decline rate eventually levels out at about 7% per year by year 15 and remains at that rate until the well is shut in about 12 years later (with the well producing about 6 b/d).

islandboy , 05/16/2016 at 3:24 pm
Thanks Dennis, I worked those decline rates into my spreadsheet but the essential message is the same, relative to PV shale oil will generate more than 15 times the gross revenue in year 1 and still be generating more than twice the gross revenue in year 7! Your figure of 2.9 kb/d for the average first year production seems way out of line with the numbers that shallow sand used in the analysis I referred to or anything that can be interpreted from Enno's graph below. I was really hoping that shallow or Ciaran would have commented on my estimate but, I guess my work is way too amateurish for them! :-)

Edit: Dennis, after I posted this, I noticed your additional responses below. I will try to add these additional factors into my spreadsheet as I am interested in how these enterprises gobble up millions of dollars!

I also noticed where you mention 266 kb as EUR and wonder how a well that produces 2.9 kb/d can end up with an EUR of 266 kb after 60 months?

Dennis Coyne , 05/16/2016 at 3:52 pm
Hi Islandboy,

My mistake 2.9 is a factor of 12 too high, I multiplied by 12 where I shouldn't have, but the numbers for barrels per year are correct. It should have been 240 barrels per day for the average first year output.

Also if you look at the numbers for output per year that I posted (which can be copied and pasted into a spreadsheet) it is clear that 87,696/365 is not equal to 2900 b/d, it is 240.2 b/d. Sorry for the mistake.

Dennis Coyne , 05/16/2016 at 2:00 pm
Hi Island boy,

The royalties are 20% of output, taxes are another 9% or so. So if you had 100,000 barrels of output, you keep 80,000 barrels and then figure you only get net revenue of 91% of the wellhead price and then you have to subtract opex, G+A, etc.

So at $35/b at the wellhead you get $31.85/b after taxes, then if we deduct OPEX we get $23.85/b, so net revenue would be 1.67 million the first year. Also remember the future revenue should be discounted at 10% per year. With no discount shallow sands wants the net revenue to pay for the well after 5 years. In this case the net revenue is $3.737 million after 5 years and the well is a failure (it loses money). Even after 14 years net revenue is only $5.25 million. I have ignored interest in this example and have assumed the well has been paid for out of cash flow. If the well head price were between 50 and 51 per barrel the well would be paid for after 5 years.

Shallow sand can correct my mistakes. Note that I have used my numbers for yearly well output, based on data from Enno Peters. The well used is the average 2013 Bakken well.

Dennis Coyne , 05/16/2016 at 3:17 pm
I quickly checked the same analysis for the recent Bakken well profile, which has a higher 60 month EUR (266 kb vs 196 kb for the 2013 well). The well is paid for in 60 months at a wellhead price of $40/b using the same assumptions I used in the previous example.
shallow sand , 05/16/2016 at 3:18 pm
Dennis. Looks good to me.

Of course, as you mention, none of the companies are able to pay for wells right now out of cash flow. All have interest expense, many have interest expense in excess of $5 per barrel. Then, the question is when will any of these companies begin to use cash flow to reduce debt principal. Some have reduced debt, by buying back their own debt at distressed levels, and/or exchanging the debt with creditors for reduced principal new debt, but at much higher interest rates and more stringent terms (liens upon company assets as opposed to unsecured bonds).

Also, another expense I have noticed with more frequency are gathering expenses. Many of the LTO companies sold their gathering and/or produced water disposal infrastructure in order to raise cash. They now are required to pay $X per barrel or mcf of gas in order to get their products to market.

I would also note, 20% is a "base case" for Bakken royalties. The actual figures can range from 12.5% (1/8) to over 25% (1/4). If one is looking at the EFS or Permian, I suggest using a "base case" royalty of 25% (1/4). However, taxes in TX are less than ND.

Dennis Coyne , 05/16/2016 at 3:45 pm
Hi Shallow sands,

I was trying to keep it simple. For someone like you who probably does not borrow, there would be very little interest expense. This may also be true for XTO and Statoil. So basically someone who uses a 60 month payout rule, probably is not in debt so interest payments are not a factor. I also was trying to get it done in 5 minutes so skipped some steps.

Dennis Coyne , 05/16/2016 at 3:41 pm
Hi Islandboy,

I get 137 million miles of driving, if we ignore the energy used for refining and distribution of the oil produced for the 2013 average Bakken well, for the more recent wells it is 185 million miles over 7 years. For the late 2015 to early 2016 Bakken average well we get 248 million miles of driving over a 25 year well life (ignoring refining and distribution energy). So over the long term we get more driving miles out of the PV. Note that the average Bakken well really costs more like 8 million rather than 5.9 million so the apples to apples comparison over 25 years would be 378 million miles from PV and 248 million miles from the LTO well. So 50% more miles of driving per dollar spent on energy to fuel the ICEV or EV.

GoneFishing , 05/17/2016 at 9:23 am
2.8 acres of PV produces 1 GWh annually of output (fixed array). PV farm cost is about $500,000 per acre. Typical well cost is $15 million (initial plus continuous costs) and lasts for about 15 years, with low output the last 10.
So $15 million of PV would be thirty acres at 10.7 GWh output. By year 15 the output might be at 90% so average is 95% over 15 years giving 152 GWh total ouput for 15 years. Since the PV is local I won't use transmission losses. At 0.3 kWh per mile that is 506 million miles. The PV farm will produce almost double that over it's full lifetime. No pollution produced, no pipelines, no refineries, no spills, no smog, no noise, no global warming, etc. No Red Queen effect. No depletion problem. PV panels are getting better and cheaper, oil is not.

URR of well being about 300,000 barrels would give 265 million miles at 30 mpg (70 percent fuel recovery). When one starts to take into account the energy losses in drilling, transport, refining, more transport, etc. That would drop significantly.

No brainer for transportation.

Consider also that hydropower uses over 25 times the area to produce the same amount of power and also messes up the environment. PV looks a lot better all around.

Fernando Leanme , 05/18/2016 at 8:23 am
Photovoltaic panels have a significant opex. This is associated with parts replacement, as well as panel washing (they are worse than cars left in the open). When you compare apples to lemons make sure you include everything.
scrub puller , 05/18/2016 at 2:47 pm
Yair . . .
This "panel washing" may be a factor on commercial installations but I occasionally see it mentioned in relation to domestic as a difficult problem on hard to access roofs . . . well we have been running panels for over twenty five years and they get washed when it rains.

Cheers.

Caelan MacIntyre , 05/18/2016 at 3:47 pm

"We are slowly technologizing ourselves into extinction. Technology is seductive. Is it the power? Is it the comfort? Or is it some internal particularly human attribute that drives it? Technology surrounds us and becomes part of our story and myths. Technology tantalizes the human mind to make, combine, invent. There are always unintended consequences with technology. It affects how we experience the world in time and space. It affects how we feel about the world. If all the externalities were included in the prices and cost to nature, we would be very, very wary of technology.

I think we have moved from technology in the service of religion (pyramids and gothic cathedrals) to religion and culture in the service of technology. It isn't a deity that will save humanity but in the eyes of many – it will be technology.

We will do more of the same, business as usual until there are no more holes in the ground to dig, no more water above and below to contaminate, no humans to wage slave, no other lifeforms to eliminate. Yes, we are building Trojan horses in our hearts, minds and spirits. It will be elitist and entitlement and hubris – it will end with both a bang and a whimper." ~ John Weber

[May 18, 2016] In the longer term geology plays a far more important role on single well life of field economics than completion technology.

Notable quotes:
"... 0-12 month production is a combination of reservoir and fracture dominated flow. Increases in mean rates are mainly related to advances in completion technology (longer horizontals, > number of stages, reduced spacing between stages, improved proppant technology). ..."
"... After 12 months, liquid production is reservoir dominated. Decline curves converge to +/- 5 bopd. Geology is the main controlling factor. From 2008 to 2015, the following increases have been observed; ..."
"... Completion technology gets you more gas (and oil) in the short term. In the longer term geology plays a far more important role on single well life of field economics than completion technology. ..."
peakoilbarrel.com
Ciaran Nolan , 05/13/2016 at 8:05 am
Completion technology gets you more gas (and oil) in the short term. In the longer term geology plays a far more important role on single well life of field economics than completion technology.

Conclusion: Completion technology gets you more gas (and oil) in the short term. In the longer term geology plays a far more important role on single well life of field economics than completion technology.

Enno Peters , 05/14/2016 at 3:30 am
Great comment Ciaran, thanks.

[May 18, 2016] Increasing gor in an oil reservoir is not good

Notable quotes:
"... Increasing gor in an oil reservoir is not good. But I thought you were inferring that Texas was in worse shape. My point was you can't make that assumption. My only point ..."
"... I thought maybe the units should be thousands of cubic feet of natural gas per barrel of oil because both Texas and North Dakota are over 1200 cf/bo GOR. ..."
peakoilbarrel.com
Dennis Coyne , 05/14/2016 at 5:57 pm
Hi Reno,

My point is simply that currently North Dakota is at about 1500 cubic feet natural gas per barrel of oil produced.
Fernando says this is a problem, I think.

Reno Hightower , 05/14/2016 at 6:07 pm
Not sure if it is or isn't. Increasing gor in an oil reservoir is not good. But I thought you were inferring that Texas was in worse shape. My point was you can't make that assumption. My only point
Dennis Coyne , 05/15/2016 at 7:49 am
I thought maybe the units should be thousands of cubic feet of natural gas per barrel of oil because both Texas and North Dakota are over 1200 cf/bo GOR.

[May 18, 2016] Governor candidates call for audit of North Dakota Oil and Gas Division WDAY

Notable quotes:
"... Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil. ..."
"... Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells. ..."
"... He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged. ..."
www.wday.com
Two gubernatorial candidates from opposing parties called Thursday for an audit of North Dakota's Oil and Gas Division, raising concerns that production numbers are not being verified and citing a tip that employees were ordered to destroy public records – a claim the agency's spokeswoman called "completely baseless." Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

"This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

"Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

Division spokeswoman Alison Ritter said the allegation of destroying records was untrue. "That's completely baseless," she said. "I think it's just absurd, actually." Ritter added that the office had a staff meeting Wednesday which involved making sure staff were reading the code of ethics policy, which includes a page related to records and making records available.

Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of the state's open records laws, about the report of records being destroyed. Stenehjem, who is the Republican Party's endorsed candidate for governor and also serves on the three-member Industrial Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.

Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman Doug Burgum also is seeking the GOP nomination in the June 14 primary.

Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells.

A bill co-sponsored by Nelson last year would have required a performance audit of state agencies that regulate oil and gas development, but House lawmakers rejected it 67-22.

Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to request performance audits, but he couldn't recall if there had been a formal request for a division audit.

He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged.

"There's really a public responsibility to get it right," he said.

Ritter noted the state auditor's office recently completed a routine audit of the agency for the 2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal fin

Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

"This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

"Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

Division spokeswoman Alison Ritter said the allegation of destroying records was untrue.

"That's completely baseless," she said. "I think it's just absurd, actually."

Ritter added that the office had a staff meeting Wednesday which involved making sure staff were reading the code of ethics policy, which includes a page related to records and making records available.

Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of the state's open records laws, about the report of records being destroyed. Stenehjem, who is the Republican Party's endorsed candidate for governor and also serves on the three-member Industrial Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.

Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman Doug Burgum also is seeking the GOP nomination in the June 14 primary.

Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells.

A bill co-sponsored by Nelson last year would have required a performance audit of state agencies that regulate oil and gas development, but House lawmakers rejected it 67-22.

Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to request performance audits, but he couldn't recall if there had been a formal request for a division audit.

He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged.

"There's really a public responsibility to get it right," he said.

Ritter noted the state auditor's office recently completed a routine audit of the agency for the 2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal fin

Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

"This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

"Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

[May 16, 2016] Governor candidates call for audit of North Dakota Oil and Gas Division WDAY

www.wday.com

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  • Two gubernatorial candidates from opposing parties called Thursday for an audit of North Dakota's Oil and Gas Division, raising concerns that production numbers are not being verified and citing a tip that employees were ordered to destroy public records – a claim the agency's spokeswoman called "completely baseless." Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

    "This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

    Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

    Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

    "Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

    Division spokeswoman Alison Ritter said the allegation of destroying records was untrue.

    "That's completely baseless," she said. "I think it's just absurd, actually."

    Ritter added that the office had a staff meeting Wednesday which involved making sure staff were reading the code of ethics policy, which includes a page related to records and making records available.

    Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of the state's open records laws, about the report of records being destroyed. Stenehjem, who is the Republican Party's endorsed candidate for governor and also serves on the three-member Industrial Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.

    Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman Doug Burgum also is seeking the GOP nomination in the June 14 primary.

    Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells.

    A bill co-sponsored by Nelson last year would have required a performance audit of state agencies that regulate oil and gas development, but House lawmakers rejected it 67-22.

    Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to request performance audits, but he couldn't recall if there had been a formal request for a division audit.

    He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged.

    "There's really a public responsibility to get it right," he said.

    Ritter noted the state auditor's office recently completed a routine audit of the agency for the 2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal fin

    Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

    "This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

    Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

    Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

    "Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

    Division spokeswoman Alison Ritter said the allegation of destroying records was untrue.

    "That's completely baseless," she said. "I think it's just absurd, actually."

    Ritter added that the office had a staff meeting Wednesday which involved making sure staff were reading the code of ethics policy, which includes a page related to records and making records available.

    Sorum and Nelson said they did not contact Attorney General Wayne Stenehjem, chief enforcer of the state's open records laws, about the report of records being destroyed. Stenehjem, who is the Republican Party's endorsed candidate for governor and also serves on the three-member Industrial Commission that oversees the Oil and Gas Division, "is part of the problem," Sorum said.

    Stenehjem was on the campaign trail and could not immediately be reached for comment. Fargo businessman Doug Burgum also is seeking the GOP nomination in the June 14 primary.

    Sorum said a recent audit of the state Department of Trust Lands that identified errors in how oil and gas royalty payments were made underscores the need for an independent audit of the Oil and Gas Division, which oversees about 13,000 active oil and gas wells.

    A bill co-sponsored by Nelson last year would have required a performance audit of state agencies that regulate oil and gas development, but House lawmakers rejected it 67-22.

    Nelson serves on the Legislative Audit and Fiscal Review Committee, which has the authority to request performance audits, but he couldn't recall if there had been a formal request for a division audit.

    He said mineral owners who receive oil and gas royalty payments often receive revised settlement sheets notifying them that a mistake was made, which indicates production numbers aren't being adequately tracked and shows the need for an audit so mineral owners don't get shortchanged.

    "There's really a public responsibility to get it right," he said.

    Ritter noted the state auditor's office recently completed a routine audit of the agency for the 2013-15 biennium and there were no formal findings for the Oil and Gas Division and a few formal fin

    Republican candidate Paul Sorum of Bismarck and Democratic hopeful Marvin Nelson, a state representative from Rolla, held a joint press conference in Bismarck to call for a performance audit of the division within the Department of Mineral Resources.

    "This is not a partisan issue, which is why Marvin and I and many other people are on the same page. We just want the law to be followed," Sorum said.

    Both candidates said they had planned to hold the press conference next Monday but moved it up after they were contacted by an attorney for a division employee who claimed Mineral Resources Director Lynn Helms ordered the destruction of emails and records related to the transportation and sale of oil.

    Sorum and Nelson said they had no proof that records were destroyed. The attorney asked not to be named publicly because it would identify the employee, they said, agreeing that the state's whistleblower laws provide inadequate protection.

    "Even without those rumors, there's still significant reasons why we should be do that (audit), and it should be urgent that we do that," Sorum, an oilfield consultant, said in an interview.

  • [May 15, 2016] While oil production in the Bakken has been in decline for more than a year, natural gas production continues to increase

    Notable quotes:
    "... While oil production in the Bakken has been in decline for more than a year, natural gas production continues to increase. As there is no big natural gas fields in North Dakota and most of the gas is associated, this trend can be entirely attributed to the rising GOR. ..."
    "... Since the beginning of the shale boom in the Bakken North Dakota the natural gas to oil production ratio has increased almost 3 times ..."
    peakoilbarrel.com
    AlexS , 05/13/2016 at 6:22 pm
    While oil production in the Bakken has been in decline for more than a year, natural gas production continues to increase. As there is no big natural gas fields in North Dakota and most of the gas is associated, this trend can be entirely attributed to the rising GOR.

    Oil and natural gas production in the Bakken
    source: NDIC

    AlexS , 05/13/2016 at 6:26 pm
    Since the beginning of the shale boom in the Bakken North Dakota the natural gas to oil production ratio has increased almost 3 times

    Natural gas to oil production ratio in the Bakken (kcf/barrel)

    [May 14, 2016] an OGL that is past its primary term must produce oil and/or gas in paying quantities with no cessation of more than xx days

    Notable quotes:
    "... Generally speaking (in Texas anyway) a lease must generate cash flow in excess of its monthly cost of production. $1 over that monthly cost is sufficient. Naturally, each operator's cost are different and each lease/well is different. ..."
    peakoilbarrel.com
    John S , 05/13/2016 at 8:45 am
    Hi R Walter,

    Generally speaking, an OGL that is past its primary term must produce oil and/or gas in "paying quantities" with no cessation of more than xx days (depends on lease language) to continue to be held in effect. There are many ways an operator can handle this situation by producing just a few days a month. An operator can pay a "shut-in gas" royalty to defer a production obligation in certain circumstances. Each situation is different and requires its own analysis.

    An operator is not required to show that a well or leasewell is capable of "paying out" it's cost of the lease, drilling and completion, gathering, treating facilities and so forth.
    The important issue is that a well or lease must be capable of producing oil or gas in "paying quantities".

    Generally speaking (in Texas anyway) a lease must generate cash flow in excess of its monthly cost of production. $1 over that monthly cost is sufficient. Naturally, each operator's cost are different and each lease/well is different.

    In my opinion, many wells are "magically" producing just enough oil and gas to generate a marginally positive cash flow. Why you ask? To avoid plugging and abandonment until a greater fool comes along to buy the lease and allow the current operator to get off the hook.

    I know of one case where SandRidge Energy (Arena Acquisition) drilled 52 vertical wells in one 640 acre section. Each well is capable of producing 1-2 bbls/day. Payout will never happen and I doubt that production in paying quantities is happening. I also doubt that a greater fool exists to take over this lease

    But…… someday someone (perhaps you) will be on the hook to plug and abandon and restore the surface to its original condition.

    Matt Mushalik , 05/13/2016 at 5:37 am
    HAYNES AND BOONE, LLP OIL PATCH BANKRUPTCY MONITOR May 1, 2016
    http://www.haynesboone.com/~/media/files/attorney%20publications/2016/energy_bankruptcy_monitor/oil_patch_bankruptcy_20160106.ashx
    John , 05/13/2016 at 6:06 am
    Hi Ron,

    In your opinion will the Saudi's and Russians be able to significantly ramp further production capacity as they threaten?

    AlexS , 05/13/2016 at 7:14 am
    I'm not Ron, but this is my view:

    Russia is not planning to significantly ramp production capacity.
    Energy Minister Novak said today that the country will be able to maintain long-term production levels within the range 525-545 million tons per year (10.5-10.9 mb/d). That's what Russian officials were saying earlier.

    According to the Saudi officials, planned expansion of the Khurais and Shaybah oil fields will only
    compensate for falling output at other fields. They claim that the country's "maximum sustainable output capacity is 12 million barrels per day and the nation's total capacity is 12.5 million bpd", but there are no plans to increase capacity and there is no evidence that this capacity really exists.

    I think that in reality Saudi Arabia is able to increase crude production from the current 10.2 mb/d to 10.5-10.6 mb/d during the peak season for local demand in the Summer, but not well above those levels.

    [May 13, 2016] The decline after peak of new wells appears to be significantly steeper than previous years

    Notable quotes:
    "... We just did some work on the EIA/IHS report on well costs that came out a little while ago. We suspect that these longer peaking wells may be possible due to lower service costs. Operators have switched to natural sand, and lots of it. Not being an engineer, this is only an educated guess, but the general gist I can gather is that natural sand crushes more easily than artificial ceramic proppant, but is significantly cheaper. ..."
    "... Our assumption on the interests of operators like CLR and WLL is that they currently want to maximise short-term production to boost revenue, and they care significantly less about maximising recovery. Using lots of natural sand fits in with that – though the sand will be crushed more quickly than if artificial proppant will be used, more fractures will be propped open in the short term. ..."
    "... Many of these short term production gains may be given up shortly after any price increase, as the service costs will also rise, and the short term revenue considerations will become less important. That's the theory we're working under currently, anyway… ..."
    peakoilbarrel.com
    gwalke , 05/13/2016 at 5:47 am
    Great comment, Enno, as ever. It's important to remember that the EIA's forecasts seem to generally be very "smooth", and their models are mostly done at an economic level, meaning they aren't working from number of wells upwards. This meant they completely missed the beginning of the production decline – their initial forecasts kept on adding ~30kbpd a month to Bakken until April15, for example. Now they are a little to heavy to the downside.

    We just did some work on the EIA/IHS report on well costs that came out a little while ago. We suspect that these longer peaking wells may be possible due to lower service costs. Operators have switched to natural sand, and lots of it. Not being an engineer, this is only an educated guess, but the general gist I can gather is that natural sand crushes more easily than artificial ceramic proppant, but is significantly cheaper.

    Our assumption on the interests of operators like CLR and WLL is that they currently want to maximise short-term production to boost revenue, and they care significantly less about maximising recovery. Using lots of natural sand fits in with that – though the sand will be crushed more quickly than if artificial proppant will be used, more fractures will be propped open in the short term.

    Many of these short term production gains may be given up shortly after any price increase, as the service costs will also rise, and the short term revenue considerations will become less important. That's the theory we're working under currently, anyway…

    The decline after peak of new wells appears to be significantly steeper than previous years, so when companies claim 40% IP increase = 40% EUR increase, one should be extremely skeptical. By month 7 of production, the average 2014 well had produced 18% more oil than the average 2010 well at the same stage of its life – but by month 26, that difference was down to 7.6%. In month 3, the average 2014 well had produced nearly 9% more than the average 2013 well – by month 26, that was down to 2%. Those are total cumulative oil produced figures, btw.

    [May 13, 2016] Next round of ND oil production figures going to be bad

    Notable quotes:
    "... Total oil production in North Dakota Bakken fell to 1057 kb/d in March, a monthly drop of 8 kb/d. Decline in February-March was only 10 kb/d. Cumulative decline from December 2014 peak level is 107 kb/d (-9%). ..."
    "... as Shallow Sand pointed out: "It surprised me that production in ND didn't fall much when Mr. Helms stated there would be a dramatic drop." ..."
    peakoilbarrel.com
    AlexS , 05/13/2016 at 4:52 am
    repost from the previous thread:

    Total oil production in North Dakota Bakken fell to 1057 kb/d in March, a monthly drop of 8 kb/d. Decline in February-March was only 10 kb/d. Cumulative decline from December 2014 peak level is 107 kb/d (-9%).

    The chart below shows that both the EIA Drilling Productivity Report and the EIA/DrillingInfo monthly LTO production statistics tend to underestimate the resilience of tight oil production, at least in the case of the Bakken. The EIA estimates for February and March will likely be revised upward. I think that even bigger upward revisions will be done for the Eagle Ford.

    Bakken oil production statistics: NDIC data vs. the EIA reports (kb/d)

    AlexS , 05/13/2016 at 5:27 am
    as Shallow Sand pointed out: "It surprised me that production in ND didn't fall much when Mr. Helms stated there would be a dramatic drop."

    From an article in Bismarck Tribune:

    "Next round of N.D. oil production figures 'going to be bad,' Helms says

    May 4, 2016
    http://bismarcktribune.com/news/state-and-regional/next-round-of-n-d-oil-production-figures-going-to/article_5633c44e-09a9-5d3c-a47c-664f43dfd9cb.html

    Early March oil production numbers show that North Dakota will likely drop below 1.1 million barrels per day for the first time since June 2014, the state's top oil regulator said. An official update will be released next week, but Director of Mineral Resources Lynn Helms told an oil industry group in Williston he expects to see a "severe" production drop. "It's going to be bad," Helms told the Williston Basin chapter of the American Petroleum Institute Tuesday night."

    In fact, the decline was not as big as was expected and total ND oil production (incl. conventional) in March was 1109 kb/d.

    The chart below does not show any acceleration in monthly decline rates:

    Year-on-year and month-on-month growth/decline rates in Bakken North Dakota oil production (%)

    [Apr 13, 2016] Most E P Efficiency Gains Tied to OFS Pricing Concessions, Not Better Drilling

    peakoilbarrel.com
    Most E&P Efficiency Gains Tied to OFS Pricing Concessions, Not Better Drilling, Says Schlumberger CEO

    Carolyn Davis March 21, 2016

    http://www.naturalgasintel.com/articles/105768-most-ep-efficiency-gains-tied-to-ofs-pricing-concessions-not-better-drilling-says-schlumberger-ceo

    Another myth is the drilling efficiencies being touted by E&Ps. Yes, drilling has gotten better, but most of the price gains touted by E&P management are related to pricing concessions extracted from the OFS sector. OFS operators simply are fighting for survival and are doing what it takes to keep customers - cutting prices as much as they can and even taking losses. Once activity begins to pick up, OFS pricing mostly will reverse, he said.

    "The fact remains that the industry's technical and financial performance was already challenged with oil prices at $100/bbl, as seen by the fading cash flow and profitability of both the IOCs and independents in recent years," Kibsgaard said.

    "Over the past decade, our industry has simply not progressed sufficiently in terms of total system performance to enable cost-effective development of increasingly complex hydrocarbon resources. This can be seen by the escalating industry cost per barrel."

    The U.S. land rig count peaked in October 2014, and the "rate of disruption" across the energy sector has led to a "full-scale cash crisis."

    "The latest data points have, in recent weeks, sent the oil price up toward $40/bbl, and we would expect the upward trend to continue as the physical balances tighten further in the coming quarters," said Kibsgaard.

    "In spite of this, we maintain our view that there will be a noticeable lag between higher oil prices and higher E&P investments given the fragile financial state of our customer base, which means that there will be no meaningful improvement in our activity until 2017" .

    [Apr 12, 2016] Geology issues might constitute a significant part of the LTO production decline. LTO producers might be are running out of sweet spots.

    peakoilbarrel.com

    Ron Patterson, 04/11/2016 at 7:39 pm

    The EIA's latest Drilling Productivity Report has US shale oil production down by 114,000 barrels per day in May. On an annualized basis that is 1,368,000 barrels per day. That is huge.

    Notice that the rate of decline is now increasing every month. It took a while, until December 2015, for the decline to really get started in earnest. But now it is clearly underway. It appears that the decline will now clearly be far greater than a lot of people estimated. Well, that is if the EIA has any idea of what they are talking about.

     photo Total Shale_zpsse1xwfg7.jpg

    likbez , 04/11/2016 at 8:35 pm
    Hi Ron,

    Notice that the rate of decline is now increasing every month.

    Looks like an important trend.

    Silicon Valley Observer , 04/11/2016 at 10:56 pm
    That is truly striking. Can't wait to see how this plays out.
    Tom , 04/12/2016 at 2:06 am
    I more and more suspect that geology is a significant part of the LTO production decline. The production curves for each major shale and total of all US LTO play (ref. Enno Peter's http://shaleprofile.com/ ) are starting to look like bell curves. Also, top producer EOG seemed to stop its growth in June 2014 and that's before the oil price decline. Rune Likvern in his recent post @ fractionalflow mentions that some sweet spots in Bakken are becoming satured with wells. In fact it looks like Bakken stopped the production increase between July – Nov 2015 which in my eyes is a bit too early to blame it solely on the oil price.

    Maybe Verwimp and Paztec are right? Now it is probably a combination of oil price and geology, but to me it seems that geology is a significant part of it.

    [Apr 06, 2016] Is US Shale Oil Gas Production Peaking

    Notable quotes:
    "... Your point on the Marcellus displacing production from the other less productive basins is fair enough. That said I don't really see how anyone is making money in the Marcellus. ..."
    "... I am reminded of what Rex Tillerson said about gas producers a number of years ago, "Everyone is losing their shirts. It's all in the red." ..."
    "... As a conventional oil and natural gas producer who is suffering financially at the moment because of overleveraged shale oversupply, Mr. Coffee might rightfully suggest that I am bias against the shale industry. Truthfully, I want the shale industry to succeed but it must do so by standing on it's own feet, without borrowing money from outside sources it cannot pay back. It must develop it's remaining reserves from net cash flow, in a manner that is commensurate with worldwide supply/ demand fundamentals, at a reasonable, rational pace that will ensure price stability, not price volatility. It must find a way to do that AND pay back it's indebtedness. ..."
    "... America has 2.8 million BOPD of conventional oil production that is getting hammered right now largely because of an LTO industry who has had, for the most part, no finding costs the past nine years. There are thousands of shale gas wells in the App Basin that were drilled with borrowed money that have been shut in for years with no takeaway capacity. I can find no success story in that kind of stupidity. ..."
    "... Another summary on the investing disaster in shale here, it all comes down greed, corruption and stupidity in the end: ..."
    "... My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated for political and propaganda reasons is unchanged and now supported by sufficient data. ..."
    "... And for economic reasons too. The principal question here is "Whether deferred adjustment to higher oil prices is beneficial to the USA economy in a long run?". They were definitely beneficial to "team Obama", but this might well be "after us deluge" type of thinking. ..."
    peakoilbarrel.com

    aws. , 04/05/2016 at 4:25 pm

    Is U.S. Shale Oil & Gas Production Peaking? Part I: Gas Production

    Tad Patzek makes a wise point in a reply to Coffeeguyzz in his post above.

    My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated for political and propaganda reasons is unchanged and now supported by sufficient data. While the overall resource is giant, the recovered fraction will remain small because of the generally poor quality of this resource. For the record, let me restate the obvious: Some operators in the small sweet spots in all plays will make a lot of money; most others will lose money and go bankrupt. In the old fashioned reservoir engineering practiced by people of my age, these sweet spots are called reservoirs.

    coffeeguyzz , 04/05/2016 at 6:23 pm
    Aws

    I think the most 'agreeable' point Mr. Patzek and I may hold is the inclination to embrace, promote and disseminate data that reinforces our already held positions.

    If you read Mr. Patzek's piece, and the comments I made in reply on his blog site, you would see how I questioned virtually everything he presented as being , at best, skewed.

    Now, anyone following would be strongly inclined to favor a professional, published-numerous-times and highly regarded in his field such as Mr. Patzek, over some anonymous commenter.

    That's natural.

    But how in the heck could Mr. Patzek virtually dismiss the Marcellus' output, ignore the Utica, mischaracterize the current Pennsylvania reporting parameters and MOST importantly, NOT recognize that the decline in output from the other formations is a direct consequence of being displaced by the much bigger, more economic Appalachian Basin?

    I claim no special insight. I acknowledge my partiality to fossil fuel use/consumption now and for the foreseeable future. I would suggest that those who feel/think otherwise are not so immune from cognitive bias as they would wish to be.

    Aws. , 04/05/2016 at 7:30 pm
    Hi Coffeeguyzz,

    What prompted me to post was how Patzek characterized sweet spots. From what I understood in Patzek's post was that he felt there really wasn't enough data to honestly assess the Marcellus. Which is why he gave it an optimistic fudge factor. Your point on the Marcellus displacing production from the other less productive basins is fair enough. That said I don't really see how anyone is making money in the Marcellus.

    I am reminded of what Rex Tillerson said about gas producers a number of years ago, "Everyone is losing their shirts. It's all in the red."

    Btw, you may have a pseudonym, but I don't consider you anonymous. You are familiar enough to no longer appear anonymous. :-)

    Mike , 04/05/2016 at 8:06 pm
    Coffee, it took nuts to stir up Tad Patsek's oatmeal on some stinking shale gas play; I'll give you that. He is a renown reservoir engineer having taught at one of the best, if not THE best petroleum engineering schools in the entire world. He is a "distinguished" member of the Society of Petroleum Engineers. The SPE does not hand those out to anyone. I have set in on his lectures, and his talks; he is a good man and I can assure you he has only the need for truth in his heart about the future of hydrocarbons.

    You, on the other hand, are anonymous and won't say why exactly you are such a adamant cheerleader for the shale industry. You "claim no special insight" in shale matters yet you are willing to go toe to toe with a reservoir engineer who taught tens of thousands of petroleum engineers to deal with facts, the science of the rock and how to extract the hydrocarbons from that rock…profitably. Forgive me, but you appear to simply be using stuff you glean from the internet, most of which is put there by shale companies themselves.

    You cannot credibly root for an industry based on MCF's, or monster IP's, and not dollars, sir. It has to make money. For instance, 16.5 BCF wells in 3 years are war horses, for sure; at 5 dollar gas. At 70 cent gas those cherry picked wells of yours still have not paid out and might themselves, in yet another 3-4 years, but won't ever help pay back the sorry wells the same company drilled nearby. Tight shale gas formations in the App basin are displacing other gas production in the US by natural decline, not because they are more economic. That statement put the b in bias.

    likbez , 04/05/2016 at 9:54 pm
    For instance, 16.5 BCF wells in 3 years are war horses, for sure; at 5 dollar gas. At 70 cent gas those cherry picked wells of yours still have not paid out and might [pay] themselves in yet another 3-4 years, but won't ever help [to] pay back the sorry wells the same company drilled nearby

    The issue of "ultimate profitability" brings us back to the "cheap, abundant money supply" theme. Or more correctly the Feb induced regime of "cheap credit for shale" that existed for the last 7 years. When anybody with a rig could get loans or sell bonds because banks were flush with the Fed money and wanted to put them to work somewhere, even if this "somewhere" was extremely risky (somewhat similar to subprime mortgages). Add to this the political pressure from Obama administration (energy independence theme) and we get a unique environment for shale producers that existed probably until the second half of 2015. This regime of abundant credit lines and junk bond issuance for now is over.

    With enough money you can make pigs fly, but you better do not stand at the place where they are going to land.

    This is the issue that Coffeeguyzz and Co fail to understand.

    Mike , 04/06/2016 at 6:05 am
    As a conventional oil and natural gas producer who is suffering financially at the moment because of overleveraged shale oversupply, Mr. Coffee might rightfully suggest that I am bias against the shale industry. Truthfully, I want the shale industry to succeed but it must do so by standing on it's own feet, without borrowing money from outside sources it cannot pay back. It must develop it's remaining reserves from net cash flow, in a manner that is commensurate with worldwide supply/ demand fundamentals, at a reasonable, rational pace that will ensure price stability, not price volatility. It must find a way to do that AND pay back it's indebtedness.

    America has 2.8 million BOPD of conventional oil production that is getting hammered right now largely because of an LTO industry who has had, for the most part, no finding costs the past nine years. There are thousands of shale gas wells in the App Basin that were drilled with borrowed money that have been shut in for years with no takeaway capacity. I can find no success story in that kind of stupidity.

    The shale industry must find a way to make shale oil and shale gas extraction profitable or it will play NO role in the energy future of America. The first place to start, in my humble opinion, is to quit lying to the America public about it's sustainability. I detest that BS. As I do cheerleading for an industry who is about to financially implode. Thank you likbiz, and Mr. Leopold.

    Mike

    Heinrich Leopold , 04/05/2016 at 11:58 pm
    Mike,

    Thank you for your comment, which is in my view very important.

    George Kaplan , 04/06/2016 at 2:35 am
    Another summary on the investing disaster in shale here, it all comes down greed, corruption and stupidity in the end:

    http://www.credoeconomics.com/shale-euphoria-the-boom-and-bust-of-sub-prime-oil-and-natural-gas/

    John S , 04/06/2016 at 9:46 am
    Mike. Heinrich, & Shallow

    I really hope that in a year or 2, we can climb out of the bunker, pat one another on the back and say we made it through this mess. If we do…..adult beverages are on me. Anywhere in Texas that is.

    shallow sand , 04/06/2016 at 12:04 pm
    JohnS,

    TX is ok w me.

    I'd just like to get to $55 WTI, because then we can go back to normal and we could see how well LTO will do at that price.

    I suspect that would not do them any good other than get some more money out of investors, especially into the Permian companies. Share issuance, but likely not much more debt issuance.

    John S , 04/06/2016 at 1:58 pm
    I agree Shallow.

    I hope $55 works for you. I don't think it will be enough to save the debtor class in the oil patch. $55 won't be enough to make the PE/HF crowd whole so I think you are right. Those days are gone.

    It is going to be fascinating to watch the secured and unsecured creditors carve up the carcasses in the LTO & shale gas. Where is all that off balance sheet financing going to land?

    Carrion and dead carcasses everywhere. We are going to need a lot of vultures to clean up the dead and dying.

    The IRS is standing at the head of the line to get its cut. A lot of liens are going to be filed and bank accounts frozen.

    As I peck away here, creditors are putting in lock boxes to intercept account receivable payments. Debtors are intercepting the lock boxes to keep funds away from creditors. Local bank accounts are being closed and funds are redirected to the home office (some out of the country)

    Ever tried to secure a place in line with the other creditors when the debtor files for bankruptcy outside the USA?

    likbez , 04/05/2016 at 9:45 pm
    My main argument that production potential of all shale plays in the U.S. has been vastly exaggerated for political and propaganda reasons is unchanged and now supported by sufficient data.

    And for economic reasons too. The principal question here is "Whether deferred adjustment to higher oil prices is beneficial to the USA economy in a long run?". They were definitely beneficial to "team Obama", but this might well be "after us deluge" type of thinking.

    [Apr 06, 2016] Talk of the best wells is a red herring, its average that matter

    Notable quotes:
    "... What matters for a company's bottom line is the average output of all there wells. I imagine if you take a close look at the 10k you can determine how many producing wells they have and what their total output is, pretty sure it is going to be about 5 to 10% of that monster well, maybe less. Talk of the best well is a red herring. ..."
    "... Don't understand why they don't recognize this and just complete their DUCs (if it will not result in cash burn, at current oil prices it will) once prices make it profitable to do so. Enno Peters has more data so perhaps he sees something that I do not. ..."
    "... According to Enno, the average productivity for Pioneer's wells in the Permian is much lower than what the company shows in the presentation. ..."
    "... Enno Peters' numbers for 629 Pioneer's wells that started production in Spraberry formation in 2015 show ~34 kbo average cumulative production for the first 3 months. Pioneers's numbers for 11 wells in 4Q15 show ~60kboed (48 kbo, assuming 80% oil)As in all shale companies' presentations, the numbers for individual wells is simply cherry picking ..."
    "... Anyway, a likely reason for the increased productivity for the well is much due to the fact the the wells are drilled longer. I have a source (unfortunately not in English) saying that 1st generation fracking wells were 200-300m long, second generation wells up to 2-3km, with increased number of explosions. No wonder the well productivity goes up. ..."
    "... I suspect that the parameter "Production/area" would be more meaningful and most likely not show such a large an increase, maybe even a decrease. ..."
    "... Remember an oil man really doesn't care about the oil produced, it is the dollars produced that is the aim. So to the oil company oil per unit area is not something they would really consider. They are really interested in the oil produced per dollar spent, but most interested in the profits produced. Often the higher productivity wells are more expensive to complete (more frack stages, more proppant, or longer laterals), if they spend 10% more on the D+C and get 15% more output from the well (especially if the extra output happens early in the life of the well) that is money worth spending. ..."
    "... Usually they figure out the optimum setup after 2 or 3 years, eventually sweet spots will run out of room and well productivity will decrease, so far there is little evidence of well productivity decrease in the Bakken or Eagle Ford. ..."
    "... I still think the 2015 average Permian well will have an EUR over 180 months of under 210 kb, similar to the average Eagle Ford well and at $8 million per well and current oil prices, these wells should not be drilled. ..."
    "... Pioneer does have a few big Sprayberry wells, but most will never produce more than 300-400K barrels of oil, absent refracks or EOR breakthroughs. Most seem to really tail off after hitting 75-150K BO, and will produce the remainder over the next 20-40 years. At least that is what I see generally. ..."
    peakoilbarrel.com
    From Pioneer's most recent presentation:

    D&C cost per well:

    –Forecasting EURs ranging from ~0.8 MMBOE to ~1.2 MMBOE with IRRs up to 30% at current strip prices

    ( Reflects strip prices ranging from $36.00/BBL in 2016 to $49.00/BBL in 2020 for oil and $2.35/MCF in 2016 to $3.10/MCF in 2020 for gas)

    According to the presentation, an average well produces ~80% oil, 20% gas.

    coffeeguyzz , 04/04/2016 at 6:11 pm
    dclonghorn

    Richard Zeits raised some eyebrows with his latest Seeking Alpha post projecting Cabot's Susquehanna county wells (northeast PA) with putting out 27 Bcf EUR … a seemingly preposterous number for an $8 million well.

    Thing is, their #1 producer in the Marcellus, the T Flower 2, has ALREADY produced 16 1/2 Bcf in three years time.

    Currently putting out a steady 7/8 MMcfd.

    Dennis Coyne , 04/04/2016 at 6:45 pm
    Hi Coffeguyzz,

    They should only drill those kind of wells. :-)

    What matters for a company's bottom line is the average output of all there wells. I imagine if you take a close look at the 10k you can determine how many producing wells they have and what their total output is, pretty sure it is going to be about 5 to 10% of that monster well, maybe less. Talk of the best well is a red herring.

    Dennis Coyne , 04/04/2016 at 6:39 pm
    Hi AlexS,

    Thanks. Looking at Enno Peter's site http://www.shaleprofile.com ,

    Pioneer's average well in 2015 looks like it has high output for 10 months and then looks like it will revert to the average 2011 well profile from months 12 to shut in. I would estimate the EUR on these wells is about 160 kbo at most, adding in 20% natural gas would get the well to maybe 200 kboe of oil, NGL, and natural gas (in boe) for a URR. The return on these wells will be negative.

    Don't understand why they don't recognize this and just complete their DUCs (if it will not result in cash burn, at current oil prices it will) once prices make it profitable to do so. Enno Peters has more data so perhaps he sees something that I do not.

    AlexS , 04/04/2016 at 6:49 pm
    Dennis,

    I have also looked at Enno Peters' recent post on the Permian.

    According to Enno, the average productivity for Pioneer's wells in the Permian is much lower than what the company shows in the presentation.

    Enno's numbers are for total wells, and the presentation mentions only those wells that were completed in 2015. There were obviously improvements in average productivity in the past few years, but I doubt that they were that big.

    Dennis Coyne , 04/04/2016 at 6:58 pm
    Hi AlexS,

    You can look at individual years for individual companies, the site is awesome if you play with it a bit. Chart below.

    Toolpush , 04/05/2016 at 3:59 am
    Dennis,

    I know Enno cautions on reading too much into the the last couple months data, as it can wriggle around a bit, but if PDX's 2015 wells continue as shown in your graph, it may just mean that PDX were just trying a little too hard to get good production figure from the Sprayberry, and potentially are going to pay the price for this over production with long under performance of the well.

    Dennis Coyne , 04/04/2016 at 7:00 pm
    Chart below is the cumulative well profile for Pioneer wells in the Spraberry by year.

    AlexS , 04/04/2016 at 7:28 pm
    Thanks Dennis.

    Enno Peters' numbers for 629 Pioneer's wells that started production in Spraberry formation in 2015 show ~34 kbo average cumulative production for the first 3 months. Pioneers's numbers for 11 wells in 4Q15 show ~60kboed (48 kbo, assuming 80% oil)As in all shale companies' presentations, the numbers for individual wells is simply cherry picking

    Tom , 04/05/2016 at 3:24 am
    AlexS

    Interesting! Well spotted!

    Anyway, a likely reason for the increased productivity for the well is much due to the fact the the wells are drilled longer. I have a source (unfortunately not in English) saying that 1st generation fracking wells were 200-300m long, second generation wells up to 2-3km, with increased number of explosions. No wonder the well productivity goes up.

    But I wonder how meaningful this parameter is. I suspect that the parameter "Production/area" would be more meaningful and most likely not show such a large an increase, maybe even a decrease.

    Dennis Coyne , 04/05/2016 at 8:01 am
    Hi Tom,

    Remember an oil man really doesn't care about the oil produced, it is the dollars produced that is the aim. So to the oil company oil per unit area is not something they would really consider. They are really interested in the oil produced per dollar spent, but most interested in the profits produced. Often the higher productivity wells are more expensive to complete (more frack stages, more proppant, or longer laterals), if they spend 10% more on the D+C and get 15% more output from the well (especially if the extra output happens early in the life of the well) that is money worth spending.

    Usually they figure out the optimum setup after 2 or 3 years, eventually sweet spots will run out of room and well productivity will decrease, so far there is little evidence of well productivity decrease in the Bakken or Eagle Ford. In the Permian in 2015 it looks like high output in the first 13 months has hurt the well productivity for months 15 and later bringing the well to the level of the 2011 or 2012 wells after month 13. It is also possible that the last data point (month 13 for the 2015 wells) is based on too few wells to be reliable and may be statistical noise.

    I still think the 2015 average Permian well will have an EUR over 180 months of under 210 kb, similar to the average Eagle Ford well and at $8 million per well and current oil prices, these wells should not be drilled.

    shallow sand , 04/04/2016 at 7:03 pm
    AlexS.

    I have a data subscription and have finally broken down and paid a little $$ to satisfy myself about both the Permian hz wells, and also the OK hz wells.

    I cannot legally reproduce the data, but my view is:

    A. Enno's data is trustworthy re Permian.

    B. The OK hz wells are generally gas wells, with associated liquids, which rapidly deplete. Will not impact US oil production in a meaningful way. Some prolific gas wells, however.

    Pioneer does have a few big Sprayberry wells, but most will never produce more than 300-400K barrels of oil, absent refracks or EOR breakthroughs. Most seem to really tail off after hitting 75-150K BO, and will produce the remainder over the next 20-40 years. At least that is what I see generally.

    AlexS , 04/04/2016 at 7:04 pm
    Now compare what is said about those excellent wells IPs, EURs and D&C costs with Pioneer's actual 2015 results.

    With annual average WTI oil price of $48.66 + hedges, the company posted net loss of $273 million.

    Oil and gas revenues were $2 178 million,
    Net derivative gains: $ 879 million;
    Net gain on disposition of assets: $782 million.
    So, without hedges and gains on asset sales, Pioneer's net loss would be much bigger.

    Now look at their cash flow statement:
    Net cash provided by operating activities: $1 248 million
    Cash capex: $2 393 million;
    Negative free cashflow: $1 145 million.

    Not surprisingly, they had to borrow almost $1bn and sell assets for $553 miilion.
    And this is one of the leaders in the shale sector!

    shallow sand , 04/04/2016 at 8:08 pm
    Look at Q1 16 earnings estimates. Even worse.

    And they have better hedges than most.

    CLR and WLL have ceased completing oil wells. They are projected to lose major $$.

    BTW, it looks like CLR Red River wells will wind up being a much better investment at $30 oil than their Bakken and TFS wells are. Those Red River wells cost a fraction of the Bakken/TFS and will wind up producing similar, if not superior cumulative oil per well.

    shallow sand , 04/04/2016 at 9:39 pm
    AlexS.

    NASDAQ has earnings estimates on its site.

    I think every US E & P that is not integrated will post a loss in Q1 2016. This is before impairments.

    In fact, the Chevron estimate is an 11 cent/share loss.

    $30 oil is destroying the US E & P industry.

    Watcher , 04/05/2016 at 1:48 am
    Imagine that. Who would like to see such a thing?

    What happens if it is nationalized? The shareholders might get, say, a 10% premium over market price for their shares (making them happy), paid for with printed money.

    The employees get gov't benefit packages and the executives even have a bonus plan like AMTRAK or USPS.

    The enemy would have to try a new tactic.

    [Apr 02, 2016] Economics of Eagle Ford well

    Notable quotes:
    "... At some point people realize that the emperor has no clothing. ..."
    "... And that also gives an explanation to Dennis' supposition that rigs will fly at $50 oil (or maybe pigs will fly). Using the same numbers at $50, you get a negative return on a well that produces 148k over 36 months. Who can afford to wait 36 months in this environment, anyway? ..."
    "... They have been completing wells at $40/b or less, I agree nobody is making money at these prices, but if you have already spent $2 million to drill and case a well, that horse has left the barn. Now the question is do you spend another $3.5 million to frack and complete the well so you can generate some cash flow to keep the lights on. ..."
    "... When these companies are losing money, which I am confident was the case in 2015, and will likely be the case in 2016 also, income tax is zero, I think. Perhaps 30% would be a better number for royalties and taxes in Texas, 27% was a guess on my part. ..."
    "... Note that 148 kb is the average cumulative output over the first 36 months of the average 2013 to 2015 Eagle Ford Shale(EFS) oil well. ..."
    "... I think the rule of thumb is that the payout in 36 months means the well is acceptable for Mike who is conservative, the shale players are not very conservative financially so 36 months would be outstanding as far as they were concerned. If the well cost was $6.5 million simple interest would be $325,000 at 5% and would be covered by the well in our example above, land and development costs might be covered by associated gas, I don't have numbers on that. ..."
    "... Let's assume no associated gas (unlikely to be the case) and using Reno's land numbers from below say land and development costs are $350k/well, then we would need $83/b for the well to pay out in 36 months for the average well. ..."
    "... So if we need $83 to payout in 36 months, the current price is $38 and the NYMEX strip for 36 months is well below $50 WTI, why are there any wells being drilled and completed in the EFS? ..."
    "... Commodity markets can remain irrational longer than many can stay solvent, unfortunately. ..."
    "... I am getting a little more conservative in my price predictions seeing maybe $50/b by Dec 2016 and maybe $80/b by Dec 2017, but the faster output falls the quicker the turnaround in oil prices will be. ..."
    "... The main and probably only reason they are drilling in non-sweet spots in the Eagle Ford, now, is to hold the lease. I think, even the DUCs that are being completed now fall into that category. Or, in some cases, like Dennis says, the completion cost as current year capex would be covered. The only reason a company would drill with a three year payout, is if they had adequate lending or capital resources. Otherwise, they well should mainly pay for itself the first year, or they lose the capex for next year in cash flow loss. ..."
    "... Most of the revenue is in the first year, about 63% of the oil flows in the first year. For the well to pay out in the first year would take an oil price of $117/b, but after a few years of wells you have cash flow not just from this years wells but the cash flow from previous years as well, this is why the 36 month rule probably works, to get the operation started you would need to borrow some money, but if you do it right you pay off those loans after 5 years or so and then work from cash flow and never need to borrow money, if you do it right and don't have oil prices in the toilet for a couple of years. ..."
    "... Why are the shale guys given massive lines of credit based on the" assets" that are still in the ground and essentially worthless in today's market? ..."
    "... "Analysts" are projecting a 30% haircut on the shale guys lines of credit in April, why only 30%? How about 100%? ..."
    "... I just don't see the hyped OK plays adding much crude, based on available data. Would be neat if all states had ND data. ..."
    peakoilbarrel.com
    Dennis Coyne , 03/30/2016 at 12:56 pm
    Hi shallow sand,

    At some point people realize that the emperor has no clothing.

    Quick question on Eagle Ford.

    Assume

    With the assumptions above the net revenue per barrel is $44.13/b and the cost of the well is covered in 36 months (with no discounting).

    Mike has often said he wants his wells to "pay out" in 36 months at minimum (he prefers 24 months, I would prefer 12 months :- ). At $77/b at the refinery gate and 148 kb cumulative in 36 months, does the well meet those requirements under the assumptions I have given?

    How might you revise the assumptions to make them more realistic? What am I missing, if it does not require a book length answer :-) ?

    shallow sand , 03/30/2016 at 4:28 pm
    Dennis:

    148K gross oil over first 36 months.

    Assume 20% royalty and 7% severance taxes?

    So net oil is 118,400 barrels.

    118,400 x $77 price realized = $9,116,800.00

    $9,116,800.00 x (100% – 7%) = $8,478,624.00

    Assume $11 LOE, water disposal, transport cost = $1,302,400.00

    Assume $10K per month of "maintenance CAPEX" = $360,000.00

    Subtract those two figures from our net oil = $6,816,224.00

    You payout in 36 months, assuming no interest expense. Also, need to allocate lease acquisition cost, seismic, permitting etc., to our well. On the plus side, we need to also figure in the gas/natural gas liquid revenues. Also, need to see how income taxes figure in. Also, not sure if LOE is correct, does it include county ad valorem taxes?

    So in 36 months, we still need to pay our interest expense, our up front land and development costs. Maybe some income tax, maybe we need to add ad valorem taxes.

    Oh, also, where is our G & A allocation? Or is that included up there somewhere? That seems to be running about $2-4 per BOE (note not BO, and likewise, all other expenses are always set forth as BOE, so we need to know our GOR to adjust for that maybe?)

    Finally, should we factor in time value of money, or if we add actual interest expense does that solve the problem? I agree interest rates are super low, maybe we should us PV8 or PV7? Rune and I have discussed this some.

    I assume this is a pretty darn good EFS well? I guess just need to look at shaleprofile.com don't we?

    shallow sand , 03/30/2016 at 11:56 pm
    Dennis. I suppose your example is close to what will be the "average" EFS well in 2016.
    One thing to remember, the EFS has different "windows" and many areas produce all, or mostly gas.

    Sánchez Energy is a prime example. Only 37% of 2015 production was oil. Their Catarina area is mostly gas and natural gas liquids, yet it is their primary field, and well costs are much lower.

    Sánchez plans on completing 55 net wells, 36 in Catarina. This compares to 116 well completions in 2015, companywide. Cost for all wells will be $180-220 million, only 3 net DUC wells from 15, rest are new drills. Plan on spending another $20-30 million on facilities.

    Just some EFS company info that might interest some.

    I suggest looking at Sánchez Energy's 2015 10K. Very detailed.

    One area they reported was royalty burdens. Those range from 20.9% to 30.5%. I think royalty burdens are more onerous in EFS than Bakken, I think 25% is very common, and 30+% is not unheard of.

    Despite a high percentage of gas, Sánchez production expenses (which appear to include gathering and transport) were $8.16 per BOE. Production and ad valorem taxes were$1.40 per BOE on realized per BOE of $24.80. DD &A was $17.96 per BOE, interest expense was $6.60 per BOE, G & A $2.89 per BOE, and impairments were $71.15 per BOE.

    Sánchez has $435 million of cash, $1.75 billion of long term debt, PV10 of $593.5 billion, PDP PV10 of $465.5 billion.

    They have two large acreage areas where they have no present plans for new wells, very few currently producing wells, and almost no PV10, being EFS Marquis area, and in the Tuscaloosa Marine Shale.

    To achieve the above stated PV10, future production cost estimates were slashed from $2.635 billion as of 12/31/14 to $1.745 billion as of 12/31/15.

    Another interesting thing I noted that Sánchez reported, that few others do, is that they have a NOL carry forward of $765.9 million. More interesting is they adopted some type of plan to keep a hostile acquirer from obtaining benefits of this NOL. Clueless, if you are out there, would love to hear your comments on this.

    Sánchez has an interest in 621 gross, 504.6 net wells.

    Despite being in EFS, their oil sold for an average price of $42.98 per barrel, well below WTI.

    Their production really increased, from 43,893 boepd in Q4 14 to 58,115 boepd in Q4 15. They completed more wells in 2015 than in any prior year, and do not appear to have DUC's.

    Guy Minton , 03/31/2016 at 12:33 am
    And that also gives an explanation to Dennis' supposition that rigs will fly at $50 oil (or maybe pigs will fly). Using the same numbers at $50, you get a negative return on a well that produces 148k over 36 months. Who can afford to wait 36 months in this environment, anyway?
    Dennis Coyne , 03/31/2016 at 9:30 am
    Hi Guy,

    They have been completing wells at $40/b or less, I agree nobody is making money at these prices, but if you have already spent $2 million to drill and case a well, that horse has left the barn. Now the question is do you spend another $3.5 million to frack and complete the well so you can generate some cash flow to keep the lights on.

    All the G&A, land acquisition and development costs and so forth have been allocated to other producing wells, income tax is not an issue because last I checked you don't pay taxes when you are losing money.

    When we do the calculation using all the same assumptions as before and look only at the fracking and completion cost of $3.5 million, that cost is paid in 36 months at $50/b.

    Perhaps that is why some wells continue to be completed at $50/b, the $40/b completions may be the best well locations that have higher than average EUR.

    Dan , 03/31/2016 at 1:35 am
    Shallow,

    SN's production increase is all gas and NGL. Their 2015 oil production was down compared to 2014 despite completing more than 100 new wells in 2015.

    shallow sand , 03/31/2016 at 6:32 am
    Guy and Dan, great points.

    EFS is tougher to get a handle on, because it is much more variable than the Bakken in terms of GOR and well depth.

    I would note SM Energy still has two rigs going in Divide Co., ND. Apparently the wells there aren't as costly as in the core of McKenzie Co. Other than that, seems like Bakken activity right now is centered in one area, where things are similar.

    I don't know a whole lot about EFS, but do know that some areas, like Catarina, are almost all gas and liquids, little to no oil. Pioneer seems to have the gassy acreage, thus zero rigs running.

    Dennis Coyne , 03/31/2016 at 9:34 am
    Hi shallow sand,

    I have focused on oil wells and ignore the gas and condensate wells. In the most recent 12 months about 80% of the C+C output is from oil wells and 20% is condensate from gas wells.

    When these companies are losing money, which I am confident was the case in 2015, and will likely be the case in 2016 also, income tax is zero, I think. Perhaps 30% would be a better number for royalties and taxes in Texas, 27% was a guess on my part.

    Dennis Coyne , 03/31/2016 at 7:02 am
    Hi Shallow sand,

    The 36 month payout rule that Mike uses, would be a company that operates by using cash flow, so interest expense would be zero, the associated gas of the average oil well in the EFS I am not sure about, but the gas and NGL might offset some of the LOE. I was assuming all taxes and royalties would be covered by the 27% of wellhead revenue, does that seem too low, maybe 30% would be more realistic?

    Note that 148 kb is the average cumulative output over the first 36 months of the average 2013 to 2015 Eagle Ford Shale(EFS) oil well.

    When the 36 month payout rule is used, I thought the discount rate was left out of the calculation. Also note that the land and development costs is spread over many wells, what would your estimate be for these costs per well, I have no clue.

    shallow sand , 03/31/2016 at 7:25 am
    Dennis, some good points.

    See my Sánchez Energy post re their royalty burden and production and ad valorem taxes per bbl.

    Some acreage went for over $50K per acre. So if we are on 100 acre spacing, that would be $5 million per well? I agree, that is extreme. So use $10K per acre, 60 acre spacing, still $600K per well. Not insignificant. I do not know what seismic shoots were costing, you have the bill to the land man, and the attorney. So much of the shale plays have severed minerals, so landowner had to be paid. Plus, look at the division of interests on some of these shale units, usually over 100 separate mineral owners, all have to be contacted to sign. And the land men had to run the records in the remote county court houses to figure all of this out, very costly, leasing.

    Just because Mike doesn't borrow doesn't mean shale doesn't. Wouldn't the fact that shale borrows means they need a quicker payout than Mike, who pays cash?

    The gas in EFS is much more relevant than Bakken.

    Dennis, would really help you to read some 10K. On EFS, I highly recommend Sánchez for starters, as they are solely EFS (TMS insignificant) and have acreage in different EFS windows, yet they break out a lot of detail on each.

    They are no small player, 58K BOEPD in EFS.

    Reno Hightower , 03/31/2016 at 8:09 am
    Sanchez bought 106,000 acres from Shell for 639 million. They picked up 43,000 acres from Hess for 265 million. Paid about 6,000 an acre.
    Dennis Coyne , 03/31/2016 at 9:53 am
    Hi Shallow Sand,

    I think the rule of thumb is that the payout in 36 months means the well is acceptable for Mike who is conservative, the shale players are not very conservative financially so 36 months would be outstanding as far as they were concerned. If the well cost was $6.5 million simple interest would be $325,000 at 5% and would be covered by the well in our example above, land and development costs might be covered by associated gas, I don't have numbers on that.

    Let's assume no associated gas (unlikely to be the case) and using Reno's land numbers from below say land and development costs are $350k/well, then we would need $83/b for the well to pay out in 36 months for the average well.

    shallow sand , 03/31/2016 at 10:45 am
    Dennis, sounds good. And right now the app on my phone says WTI is $38.51.

    So if we need $83 to payout in 36 months, the current price is $38 and the NYMEX strip for 36 months is well below $50 WTI, why are there any wells being drilled and completed in the EFS?

    For example, Sanchez, who has $1.75 billion of long term debt with PDP PV10 of just $450 million, plans on spending over $200 million of CAPEX in the EFS in 2016. They do have hedges, but they really do not help much.

    See why this stuff frustrates the heck out of people like Mike and me? It is like throwing cash in a burn barrel.

    Dennis Coyne , 03/31/2016 at 10:53 am
    Hi Shallow sand,

    I gave an example above for why someone might complete a DUC at $50/b for an average well.

    So find your better DUCs that might produce in the 75th percentile and maybe completing the well makes sense at $38/b, I really don't know desperate times call for desperate measures I guess. Every oil company is secretly hoping they can outlast the other company so that output goes down and prices go up, this is a game of last man standing as far as I can tell.

    shallow sand , 03/31/2016 at 11:08 am
    Dennis. Pretty much all are in dire straits, I agree.

    Looks like ND rig count is ready to drop below 30, at 30 today with one to stack.

    I like that you see a quick rebound in oil prices, but I think you have been saying that for awhile.

    Commodity markets can remain irrational longer than many can stay solvent, unfortunately.

    The same game is going on in the grains, there is supposedly a glut there too, but, like oil, a world wide price trades heavily on US government inventory estimates, with little data on stocks in huge chunks of the world.

    Unfortunately, sentiment is so much more important than it should be in the commodity markets.

    Dennis Coyne , 03/31/2016 at 11:24 am
    Hi Shallow sand,

    I am getting a little more conservative in my price predictions seeing maybe $50/b by Dec 2016 and maybe $80/b by Dec 2017, but the faster output falls the quicker the turnaround in oil prices will be.

    I hope for the sake of the oil guys and the environment, that oil prices get to $85/b sooner rather than later, but you are correct that I am wrong on oil prices more than I am right.

    The reason I have been wrong is that I have expected a steep decline in LTO output that has not occurred, when it finally happens then within 6 to 12 months we will see oil prices rise, perhaps very quickly.

    Nobody knows what oil prices will be unless a huge range is chosen ($10 to $200/b for the next 5 years would probably be right, but far from useful).

    Mike , 03/31/2016 at 11:53 am
    The internal accounting standards that I use to drill wells, for instance ROI and time to payout, were actually taught to me nearly a half century ago by numerous oilmen before me. I think there is a reason that those standards have been passed down over generations. They work. They essentially enable an operator to be, for lack of a better term, "self sufficient." By that I mean reserve inventory that is being liquidated can be replaced with net cash flow, and not borrowed funds. Well costs, oil prices and risk affect those accounting standards and when and if to pull the trigger, sure. The same standards SHOULD apply to the shale oil industry but of course they haven't and profitability has taken a back seat to reserve growth, which now of course, has proven to be a dumb mistake also. Along with a half dozen other dumb mistakes.

    I won't speculate on DUC wells and when and why they would become profitable to complete; I think perhaps it might be a mistake to assume there will be enough money to borrow to complete those wells. I see a lot of DUC wells being completed in the EF; in fact that is all I see being done in the EF. Myself and others believe the rig count in the EF is grossly over exaggerated. EF production is going to nose dive now to the rest of the year.

    S. Texas is a very mature producing province and mineral owners very savvy; 25% royalty burdens are the norm and many of those leases are burdened with additional ORRI's. Severance taxes are 4.6% of gross revenue and ad valorem taxes generally another 2.4% of net revenue to the WI.

    Sanchez put all of its eggs in the Catarina basket several years ago and they are under one of the most onerous drilling commitment provisions I have ever seen. They drill it, or they lose it. That stuff is in the liquids rich gas interface window, and close to Mexico; they appear to have a plan of some kind. Others still drilling anything unconventional right now, anywhere, have no plan whatsoever. They are doing stupid things with borrowed money they will never be able to pay back at anything less than 100 dollar oil prices, sustained. The "breakeven" metric is now even more irrelevant because for a shale oil company to survive they must generate sufficient cash flow to replace very high decline rate wells… AND pay back massive amounts of accumulated debt. That ain't gonna happen and all of them, with few exceptions, are now in Hospice care.

    Dennis Coyne , 03/31/2016 at 12:26 pm
    Hi Mike,

    Thanks.

    Not sure how to translate 2.4% of net revenue of working interest for the ad valorem tax.

    Lets take the example where Mike owns the well with a 25% royalty and gets $40/b at the wellhead for any oil he sells, lets assume the well produced 1000 barrels yesterday and OPEX+ water disposal+ G+A+ land and development costs + the stuff I don't know about is $15/b.

    How much money does Mike take home in this example (I am unsure about how the ad valorem tax works)?

    Before taxes it looks like $25/b times 750 barrels so $18,750 of revenue, the severance tax would be $1380, is the ad valorem only on the $15,000 of net revenue? That would be $360 at 2.4% of $15,000 net revenue. So I think the take home (before income taxes) would be $17,010.

    Probably that is wrong, I am not good at accounting.

    Dennis Coyne , 03/31/2016 at 1:57 pm
    Nope, I got it wrong.

    The net revenue would be $25/b times 750 barrels or 18750 and at 2.4% that would be $450 for the ad valorum tax, so taxes would be 1380+450=$1830 and before income tax the take home would be $16920. If the marginal income is taxed at 35%, then the take home pay would be $10,998 if I did it correctly this time. :-)

    Dennis Coyne , 03/31/2016 at 2:09 pm
    Hi Mike,

    On that nosedive in the Eagle Ford, does Enno Peters estimate of about 60 completions per month in the Eagle Ford in 2016 sound right? The past 3 months (Nov to Jan) the completion rate has been about 145 wells per month and for all of 2015 it was about 185 wells completed per month. So a rate of 60 per month in 2016 would be about 1/3 of the 2015 completion rate. I expect something like 90 wells per month, but my guesses are usually not very good.

    From your comment above I am thinking that you might choose something like 40 completions per month, maybe lower.

    Guy Minton , 03/31/2016 at 2:02 pm
    The main and probably only reason they are drilling in non-sweet spots in the Eagle Ford, now, is to hold the lease. I think, even the DUCs that are being completed now fall into that category. Or, in some cases, like Dennis says, the completion cost as current year capex would be covered. The only reason a company would drill with a three year payout, is if they had adequate lending or capital resources. Otherwise, they well should mainly pay for itself the first year, or they lose the capex for next year in cash flow loss.
    Dennis Coyne , 03/31/2016 at 2:27 pm
    Hi Guy,

    Most of the revenue is in the first year, about 63% of the oil flows in the first year. For the well to pay out in the first year would take an oil price of $117/b, but after a few years of wells you have cash flow not just from this years wells but the cash flow from previous years as well, this is why the 36 month rule probably works, to get the operation started you would need to borrow some money, but if you do it right you pay off those loans after 5 years or so and then work from cash flow and never need to borrow money, if you do it right and don't have oil prices in the toilet for a couple of years.

    HR , 03/30/2016 at 2:41 pm
    Maybe Hamm has better contacts on Wall Street? That's all it takes, remember that there are different rules and laws for the regular citizens and for those that fund campaigns. It is what it is.

    Why are the shale guys given massive lines of credit based on the" assets" that are still in the ground and essentially worthless in today's market?

    Why did the federal reserve step in during the redetermination period last year and tell the bankers to encourage the sale of assets rather than call the loans?

    Why are some people forced to mark to market while others skate?

    Why aren't guys like me and you given say a 20 million line of credit? I wouldn't sell my soul to those assholes anyway, so no need to answer that.

    "Analysts" are projecting a 30% haircut on the shale guys lines of credit in April, why only 30%? How about 100%?

    If you and I were running a pretend business, would they loan us a lot of money and then look the other way when it all heads south on us? They would if Wall Street has figured out how to make big bucks and on it.

    shallow sand , 03/31/2016 at 6:49 am
    One thing some argue is that CLR has so much acreage that they got so cheap.

    My response to that is go look at how much they have expiring. They are not completing any wells in Bakken, meaning all of their acreage in ND and MT is very uneconomic at Q1 prices.

    So we are left with the mostly gassy OK acreage, with wells that are more costly than, but far less productive than the Marcellus. Again, we really need better info, but CLR companywide went from 70% oil 30% gas in 2014 to projected 60%/40% in 2016.

    Their BOE is poised to drop 10% in 2016, but oil will drop much more steeply.

    I just don't see how under $2 gas works, although they do have some gas hedged, unlike oil.

    So if an OK well produces 70% gas and ngls, hypothetically, with wellhead oil of $35 and gas of $1.75, per BOE is just $17.85. Over the life of the well, ignoring all other expenses, you are looking at just under $20 million of gross revenue using their EUR of 1.1 million BOE. That is over 30 plus years, I assume.

    I don't get SCOOP and STACK attractiveness. Devon did pay big $$ for acreage there recently, another head scratcher, especially given their enormous Barnett shale exposure, which right now is likely negative on an operating basis. DVN used to be cream of the crop independent, but have to wonder?

    OK C + C production per day per EIA has fallen from a peak of 473K in 3/15 to 400K in 12/15, very steep, and even steeper when you consider there is a stripper production C + C base of 130-150K per day (although it likely declined at least 10% as well during the same timeframe).

    I do agree, part of the collapse is due to Mississippian activity falling off the table. See SD and CHK, for example.

    I just don't see the hyped OK plays adding much crude, based on available data. Would be neat if all states had ND data.

    [Mar 29, 2016] Good article in DrillingInfo on US oil price differentials and LTO economics

    peakoilbarrel.com

    AlexS , 03/28/2016 at 7:05 pm

    Good article in DrillingInfo on US oil price differentials and LTO economics:

    The Bigger Picture of Local Oil Price Points

    March 24, 2016 by Mark Nibbelink
    http://info.drillinginfo.com/local-oil-price-points/

    [Mar 29, 2016] Summary of average well costs

    If we assume that previous break even cost (which is stupid metric in any case) was $80 then 20% reduction means that now it is $64.
    Notable quotes:
    "... apart from Delaware Basin, well costs had dropped by less then 20%. ..."
    peakoilbarrel.com

    Daniel , 03/28/2016 at 4:03 am

    Potentially interesting summary of average well costs ( http://www.eia.gov/analysis/studies/drilling/pdf/upstream.pdf ):

    Here's how well costs dropped in recent years:

    IHS expects rig rates to fall by 5-10 percent this year, but increase 5 percent in 2017 and 2018

    Interesting to note, that apart from Delaware Basin, well costs had dropped by less then 20%.

    [Mar 22, 2016] Seeking Alpha

    Notable quotes:
    "... I have grave reservations about the alleged spare capacity of Iran. The assumption is that the big, bad sanctions resulted in a huge drop in Iran's oil production. I am not buying it. I think the sanctions were a joke. For starters many nations refused to take part in the sanctions. Nations like India, china, japan and South Korea for starters. It would not be difficult to then reexport this oil to the rest of the world on the sly. ..."
    seekingalpha.com
    Enno Peters , Comments (67) |+ Follow |Send Message
    Michael, CLRs wells perform less than the average well in North Dakota, in every single year. It is easy to verify this claim:

    1) go to my site at http://bit.ly/21BwM7G

    2) select the "Well quality" tab and compare CLR vs all operators for each year.

    From the map there ("Top companies" tab), I see that CLR has a lot of poor acreage scattered around the Bakken, but not much acreage in real sweet spots, like Whiting and EOG had in the past in Mountrail. I was therefore wondering at which WTI price do you think that CLR can drill profitable wells in the Bakken? In my estimation they need over $50 WTI to just pay back the cost of the well within 5 years. I come to this figure by

    1) taking a rather optimistic 200k barrels of oil output within 5 years, for their average well.

    2) subtracting a rough 30% for royalties & production taxes: 200kbo -30% = 140kbo. $6.7m per well / 140kbo = $48 of well cost for each barrel of oil.

    3) and adding a WTI differential.

    If you then add all other costs, such as lifting costs, extra CAPEX later in the well life for pumps etc, G&A, interest, income taxes, etc, wouldn't they need WTI to be much higher than $70-80 to be profitable on these wells? I know non-shale operators who want to see their money back within 3 years, so the 5 years payback time I took above is still rather risky, especially given the faster decline of shale wells.

    You mentioned that you like them because of STACK/SCOOP, about which I don't have much info. I just hoped you can share your thoughts on the above, as they are still big in the Bakken.

    Thanks.

    oil baron 20 Mar 2016, 05:36 AM
    Enno

    As a member of the oil fraternity for the last 45 years it is refreshing to read a post from someone who really understands the economics of production and the cost/benefits of today's price environment.

    kudos to you

    Michael Filloon, Contributor 20 Mar 2016, 09:19 AM

    ... ... ...

    I don't do average payback times for companies like CLR because much of the marginal areas wont see any development at all (unless oil prices head much higher, which we don't see happening in the near term).

    Operators will focus on core areas and this plus well design improvements are why we have seen EURs drive higher. We probably have different estimates as to the number of bbls produced over the first five years which would cloud the results some.

    Working core acreage and switching to slickwater, we believe these wells will produce about 360K BO over the first five years.

    This is probably the biggest issue right now with those bearish and bullish, its estimates. Not saying you are wrong or that I am for that matter, just that we will have to wait and see. To your point on acreage, it does have a pretty decent footprint in NE McKenzie County or in the southern part of the Nesson Anticline and those wells could produce about 450K BO in the first five years depending on estimates. Now if we look at its acreage in Burke, N Williams or Montana the well results are no where near as good and that acreage will need considerably higher WTI to develop. I would also say that you are right about 5 year payback times being way too long and that operators use to think at least 18 months was adequate.

    We are definitely in interesting times. I don't have time to do it right now, I am heading to the gym but will try to put some quick thoughts in on the STACK/SCOOP this evening. The reason we like CLR isn't the Bakken and we do see production in ND dropping here more than in Texas and Oklahoma. We actually think that we could continue to see the Permian and SCOOP increase production while the Bakken and Eagle Ford roll over a bit. Thanks again, real good questions and I always appreciate our conversations. Unlike some here you are always respectful and that only adds to the current debate on some of these names.

    phaedrus1952 20 Mar 2016, 02:01 PM

    Mr. Filloon/Enno

    Re Continental's historic underperformance in its Bakken wells compared to peers ...

    1). They were VERY early movers in this play and accumulated vast acreage at rock bottom prices.

    2). This 'Land Grab' phase generally only offered 36 months in which to get a producing well in place so as to HPB.

    3). A significant portion of this acreage is now recognized as being outside the sweet spots.

    4). CLR purposefully chose a cookie cutter approach to completions, namely, 30 stage and sliding sleeve. Reasons for this were speed through repetition (they were racing the HPB clock), relative cost reduction with operational familiarity, and - ALSO - having a position-wide identical well design so as to evaluate the differing resource potentials throughout their vast holdings.

    The future of their Bakken wells is apt to be far more productive than their past.
    Crudely_Midstream 21 Mar 2016, 12:38 AM
    Great work gentlemen - it is indeed awesome to see experts on here. Couple of points that might be of interest: -In case you wanted a real data point, avg. well head price for *cough* was ~$16.86/bbl last month, probably +$3 now based on the flat price. -I saw Jim Volker two weeks ago and he said his research lab in Denver had found "the holy grail" of shale rock oil extraction technology.

    Interesting for whiting...perhaps CLR isn't far behind. -The production math from ND DMR does not add up to CLR's type curve slides. I'm still trying to figure out why. Do you think reworks are baked into type curves? I thought not. -I would attribute the lower than expected IP rates to the choke...only a few people like Statoil like to blow their wells out (although there are a couple of exceptions) Option B: go the classic route of rocks are bad or poor frac design.

    Enno Peters 21 Mar 2016, 02:28 PM
    Michael, Thanks for your elaborate response. I also enjoy these civil debates with you, and I appreciate your comments on my site. You do got me very surprised by the estimates you mentioned: 360 kbo & 450 kbo in 5 years.

    Those are really exceptional numbers, that so far only a few companies been able to get in highly prolific spots in the Bakken. 360 kbo is more than double the results of CLRs wells that already reached 5 years.

    You don't expect the average well of CLR in 2015 or 2016 in the Bakken to come close to that, right? But if you're not, then that means that your example should be adjusted if we look at the economic performance of CLR in ND, and that would then show that CLR would not be able to expect its money back on all wells drilled under current conditions within 5 years (even though we both agree that to be a very long time already), right?

    Enno Peters 21 Mar 2016, 04:39 PM
    Phaedrus, "The future of their Bakken wells is apt to be far more productive than their past." Can you be more specific, e.g. indicate using ranges what you expect, and when, from the average wells from CLR in the Bakken? Note that it is not a given that companies improve their results in the Bakken every year. Whiting, and EOG already have shown several years of declining well results, as is what we can see in several locations. So far, on the aggregate, this has been compensated elsewhere. Also, what I think is very clearly shown on my site, on average, the main improvements have been during the initial months of production, but not in the long production phase after 12 months. You expect CLR to buck these trends?
    Michael Filloon,

    alpha, We have a current target of WTI to 41.80 or so, so would add to the DWTI position into that number. $40 will be very difficult to breach and some traders think momentum could take us to $49 in the short term, so this trade does have significant risk. We would close this trade in the $32 to $34 range. But if we breach $30 may climb back in. Have a great day!

    shallow sand Comments (148)
    It is interesting to note the following from CLR's 2015 10K: CLR suffered from a rather large discount concerning realized oil prices. 2015 SEC oil price was $50.28, but CLR had to discount that to $41.63 per barrel. The gas discount resulted in utilizing $2.35 per mcf. CLR's proved reserves dropped 9% from 12/31/14 to 12/31/15.

    More importantly, however, they became much more gas weighted, as 43% of proved reserves are gas on a BOE basis. Therefore, analysis of gas production and future gas prices is required in analysis of CLR. A look at CLR's statement of future cash flows is also important. In 2014, CLR's estimate of future cash inflows was $90.9 billion.

    This dropped to $35.6 billion in 2015. This is largely the result of the commodity crash, so it is very important if a lower for longer scenario is correct. In 2014 the estimated future production costs were $25.8 billion. In 2015 that fell by 60% to $10.9 billion. That is a very large drop, and I hope analysts are able to get CLR management to walk through the steps that they undertook to achieve such a large drop in future production costs, but yet not a similar drop in proved reserves.

    I compared these results to industry leader, ExxonMobil, and CLR knocks it out of the park, as ExxonMobil suffered about a 24% drop in proved reserves while cutting future production costs about 29% during the same period. CLR also cut future development cost and abandonment cost estimates from $12.8 billion in 2014 to $6.9 billion in 2015.

    These production, development and abandonment cost cuts are critical, had they not been achieved, CLR would have negative $1 billion in estimated net future cash flows. Estimated net future cash flows from 2014 to 2015 fell from $38.4 billion to $15 billion. Standard measure PV10 fell from 2014 $18.433 billion to 2015 $6.476 billion. CLR has never carried much cash, 2014 $24.4 million, 2015 $11.5 million.

    Long term debt increased from $5.927 billion to $7.116 billion. CLR's traded enterprise value continues to greatly exceed its peers.

    I think it would be interesting to know if there are any other industries, besides E&P, where such a high market capitalization could be achieved, with such a low amount of cash, such a high long term level of debt, and with future net cash flows, utilizing a discount rate of 10%, below the amount of long term debt. Tesla comes to mind.

    shallow sand
    Michael. Is CLR's high density Poteet Unit a good representation of the productivity of its SCOOP assets? Are there some other wells/units you could recommend. I have an IHS Global subscription, would like some guidance on assets you feel would be best to review.
    22023171
    Good article Iran doesn't have 50 million barrels on ships anymore though. They started selling those shortly before sanctions were lifted late last year and have been gradually selling those takers this year not sure there is that much left to sell. of those at this point.

    Michael Filloon,

    22023171, Where did you get that information? As of March 17th Iran had an estimated 51.6 million bbls in floating storage including condensate. It has steadily increased since Oct of last year when it had 42.02 million bbls

    Enno Peters Comments (67) |+ Follow |Send Message

    Bison, Production taxes in ND dropped from 11.5% to 10% since Jan 1st this year. E.g. link at http://bit.ly/1WApDmP Royalties : I have seen many numbers & estimates in the range of 18%-24%. For convenience, I took 20%. Together this means that companies have to turn over a 30% or so of production before subtracting their own costs.
    21793061 20 Mar 2016, 12:34 PM Comments (591) |+ Follow |Send Message
    Enno: I think the royalties and excise taxes are off the wellhead price, not off of the WTI reference. So, that adds about $3 per barrel back to the margin. (WTI-BD)*0.7 > WT*0.7-BD Because [(WTI-BD)*0.7] - (WT*0.7-BD) = 0.3*BD ~ 0.3*10 = 3
    Report Abuse Reply 1 Like

    Enno Peters 20 Mar 2016, 01:04 PM

    Please review my calculation again. I didn't take the severance taxes & royalties from the WTI reference, I took them straight off the gross production volume.

    200 kbo gross oil production volume from an average CLR well within the first 5 years means (subtracting production taxes & royalties of 30% or so) about 140 kbo net oil production volume for CLR, right?

    Besides, my calculation wasn't meant to be ultra-precise. I also didn't add land costs, seismic & other CAPEX, stock-based compensation, time value of money (discount factor), or the positive contribution from some gas.

    I just wanted to show that oil prices have to be materially higher than the strip prices in order for CLR to have its money back on these kind of wells within a reasonable time frame. I'd love it if someone could point out to me where I am wrong on this.

    Bison73 20 Mar 2016, 01:37 PM

    Comments (589) |+ Follow |Send Message

    Thanks. I have one comment on royalties. Most of the early drillers got in for a lot less than the 20% you estimated. My mineral acres are 13% and I know several others that are in the 16% range. The reason for the low royalties is that a lot of the mineral rights owners didn't know what they had and in hindsight got rooked out of a lot of money.
    21793061 20 Mar 2016, 02:17 PM Comments (591) |+ Follow |Send Message
    1. If you subtracted the barrels explicitly, than that would seem to make sense so my comment is wrong.

    2. I wasn't trying to nitpick one thing to shoot down an overall argument. Just to note the one place I (thought I) saw an error. Chill. I thought you were doing well and just wanted to hone it better.

    3. Since your discussion was already about simple payback, no reason to model time value of money. It's already understood that this not an NPV.

    4. I would treat the land costs as sunk. We are trying to think about what price of oil it takes to drill now. (Similar for long ago seismic or infrastructure buildout.) Obviously this is a judgment call and if you acquire new acres or build new infrastructure than you need to charge the drill-or-not decisions with the cost. Similarly stock costs and the corporate center G&A are a little bit of a question.

    I would probably keep them clear from the project decision (if you don't drill, do you recover those costs? Maybe, if you do a layoff like SWN did...)

    shallow sand 20 Mar 2016, 04:40 PM

    Comments (148) |+ Follow |Send Message

    Bison. I have reviewed many non-operated working interests for sale on energynet.com located in the Williston Basin. 1/8 royalties are rare. I have seen 72-83.3% NRI.

    My understanding is land men and others were able to latch onto significant ORI. However, go ahead and do Enno's calculation with 87.5 NRI. You still don't get there. We stay under $50 for awhile, eventually CLR will be bankrupt. Too much debt, not enough future net cash flow.

    This is supported by the numbers in their own 10K submitted to the SEC. It is now almost a year and a half into the worst bust my family has endured, yet shale proponents are still in denial.

    I do not deny shale is a game changer, is very important for our country, has had many technical breakthroughs, etc. I only deny it works broadly sub $50, or even sub $70 oil as a good, or even marginal investment.

    We have enough well histories and cost statistics, including horrific 2015 earnings, massive layoffs and depressed and wildly volatile stock prices to know that. So please acknowledge this and join me in praying shale will stop completing wells and fibbing about $30 break even. I unfortunately own shares in two previously good companies COP and EGN, who got caught up in the allure of shale. One has cut its dividend and the other eliminated it. The shares are way down, and very volatile. They only go back up if oil prices recover.

    21793061 20 Mar 2016, 10:30 PM Comments (591) |+ Follow |Send Message
    Rig count has crashed to below 400. It continues to go down as rigs come off contract or as projects complete. How much less drilling do you need? Seems like they have laid the drill bit down.
    shallow sand 20 Mar 2016, 10:52 PM Comments (148) |+ Follow |Send Message
    I hope you are right, but what happens if WTI hits $50? I don't want a repeat of the spring of 2015, and the resulting price crash. Look at what happened Friday. Add one stinking oil rig, and WTI turns lower.
    Michael Filloon, Contributor 21 Mar 2016, 12:35 AM Comments (4564) |+ Follow |Send Message
    Author's reply "

    shallow sand, Oil price forecasts are never concrete but some analysts think oil will see $60/bbl this year (this means we see it, not average it), or early next year. Lets hope oil prices are much higher next year, as it could be a tough 6 months, but if things go well the oil markets will balance at that point.

    shallow sand 21 Mar 2016, 12:59 AM Comments (148) |+ Follow |Send Message
    We have discussed this before. $20 long term = destruction of the US oil industry, which will be followed by a massive oil super spike. Commodity volatility is not good for the world economy. What is not good for the world economy is not good for the US economy, generally. $100 is not good. $20 is not good. But we are all entitled to our own opinions.
    shallow sand 21 Mar 2016, 06:10 AM Comments (148) |+ Follow |Send Message
    Very good point, Michael. I would rather see the DUC wells completed, before rigs are added, as there is no good DUC count quoted, and it seems traders aren't trading off that. It seems more logical to complete all DUCS, than add rigs, if prices rise.

    But, there were some long rig agreements entered into, compared to completion agreements. I hope you are right about $60. I hope you know my primary beef with the shale industry is the failure, a long time ago, to acknowledge they cannot win a "to the death" price war with Russia and Saudi Arabia. In retrospect, had this been acknowledged, with activity limited to establishing HBP, I doubt prices would have stayed so low. I note that prices jumped almost immediately after 10K came out, showing there are no future net cash flows for these companies at sub $30 WTI. However, when shale continues at it, claiming massive cost and production improvements that will make $30 work, it sends the wrong signals to the market concerning where prices should be, IMO. What shale has done is truly remarkable on the production side, but the companies seem to forget they are in business to make money first. This is why EOG's $30 competition with OPEC statement surprised me. I had viewed them as disciplined, they stated as much, then came out with that presentation. Very confusing. In summary, we own production in a very shallow, old field.

    The field was old in the 1970s, annual decline is less than 2%. Since 1997, when I started, I have lost $$ two years, 1998 and 2015. 2015 was worse than 1998. 2016 is setting up to be worse than 2015. An example I use is Coca Cola. What happens to them if top line revenues drop 70%? In one year? Or Apple, or any other company in any industry.

    Pablomike 21 Mar 2016, 08:20 AM Comments (3991) |+ Follow |Send Message
    I agree with Mike about tracking completion crews. CLR has 135 DUCs and expects to exit 2016 with 195. EOG has some 300. HAL and many other sources estimate as many as 4,000 DUCs. However this includes wells on pads just waiting for crew not higher oil price. Maybe 2,000 waiting on higher oil???
    Michael Filloon, Contributor 21 Mar 2016, 10:32 AM
    shallow sand, It would seem that many of the "better" rigs were kept on contract and instead of paying to end the contract early they just kept drilling for wells to be completed at a later date. I would agree with you in that this is not a great way to run business. Spending investor money to do work that may or may not get done depending on oil prices isn't the best way to run a business.

    Normally EOG is one of the more disciplined operators, but I would guess everyone is a little scared, and fear does a better job than anything of getting people to make poor decision choices. Not saying it is right, especially since some investors don't know what is meant by such statements. Operators seem more scared what a production decrease announcement would do to stock prices than working for a profit. 2016 could still have significant pain ahead. Since supply and demand is only off by a couple percent, it has just taken way too long to correct. Something to be said for massive overproduction, at least the bottom is hit hard and fast.

    Michael Filloon, Contributor 21 Mar 2016, 12:45 PM
    Pablomike, More importantly, how many of those are in marginal areas that will need $70 or $80 oil to complete? Some operators were still drilling marginal wells when this all started and then just decided to sit on those holes and wait. I am guessing the newer DUCs are probably in core or Tier 2 type acreage, but some of this overhang could end up sitting for a while (while some operators will go out of business and never complete). I would say somewhere in between 4000 and 2000 is a good number, but that one I don't know for sure.
    21793061 21 Mar 2016, 12:48 PM Comments (591) |+ Follow |Send Message

    EOG had a hefty rig penalty if they stopped all drilling. They were clear about this on the call and that is why they are drilling DUCs. The money is effectively gone already. Sunk cost.

    They would be drilling less (maybe not at all) in the Bakken if it were not for the rig contracts. I suspect same is true for CLR although details were not pinned down as well in their conf call. The meme of crazy E&P companies is overdone by the peak oilers.

    Remember these are the same critics who complained about growth when oil was at 100+. These E&Ps are very NPV oriented and they have CRASHED the amount of drilling down. There is a limit to how fast rigs can roll off. But we are already down to sub 400.

    Gtoz 21 Mar 2016, 01:19 PM Comments (390) |+ Follow |Send Message
    The backlog of DUCs is already shrinking. Wolfcamp/Bone Spring and Eagle Ford formations - in each of those formations, the excess has fallen by about 150-175 over the past six months, bringing the surplus to around 300 wells in each.

    In North Dakota, it might not be economic. There, the number of DUCs climbed above 1,000 in September before falling to 945 in December, according to the latest data from the state's energy regulator.

    Wood Mackenzie reckons that the backlog of excess DUCs will decline over the next two years and return to normal levels by the end of 2017. It is expected to fall 35% from current levels in the Bakken and 85% in the Eagle Ford by the end of 2016.

    These are excerpts from the following article released today:

    http://bit.ly/22spvww

    So, Bakken 1,000, 300 each Permian and Eagle Ford = 1,600. Other formations? If one excludes NG Marcellus/Utica etc, perhaps other primary oil formations would bring total to 2,000?
    Pablomike 21 Mar 2016, 02:32 PM Comments (3991) |+ Follow |Send Message

    Michael,

    Good point. I suppose we need to categorize DUCs. Some operators realize they have poked holes in some really lousy rock and won't complete without much higher prices. Some like WLL, while in their best core acreage, will keep poking holes but won't complete ANY wells until prices rise. Then there is EOG which claims profit at $30 oil but has as many DUCs as anybody.

    Gtoz 21 Mar 2016, 06:47 PM Comments (390) |+ Follow |Send Message
    re: DUCs. I wanted to update my previous post. After reading again the cited Reuters article, I realize one has to differentiate between their talking about 'excess' DUCs (above average) and actual nominal DUCs.

    So, consider the following excerpt: "Typically, average DUC inventory is around 550 in the Wolfcamp/Bone Spring formations and around 300 in the Eagle Ford....In each of those formations, the excess has fallen by about 150-175 over the past six months, bringing the surplus to around 300 wells in each." So if the surplus is 300 each, then the total DUCs would be 850 in Wolfcamp/Bone Spring and 600 in Eagle Ford. So formation totals would = ~1,000 Bakken + 850 Permian + 600 Eagle Ford = 2,450 for these three formations. Anyone have any insight on where the remaining oil primary formations currently sit at regarding their DUCs?

    Forty Years a Speculator 21 Mar 2016, 07:06 PM Comments (50) |+ Follow |Send Message

    I have grave reservations about the alleged spare capacity of Iran. The assumption is that the big, bad sanctions resulted in a huge drop in Iran's oil production. I am not buying it. I think the sanctions were a joke. For starters many nations refused to take part in the sanctions. Nations like India, china, japan and South Korea for starters. It would not be difficult to then reexport this oil to the rest of the world on the sly.

    Would you please comment on this important matter. Does anyone have any inside information about this?

    nuassembly 20 Mar 2016, 11:25 AM

    Comments (13) |+ Follow |Send Message

    Agree, most of us follow news as herd effect, but devil is in the detail.

    Before the sanction, Iran was export 2.5 million barrels of oil per day but had to import almost 0.5million barrels of processed fuel, gasoline and diesel.

    Now, 4 years after the sanction starts, Iran already built up the refinery capacity, so it will no longer need import of refined fuels; instead it will be exporting, how much is yet to be decided. So, right there, we will see over 0.5 million barrels of reduction in the oil to be exported from Iran. Yes, the sanction reduced the Iranian oil export from 2.5million to 1.5million per day, but the net effect after sanction now will be less than 0.5 million per day to the world market.

    Michael Filloon, Contributor 20 Mar 2016, 01:47 PM

    Author's reply "

    40 years, I would be surprised if you didn't have reservations. You aren't the only one. Iran's infrastructure wasn't that great before the sanctions so I would guess they are abysmal now. I don't think they can get to 4 million this year, but the problem with that is I am speculating so we will just have to track its exports and see what happens. Right now, I think it would be ok to reduce that number by 400K BO/d. I think the biggest issue is Iran thinks its possible, so maybe there is something going on we haven't thought about. Probably not, but it is still something to consider. I wasn't a big fan of the sanctions either, but some politicians would say they worked. I think it is very possible to re-export the oil the only problem is the very large volumes Iran can produce. If this was a small producer it is probably easy if you sell it cheap enough (like ISIS does).

    FracDaddy 20 Mar 2016, 12:16 PM

    Comments (6) |+ Follow |Send Message

    Continental comes in 3rd, behind EOG and Hess in the Bakken. Hess has the lowest cost and 5 of the top 10 wells in the Bakken.
    Michael Filloon, Contributor 20 Mar 2016, 01:39 PM

    Comments (4564) |+ Follow |Send Message

    FracDaddy, I agree on EOG, but I wouldn't say they are really Bakken focused. I think they like the Eagle Ford and Delaware Basin better. I would probably call them a top Eagle Ford pick though. Hess has done a great job with costs and has excellent margins, but they are still doing sleeves for the most part, and I don't think they offer as much from a growth in production per foot perspective. I probably like EOG more and HES less than CLR but I wouldn't say I dislike any of them.
    nuassembly 20 Mar 2016, 05:38 PM Comments (13) |+ Follow |Send Message
    Michael,

    Do you know why CLR drilled much less number of wells in the Springer than the Woodford below? If the economics for Springer is much better than Woodford as CLR said before (such hype like "3X better" is no longer in their latest PPT), they should be targeting Springer, like they are targeting STACK? The 300K curve in 240days in Woodford is for wet gas or NGL, probably not even light condensate.

    Looking at CLR's 2016 plan, they will drill almost zero wells in Springer. Is it possible Springer actually is hard to drill? Studying the Springer/STACK/Meramec and found that these stacks,although quite thick, i.e. >400', they are not homogeneous, meaning the sweetspot layers could be hard to locate within <50'. This is different than the Woodford shale below, where the target is well defined, i.e. the core is in the shale. It is easy to do geosteering using gamma.

    Report Abuse Reply 1 Like

    Michael Filloon, Contributor 20 Mar 2016, 01:49 PM Comments (4564) |+ Follow |Send Message
    nuassembly, I think it has much to do with what you said. They are still getting comfortable with the Springer geology while the Woodford is already seeing pilot projects. The Springer definitely looks better though. I cant comment on the wetgas/NGL versus light condensate comment, as Im not sure about that.

    It is possible that right now CLR doesn't want any failures given the current economic conditions (especially with no hedge book). Thank you for sharing your knowledge with respect to the Springer/STACK/Meramec.

    marpy 20 Mar 2016, 05:48 PM Comments (1577) |+ Follow |Send Message
    You are using old info - at lot of SAGD oil sand production has half the costs indicated in your chart. To may authors just scrape up the old obsolete charts that are out there and use them in their articles.
    20 Mar 2016, 02:16 PM Report Abuse Reply 0 Like

    Michael Filloon, Contributor

    Comments (4564) |+ Follow |Send Message

    Author's reply "
    marpy, Sorry if you didnt like the chart. Feel free to share links to any charts you feel are appropriate. The article had little to do with oil sands, but if you think PIRA's data is off feel free to correct it in future comments. Have a good day!
    Bruce909 Comments (26) |+ Follow |Send Message

    Is this article a joke? Discussion the investment value of an oil company that does not pay a dividend! Executives may be getting fat on this company, but I doubt this result for stockholders.

    Michael Filloon, Contributor 20 Mar 2016, 03:40 PMComments (4564) |+ Follow |Send Message
    Bruce909, No joke and no one is getting fat of any oil companies right now. When investing we generally try to estimate where companies and oil prices are going not where they are right now. I don't know what the plans are for a dividend, but CLR and most unconventional producers aren't in a position to do much. Thanks for the comments, and glad I could make you laugh :)
    21793061 20 Mar 2016, 05:53 PMComments (591) |+ Follow |Send Message
    I don't see why HBP drilling a couple years ago was such a great decision. After all, the costs were higher at that time, then they are now.

    Also, the value of the acreage has dropped. Would seem to have been better to keep the cash and wait to HBP (or let leases lapse even) now. The one possible benefit from CLR's approach might be that they have stuck to a plan and done a huge Design of Experiments assessment of geology and completion techniques across the basin. And then there is some value of that. I don't really buy that though. Don't think that kind of knowledge has as much value in the world where marginal acreage doesn't get drilled, in a world where downspacing is less. (Because oil is worth less.)

    For that matter, I have read that many companies put too much value on data points that they acquire themselves and too little value on the data that is easily acquired on wells that competitors did (from logs, cores, NDIC database, DrillingInfo, etc.). So, I don't really buy it as a rationale. But just listing it as a possibility.

    Michael Filloon, Contributor 20 Mar 2016, 04:47 PM
    21793061, Thanks for the comment. In hind sight you are definitely correct. I bet the mineral rights owners are happy they got the royalties they did (and I am happy for them too, but wish Bison73 would have gotten more). I think many thought we would have high oil prices for a long time, as not too many thought it would be possible for unconventional production to grow enough to cause a glut. That said, you are correct. Bigger names with some cash will make out like bandits, as they are able to add acreage at what will look like great deals in a year or two.
    phaedrus1952 20 Mar 2016, 06:48 PM Comments (69) |+ Follow |Send Message
    217930681 CLR actually has small working interests in a great many of the wells that their peers drilled with operational control. Hamm has said repeatedly that CLR studied and learned just about everything that occurred with these non operated wells.

    They have a huge amount of acreage with minimal second and third bench TF development ... to say nothing about the almost nonexistent delineation of the fourth bench.

    CLR has made an enormous investment very early on in the Bakken.

    When prices recover, they are apt to reap significant benefits.

    Bison73 20 Mar 2016, 08:08 PM Comments (589) |+ Follow |Send Message
    Mike - my mother signed the rights for that royalty although her initial rate was 12 and 1/2%. She is 91 years old and when they came and initially got the rights (back in 1985 or so) it was considered a good rate. That's why I sometimes laugh at everyone who thinks that mineral owners in the Bakken got 20% especially in the Parshall area (EOG prime area).

    And my mineral acres are between Van Hook and New Town! I am not complaining by the way. Some people unknowingly sold their mineral rights when they sold their land and when the reservoir was created the Corp of Engineers bought a lot of land and a lot of people lost their mineral rights but I digress!

    Michael Filloon, 20 Mar 2016, 09:05 PM
    Bison, I am guessing any rate in that area would be pretty good. When people start talking about royalty payments the number always seems to get bigger as each person passes the rumor around. When the deals were signed in Parshall Field no one new the volumes of oil the operators would get out of the ground, or how high oil prices would go.
    Bison73 21 Mar 2016, 12:56 AM Comments (589) |+ Follow |Send Message

    Michael -

    Thanks for the comment. Since Parshall is my hometown I know quite a bit about what happened during the run up to the Bakken boom. Landmen were throwing money (what people in the area thought was a lot) around and they signed on the dotted line very quickly. I remember bonuses being paid in 2010 in the thousands of dollars/acre range which in hindsight was insane.

    Oil Can 21 Mar 2016, 12:50 PM Comments (348) |+ Follow |Send Message

    Michael - nice article, some really good data here. I'd like your opinion on something, if I may. Shale plays have completely changed the game over the past few years. Their startup economics is pennies on the dollar compared to say, deepwater, where only the biggest players could play and the investment costs were enormous before even a single barrel of oil was produced. Relatively cheap to get into = lots of potential players. Now one of the things I've only seen mentioned in one or two SA articles is this business of "producer discipline".

    There was a recent quote by the CEO of EOG saying something to the effect that US operators had "learned their lesson" (I'm paraphrasing) and that producer discipline would definitely be an active concern going forward once the recovery comes. You appear to know the players in the unconventional space pretty well. Given the current operators and any new we may see once a recovery does come, is "producer discipline" even a remote possibility? I personally have my doubts but would like to know what you think. Thanks.

    Report Abuse Reply 3 Like

    shallow sand 20 Mar 2016, 10:05 PM Comments (148) |+ Follow |Send Message

    Oil can. Great comment!
    21793061 20 Mar 2016, 10:20 PM

    Comments (591) |+ Follow |Send Message

    In a free market (non collusion), then the only thing that enforces "discipline" is the marginal producer effect. If there are operators who produce below cost of capital (irrational), then eventually the market disciplines them.

    Conversely if there is irrational hesitation to invest, then other entrants will come and take the opportunities. It makes me cringe to hear all this talk about "discipline". Reminds me of Dick Cheney talking about reducing volatility.

    These are code words for collusion. Fortunately this is against the law and also difficult to achieve, given all the small producers. Well...fortunate for consumers. For producers, they would love to have them some collusion. Even better if OPEC will do the job for them.

    seeking betta 20 Mar 2016, 10:29 PM Comments (580) |+ Follow |Send Message

    Michael - any thoughts on the Devon Scoop/Stack acreage?
    nuassembly 20 Mar 2016, 10:44 PM Comments (13) |+ Follow |Send Message

    Devon paid 1.6Billion in the past December, 3 months ago, for Felix acreage. It is $20K/acre!!! while oil price dipped below $40!!

    According to CLR STACK PPT, more than half of the Felix acreage is outside (east) the so called "Pressurized zone", which means under par?

    According to CLR's initial Springer story, it is over 200' thick, while Newfield claimed it is as thick as 700'. Boy, that means everywhere you drill there is oil--- it can not be that easy, you need to be able to geosteer in the sweet stack, e.g. within 50' of the 700' possible. Do you see that CLR is no longer mentioning its Springer in their latest report?

    My speculation is that they will have similar challenges in Springer, or even greater challenges, in the STACK than in Springer.

    21793061 21 Mar 2016, 12:14 AM Comments (591) |+ Follow |Send Message

    1. Does the Felix transaction make you think less or more of CLR assets?

    $1.9 B for 80,000 acres per this link: http://devonener.gy/1R...

    That's $23,750/acre.

    Not sure how CLR and Felix compare in sweetness (or in wells dug and producing, i.e. steel in the ground.) But just looking at the latest CLR conf call powerpoint, they have 595,000 acres of STACK & SCOOP. If you make simplest assumption and say same price as Felix than that gives you $14.1 billion for their OK acreage.

    2. I agree that they don't seem to be pushing the Springer as much as earlier. That said, it was still in several pages of their PowerPoint and in the 10-K. So not sure what you mean when you say "no longer mentioning". And which CLR report are you referring to?
    dducolo 21 Mar 2016, 04:53 PMComments (15) |+ Follow |Send Message
    Michael, Thanks for all the work you put in for this article. Lots of good information.

    The one problem I have with most oil companies, is using BOE. It was refreshing to see CLR state actual bbls /day in their presentation. Look like decent wells but they are going to have to reduce their CWC to make it a great play. I expect a year from this time, these well cost will have decreased significantly.

    greenlaw7777 21 Mar 2016, 01:13 AM Comments (5) |+ Follow |Send Message
    Excellent article, but my question is one of changing the oil curve. Most of CLR's success had been as oil stayed above $80.BBL from 2003 until 2014. If we are resetting the standard price based on supply and demand oil could end up between $15-$45 for the next 2-4 years. How can CLR sustain a longer period of lower prices with the amount of debt currently to equity, and taking into consideration the low float? I cannot recall a time when they were as cash strapped as they are now and debt ridden.

    If I understand your theory oil would have to be $40-$80 and if you compare current supply to that of 1985 I believe too many investors are forgetting how long we can stay in the lower end of $25 BBL.

    shallow sand

    green law. If you have the time, go to the section near the back of CLR 10K where is contained future cash flow estimates for the years 2013, 2014 and 2015. Reduce the estimate of future cash flows to $25 billion and estimated future income taxes to zero for 2015.

    Undiscounted future net cash flows fall to $7 billion under your pricing scenario, which means trouble given company debt levels.

    [Mar 22, 2016] Calculating shale break even price

    Notable quotes:
    "... A lot is written at the moment about shale break even prices of 24 to 40 usd. Every time i try to calculate those numbers, even when using best wells as per shaleprofile.com i cannot get even close to those numbers. Does somebody have the basics behind the above break-evens? ..."
    "... There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue. ..."
    "... Daniel, in 50 years of being an oil producer I had never heard the term "breakeven" until the shale oil industry came along; it is a meaningless, much overused metric. The oil industry drills wells to make money, so we can drill more new wells with net cash flow from old wells. Profitability is all that matters. Reserve growth cannot occur without profitability; unless of course you are in the shale oil business, in which case you simply borrow enough money to grow, in spite of unprofitability, and suffer the consequences down the road. Which is precisely what is happening now. ..."
    "... I don't borrow money to drill wells (that is a well known no-no) so I can't wait 60 months to get my money back on a well I've drilled and completed. Thirty six months is the maximum and even that is too long. The 150% ROI numbers the shale industry use to throw around regarding "profitability" (but certainly can't any longer!!) is insufficient return on investment to keep moving forward, at least to me. I need at least 300% ROI. If my CAPEX is risked I need even higher ROI. If I can't achieve that, I don't drill the well. I was taught these standards by many before me and they still apply today. ..."
    "... With great respect for my friend Shallow sand, I think it would actually require in excess of 120 dollar oil prices for the shale industry to be able to drill wells off net cash flow, in other words, to live within its means and not borrow money it can't pay back. As far as I am concerned the hundreds of billions of dollars it has already borrowed…we'll never see that. It's gone. ..."
    peakoilbarrel.com

    daniel , 03/21/2016 at 2:37 am

    A lot is written at the moment about shale break even prices of 24 to 40 usd. Every time i try to calculate those numbers, even when using best wells as per shaleprofile.com i cannot get even close to those numbers. Does somebody have the basics behind the above break-evens?
    Enno Peters , 03/21/2016 at 3:25 am
    Daniel,

    I can highly recommend you reviewing the presentation from Ciaran Nolan on this subject, which was presented here in January 2016.

    You also may be interested in the discussion (in the comment section) I had yesterday with Michael Filloon (a writer on Seeking Alpha), in which also a few calculations were presented: http://seekingalpha.com/article/3959718-bakken-update-continental-resources-top-bakken-player-2016

    shallow sand , 03/21/2016 at 7:08 am
    Enno and Daniel. The simple, undiscounted 60 month payout calculation has not been refuted, with really even no attempt to, since I first used it in early 2015 on LTO.

    The only real criticism that has been valid has been from Mike, and a few other oil producers, who say 60 months is too long. Mike is probably right, but I am trying to give the companies the benefit of the doubt.

    There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue.

    I have posted this model on seeking alpha several times. No successful attacks of my fifth grade math that I am aware of.

    Enno, I think you made a good point with me awhile ago that the audience needs it dumbed down. Given few can understand the 60 month payout, let alone discounting future net cash flows, I wholeheartedly agree.

    I encourage all to visit Enno's site. It exposes the 900K EUR fallacy very well. Of course, the 900K is routinely half or more BOE gas, which has been selling below $12 per BOE for months.

    There is a producer who posts on Oilpro.com named Jackie, whose posts I really enjoy. He keeps it simple, and I agree with him. If there is less money coming in the bank account than going out, you are losing money. No amount of slick investor presentations can refute that.

    Mike , 03/21/2016 at 11:14 am
    Daniel, in 50 years of being an oil producer I had never heard the term "breakeven" until the shale oil industry came along; it is a meaningless, much overused metric. The oil industry drills wells to make money, so we can drill more new wells with net cash flow from old wells. Profitability is all that matters. Reserve growth cannot occur without profitability; unless of course you are in the shale oil business, in which case you simply borrow enough money to grow, in spite of unprofitability, and suffer the consequences down the road. Which is precisely what is happening now.

    I don't borrow money to drill wells (that is a well known no-no) so I can't wait 60 months to get my money back on a well I've drilled and completed. Thirty six months is the maximum and even that is too long. The 150% ROI numbers the shale industry use to throw around regarding "profitability" (but certainly can't any longer!!) is insufficient return on investment to keep moving forward, at least to me. I need at least 300% ROI. If my CAPEX is risked I need even higher ROI. If I can't achieve that, I don't drill the well. I was taught these standards by many before me and they still apply today.

    And by the way, anybody claiming that shale oil CAPEX is not highly "risked" I submit to you that the price of oil has fallen 70% in the past 16 months.

    With great respect for my friend Shallow sand, I think it would actually require in excess of 120 dollar oil prices for the shale industry to be able to drill wells off net cash flow, in other words, to live within its means and not borrow money it can't pay back. As far as I am concerned the hundreds of billions of dollars it has already borrowed…we'll never see that. It's gone.

    Shallow you and Enno did great yesterday on Alpha; Filloon is a big time Bakken cheerleader. Those guys are getting desperate with their we're OK rhetoric now. Its not about big IP's and EUR's, it's not barrels and mcf's…its about dollars and cents, nothing else. Keep up the good work, y'all.

    Mike

    John S , 03/21/2016 at 12:41 pm
    Amen Amen, I say unto you. Welcome back Mike. It's good to hear your voice
    Mike , 03/21/2016 at 2:48 pm
    Thank you, John. You and Shallow are doing a fine job without me. Keep a bind on it, pardnor.
    Toolpush , 03/21/2016 at 5:57 pm
    G'day Mike,

    The boys, certainly did have a good time in Seeking Alpha. I feel Filloon, was getting rather pissed off by the end of the interrogation.

    Keep the bastards honest they say!

    islandboy , 03/21/2016 at 8:37 pm
    As always, it is a pleasure to read your "no B.S." comments. Cut to the chase and tell us like it is. Nice to have people in the reality based world weigh in on the madness.
    Caelan MacIntyre , 03/22/2016 at 12:09 am

    "Filloon is a big time Bakken cheerleader. Those guys are getting desperate with their we're OK rhetoric now." ~ Mike

    "My husband's company has it's own studies saying to expect 2 million barrels a day from this state in 2019 and staying at that level until around 2030." ~ dn_girl

    "We had a proud young woman post yesterday about her… optimism about… future in the oilfields of North Dakota. It is a powerful message that we should have all embraced…" ~ Mike

    "I gotta go let some good kids go. Damn, I hate that…" ~ Mike

    "As always, it is a pleasure to read your 'no B.S.' comments. Cut to the chase and tell us like it is. Nice to have people in the reality based world weigh in on the madness." ~ islandboy

    "I mix with professional people and and I know i have earnt up to double their pay scale…" ~ toolpush

    A Mouthful of Marbles

    [Mar 21, 2016] From 2008 to 2012 Chesapeake, Southwestern, EOG, and Devon spent over 50 billion dollars more than they took in

    peakoilbarrel.com
    likbez, 03/20/2016 at 2:50 pm
    I believe that $100 plus oil prices was the real fuel that fed the growth in LTO production. At that price a very good ROR was made and fund were provided.

    It was simply the situation in which Wall Street needed a place to dump money provided by Fed and shale came quite handy.

    According to Art Berman, during the 5 year period (2008-2012), Chesapeake, Southwestern, EOG, and Devon spent over 50 billion dollars more than they took in. Such a great profitability.

    [Mar 21, 2016] No company can make shale wells profitable at prices under 50 dollars WTI, and really over 80 is needed to have a good business

    Notable quotes:
    "... You also may be interested in the discussion (in the comment section) I had yesterday with Michael Filloon (a writer on Seeking Alpha), in which also a few calculations were presented: http://seekingalpha.com/article/3959718-bakken-update-continental-resources-top-bakken-player-2016 ..."
    "... There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue. ..."
    "... I encourage all to visit Enno's site. It exposes the 900K EUR fallacy very well. Of course, the 900K is routinely half or more BOE gas, which has been selling below $12 per BOE for months. ..."
    "... There is a producer who posts on Oilpro.com named Jackie, whose posts I really enjoy. He keeps it simple, and I agree with him. If there is less money coming in the bank account than going out, you are losing money. No amount of slick investor presentations can refute that. ..."
    peakoilbarrel.com

    daniel , 03/21/2016 at 2:37 am

    A lot is written at the moment about shale break even prices of 24 to 40 usd. Every time i try to calculate those numbers, even when using best wells as per shaleprofile.com i cannot get even close to those numbers. Does somebody have the basics behind the above break-evens?
    Enno Peters , 03/21/2016 at 3:25 am
    Daniel,

    I can highly recommend you reviewing the presentation from Ciaran Nolan on this subject, which was presented here in January 2016.

    You also may be interested in the discussion (in the comment section) I had yesterday with Michael Filloon (a writer on Seeking Alpha), in which also a few calculations were presented: http://seekingalpha.com/article/3959718-bakken-update-continental-resources-top-bakken-player-2016

    shallow sand , 03/21/2016 at 7:08 am
    Enno and Daniel. The simple, undiscounted 60 month payout calculation has not been refuted, with really even no attempt to, since I first used it in early 2015 on LTO.

    The only real criticism that has been valid has been from Mike, and a few other oil producers, who say 60 months is too long. Mike is probably right, but I am trying to give the companies the benefit of the doubt.

    There are outlier wells that work, but Enno's shale profile.com site is an excellent resource which shows that really no company can make these wells work at prices under $50 WTI, and really that $80+ is needed to have a good business. Remember when CLR cashed their hedges, they said they saw prices returning to $80-$90 soon. They did not. CLR and all others have cut to the bone on costs, but it is impossible to cut enough to overcome a 60-70% loss of gross revenue.

    I have posted this model on seeking alpha several times. No successful attacks of my fifth grade math that I am aware of.

    Enno, I think you made a good point with me awhile ago that the audience needs it dumbed down. Given few can understand the 60 month payout, let alone discounting future net cash flows, I wholeheartedly agree.

    I encourage all to visit Enno's site. It exposes the 900K EUR fallacy very well. Of course, the 900K is routinely half or more BOE gas, which has been selling below $12 per BOE for months.

    There is a producer who posts on Oilpro.com named Jackie, whose posts I really enjoy. He keeps it simple, and I agree with him. If there is less money coming in the bank account than going out, you are losing money. No amount of slick investor presentations can refute that.

    [Mar 20, 2016] Dramatic deterioration of s by closer spacing

    Notable quotes:
    "... I have read all about the sweet spot and certainly understood the concepts, but maybe I put a little too much belief in the corporate presentations. It is had to find a good balance, with so much information at hand, but it is also hard to come to any other conclusion with EOG, that their sweet spots are just not so sweet these days! ..."
    "... Look at Whiting. Another early entrant. 2008, 2009 and 2010 far superior to all years thereafter. Look at these two in Niobrara also. ..."
    "... I love Whiting Niobrara, 2015 well productivity. So much for all the "productivity" improvements. lol These graphs, really cut though the gloss put out by the companies. ..."
    "... I also found the EOG results quite shocking. Do note though that their average well is still performing nicely compared with other operators. I get the strong impression that EOG is only interested in clearly profitable operations, and not the unprofitable/marginal stuff. EOG has also hardly drilled into the Three Forks formation, which is clearly (>15%) performing worse than the Middle Bakken, while other operators have shifted new wells to a great extent (up to 50%) to the Three Forks. The annual total number of new wells in the Middle Bakken formation already peaked in 2012. ..."
    "... EOG was the first big operator to rapidly pull back from Bakken in 2014, and its production has halved by now since Sep 2014. ..."
    "... Although we don't yet see a major deterioration of new wells in ND overall yet, there are several areas within the Bakken where this can be found – so far this effect gets compensated in other areas. It is also striking to me that despite a drop in completions of > 30% from 2014 to 2015, there has not been a marked improvement in well productivity which you would expect as operations shifted to better areas. ..."
    "... If the meme of retreating to the sweet spots and bigger better completions was true, then we should be seeing an increase in well productivity during 2015. Certainly across some of the major companies, this is shown not to be true. This must bring doubt upon the validity of closer well spacings, that have been the flavour of the day, and allowed high intensity well pad drilling. ..."
    peakoilbarrel.com

    Toolpush , 03/19/2016 at 1:09 am

    Firstly, I love Enno's graphs. I know they have been up for a while, but today is the day I have really had a chance to explore.

    I got a shock when I looked at EOG well quality. 2013, was obviously a high water mark for well quality. But it is the poor performance of 2014 and 2015, that caught my eye. I do know EOG were one of the first to cut back drilling, and also made even deeper cuts in completions. I can understand the severe cut backs, and EOG could afford them, but I don't understand any reason why they would be selectively completing their poorer wells, especially when the drop in productivity starts in 2014. It is not just the initial production that is down. The 2014/15 continue dropping, with both about to fall below the 2010 line, which is the lowest water mark.

    I have read all about the sweet spot and certainly understood the concepts, but maybe I put a little too much belief in the corporate presentations. It is had to find a good balance, with so much information at hand, but it is also hard to come to any other conclusion with EOG, that their sweet spots are just not so sweet these days!

    EOG were the first in, and maybe the first to show the longer term future, or lack of it?

    shallow sand , 03/19/2016 at 4:29 am
    Toolpush.

    Look at Whiting. Another early entrant. 2008, 2009 and 2010 far superior to all years thereafter. Look at these two in Niobrara also.

    Toolpush , 03/19/2016 at 6:36 am
    Shallow,

    I love Whiting Niobrara, 2015 well productivity. So much for all the "productivity" improvements. lol These graphs, really cut though the gloss put out by the companies.

    Enno Peters , 03/19/2016 at 5:43 am
    Toolpush,

    I also found the EOG results quite shocking. Do note though that their average well is still performing nicely compared with other operators. I get the strong impression that EOG is only interested in clearly profitable operations, and not the unprofitable/marginal stuff. EOG has also hardly drilled into the Three Forks formation, which is clearly (>15%) performing worse than the Middle Bakken, while other operators have shifted new wells to a great extent (up to 50%) to the Three Forks. The annual total number of new wells in the Middle Bakken formation already peaked in 2012.

    EOG was the first big operator to rapidly pull back from Bakken in 2014, and its production has halved by now since Sep 2014.

    Although we don't yet see a major deterioration of new wells in ND overall yet, there are several areas within the Bakken where this can be found – so far this effect gets compensated in other areas. It is also striking to me that despite a drop in completions of > 30% from 2014 to 2015, there has not been a marked improvement in well productivity which you would expect as operations shifted to better areas.

    Toolpush , 03/19/2016 at 6:54 am
    Enno,

    If the meme of retreating to the sweet spots and bigger better completions was true, then we should be seeing an increase in well productivity during 2015. Certainly across some of the major companies, this is shown not to be true. This must bring doubt upon the validity of closer well spacings, that have been the flavour of the day, and allowed high intensity well pad drilling.

    [Mar 20, 2016] US shale is a surprisingly unprofitable miracle

    Notable quotes:
    "... Letter in response to this article: ..."
    "... From Mr T C Smith. ..."
    www.ft.com

    October 11, 2013 | FT.com

    That a company with the technical ability and cash of Shell would find production from fracked shale had not "play(ed) out as planned" should give pause to the investors and commentators who have become believers in the shale miracle.

    Mr Voser commendably took responsibility in August for a $2.1bn writedown on the value of the company's US shale assets – particularly since I also misestimated the productivity of some US unconventional gas reserves, although in a different direction.

    I had thought, when the benchmark US Henry Hub gas price bottomed at the beginning of last year,
    that a decline in gas drilling forced by a shortage of exploration and production sector cash flows would result in a very rapid rise in price to cover the full cost of production.

    Well, prices have risen, but not as fast as I imagined.

    That is due to high production from two sources that increased at greater rates than most industry people – and I – expected: "associated" gas, from oil or gas-liquids directed drilling, and gas wells in the Marcellus Shale .

    The Marcellus is a huge "play" of sedimentary rock across much of the northeastern US, with gas and liquids production concentrated in western Pennsylvania, Ohio and West Virginia. There are also a lot of Marcellus reserves in New York state, but there is effective political opposition to developing them.

    Without new production from the Marcellus, US gas supplies would probably have declined since President Obama hailed the shale revolution in his January 2012 State of the Union address. From a technical point of view, the strength of Marcellus production has been driven by shallow depth and short lead times, along with the industry's rapid productivity increases.

    Even so, there are some reasonable questions that can be raised about the Marcellus miracle, setting aside any tightening of federal, state or local regulation of shale gas drilling .

    To begin with, despite the extraordinary success of the exploration and production effort, not a lot of money is being made. Consider Cabot Oil and Gas , which has an excellent reputation for management, reserve quality and technical ability, especially in the Marcellus region.

    Last year, it chalked up a return on equity of about 9.5 per cent.

    That is good; if it were a European bank, COG would be at the head of the class, but it is not at the lighting-cigars-with-$100-bills end of capitalism.

    As Mr Voser told the FT: "[Shale well] decline rates are very high, so after 18 months your production drops very sharply, which means you have a business model of constant investment."

    That is demanding enough for a highly diversified investment grade company such as Shell; if your company is junk-rated, it is much harder.

    Also, rising Henry Hub prices overstate how much Marcellus producers have benefited from their hard work and good luck. Ryan Smith, an analyst at Bentek, an energy research firm that recently published a report on the Marcellus and Utica shale plays, points to the "basis", or discount, that Marcellus gas is getting. "Producers are constrained by pipeline capacity, which is vital. When [one of two new pipelines comes on line] in November, that will be filled up within a month. Drilling is backlogged."

    Beyond next year , though, there is a steep wall of capital demands for new pipelines, reversals of existing pipelines, export terminals, nearby chemical plants, and gas-fired power plants.

    What really surprised the industry was the continuing supply of new capital from lenders and return-short investors. This interrupted what would have been a typical oil and gas drilling cutback phase.

    In other words, yes, there is a big Marcellus effect, but it may turn out to have been superhyped by quantitative easing. We will see what happens if the oil price falls and interest rates ever rise.

    -------------------------------------------

    Letter in response to this article:

    We warned all you shale cheerleaders / From Mr T C Smith

    Related Topics

    Nick Grealy , Oct 17, 2013

    John Kemp: Why shale skeptics are wrong: http://www.reuters.com/article/2013/10/17/shale-idUSL6N0I72FD20131017?feedType=RSS&feedName=everything&virtualBrandChannel=11563

    CitrusElement , Oct 15, 2013

    The UK has over 2,000 years of shale gas. This is a proven fact. Shale gas is incredibly cheap (the price of gas in the US has plummeted) and abundant.

    We could add many percentage points to our growth if we embraced shale gas 100%. Brush aside the useless hippies and enviro-wack-jobs and get drilling. In an instant we would become 100% energy independent, household energy bills - including electric - would plummet to about only 10% of what they are now which would free up a tidal wave of money to be spent into the economy. Also, about 500,000 new jobs would be created in the shale gas industry.

    This is a no brainer! Frankly the naysayers should be arrested for treason.

    Stuttgart88 , Oct 14, 2013

    Did anyone read Dr. Tim Morgan's piece from earlier this year saying shale gas is the next big popular delusion? It was on FT Alphaville.

    He says that the whole global growth story of the last century boiled down to a "surplus energy equation": in the past, one unit of energy used could extract fuel that created 100 units of energy. But now this ratio is declining and will continue to do so.

    If it now takes 20 people to extract X amount of fuel whereas in the past it used to take 1, then that's 19 people who can't be deployed elsewhere to do other useful stuff. And it costs more to extract energy, in line with the thesis above.

    A FT front page image from about 6 months ago seemed to support this point. The FT published a "heat map" photo from space showing fracking sites in the US. They were all aglow - much more so than other production sites or towns and cities!

    MacroMacro , Oct 14, 2013

    Please - Try accrual accounting and you get a different picture - unfunded entitlements and lets not forget promises that pols will make to voters at the expense of those yet to be born.

    Jeannick , Oct 14, 2013

    The depletion rate for a well has been given as 80% in two years The well can be re-stimulated and will produce some more , any further efforts bring decreasing yield .
    an operating company must then drill one new well for each older than one year old , this just to keep their flow rate .
    there is good money but not a given, each well pan out differently

    Him Nao! , Oct 13, 2013

    If it costs $5mm per well and you recover $10mm PV over the life of the well, then it appears to be a good investment. Wash, rinse and repeat. If you spent too much on the leases and your all in cost of each well is higher than PV production values (Shell), then wind it up. One real issue for these properties is their nature as a depleting asset, an asset the rarely gets valued correctly in the markets. And one real offset for this risk is the potential for stacked plays (layer upon layer of frackable gas under the same piece of land) - for COG it's the Utica under the Marcellus, and for Bakken, Permian and Niobrara players it's multiple stacked layers. Hence the recent conclusion by analysts that the Permian basin is still one of the largest oilfields in world with future production numbers that are expected to massively surprise on the upside. FT, don't make us do your work.

    Him Nao! , Oct 13, 2013

    Analysis seems a bit limited in its understanding of the drilling business model - need to drill land to hold reserves requires lots of upfront expenses, etc. As always, the FT seems to dig enough for our attention, but not enough for conclusions worth the read.

    Alfred Nassim , Oct 13, 2013

    Idiot is a lot cleverer than he thinks.

    Dizard,

    Thank you for an article which mentions depletion - "decline rates" in a serious way. The fact is that the only people who have made serious money in this game were the people who speculated in "prime acreage" and sold it on to the big boys like Shell and BHP.

    Of course, the best acreage is that which is used early on so the idea that the productivity will always increase is at variance with geological reality. The document below shows that in the 12 months to July 2013, the number of wells in the Bakken increased by 1,628 (36%) - and the oil produced increased by 172,643 barrels per day (27%). So much for the much touted "the industry's rapid productivity increases.". True, these figures are for oil, but there is little reason to think they are dramatically different for gas.

    https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf

    I think the Red Queen understood it well: "Now, here, you see, it takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!"

    oilcat is entirely correct.

    Idiot , Oct 13, 2013

    @Felix Drost: You are quite right when you say "Shale is only profitable in a world where energy prices are high". What people tend to forget is that the shale plays were known about decades ago, and the first fracking of a well happened in the 1940's. Clearly we are only exploiting these expensive resources because all the cheap resources have been exploited and are in production decline. It's not as if they are a bonus for some great new technological achievement!

    Don Peppe di Prata , Oct 13, 2013

    truth serum | October 13 12:28am
    thank you for your reply.
    "you look into statistics on the time to drill wells, you'll see that in each emerging play, the time taken to drill and complete wells decreases over time. "
    Those would be really interesting data.
    I googled the expressions you suggested, namely Fayetteville Shale, Eagle Ford and Barnett Shale, and there comes out a flood of references.
    Would you please be more specific ? I would really appreciate.
    Is there a website where those data are available beyond anectodical evidence ?

    Felix Drost , Oct 13, 2013

    Shell paid far too much to get into the market, that's the main reason why it has a substantial write off. It bought into shale during the heady days when it seemed "There's gold in them thar hills." They took a large risk. But right now they have expanded the expertise to explore shale and are increasingly good at it.

    Shale is only profitable in a world where energy prices are high, it is simply too costly to exploit otherwise. That returns are around 10% and will probably stabilize around there isn't odd, returns never would have reached Saudi-levels, that was plain from the start. Neither do oil majors earn much from easy to access resources, the host countries typically do. 10% ROI sounds pretty good in an industry that must continue risky investments to exploit smaller and harder to access fields.

    What's great about shale in the US is the huge investments required which translate into jobs jobs jobs, powering a recovery in many states. The low ROI and high costs ensures a more equitable spread of the proceeds in the economy when compared to e.g. Saudi Arabia.

    oilcat , Oct 12, 2013

    During the 5 year period (2008-2012), Chesapeake, Southwestern, EOG, and Devon spent over 50 billion dollars more than they took in according the Houston consulting geologist Art Berman. Rapidly declining very low productivity "shale" gas wells are the culprit. The operators have to keep drilling or their production drops like a rock! The smaller public companies cannot allow this to happen or their stock tumbles and it is curtains for the company. Shell's Voser explained what many oil & gas folks in the U.S. determined two or three ago. The "shale players" over-estimated the productivity and under-estimated cost by a factor of two or more. Add the low natural gas prices and most shale plays will be gone in a few more years. Raise natural gas prices to $8 or more and the fragile U.S. economy heads south again.

    truth serum , Oct 12, 2013

    Five other operators - EOG Resources, ConocoPhillips, Continental Resources, Oasis, Pioneer. Hess, Apache are two others. Of course, not all of these are PURE unconventional plays. Petrohawk was another one but they were acquired by BHP. Don't have time to look up the stats right now. Look, if these plays were unprofitable why would companies continue to pour resources into them? I think it you look into statistics on the time to drill wells, you'll see that in each emerging play, the time taken to drill and complete wells decreases over time. Look to Fayetteville Shale, Eagle Ford and Barnett Shale for evidence.

    Would you turn to the CEO of Blackberry for an assessment of the profitability of smartphones in 2013, and future market trends? I didn't think so. Ask Ryan Lance (ConocoPhillips), Mark Papa (EOG) and Harold Hamm (Continental) what they think of unconventionals' profitability.

    baldwincng , Oct 12, 2013

    The reason Shell lost money is hey did not appreciate gas was so abundant and costs to produce it would fall so much. We have hundreds of years worth of gas

    Don Peppe di Prata , Oct 12, 2013

    Great Article.
    @truth serum | October 12 2:17am
    great remarks.
    "Shell is unwilling or unable to learn from successful operators"
    would you please list five of them ? it would be a very interesting counter evidence. Especially if you manage to mention their ROE and their Free Cash Flow.
    If I have understood well what the article means, shale gas extraction is in a profitable stage of its life cycle but, at the same time, in a negative Free Cash Flow one, because competitors need to invest a lot to keep the pace of a constant decrease of extraction costs coupling it with pre-emptive strategies on prime acreage.
    Those are the strategic business units which many years ago used to be called "stars" in the Boston Consulting Group Matrix, see http://bit.ly/1g9n21U
    moreover,
    "cutting costs in manufacturing mode while ascending a steep learning curve"
    do you mean that shale gas/oil costs are decreasing rapidly for those who keep investing? a sort of "learning by doing" (and investing)?
    again, do you have any evidence for that ?
    My interest is purely academic. Shale gas extraction industry would be worth setting up a case study and some research papers.

    truth serum , Oct 11, 2013

    Just because Peter Voser's Shell cannot figure out a way to produce unconventional gas and oil profitably, this does not mean that the industry as a whole has not figured out a way to produce unconventional gas and oil profitably. Alas, Shell is unwilling or unable to learn from successful operators. It's all about 1) getting prime acreage early and 2) cutting costs in manufacturing mode while ascending a steep learning curve to optimize well completions and spacing. Ask Harold Hamm if he thinks the Bakken Shale is unprofitable.

    October 15, 2013 8:39 pm

    We warned all you shale cheerleaders

    FT.$doc.trigger("pgObjStop", {key: "8"}); FT.$doc.trigger("pgObjStart", {key: "9", keyType: "el"}); From Mr T C Smith.

    Sir, I refer to John Dizard's article " US shale miracle is surprisingly unprofitable " (FTfm, October 14). I would question to whom this is surprising.

    My colleague Tim Morgan clearly highlighted shale's poor energy return on energy invested, which is the root of the problem, in his publication Dangerous Exponentials in June 2010.

    Of course his warnings about this troublesome equation have been universally ignored by the cheerleaders for the "US shale miracle", so I suppose to them this disappointment is surprising.

    T C Smith, Chief Executive, Tullett Prebon, Chief Executive, Fundsmith, UK

    [Mar 16, 2016] 03/15/2016 at 4:46 pm

    peakoilbarrel.com
    Aren't we missing the monthly Bakken report?
    Dennis Coyne , 03/15/2016 at 6:09 pm
    Hi Watcher,

    Yes we are, I would direct people to Enno Peters website.

    He does a fine job on this,

    Based on the latest NDIC data, total oil production in North Dakota fell to 1122 kbo/d in January, again a monthly drop of 30 kbo/d. This decline was slightly higher than I expected. The number of new wells producing dropped to 70.

    https://shaleprofile.com/

    [Mar 11, 2016] no title

    Notable quotes:
    "... Seems to be the possibility of a decrease of 200K-400K in one state over a two year period is noteworthy. ..."
    "... I think that ND production could decline to 800 kb/d by year-end only if very few new wells are drilled and completed. ..."
    "... I actually expect ND rig count and completion activity to rebound in the second half of the year. Therefore, oil production is unlikely to drop to 800 kb/d, in my view. ..."
    peakoilbarrel.com

    Dennis Coyne , 03/11/2016 at 3:30 pm

    Hi everyone,

    Ron just sent me an e-mail on the Bakken Data.

    Bakken production down -28424
    North Dakota down -30590

    ​He is busy today and will have a post up in a couple of days.

    He sent me the chart below.
    ​ ​

    shallow sand , 03/11/2016 at 4:06 pm
    Dennis: Not to steal your thunder concerning your post, but the last two months' ND data indicate an annualized decline of approximately 30%.

    Way too early to tell, but if that rate held up throughout 2016, by year end ND production would be in the low 800K range, by my math at least.

    If that occurs, I question whether the 12/14 peak could be surpassed. I suppose if operators work through their DUC inventories this year, assuming prices rebound enough, 800K range is out of question, but I think below 1 million is very likely.

    Seems to be the possibility of a decrease of 200K-400K in one state over a two year period is noteworthy.

    AlexS , 03/11/2016 at 4:31 pm
    shallow sand,

    I think that ND production could decline to 800 kb/d by year-end only if very few new wells are drilled and completed.

    Theoretically, the December 2014 peak could be surpassed, but only several years from now, and only if oil prices stay at relatively high levels (above $70) for at least 2-3 years.

    Dennis Coyne , 03/11/2016 at 4:39 pm
    Hi AlexS,

    Interesting that the scenario I created matches your estimate, or Shallow sands.

    I assume the completion rate falls to 50 new wells per month by May and stays at that level until Dec 2016.

    AlexS , 03/11/2016 at 5:15 pm
    Dennis,

    I actually expect ND rig count and completion activity to rebound in the second half of the year. Therefore, oil production is unlikely to drop to 800 kb/d, in my view.

    Dennis Coyne , 03/11/2016 at 4:35 pm
    Hi Shallow Sand,

    A Scenario below.

    Check out Enno Peters site

    http://shaleprofile.com/

    Reply

    [Mar 11, 2016] North Dakota – update until 2016-01 – Visualizing US shale oil production

    shaleprofile.com
    Based on the latest NDIC data, total oil production in North Dakota fell to 1122 kbo/d in January, again a monthly drop of 30 kbo/d. This decline was slightly higher than I expected. The number of new wells producing dropped to 70.

    I have added 2 tabs in the above presentation; one that shows the top operators, and another one that shows the gas and water production that is produced together with the oil, in North Dakota. By using the arrows you can browse through the 5 tabs.

    Drilling activity has continued to drop sharply during the last months. There were 88 wells spudded in December, 61 in January, and based on preliminary data it looks like just 30 wells were spudded in February. This sharp drop surprised me, as the drop is even more steep than the drop in rigs. This indicates that the drilling efficiency has dropped again these months.

    ... ... ...

    [Mar 10, 2016] Is It All Over Now? Producers Lose Their Appetite For Bakken Crude Output by Sandy Fielden

    Notable quotes:
    "... A number of signs point to the decline in production continuing during the rest of 2016 unless there is an extended oil price recovery. For a start, the number of new permits to drill wells in North Dakota is at a seven year low – indicating a low appetite for drilling (more on that in a minute). Second, there were 1183 inactive wells in the state in December - about 30% above normal for this time of year. The operators have essentially abandoned these inactive wells – usually because they are losing money. Many of these inactive wells are older and had very low production rates - less than 35 b/d. Such older wells are known as "stripper" wells and their costs are long ago written off – so operators usually keep them running unless transport and maintenance costs exceed the value of the crude – i.e. prices get too low. ..."
    "... The strongest indicators of a slowdown in Bakken production come in the reduction in drilling rigs operating in North Dakota and a parallel decline in the number of well completions. We'll look at the rig count first then get to completions. ..."
    "... The combination of the potential tax incentive early in 2015 and the extension of the one year limit in October led to a growing backlog of DUC wells in North Dakota that is now having an impact on production forecasts ..."
    "... It seems that those producers who can afford to are increasingly opting not to complete Bakken wells but instead to leave DUC wells "on the shelf" as a kind of storage play – waiting for prices to improve. ..."
    "... Many smaller companies do not have the luxury of waiting and many of these are likely to be either already casualties of the price crash or living on borrowed time (see Zombies ). ..."
    "... The summary chart shows that at $30/Bbl - to achieve a consistent IRR above 20% (for even the highest cost wells) - producers need to target wells with an IP of at least 1500 b/d. Looking at historic drilling and production records, NDPA found only 63 wells – concentrated in McKenzie, Mountrail and Dunn Counties that had IP rates of 1500 b/d or higher. Those 63 wells represent just 1% of the 6000 Bakken wells that would breakeven if wellhead prices were between $55 and $70/Bbl. In short the analysis makes clear that only a fraction of existing wells would breakeven or produce an acceptable IRR at today's low crude prices. ..."
    "... The expectation that oil prices might remain low for a long time is rapidly sinking in for U.S. shale producers. Many smaller operators have already fallen victim to bankruptcy but now even those with a strong balance sheet are recognizing that continued drilling and production no longer make financial sense. As a result all expectations are that U.S. shale production will tumble this year (although despite the suggestion in today's title it is not quite "all over" yet). The situation on the ground in North Dakota that we have reviewed today indicates that the slowdown is gaining momentum. The extent of any decline in production is still hard to forecast accurately – clouded as it is by the unknown impact of an increase in DUCs. As 2016 progresses you can be sure that we'll be keeping a close track on the trends for you. ..."
    rbnenergy.com
    For the past, year many shale oil producers have defied the expectations of many and kept output at or near to record levels in the face of falling oil prices and much tougher economics. Improvements in productivity, cost cutting and a concentration on "sweet spot" wells that generate high initial production (IP) rates have all helped cash strapped producers survive. But with oil prices so far in 2016 stuck in the $35/Bbl and lower range and with the worldwide crude storage glut still weighing on the market – producers are finally pulling back. Today we look at how increased pressure on North Dakota producers is putting the brakes on Bakken crude production.

    In December 2015, crude production in North Dakota Bakken fell by 2.5% to 1,152 Mb/d (from 1,182 Mb/d in November). That December output is down 6% from the record 1,227 Mb/d produced a year earlier in December 2014. Lynn Helms – Director of the North Dakota Industrial Commission (NDIC) Department of Mineral Resources commented in a February 2016 press conference that the December 2015 drop in production was the first significant decline in North Dakota crude output not explained by other factors such as weather. A number of signs point to the decline in production continuing during the rest of 2016 unless there is an extended oil price recovery. For a start, the number of new permits to drill wells in North Dakota is at a seven year low – indicating a low appetite for drilling (more on that in a minute). Second, there were 1183 inactive wells in the state in December - about 30% above normal for this time of year. The operators have essentially abandoned these inactive wells – usually because they are losing money. Many of these inactive wells are older and had very low production rates - less than 35 b/d. Such older wells are known as "stripper" wells and their costs are long ago written off – so operators usually keep them running unless transport and maintenance costs exceed the value of the crude – i.e. prices get too low. A third indicator of declining producer interest in the Bakken is the large number of producing wells in North Dakota currently being transferred (sold) by one operator to another – 697 wells as of February 17, 2016 according to Helms. Some large producers such as Occidental Petroleum that is selling 346 wells - are leaving the North Dakota Bakken oil patch altogether. Others that are staying in the Bakken have sold off wells to other operators to raise cash – including Whiting Petroleum Corp (the largest Bakken producer – selling 331 wells) and EOG Resources, grandfather of the crude-by-rail phenomenon.

    The strongest indicators of a slowdown in Bakken production come in the reduction in drilling rigs operating in North Dakota and a parallel decline in the number of well completions. We'll look at the rig count first then get to completions. As of March 8, 2016 the rig count in North Dakota stood at 33 – down 85% from the all time high (218) in May 2012. The green shaded area in Figure #1 shows the North Dakota rig count since January 2013 (right axis). The number of rigs operating hovered between 180 and 195 from January 2013 to December 2014 before dropping off a cliff from January 2015 onwards. By the end of 2015 the average rig count was down to 64 and the number fell to an average of 52 in January 2016. The NDIC has not released the February average rig count yet – but their daily count was down to 35 at the end of February. Just 16 producers operated those 35 rigs with only eight companies operating more than one rig – headed by ExxonMobil affiliate XTO who still had 5 rigs and followed by Continental Resources, Hess and Conoco Phillips running 4 each. In the past week XTO and Hess have each dropped one more rig.

    Figure #1 Source NDIC, RBN Energy (Click to Enlarge)

    Turning now to completions – by which we mean when the first oil is produced through wellhead equipment into tanks from a new well. As we have described previously – completion occurs in shale wells after the well is drilled and the hydrocarbons are stimulated to flow by hydraulic fracturing (see I Cannot Complete With Your Tax Scheme). When oil prices were riding high any delays in completions were usually practical rather than deliberate – caused by a lack of fracking crews able to complete new wells. Producers had every incentive to complete wells to get cash flowing to help finance more new drilling. But in an era of falling oil prices completion timing has become a big deal for producers because waiting for a hoped for increase in prices before producing oil has become a strategy for protecting future revenue. In North Dakota that strategy has led to a steady increase in wells that are drilled but uncompleted (the DUCs) since the start of 2015. We previously discussed how the North Dakota Legislature provided incentives for producers to hold off completions in the first half of 2015 while they waited for low prices to trigger a tax break (see Tax Scheme). Those tax incentives did not pan out due to a jump in oil prices in May 2015. However the issue of completions in North Dakota stayed on the front burner when producers began to ask for waivers from State mandated completions one-year after drilling (see Incomplete). In October 2015 the NDIC decided to issue waivers to allow producers to delay completions by up to two years from drilling. The combination of the potential tax incentive early in 2015 and the extension of the one year limit in October led to a growing backlog of DUC wells in North Dakota that is now having an impact on production forecasts in 2016. Figure #1 shows NDIC data for well completions - that have been falling (blue line left axis) and wells waiting on completion that have been increasing since mid-2014 (red line left axis). As of the end of December 2015 there were 945 DUC wells in North Dakota – down from an all time high of 1080 in September 2015 but 26% higher than the 750 DUCs the previous December (2014).

    It seems that those producers who can afford to are increasingly opting not to complete Bakken wells but instead to leave DUC wells "on the shelf" as a kind of storage play – waiting for prices to improve. A couple of weeks ago (February 27, 2016) the largest Bakken producer - Whiting Petroleum - stated in an earnings report that they would suspend well completions in the Bakken in April 2016 until prices rebound. In the meantime they will maintain 2 drilling rigs in North Dakota – basically increasing their DUC inventory with no new production. Another large Bakken producer Continental Resources announced plans in their January 2016 guidance to defer completing most Bakken wells in 2016 - increasing DUC inventory from 135 at year-end 2015 to 195 at year-end 2016. Note that we are just highlighting DUCs in North Dakota here but this phenomenon is widespread in the oil shale sector and has also impacted natural gas drilling in the Northeast. The strategy is only feasible for those production companies that have reasonably robust balance sheets and can afford to wait before completing wells. Many smaller companies do not have the luxury of waiting and many of these are likely to be either already casualties of the price crash or living on borrowed time (see Zombies). It remains to be seen to what extent large increases in DUCs during 2016 will accelerate expected declines in output that have been forecast based on ever lower rig counts and low prices.

    The economic realities that are pushing operators to withdraw rigs and avoid completions in once bustling plays like the Bakken are aptly illustrated by a video presentation from the Director of the North Dakota Pipeline Authority (NDPA) Justin Kringstad at the end of December 2015. The presentation is an update on analysis Justin provided earlier in the year that is designed to show how lower oil prices impact the number of wells in North Dakota that would produce an internal rate of return (IRR) between 10 and 20% based on different drilling cost scenarios. The analysis is specific to the Bakken but otherwise similar to the models RBN uses for production forecasting that were explained in detail in out January 2015 Drill Down Report "It Don't Come Easy" available to our Backstage Pass subscribers. We are in the process of updating this analysis to reflect current drilling economics.

    The chart in Figure #2 shows a summary of the NDPA's December analysis with Bakken wellhead crude priced at $30/Bbl. That equates roughly to a West Texas Intermediate (WTI - the U.S. Domestic benchmark) price of $35/Bbl less transportation discounts to get crude to market from North Dakota. As of yesterday (March 8, 2016) WTI prices on the CME/NYMEX futures exchange closed at $36.50/Bbl. The blue bars on the chart indicate the % IRR that a producer might expect based on a range of 30-day average initial production (IP) scenarios between 400 B/d and 1500 b/d (numbers along the top of the chart). For each IP scenario there are 3 alternate well drilling and completion cost cases - $6 Million, $7 Million and $8 Million (indicated on the bottom axis).

    Figure #2; Source: NDPA (Click to Enlarge)

    As you can see the blue bars get higher from left to right as the well IP increases – because the higher the IP rate the faster the oil revenues accrue towards the IRR. The IRR rates are also higher when the drilling and completion costs are lower. The summary chart shows that at $30/Bbl - to achieve a consistent IRR above 20% (for even the highest cost wells) - producers need to target wells with an IP of at least 1500 b/d. Looking at historic drilling and production records, NDPA found only 63 wells – concentrated in McKenzie, Mountrail and Dunn Counties that had IP rates of 1500 b/d or higher. Those 63 wells represent just 1% of the 6000 Bakken wells that would breakeven if wellhead prices were between $55 and $70/Bbl. In short the analysis makes clear that only a fraction of existing wells would breakeven or produce an acceptable IRR at today's low crude prices.

    The expectation that oil prices might remain low for a long time is rapidly sinking in for U.S. shale producers. Many smaller operators have already fallen victim to bankruptcy but now even those with a strong balance sheet are recognizing that continued drilling and production no longer make financial sense. As a result all expectations are that U.S. shale production will tumble this year (although despite the suggestion in today's title it is not quite "all over" yet). The situation on the ground in North Dakota that we have reviewed today indicates that the slowdown is gaining momentum. The extent of any decline in production is still hard to forecast accurately – clouded as it is by the unknown impact of an increase in DUCs. As 2016 progresses you can be sure that we'll be keeping a close track on the trends for you.

    "It's All Over Now" was written by Bobby and Shirley Womack and first released by The Valentinos in 1964. The Rolling Stones had their first number-one hit (in the U.K.) with a cover version in July 1964 – also a hit for the band worldwide.

    [Mar 05, 2016] In no way 55 dollar per bbl WTI price is enough to grow shale oil production without significant cost reductions

    Notable quotes:
    "... I do not agree that $55 (assume WTI) is enough to keep the basins flat or grow production, without significantly more cost reductions. The company 10K, demonstrate that. Not enough future net cash flow. Especially as those calculations are sans interest and g & a. ..."
    "... the average Bakken well produces 190K in 60 months. 152K is assumed 80% NRI. ..."
    "... These guys just throw out prices, never any substance behind what they say. For once I would like to see an article that walks through the numbers and proves us wrong, but they can't, so they won't. ..."
    peakoilbarrel.com
    shallow sand, 03/05/2016 at 8:31 pm
    I do not agree that $55 (assume WTI) is enough to keep the basins flat or grow production, without significantly more cost reductions. The company 10K, demonstrate that. Not enough future net cash flow. Especially as those calculations are sans interest and g & a.

    Again, the average Bakken well produces 190K in 60 months. 152K is assumed 80% NRI.

    152,000 x $48 per barrel (assumed $7 basis discount) is $7,296,000.00

    $7,296,000.00 less 10% severance = $6,566,400.00

    Subtract gathering of $1.50, LOE of $8 and G &A of $2.50. We are now at $4,742,000.00. This isn't enough in 60 months for a well that costs $6.5-8 million.

    These guys just throw out prices, never any substance behind what they say. For once I would like to see an article that walks through the numbers and proves us wrong, but they can't, so they won't.

    Sure, a standout well can work. Our standout wells work at $20. No one has only standouts, unless they are fairly small.

    Gary, 03/06/2016 at 10:20 am
    What is NRI? Net Return on Investments? I googled and could not find even that.

    What is LOE and G&A? What is severance? Is it a form of tax; local, state, or federal?

    Thanks for your calculations. It spells out clearly that the drillers are losing their shirts right now.

    Reno Hightower , 03/06/2016 at 12:08 pm

    NRI is Net Revenue Interest. The Net revenue to the producer LESS Royalty. SS is assuming a 20% royalty to the mineral owner.

    LOE is lease operating expenses. Pumpers, well treatment, etc

    G&A is General and Accounting. Things like human resources, overhead, legal

    Severance are taxes paid on production. Varies from state to state but everyone who gets a check pays. Royalty and Working Interest owners.

    These are all ongoing costs associated with producing a well and can add up over time. It is not just about how much does it cost to drill a well.

    AlexS, 03/06/2016 at 12:32 pm
    G&A is General and Administrative expense

    [Mar 05, 2016] It takes about a month, I am told, do drill a horizontal well, a lot shorter for a vertical well.

    peakoilbarrel.com

    Ron Patterson ,

    07/27/2014 at 10:50 am
    Actually that's just a wild ass guess. It takes about a month, I am told, do drill a horizontal well, a lot shorter for a vertical well. But I may be wrong. Mike or some other oilman may chime in and tell me how wrong I am. I found this so it looks I was pretty close.

    Costs for Drilling The Eagle Ford

    While there have been instances when wells were drilled in as little as 15 days, a reasonable expectation for the time required to drill a well in the Eagle Ford is around one month.

    And this concerning the Marcellus: Marcellus Shale FAQs

    How long does it take to drill a well and begin producing natural gas?
    Horizontal drilling currently takes approximately 18-25 days from start to finish. Then, the well needs to be fracture stimulated in order to release the gas. It is then connected to a pipeline, which transports the gas to the market. From drilling to marketplace, the entire process can take up to 3-4 months.
    Mike , 07/27/2014 at 1:08 pm

    Mr. Patterson, I enjoyed this post and sent it immediately to my employees and my family with a beware or be square header; I can't give you a bigger compliment than that. I hope it gets attention outside the peak community.

    A typical 14,000 ft. TMD well in unconventional shale takes about 3 weeks, spud to TD, you are correct. They can blow them down these days because there are no intermediate casing strings to set, or logging or evaluating to do going down, and the top drives they use now, instead of rotary tables, makes the radius and lateral a piece of cake. To reach some economy of scale, as we now know, they drill multiple wells on long pads simply being able to walk the rig from well to well; that is where the 2 1/2 to 3 weeks per well number comes from, IMO. It takes a good week to tear down a big rig, load it out (35-50 loads), get it down the highway, unload it, put it all back together again and ready to turn to the right. In that case, 4 weeks, plus.

    I think we can't use unconventional shale data for well time or costs in Russia, however. That's all typical conventional reservoirs, many of which are under pressured, and over pressured, require several casing strings and everything in Russia happens in very slow motion. Many big fields in Russia range greatly in depth too.

    While I am on, I always get a kick out of the notion that other shale resources throughout the rest of the world will save the day. The maps sure look perddy. But no other country in the world will have the ability to develop its shale resources as efficiently, and cheaply, as N. America can, IMO.

    And by the by, here in the US all we can hope for from shale is internal rates of return of 70-80% of total CAPEX, over 20 years, so the shale industry hopes.

    Can the rest of the world find the money to get on the shale treadmill, for only those kinds of returns? No way, Jose. I always like to remind folks who look forward to abundant shale production from the rest of the world…of Poland.

    [Mar 05, 2016] The rig count will not increase following the recent uptick in oil prices because access to financing for shale companies is now cut

    Notable quotes:
    "... Offshore oil exploration success has not been good recently. Admittedly there was a hit in the GoM from the BP disaster and now the price collapse, but in the past some of the best quality finds occurred in slow down periods. ..."
    "... The decline rates for deep water are very high, not quite in the LTO league but requiring a lot of drilling to keep the production facilities at high capacity ..."
    "... For me that would present much higher risk to future price volatility than for what I would think of as "conventional" developments, so requiring bigger resources and/or guaranteed higher prices for FID decisions. ..."
    "... George, US is NOT the world. Canadian conventional drilling slowed greatly already a year ago. Deep water drilling plans off the cost of Africa and North Sea are also cancelled. Shell Arctic drilling is cancelled. Are you telling me that all these worldwide projects are equivalent to 3 mediocre Shale plays in US? ..."
    "... Well said -- Simultaneous production of junk bonds and shale oil was probably the most recent of Wall Street "innovations". Which under close look are always reincarnations of some old financial scam. In this case, in price range 0-70 per bbl it is just a Ponzi scheme or, at best, a speculative investment which fully relies on "evergreen" loans. ..."
    peakoilbarrel.com

    Ves , 03/04/2016 at 5:21 pm

    " expect the rig count to increase somewhat following the recent uptick in oil prices."

    I really doubt that will happen again. That already happened last spring and many got burned really badly.

    Stavros H , 03/04/2016 at 5:55 pm
    As long as shale corps. will find any kind of financing, then they will keep drilling. The only reason that they have decreased drilling by so much recently is because their access to loans has been slashed. Their last line of defense is that they have managed to issue shares on Wall Street.
    Ves , 03/04/2016 at 6:51 pm
    But at the end of the day there is way more conventional, deep water around the world that will not be drilled at these prices so on the global scale shale is just too small to make up a difference and eventually they will run out of sweet spots anyway. Shale is like one hit wonder like "99 Luftbaloons" from Nena in the 80's :-)
    Stavros H , 03/04/2016 at 7:38 pm
    The long-term for US shale oil production is definitely down, also of US oil production in general. For that there can be no doubt. But there will be ups and downs along the way.
    George Kaplan , 03/05/2016 at 7:07 am
    "conventional, deep water" is a bit close to an oxymoron for me. And is there really "way more" of it or has that just been wishful thinking as we've run out of other plays?

    Offshore oil exploration success has not been good recently. Admittedly there was a hit in the GoM from the BP disaster and now the price collapse, but in the past some of the best quality finds occurred in slow down periods.

    The discoveries I've seen recently have mostly been small gas fields. But Marathon and COP look to have lost interest. The decline rates for deep water are very high, not quite in the LTO league but requiring a lot of drilling to keep the production facilities at high capacity .

    For me that would present much higher risk to future price volatility than for what I would think of as "conventional" developments, so requiring bigger resources and/or guaranteed higher prices for FID decisions.

    Ves , 03/05/2016 at 8:20 am
    George, US is NOT the world. Canadian conventional drilling slowed greatly already a year ago. Deep water drilling plans off the cost of Africa and North Sea are also cancelled. Shell Arctic drilling is cancelled. Are you telling me that all these worldwide projects are equivalent to 3 mediocre Shale plays in US?

    Volatility? Shale is synonym for volatility. So the rest of the higher cost world oil industry said "Let the Shale pump what it has to pump and then we will get back to oil business again"

    George, I can assure you that the rest of the world, including US conventional, pumps oil not for the sake of practice but for the sake of profit.

    So they will let Wall Street run their shale pet project to the ground and go back to business later.

    likbez , 03/05/2016 at 11:44 am
    Ves,

    let Wall Street run their shale pet project to the ground and go back to business later.

    Well said -- Simultaneous production of junk bonds and shale oil was probably the most recent of Wall Street "innovations". Which under close look are always reincarnations of some old financial scam. In this case, in price range 0-70 per bbl it is just a Ponzi scheme or, at best, a speculative investment which fully relies on "evergreen" loans.

    In a Ponzi scheme the operator pays returns to its investors from new capital, rather than from profit earned by the operator in the expectation of oil price rise. This is were "unlimited" Wall Street financing of shale bubble played the crucial role. It allowed carpet bombing of shale plays with wells and eventually led to the current oil price crash. And new profits to Wall Street. A new redistribution of wealth up.

    As John Kenneth Galbraith said: "Financial operations do not lend themselves to innovation. What is recurrently so described and celebrated is, without exception, a small variation on an established design . . . The world of finance hails the invention of the wheel over and over again, often in a slightly more unstable version."

    It will be very interesting to see the situation in oil market three years from now.

    [Mar 04, 2016] Hedging only gets the job done if you can hedge at a price higher than breakeven

    peakoilbarrel.com

    Dennis Coyne , 03/02/2016 at 1:16 pm

    Hi Nick,

    Hedging only gets the job done if you can hedge at a price higher than breakeven. If the spot price is $50/b. You would need to be able to hedge at $75/b or more for the average well to break even, in practice this is not likely to happen.

    Currently the futures price in Dec 2018 is $10/b above the April 2016 futures price.

    So possibly if oil prices reach $65/b hedging might be an option, below this maybe not. (I have ignored transaction costs in this example.)

    [Mar 02, 2016] There are DUCs because there is always a delay between when the drillers finish their work and when the frackers start their work

    Notable quotes:
    "... And the number of DUCs reached their peak while prices were still high. There are DUCs because there is always a delay between when the drillers finish their work and when the frackers start their work. And the number of DUCs grew, during high prices, because there were more wells being drilled than wells fracked. ..."
    "... higher prices will only bring on more completions if there is money to pay for them, which is not a given. ..."
    "... You don't have to be an economist or a CPA to figure out how difficult it will be for oil companies to again be growing at this point. ..."
    peakoilbarrel.com
    Why would they have DUCs? Because, they are maybe profitable wells at a higher price. How is that going to affect this lower for longer nonsense?
    Ron Patterson , 02/29/2016 at 9:56 am
    There are always DUCs. There have always been DUCs, even when the price was well above $100 a barrel. In fact the inventory of DUCs grew every year that the price of oil was in the $100 range. And the number of DUCs reached their peak while prices were still high. There are DUCs because there is always a delay between when the drillers finish their work and when the frackers start their work. And the number of DUCs grew, during high prices, because there were more wells being drilled than wells fracked.

    Higher prices will bring on more completions, bringing on more production, knocking prices back down again, keeping prices lower for longer. Right or wrong, that is simple logic. It is not nonsense.

    gwalke , 02/29/2016 at 10:36 am
    Though higher prices will only bring on more completions if there is money to pay for them, which is not a given.
    Guy Minton , 02/29/2016 at 3:16 pm
    That interrupts the logic, and is not to be considered. It is not important that upstream companies are out of bucks, and nobody will lend them any. Drilling will continue to be done with cash available until which time, the coffers start filling. May take some time to put into completing those wells that are only profitable at 80. Be quacking for quite a while. However, that interrupts the logic of lower for longer, so it is not to be considered.
    Guy Minton , 02/29/2016 at 11:10 pm
    You don't have to be an economist or a CPA to figure out how difficult it will be for oil companies to again be growing at this point. It is mostly going to be funded by internal cash flow. Let's assume that EIA'S estimate of the average Eagle Ford's EUR to be 168,000 bbls, and somewhat meaningful. So, maybe the average first year's production to be 75,000 bbls. At 100 a barrel, they recover the cost of the capex, plus a little more.

    They can drill another well with positive cash flow. Probably describes the average DUC. At 80 a barrel, they are in negative cash flow. Probably, a profitable well, but negative cash flow. They did not make back enough money to drill a new well the first year. Later, next year, but not by the end of the year. So amount available for capex goes down. At 40, they may, or may not recover the cost of the well. If the DUC is an average Eagle Ford EUR, then it could sit for quite a while if lower for longer is the logic.

    That is the main reason you won't see large scale ramp ups on production until it stays over 70 for a while. A large percentage of the area is average, or less than average.

    [Mar 02, 2016] Survivor bias in determining an average well production

    Notable quotes:
    "... Another reason why production hasn't fallen as rapidly as some expected was that newer wells produce a bit more in the first couple of months, followed by a steeper decline. This can be seen from the production profiles from the different shale areas. This is more like a one-time gain however. ..."
    "... Completion is about 2/3 of the total well cost. ..."
    "... If production for a group of wells (not my model wells) completed in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015, are you seriously asserting that there is not a survivor bias issue? Or for that matter, if the percentage of plugged/inactive wells increases from 0% in 2010 to 1% in 2015. ..."
    "... The average 2008 to 2012 well will be shut in at about year 15 if they are profitable to produce at up to 7 b/d of output. This will depend on oil prices in 2023, which are hard to predict. ..."
    "... "the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015" This is a hypothetical assumption. The real number of plugged wells is low and therefore it can be ignored ..."
    "... The 50% abandonment number in five years was based on a real life case history in the Barnett Shale Play, the 2007 vintage wells on the DFW Airport Lease that Chesapeake asserted would produce "for at least 50 years." ..."
    "... So I don't see any survivorship bias. As long as we include all the wells in the data (including those abandoned) survivorship bias is eliminated. ..."
    peakoilbarrel.com

    Enno Peters ,

    02/29/2016 at 9:57 am
    Thanks for the post Ron.

    Couple of comments:
    – I think the rig count is an important metric to follow. However, some adjustment is needed to correct for the fact that rigs are more efficient now in drilling wells. Probably several reasons for this (better rigs, crews, methods, pad drilling, drilling in a closer area, etc). E.g., in ND in 2012 every rig on average drilled 0.8 well per month. In 2014 this was 1.1, and in the last few months it was 1.4. I agree with you that the rig count eventually has to impact production (it will be with some delay, and corrected with the above factor).

    – Shallow showed a comment from the Hess CEO that another reason to keep drilling was to keep at least some experienced production staff in the company.

    Another reason why production hasn't fallen as rapidly as some expected was that newer wells produce a bit more in the first couple of months, followed by a steeper decline. This can be seen from the production profiles from the different shale areas. This is more like a one-time gain however.

    – Some companies apparently do intend to drill more wells than complete them in 2016. Continental Resources plans to drill 73 wells, and complete 26 (net) wells in 2016. Note that in 2015 they actually reduced the number of wells waiting for completion by 35. Completion is about 2/3 of the total well cost.

    Ron Patterson , 02/29/2016 at 10:09 am
    Completion is about 2/3 of the total well cost.

    Thanks Enno, I did not know that.

    gwalke , 02/29/2016 at 10:44 am
    Imagine the production profile if they could complete every single well in the fracklog on the same day, vs if they complete one a day for the next 11 years.

    These are obviously absurd examples, but just to make the point that really what we would like in order to accurately predict production is a 'frac crew count' rather than a rig count, and to agree with what you say above.

    Jeffrey J. Brown , 02/29/2016 at 12:29 pm
    Re: Survivor Bias in Calculating Decline Rates

    Enno,

    Following is a link to, an excerpt from, a question I posed on a prior thread. It's my understanding that you are attempting to correct for survivor bias, in regard to decline rates, by dividing annual production by the original number of producing wells. I constructed a simple model which seems to show that this makes no difference. It seems to me that one is calculating rates of change in total production in both cases (total production or total production divided by original number of wells).

    http://peakoilbarrel.com/texas-oil-production-still-on-a-plateau/#comment-560963

    As my example model shows, one can produce a year over year rate of change chart that looks a lot like the Bakken year over year rates of change, but by the time that the decline has settled down to 10% per year, 90% of the wells completed in year one of the model (2010) are no longer producing.

    I don't know what the percentage of inactive wells is for the Bakken Play by year, for example, the percentage of Bakken wells completed in 2007 that are no longer producing, and I don't know whether the percentages are material, but there are numerous examples of very high abandonment rates in other shale plays.

    For example, Chesapeake claimed that their 2007 vintage wells on the DFW Airport Lease, in the Barnett Shale Play, would produce "For at least 50 years." Five years later, about half of the 2007 wells had already been plugged and abandoned.

    Enno Peters , 02/29/2016 at 6:37 pm
    Jeffrey,

    I don't use the well count. For each vintage group, for each exact year on production, I sum the latest 12 months production, and compare it with the total (again over all relevant wells) 12 months production of the prior year on production.

    For example, to calculate the decline rate of the 2008 vintage group, in year 4, I calculate the total production these wells had in their 4th year of production, and compared it to the total production from the same wells in year 3 on production.

    I have excluded wells that appear to have been refracked from the whole set, to try to establish the natural rate of decline.

    Jeffrey J. Brown , 03/01/2016 at 6:53 am
    As I noted in my comment, I agree that this works for volumes, but not for rates of decline, i.e., there is no difference between rates of change for total production by vintage year versus total production by vintage year, divided by the original number of wells.

    Following is an excerpt from my comment linked above:

    Following is a model with more relevant (hyperbolic) simple percentage decline rates. I assume a fully developed lease with 10 producing wells, all completed in 2010. There is one very good well, with 9 relatively poor wells. Production drops by 40%, then 30%, then 20% and then settles down to a 10%/year decline rate. The lease loses three wells per year, until it is down to the one good producing well. Here is the model:

    2010: 1,000 bpd, 10 Producing Wells
    2011: 600 bpd, 40% decline, 7 Producing Wells
    2012: 420 bpd, 30% decline, 4 Producing Wells
    2013: 336 bpd, 20% decline, 1 Producing Well
    2014: 302 bpd, 10% decline, 1 Producing Well

    From 2014 on, production declines at 10%/year, from one well.

    The exponential year over year rate of decline in total production from 2012 to 2013 was 22%/year (natural log of 336/420).

    If we divide the 2012 and 2013 production by 10, i.e., the original number of wells completed in 2010, the exponential year over year rate of decline in production was also 22%/year (natural log of 33.6/42.0)–as the number of producing wells on the lease fell by 75%.

    So, again, unless I am missing something, it seems to me that the rates of decline chart you showed reflects the rates of decline in total production by year, without any weight given to survivor bias.

    Are you disputing this?

    The only way I see to address the survivor bias issue is to show the number or percentage of plugged/inactive wells by year, on the same chart as the year over year rates of decline chart. On the example I showed, the plugged/inactive percentage would be 0% in 2010, rising to 90% in 2013.

    Enno Peters , 03/01/2016 at 7:42 am
    Jeffrey,

    I understand your example, but I don't see an issue regarding survivor bias. The 22% is the decline number I am interested in, as it reflects the total decline that can be expected for that group, for that year.

    In any case, it's a non-issue for now, as not many wells are dropping out yet (about 1% of wells a year). Let's leave it at this.

    Jeffrey J. Brown , 03/01/2016 at 8:33 am

    I understand your example, but I don't see an issue regarding survivor bias. The 22% is the decline number I am interested in, as it reflects the total decline that can be expected for that group, for that year.

    I agree that the 22% decline number reflects the decline from the wells still producing, and the percentage of plugged/inactive wells may or may not be material in regard to survivor bias. But that is not the issue. It doesn't matter whether 1% of the original producing wells or 50% of the original producing wells are plugged/abandoned at a given point in time.

    This is a math question.

    If production for a group of wells (not my model wells) completed in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015, are you seriously asserting that there is not a survivor bias issue? Or for that matter, if the percentage of plugged/inactive wells increases from 0% in 2010 to 1% in 2015.

    In any case, why not include a chart showing the percentage, by year, for the plugged/inactive wells along with the chart showing decline rates by year? For example, 100% of the wells completed as oil wells in 2010 had some level of production, and what percentage of those 2010 wells were plugged/inactive by year, as time goes on?

    Probably the best way to show a survivor bias chart is to show the number of wells showing some level of production as time goes on, expressed as a percentage of total number of wells with reported production in the reference year. That way, the slope of the curve would be in the same direction as the slopes of the decline rates. For my example, the survivor percentage by year for my 10 well model would be:

    2010: 100%
    2011: 70%
    2012: 40%
    2013: 10%*

    *2013 and subsequent years until last producing well is plugged.

    Of course, when the survivor percentage hits 0%, production = zero.

    An interesting question would be projected half-life, to-wit, how many years would it take for the survivors among a group of wells completed in a given year, e.g., 2010, to be reduced to 50% of the original number?

    As noted above, the observed half-life for the 2007 vintage wells completed on the DFW Airport Lease in the Barnett Shale Play–the wells that Chesapeake asserted would produce "for at least 50 years–was about five years.

    Dennis Coyne , 03/01/2016 at 1:09 pm
    Hi Jeffrey,

    As Enno points out for the Bakken/Three Forks after 8 years about 1% of 2007 wells that were not refracked have been permanently abandoned. The average 2008 to 2012 well will be shut in at about year 15 if they are profitable to produce at up to 7 b/d of output. This will depend on oil prices in 2023, which are hard to predict.

    Jeffrey J. Brown , 03/02/2016 at 7:35 am
    Dennis,

    Are you now arguing that the survivor bias is not material, whereas you previously, and repeatedly, asserted that there was no survivor bias in regard to rates of change calculations? Following is a link to the original question, followed by three of your comments:

    http://peakoilbarrel.com/texas-oil-production-still-on-a-plateau/#comment-560612

    Dennis Coyne ,
    02/23/2016 AT 2:06 PM
    Hi Jeffrey,

    I have given you that data in the past. The well profiles do not have survivorship bias as long as a zero is entered for output for abandoned wells.

    That is what Enno does.

    I can send you Enno's spreadsheet or Ron can, just email and ask.

    Dennis Coyne ,
    02/24/2016 AT 7:11 AM
    Hi Jeffrey,

    To me (and possibly Enno), using the original 10 wells in the denominator* is adequate to calculate the average well profile. Note that in the first five years the wells abandoned are very low (probably less than 1% per year). As I said before, request Enno Peter's data from Ron and make any chart you would like. Oh and it would be nice if you stop claiming survivorship bias when both Enno and I have repeated this several times, but you continue to bring it up.

    Dennis Coyne ,
    02/24/2016 AT 1:36 PM
    As I said before get the spreadsheet and do what you like.

    There is no survivorship bias in the average well profiles published by Enno Peters.

    End of story

    *In regard to my model

    Dennis Coyne , 03/02/2016 at 8:00 am
    Hi Jeffrey,

    As I said before get the spreadsheet and present whatever you think is important.

    I am arguing that there is no survivorship bias, and even if there were it is not important because there is so little of it.

    Or in short, I agree with Enno Peters, and will also try to leave it there.

    Jeffrey J. Brown , 03/02/2016 at 7:26 am
    Following is my original question, followed by Enno's response. My point was and is that Enno's approach is a pointless exercise in regard to rates of change, since he is, in both cases (with or without attempted survivor bias adjustments) simply calculating rates of change in total production.

    Jeffrey J. Brown ,
    02/23/2016 AT 11:47 AM
    Is there a provision for "Survivor bias?"

    In other words, how many wells that were put on line in 2007, 2008, etc. are plugged & abandoned or temporarily abandoned?

    REPLY
    Enno ,
    02/23/2016 AT 11:57 AM
    Jeffrey,

    Yes, in my ND data I always add 0 production months after the last reported month by the NDIC. So no survivor bias in the info I present.

    Jeffrey J. Brown , 03/02/2016 at 7:38 am
    And here is the question that Enno has still refused to address:

    If production for a group of wells (not my model wells) completed in 2010 declines by 80% from 2010 to 2015, while the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015, are you seriously asserting that there is not a survivor bias issue? Or for that matter, if the percentage of plugged/inactive wells increases from 0% in 2010 to 1% in 2015.

    AlexS , 03/02/2016 at 7:51 am
    "the percentage of plugged/inactive wells (completed in 2010) increases from 0% in 2010 to 50% in 2015" This is a hypothetical assumption. The real number of plugged wells is low and therefore it can be ignored
    Jeffrey J. Brown , 03/02/2016 at 8:06 am
    The 50% abandonment number in five years was based on a real life case history in the Barnett Shale Play, the 2007 vintage wells on the DFW Airport Lease that Chesapeake asserted would produce "for at least 50 years."

    As I said, it doesn't matter whether one assumes a 50% or a 1% abandonment percentage in five years, this is a math question.

    Are you guys incapable of answering a math question?

    Enno and Dennis have repeatedly asserted that that there is NO survivor bias.

    In any case, at least for people who do not reject fundamental mathematical principles, it's when, not if, that survivor bias becomes a factor in regard to year over year rates of change calculations.

    Dennis Coyne , 03/02/2016 at 8:40 am
    Hi Jeffrey,

    Lets say output was 500 kb/d in 2010 from 500 wells and in 2015 these same 500 wells were producing 100 kb/d, but only 250 of the wells were producing. If I use 250 wells in the denominator for both 2010 and 2015 to find the output of the "average" well then in 2010 the average well produced 1000 b/d and in 2015 the average well produced 200 b/d.

    There would be survivorship bias if I claimed the "average" well produced 200 b/d in 2015 and that is not what I do.

    So I don't see any survivorship bias. As long as we include all the wells in the data (including those abandoned) survivorship bias is eliminated.

    Dennis Coyne , 03/02/2016 at 8:19 am
    Hi Jeffrey,

    Could you define survivorship bias?

    Perhaps Enno and I understand this term differently from you.

    Enno and I consider output from the entire play or in my case I will often construct a hypothetical "average well" where the average well profile is equal to total output divided by the total wells completed.

    You are correct that this is a question of arithmetic.

    Let's say 50% of the wells were abandoned and initially there were 100 wells completed. If we take total output and divide by 100 to find the average well profile, then for this hypothetical average well there is no survivorship bias.

    There would be survivorship bias if I divided output by the number of producing wells to find the average well profile, but that is not what is done, I use 100 in the denominator even if there are only 50 wells producing (in the example above.)

    Dennis Coyne , 03/02/2016 at 9:00 am
    Hi Jeffrey,

    You said:

    I agree that the 22% decline number reflects the decline from the wells still producing, and the percentage of plugged/inactive wells may or may not be material in regard to survivor bias.

    The 22% decline rate reflects the decline rate of all wells completed not only the wells still producing.

    Let's say 1000 wells were completed and output was
    100 kb/d (example chosen for simple arithmetic rather than realism) in the first year, let's also assume that 1 year later output fell to 80 kb/d from the initial 1000 wells, but that 100 wells were plugged and abandoned.

    No survivorship bias
    year 1 output is 100 b/d for average well
    year 2 output is 80 b/d for average well
    a decline of 20% for first year

    Survivorship bias
    year 1 100 b/d for avg well
    year 2 89 b/d for avg well (80,000b/900 producing wells)
    a decline of 11% for first year

    I don't use the number of producing wells, I use the total wells completed in the denominator no matter how many wells are producing, that eliminates any survivorship bias.

    The answer to your question in bold is yes that is exactly what I am asserting.

    Dennis Coyne , 03/02/2016 at 9:27 am
    Hi Jeffrey,

    As long as one uses 10 wells in the denominator for all years to construct an "average" well profile there is no survivorship bias, if one used the number of producing wells in the denominator there would be survivorship bias.

    I use your model above to find a NSB (no survivorship bias) average well profile and an SB (survivorship bias) average well profile. Chart below.

    Fernando Leanme , 02/29/2016 at 11:09 pm
    Price is too low to allow wells to live long. It's as if the ground moved up.
    Jeffrey J. Brown , 03/02/2016 at 9:01 am
    As noted up the thread, I showed that dividing annual production by the original number of producing wells (10 wells in the model I showed) to correct for survivor bias has no effect on rates of change calculations. In both cases, one is simply calculating the year over year rates of change in total production from surviving wells , and as noted, it's when, not if that it becomes a material factor.

    Dennis had the following response in one of his previous comments:

    To me (and possibly Enno), using the original 10 wells in the denominator is adequate to calculate the average well profile.

    How does one respond to people who reject fundamental mathematical principles? More importantly perhaps, why should one waste one's time responding to people who reject fundamental mathematical principles?

    I think it's time for another grizzled oil patch veteran to bid you guys adieu. Good luck with your continuing efforts to, in effect, to assert that 1 + 1 = 3, because it feels like a better answer.

    Dennis Coyne , 03/02/2016 at 9:31 am
    Hi Jeffrey,

    No we are not using surviving wells in the denominator, this is what you fail to see. We use the total number of wells completed in the denominator.

    George Kaplan , 02/29/2016 at 2:20 pm
    Jean Laherrere had a post on POB that indicated a 20 to 30 month lag between rig count and production, during the expansion phase. Empirically the curves seemed to match but I don't get why the delay is that high or the correlation so close. However if true it would suggest production is going to fall off of a cliff over the next 2 to 6 months.

    http://peakoilbarrel.com/bakken-oil-peak-jean-laherrere/

    Longtimber , 02/29/2016 at 2:35 pm
    "Another reason why production hasn't fallen as rapidly as some expected"
    Rats can chew thru a PV Source circuit and you have barbecue but Future Energy Production is not Jeopardized. With an unconventional well It's my understanding that the Resource may be affected if shut in or altered. Perhaps in the environment, E&P's "can not afford" to take this risk (??)
    AlexS , 02/29/2016 at 11:00 pm
    Enno,

    Thanks for your comment.

    Baker Bughes in 2012-2014 issued well count for key U.S. oil and gas basins.
    Using the well count and rig count, they have calculated the number of wells drilled per 1 rig per 1 quarter and year.
    Unfortunately, this product was discontinued in 2015.

    Below are their numbers for the Williston basin:

    [Mar 02, 2016] I dont think rig efficiency can improve much

    peakoilbarrel.com
    Dennis Coyne , 12/26/2014 at 11:06 am
    Hi Mike,

    I was wondering about my claim (which may be incorrect), that during a bust the less qualified or hard working people get laid off and a company is left with their best workers.

    If that is correct it would seem that the elite crew that remains would make fewer mistakes and get more accomplished on average on any given day. This would tend to increase rig efficiency (number of wells drilled per month per rig) if we assume everything else is unchanged (which is never correct in the real world.)

    Do I have that part right?

    Mike , 12/26/2014 at 12:06 pm
    Dennis, company men (middle management, on site supervisors) get comfortable with certain rigs and the personal on those rigs. If Dennis is given 14 wells to drill in 2015 he will stick with H&P 395, if he can, because he is on a first name basis with the toolpusher and everyone else and they all work in 3 part harmony; hands will stay with a rig and the rig boss (toolpusher). There might be some inner rig contractor personal movement based on time with the company, etc., I don't know anymore. If Nabors 419 gets stacked, most of the hands on that rig will go to the house. When I roughnecked, and was a driller, when my rig got stacked I went mostly to the wine shop and waited it out. Certain companies generally ask for certain rigs if they can.

    Again, I don't think rig efficiency can improve much; I think I have already said as much. Those shale rigs get it and go. Its like tire manufacturing, almost. There is always a problem that comes up. Think of all the wells they have drilled in the past 7 years; everyone on a rig, and steering, and running casing, and cementing and frac'ing know what the drill is now. Fourteen wells per rig per year is what I guess, maybe 15 depending on pad stuff. Costs will not go down based on efficiency as much as competition between rig and pumping services vying for limited work.

    [Mar 02, 2016] Bakken LTO needs $80 WTI, minimum, to be a good investment

    peakoilbarrel.com
    shallow sand , 03/01/2016 at 11:53 am
    I read that CLR will return to activity if prices reach $45. At least that is the headline.

    Assuming 200K gross barrels of oil from a CLR Bakken well in 60 months, 160K net with 20% royalty, with a $7 discount to WTI, per CLR recent 10K, such a well will only gross $6 million dollars in 60 months.

    So after 60 months CLR will still be over $1 million short of reaching the cost of the well, BEFORE, considering 10% severance tax, OPEX, G & A and interest. Also, none of the land acquisition, permitting , seismic, etc is considered.

    Why do the MSM ignore this. It seems so elementary to me.

    Bakken LTO needs $80 WTI, minimum, to be a good investment. Just do my 5th grade math. Don't need any exotic presentations to figure this out.

    Ves , 03/01/2016 at 1:09 pm
    SS,
    Don't pay attention to headline. They are just part of deception game. Shale production is adjusting, US on shore is adjusting. Today I have briefly scanned that Russian paper is stating that Russian big oil have a meeting today where among the topics are "freeze" (previously discussed with Saudis, Qataris) and even some possible cuts. Pieces are coming together although it looks like at snail pace from the perspective of someone like you that is caught in this bullshit politics. But it is coming.
    likbez , 03/01/2016 at 3:10 pm
    ShallowS,

    Bakken LTO needs $80 WTI, minimum, to be a good investment. Just do my 5th grade math. Don't need any exotic presentations to figure this out.

    Exactly!

    Bakken oil production is more like mining coal than it is drilling for oil ("Red Queen effect"). All company operating in this areas have crushing debt levels. Obtaining revolving credit line when prices are below $80 might become very difficult as Bakken has the highest marginal cost of production. So this slump will last longer for Bakken then for other plays.

    Also "carpet bombing" drilling is new and might have some additional effects that we now can't predict. I would give three years on restoring investor confidence. Click to Edit Request Deletion (56 minutes and 59 seconds)

    Longtimber , 03/01/2016 at 12:36 pm
    Thanks Shallow for digging thru these filings and Uncovering what should be clear --
    Fernando posted this yearly cash flow matrix ROI for the Powerwall which shows that Energy stored via Electro-Chem can not compete yet with the Delta of baseline vs peak power rates. When I point this out to people this they think I'm clueless. Anyway – Need something like this for wells in different plays or companies to point out the Insanity. Perhaps I missed it or i'm actually clueless.

    R DesRoches , 03/01/2016 at 1:00 pm
    Three Big Shale Plays Decline Rate Going To a More Than One Million Barrels A Day!

    Using Ron Patterson's updated rig counts per play, I used that data along with production data from the EIA Productivity Report to calculate the expected overall decline rate per play.

    All data is per month.

    The Bakken has 36 rig running, and has a "New Well Production Per a rig" of 725 barrels per day, and a decline rate ("Legacy Production Change) of 58,000 b/d.

    New production (rig times rate) is 26,000 b/d so the net decline rate (new – decline rate) is 32,000 b/d

    Doing the same calculation for the Eagle Ford
    Rig = 41
    Production per rig = 800
    Baseline Decline rate = 110,000

    Net decline rate = 77,000'b/d per month

    Permian
    Rigs = 162
    Production per rig = 425
    Baseline decline rate = 83,000 b/d

    Net decline rate = 14,000 b/d per month

    Adding the net decline rate for the three plays we have an overall decline rate of 123,000'barrels a day per month.

    That comes out to a yearly rate of 1.47 million barrels a day.

    We are not at that rate today as it takes time for dropping a rig to effect production rates. I would expect to see thus overall rate by some time this summer. It is much larger than anyone is expecting.

    [Mar 01, 2016] Method of calculation of EUR of Bakken wells

    seekingalpha.com

    In a previous article " The Real Natural Gas Production Decline ", I discussed a simple and effective way of estimating the real declines and realistic EURs (Estimated Ultimate Recovery) of shale wells based on two things that shale gas and oil producers can not lie about: number of wells added during a period of time, and the total daily productions.

    The Simple and Effective Method of Estimating EUR

    The idea is simple. All shale wells are in steep decline. Thus as the producers put new wells into production, a considerable portion of the new production merely compensates the decline of existing wells. If we assume producers add just enough wells to exactly compensate for the decline, then the EUR times number of wells added equals the amount of production during the same period.

    Let me explain in formulas. Let the combined daily decline of existing wells be D, and IP being the Initial Production rate per well:

    Total_Production * D = IP * Well_Additions

    EUR = Total_Production/Well_Additions = IP/D

    In surveying several different shale plays, I found that all of them have a combined decline rate of 0.2% per day. Combined decline rate means the decline of the total production from existing wells. For example if the total production is 500 MMCF one day and 499 MMCF the next day, the 499-500)/500 = -0.2%/day.

    Thus, a rough estimate of EUR equals to IP/D = IP/0.2% = 500 IP, or roughly 500 days worth of production at the IP rate.

    Estimating the Bakken Shale Well Productions

    The North Dakota Mineral Resource Commission has a web site that publishes the shale well counts and monthly productions of Bakken.

    I decide to crunch some numbers to see the real productivity of the Bakken oil wells, using the idea discussed above. Let's start from the oil productions of the latest two months:

    Aug-2012: 635,177 Barrels/Day

    Sep-2012: 662,428 Barrels/Day

    Wells added: 170

    Let's do the calculation using the above numbers. The production rate increased by 27251 Barrel/Day in 30 days. So the daily increase was 908.4 Barrel/Day. Daily well addition is 170/30 = 5.67 wells/day. Let's assume the combined decline rate of D=-0.2% also applied in Bakken. The median production rate during the 30 days from mid Aug. to mid Sep. was 648,660 Barrels/Day. So the natural decline would have been 0.2% * 648,660 BPD = 1297.320 BPD. So 5.67 new wells per day not only compensates for loss of 1297.320 BPD, but also boost the production by 908.4 BPD. Thus:

    IP * 5.67 = 1297.320 BPD + 908.4 BPD = 2205.72 BPD

    IP = 2205.72/5.67 = 389 Barrels/Day

    So that's the IP per well that I estimates, 389 Barrels/Day. The EUR then would be EUR = IP/D = IP/0.2% = 500*IP = 0.1945M barrels.

    Consider that there are so far 4629 wells in d the accumulative oil production is 458.860M barrels, averaging 0.099M per well. My EUR estimate is roughly twice the accumulative oil production per well. So I think my estimate is pretty good.

    A good thing of my method is it is pretty fair. Let's say I over-estimated the D. Let's say the combined decline rate is less than I thought, repeating the same calculation, it results in a less IP as well. Since EUR = IP/D, a less value divided by a less value, gives you a result that is about the same.

    Let's try a D = -0.15% instead of -0.2% and see what I get:

    IP * 5.67 = D * 648,660 Barrels/Day + 908.4 BPD

    EUR = IP/D = 648660/5.67 + 908.4/5.67/D = 0.22121M Barrels

    This EUR result, 0.22121M barrels, is only slightly higher than previous result of 0.1945M barrels. It is only higher by 13.7%.

    Validating My Bakken Shale Well Production Estimate

    Now let's apply the idea to model the actual Bakken oil productions.

    Prod_Rate_Change = Prod_Decline + IP* Well_Additions

    Prod_Rate * D + IP * Well_Additions.

    Thus, knowing the previous month's production rate, we can calculate what the next month's production rate should be, by subtracting the decline, then add number of new wells times IP.

    Let me assume D = -0.2%/Day. I assume IP = 365 Barrels/Day. I further assume that in 2005, 2006, 2007, 2008, 2009, the IP was only 30%, 50%, 70%, 80%, 90% of the current IP level, as the technology was less sophisticated than today, and well productivity was less than what we get today. Let's see how my calculation looks like compare with actual production:

    click to enlarge)

    It looks like a perfect match. Thus my assumed values, D=-0.2% and IP = 365 Barrels/Day, a good numbers that give perfect fit. Had I used an IP higher or lower, my projection would not match the data.

    So based on that, the average Bakken shale well EUR is

    EUR = IP/D = 365 Barrels/Day / 0.2% = 0.1825M Barrels

    My EUR estimate is far below what producers have been pitching.

    Case Study on Continental Resources Shale Wells

    Let's have a look at Continental Resources (NYSE: CLR ), who is considered the most successful developer of the Bakken shale oil resources.

    I pulled out CLR's most recent quarterly report . Here are a few relevant numbers:

    First the capital spending of %2584.434M divided by 222 net wells completed is $11.64M per well. This is the per well capital cost, not including the production cost yet.

    What is the per well IP, and the combined decline rate D? Note that production rate increased from 0.095M to 0.103M barrels in 92 days. That's a daily increase of 86.96 Barrels/Day. If D=0.2%, the daily decline would be roughly 0.2%*0.1M/Day = 200 Barrels/Day. So the daily production increase due to new wells is 200+86.96 = 287 BPD. Daily well addition is 74 wells / 92 days = 0.804 wells/Day. Thus:

    IP = 287 BPD / 0.804 = 357 Barrels/Day

    EUR = IP / D = 357 BPD / 0.2% = 0.1785M Barrels

    These numbers look lower than the average of the whole Bakken, or IP = 365 BPD and EUR = 0.1825M Barrels.

    What is CLR's profitability outlook under these numbers? From CLR's Q3 revenue and production volume, I calculated that the unit price they fetched on the oil and gas was about $65/BOE .

    So a CLR well's expected EUR=0.1785M BOE would fetch a revenue of $65*0.1785M = $11.60M per well. But as discussed above, the per well capital spending was $11.65M. So CLR barely breaks even for the well capital spending. But the capital spending is not the only cost. We have not calculated the production and maintenance costs, the G&A costs. Thus, at the current oil price, CLR is not making any real profit in developing Bakken shale wells.

    Discussions and Investment Implications?

    So then, how could CLR manage to report positive profits for the quarters? Let me explain how it works out for them.

    Just like other shale oil and gas producers, CLR does not record well drilling capital spending as cost directly. Instead, they first record it as investment activity. The the capital cost is recognized in each quarter as depletion and armortization costs.

    I discovered that as producers tend to over-estimate the EURs and over-estimate the life span of shale wells, they end up armortizing the cost way below the fair amount of armortization they should calculated. Thus, as they under-estimate the costs, they end up over-estimate the profitability of the operations.

    But one thing they could not hide is that in quarters after quarters, the producers have consistently spend several times higher on capital spending, than the revenue they take in. Producers continue to borrow more and more on debts in order to continue their well drilling programs.

    Is a business profitable, if it continues to borrow more debts quarter after quarter, and it continue to spend several times more on capital spending, than the revenue it takes in? This is neither profitable, nor sustainable. I can see that when the banks get suspicious and stop lending money, then the shale industry will collapse.

    As I stated many times. The shale gas and oil adventure is deeply un-profitable. The "cheap natural gas replacing coal" is a pipe dream. Investors should bet their money on the rebound of the coal sector, not on the false promise of shale gas or shale oil.

    Full disclosure: I have no vested interest in CLR but I may consider a short position in the near future. I have heavy long positions in coal stocks like James River Coal (JRCC), Alpha Natural Resources (ANR), Arch Coal (NYSE: ACI ) and Peabody Energy (NYSE: BTU ).

    Disclosure: I am long JRCC, ANR, ACI , BTU .

    Stocks: CLR , CHK , UNG , EOG , COGQZQ , ACI , BTU
  • Gaucho , contributor , premium contributor Comments (879) | + Follow Following - Unfollow | Send Message But not to worry. With the US government support they are now planning on selling all of our gas overseas. That way we will be out of fuel much sooner than other wise. It will also drive the prices up here so we can be less competitive. Great planning once again by the US government. Or should I say by the corporations that control the US government. 10 Dec 2012, 08:48 AM Reply Like 1
  • Carl Martin , contributor , premium contributor Comments (1530) | + Follow Following - Unfollow | Send Message Mark, Why are you simply making this assumption? "Let's assume the combined decline rate of D=-0.2% also applied in Bakken." Because, if your assumption is wrong, then the direction of your whole article/blog is wrong. I believe that decline rates for shale gas are far steeper then for shale oil. But, do you happen to have any proof to offer to back up your assumption? Meanwhile, I will put some effort into finding some proof for my belief. But, I have noticed over at TOD, that most PO believers also assume that shale oil behaves exactly like shale gas. That's where I think you are going all wrong, but we'll see... 11 Dec 2012, 03:24 PM Reply Like 0
  • Mark Anthony , contributor , premium contributor Comments (3595) | + Follow Following - Unfollow | Send Message Author's reply " Carl Martin: The D=-0.2%/Day combined decline rate is a very reasonable assumption. The proof is right in my article and in the chart. My projection based on that value matches the actual production. Had I used a less steep (smaller) decline rate, the calculation will be much higher than the actual data. Likewise, had I used a higher IP value, the calculation will also come out to be higher than actual. You simply have to use IP = 365 BPD, and not any higher, and D = 0.2%/Day, and not any lower, to project the correct total Bakken production rate as reported. Now I do have actual proof that Bakken shale wells actuall DO decline that fast. Look at this on page 63: http://bit.ly/VAYoHb The CLR chart shows the cumulative production of Charlotte 2-22H well. They claim the IP was 1396 BPD and at the end of 9.8 months (295 days), it dropped to 167 BPD and accumulative production was 87 MBOE. Going from 1396 to 167 is a loss of 88%, and in only 295 days. That is an average decline of -0.72% per day. Much higher than the -0.2%/Day I used. Of course I am talking the combined decline of all wells, old and new. That's an annualized rate of -51.8% decline/year. I think that is reasonable. 11 Dec 2012, 04:46 PM Reply Like 0
  • Mark Anthony , contributor , premium contributor Comments (3595) | + Follow Following - Unfollow | Send Message Author's reply " I forget to embed the link to the ND statistics of historic Bakken shale oil productions, which is indicated in the graph any way. The link is: http://1.usa.gov/VCJyQv The DMR of ND has a good collection of all sorts of data. I will continue to study and analysis data related to Bakken shale wells. 12 Dec 2012, 04:06 PM Reply Like 0
  • Zoltan Ban , contributor , premium contributor Comments (898) | + Follow Following - Unfollow | Send Message Zoltan Ban 944
    Followers
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    Following
    My name is Zoltan Ban, I have a double honors degree in history and anthropology, as well as a BA in economics. I am the author of the book "Sustainable Trade" Latest StockTalk With Oil Under $60/Barrel, Shale Oil Revolution May Be Over (Permanently) http://seekingalpha.com/a/1nf8x Dec 22, 2014 Latest articles & Instablog posts Here is another, much simpler calculation, which shows that there is a reasonable chance that the whole Eagle Ford field will ultimately prove to be unprofitable.
    http://bit.ly/V7dtqs
  • [Mar 01, 2016] EUR of Bakken wells

    Notable quotes:
    "... If you dont believe what the industry is saying, then you just admitted that your point of view is based upon BELIEF, not facts. Therefore, PO is a religion. If you want it to be a science, then you have to first disprove what the industry is saying. I have noticed, that no one here is actually doing that. ..."
    "... All the recent mega activity at this site just seems to be one big cover up of the fact, that all your great PO theories got shot to shit with the recent fall in oil price due to over production from US shale. The latest figures from the EIA show that 9,137,000 bpd were being produced in the US as of 12/12/14, and that is an increase. Sorry, but that is not how terminal decline plays out in the world of reality. ..."
    "... CLR was $30 a few days ago. $80 a few months ago. Maybe theyll go bankrupt. That will really mess up Mrs. Hamms lawyers. ..."
    peakoilbarrel.com
    Carl Martin , 12/22/2014 at 10:24 am
    Sorry folks,

    But I'm having an extremely difficult time even believing, that these PO discussions about Bakken sweet spots supposedly being tapped out are still going on….AFTER ALL THESE YEARS!!!!!

    All you had to do was to look at the maps KOG was putting on their website, which show exactly where each Bakken well is drilled. Then you compare that drilling pattern to CLR's maps, which show you where all the sweet spots are. Even Rune is now "aware" that the sweet spots are largely determined by pressure gradients, which is what CLR's maps shows. I found out about all this, MORE THAN FOUR YEARS AGO !!! by simply writing an email to CLR and asking why they choked back their wells so much.

    CLR also presently claims to have more than eight years of future drilling sites available in the Bakken (at their present rate of drilling) which they say will yield more than 750,000 boe in EUR's per well. As CLR is a good proxy for the entire Bakken, what does that tell you about the future of the entire Bakken?

    I might mention that "the best" definition of a Bakken sweet spot given at this website by a true believer, "Watcher", was that sweet spots were defined by latitude and longitude, not EUR's. How pathetic.

    If you don't believe what the industry is saying, then you just admitted that your point of view is based upon BELIEF, not facts. Therefore, PO is a religion. If you want it to be a science, then you have to first disprove what the industry is saying. I have noticed, that no one here is actually doing that.

    As for this sentence from the above "article"…… " The first measured 24 hour production from Bakken wells is a very good predictor of the future production of that well." The truth is exactly the opposite, for among many other reasons, the choking history is not even taken into account.

    All the recent mega activity at this site just seems to be one big cover up of the fact, that all your great PO theories got shot to shit with the recent fall in oil price due to over production from US shale. The latest figures from the EIA show that 9,137,000 bpd were being produced in the US as of 12/12/14, and that is an increase. Sorry, but that is not how terminal decline plays out in the world of reality.

    Watcher , 12/22/2014 at 11:12 am
    8 yrs. 750K barrels EUR per well. At current 175ish/month well addition rate that's 16000ish wells added in 8 years.

    Current total 11,000ish. So 27000 wells total then. X 750K =

    about 2 Trillion barrels of oil. Don't think even CLR expects more than 50 billion, and they are bizarre. But hey, at $40 barrel Bakken sweet prices, that's a lot of money. $80 Trillion. What a bonanza.

    CLR was $30 a few days ago. $80 a few months ago. Maybe they'll go bankrupt. That will really mess up Mrs. Hamm's lawyers.

    Carl Martin , 12/22/2014 at 2:24 pm
    Watcher,

    I'm not going to even bother to check your math. Your numbers are way too far out for me. But, more than four years ago, CLR estimated 24 billion boe recoverable. That was recently upped to 62-96 billion boe "recoverable" (@$100) Call it less, if you like at today's prices. But, the Bakken is still Ghawar sized, so you can eventually expect Ghawar sized production.

    As to the number of eventual wells, try starting at 100,000, and go up from there. In the 4,000 square mile CLR designated sweet spot, their plan is for 16 wells per square mile (in four different zones) which means 160 acre spacing. That's 64,000 wells right there.

    How about Y-O-U defining what constitutes a PO Bakken sweet spot in EUR's, instead. Then, we can start communicating. (maybe).

    shallow sand , 12/22/2014 at 4:03 pm
    Carl Martin: Is an average EUR of 750,000 net bbl of oil per well accurate in the Bakken? It doesn't appear that it is when one looks through the public information put out by the State of North Dakota. Further, it doesn't appear generally that Continental has the wells capable of hitting this figure. EOG and Whiting are the primary companies to have the wells capable of 750,000 net bbl EUR, based upon public data.

    I have read on this site that 320,000 gross bbl EUR is more probable overall in the Bakken, although I am sure if people have agendas they can skew the numbers. I think at least a few of the people who post here appear to have strong enough math/science/engineering backgrounds to make some pretty reasonable calculations and are making an unbiased attempt to be as accurate as possible.

    Trying to figure out what is accurate and what is not is more difficult than what you let on, IMO. It does appear that substantially lower oil prices may provide some answers.

    shallow sand , 12/22/2014 at 4:12 pm
    Oops. The 750,000 number is BOE, so that does make a difference. The 320,000 figure I referenced is BO, not BOE.
    shallow sand , 12/22/2014 at 4:59 pm
    BTW, CLR just cut CAPEX budget to $2.7 billion. This is the second cut they have announced in about 3 months.
    Watcher , 12/22/2014 at 5:21 pm
    There is that. 2.7 Billion at $10 million/well, from the CLR Nov investor briefing, is 270 wells. For the whole year.

    Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net of Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year from new wells.

    Maybe Warren Buffett will do what he did for BoA. They created a special preferred issue for him to buy $5 B of. Paid 8% dividend or something. Hell, he may get more of Harold's money than the ex.

    Thirunagar , 12/23/2014 at 1:18 am
    "Avg flow year 1 is about 450 bpd? So incremental revs in 2015 would be 270 X 450 X $30 (net of Bakken Sweet minus royalties, taxes) = $3.65 million, for the whole field for the whole year from new wells."

    err I think you forgot that a year has 365 days? That comes out to more than 1.3 billion dollars even at these depressed prices!

    Dennis Coyne , 12/23/2014 at 9:52 am
    The average well flow for the first year is about 233 b/d, not 450 b/d (second month output is usually highest at about 400 b/d), the average well produces roughly 85 kb in year 1.

    Using Watcher's figure of 270 wells and call refinery gate oil prices $60/b, transport costs $12/b, OPEX plus other costs $8/b leaving $40/b, then we need to pay taxes and royalties of roughly 25% on wellhead revenue of $48/b, so we need to subtract another $12/b and we get to $36/b net. If 270 average wells are drilled we get about 23 million barrels of oil in year 1 for a net of $826 million. The wells cost about $9 million each for a total of $2.4 billion. Looking at a single well, we need 250 kb for simple payback (ignoring the time value of money), but the average Bakken well takes at least 8 years to reach 250 kb of output, typically a "good well" pays out in 18 months or less. At two years the average Bakken/Three Forks well in North Dakota produces about 130 kb which is about $4.3 million in net revenue and far short of a $9 million payout level.

    Carl Martin , 12/23/2014 at 11:01 am
    SS,

    No, the 750,000 boe is just a reference to CLR's claim, that they have eight years of drilling activities, that can produce that much per well. TRANSLATION: The current low oil price environment is easily weathered by simply high grading. Any company with similar property can do the same. But, many of the newer, smaller Bakken dotcoms have no such property, so their very existence is in great danger.

    It is nowhere near the average Bakken EUR.

    By the way, unlike so many others here, I don't guess anything, and have very few opinions of my own. I mostly just repeat what is generally accepted knowledge about the shale industry, because no one has so far been able to prove any of it to be wrong.

    It's just that none of my researched information supports any PO theory at all. That's the rub.

    Fernando Leanme , 12/23/2014 at 1:50 pm
    So at what cost does oil have to be produced in the future? Where are we find this oil? And are you so negative about renewables you think they won't be competitive with oil at $500 per barrel in today's dollars?
    WebHubTelescope , 12/26/2014 at 3:58 am

    "I have read on this site that 320,ooo gross bbl EUR"

    I have been using just under 300,000 for the diffusional model I put together a few years ago.

    What is nice about making early projections is that you can see how production plays out.

    Fernando Leanme , 12/22/2014 at 5:43 pm
    So where do we get the oil when the better shale zones are drilled and declining? Chinese shales?
    Dennis Coyne , 12/22/2014 at 5:56 pm
    Hi Carl,

    Enno Peters collects data on all North Dakota wells from the NDIC, the EUR of the average Bakken well between 2011 and 2014 is about 325 kb of oil, if you add in natural gas and convert to barrels of oil equivalent(boe), it increases to 406 kboe, but note that the extra 80 kboe is very low value relative to crude.

    Note that the typical well in an investor presentation is not the same as an average well. Maybe CLR only drills above average wells. :)

    Carl Martin , 12/23/2014 at 11:29 am
    Dennis,

    I don't dispute your average EUR numbers, as I don't have the neccesary info to do so. Besides that, they sound about right to me. But you need to be careful about getting too hung up in the word or concept of average. After all, what do you think is the average gender in the US in Dec. 2014?

    Investor presentations ALWAYS show their best results, and almost never reveal all the failures, that bring their averages down. This is just business as usual. But, it is okay because they are always moving up the learning curve, so by showing their best results now, they are giving a clear indication of where they expect their average results to one day be.

    Also, if you want to understand this industry, it does no good to focus on average companies, you need to look at the leaders, because they are the trend setters. Ultimately everything is based upon best practices, and EOG is presently the undisputed best at everything. They just don't keep investors very well informed. Therefore, I still get most of my info from CLR.

    This sentence of yours is not as silly as you might think. "Maybe CLR only drills above average wells." In a sense, "they do." That is to say, that they have no monster wells, that I know of, they choke a lot more than others, and they have used their standard 10,000 foot lateral and 30 frack stages well design over most of the Bakken, even when it didn't make economic sense to use it. It is because they use their standard well as a measuring stick. Now they have a fixed point for reference to compare different areas of the Bakken.

    That's why they know exactly what they are talking about, and why I accept most everything they say. You obviously don't. But, you have never given a good reason for not doing so, other than the results they are claiming don't show up in the data bases you are using. Why don't you just send them an email and try to clear up a major misunderstanding on your part? Then everyone at this website will be able to move forward.

    Dennis Coyne , 12/24/2014 at 4:10 pm
    Hi Carl,

    Continental wells with first month of output between Jan 2009 and Oct 2014 have an average cumulative output over 70 months of 186 kb, this is slightly below the average Bakken well over the same period for all wells completed(925 wells).

    There is a lot of hype in investor presentations.

    The Continental wells will produce considerably less oil that the 480 kb claimed (only 80% of the 600 boe EUR is oil) in investor presentations. The EUR is more in the 250- 300 kb range for the average Continental well.

    shallow sand , 12/24/2014 at 4:50 pm
    Thank you again, Dennis, for the information you provide.
    Mike , 12/24/2014 at 5:15 pm
    AAAAAmen!
    Dennis Coyne , 12/24/2014 at 6:13 pm
    Happy holidays to all!
    Fernando Leanme , 12/25/2014 at 5:30 am
    I wonder if they have run flow meters to check how much flow they get from the toe of a 10 thousand foot lateral. You seem to follow this closely, are those wells slugging?
    Dennis Coyne , 12/25/2014 at 3:18 pm
    Hi Fernando,

    It is not clear who you are asking.
    I do not know what slugging is.

    Fernando Leanme , 12/27/2014 at 6:10 pm
    Dennis, sometimes very long wells in three phase flow can have phase segregation in the horizontal section. This causes liquid slugs to accumulate, which tend to move up the well in slug flow. This can be avoided by placing the heel higher than the toe. But I've never worked with a 10 thousand foot well. And I was wondering if they had sensors to confirm the toe is producing.
    FreddyW , 12/25/2014 at 5:53 am
    I came to the same conclusion as you Dennis. The Continental wells are actually bellow average. I have attached a graph showing the production profile for Continental wells from January 2010 to October 2014. I also included the average Bakken well profile for 2010 for reference. The first 3 year cumulative oil + gas production for an average Continental well is about 170.000 boe. No one knows what the EUR will be, but EIA suggests that 50% of the oil has been produced during that time ( http://www.eia.gov/forecasts/aeo/tight_oil.cfm ) which gives an EUR of about 340.000 boe.

    Carl, you are saying yourself that they only show the best results and don´t tell about their failures. So why should we then believe in anything they tell us? I have learned that you should never ever trust in what companies tell in their presentations. Especially not smaller companies which are dependent on cheap credits. It is actually quite disturbing that companies can make such exaggerations and get away with it.

    I however agree with you Carl that there are still drillable locations left in sweetspots. But perhaps some companies start to run out of them. That would affect total Bakken output, which I am mostly interested in.

    Dennis Coyne , 12/25/2014 at 1:26 pm
    Hi FreddyW,

    Along the same lines I did the chart below. Cumulative well profiles.

    FreddyW , 12/25/2014 at 6:16 pm
    Thanks Dennis. It´s good that we are several people who can look at the data from different angles.
    Dennis Coyne , 12/25/2014 at 3:27 pm
    I posted a chart for average Bakken cumulative output per well by company for four large companies over the Jan 2009 to Oct 2014 period( about 1/3 of all ND bakken/Three Forks wells drilled(3462 wells).
    The "avg" well is for all Bakken/Three Forks wells in North Dakota over the same period with a cumulative of 197 kb per well over the first 58 months of output.

    Chart came out a little small the first time so I will try it again.

    Dennis Coyne , 12/25/2014 at 8:56 pm
    I put together data for more companies, about 75% of total wells, too many for a clear well profile so I am using a bar chart with 54 month (4.5 year) cumulative output for the average well for each company over the Jan 2009 to Oct 2014 period. The average Bakken well is shown for comparison. Companies with more than 200 wells over the chosen period are presented below.

    shallow sand , 12/25/2014 at 10:59 pm
    Dennis, thanks so much for this information!

    Surprised by QEP, they don't get the hype the others do. Always assumed EOG had the most productive wells in the Balkan due to Parshall. Must have wells in other areas which bring the average way down.

    I wish TX reported by well as opposed to by lease. Would be really interesting to see the same info for EFS and Permian horizontal wells.

    Really seems irresponsible for these companies to claim EUR oil at 600,000+. I guess they assume the wells will produce 40-60 bbl per day for 25 years. Will be interesting to see if they do.

    shallow sand , 12/25/2014 at 11:00 pm
    Bakken. Spell check got me I guess?
    toolpush , 12/25/2014 at 11:16 pm
    Dennis,

    It looks like the quote from the other day, "Continental must drill all above average wells", may need some adjustment. To "Continental must drill all below average wells"?

    Dennis Coyne , 12/26/2014 at 8:10 am
    Hi all,

    I show the North Dakota Bakken/Three Forks cumulative average well profiles by company for the Jan 2009 to Oct 2014 period, total wells for this set of companies is 6472 wells of about 8054 wells completed (drilled and fracked) for all companies operating in the North Dakota Bakken/Three Forks (80%). This is where I got the data for the bar chart. QEP energy is the high well profile and OXY is the low well profile, the middle dashed line is the average well profile for all companies (including those not presented in the chart).

    [Mar 01, 2016] Seeking Alpha - Read, Decide, Invest.

    seekingalpha.com

    Back To Mark Anthony's Instablog HomePage "

    Instablogs are blogs which are instantly set up and networked within the Seeking Alpha community. Instablog posts are not selected, edited or screened by Seeking Alpha editors, in contrast to contributors' articles. var ratings_hash={}; comment_ids = [12437651]; ratings_hash = { 12437651: [1] };

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    [Feb 29, 2016] US Oil Rig Count Points To A Sharp Decline In Production

    Notable quotes:
    "... Jeb Armstrong, Vice President of Energy Research for the Marwood Group, doesnt expect most producers to have a large inventory of DUCs. Instead, he sees the backlog as a matter of circumstance rather than a way of loading up on potential volumes. The only reason why I can see a company willingly drilling DUCs is because they have a rig contract thats too expensive to cancel, he said in an email to Oil Gas 360®. Might as well keep the rig operating and plow the capital into the ground than pay a penalty to the rig owner. ..."
    "... Raymond James analysts shared a similar viewpoint, noting a certain dynamic on the oilservice industry. Lower returns and crimped cash flow lead operators to slow activity and conserve cash in any way possible, the note said. Since many of the land rigs had longer-term contracts and the frac crews didnt, the quickest way to conserve cash is to drill but not complete. ..."
    "... Many prognosticators of oil and gas markets have found themselves on the wrong side of US production calls throughout the shale era after failing to understand and model the risks associated with operational momentum. Increases in well productivity brought higher potential returns, and every company in the oil patch scrambled to gain the assets, people, and infrastructure to grow production (and hopefully cash) in the future. As supply growth outpaced demand, prices sank, but production hasnt responded with an equal intensity. Why doesnt production respond accordingly? The same reason you cant turn around an aircraft carrier on a dime, momentum. ..."
    "... The momentum of the shale boom can be seen in the large overhang of drilled but uncompleted wells (DUCs) sitting out in the field today, ..."
    "... looming over the market and weighing on any potential oil price recovery… ..."
    "... Until the number of DUCs returns to levels more aligned with historical working inventory levels (3-6 months of drilling), we expect their threat to loom large over the market and have a dampening effect on any near-term price recovery. But their longer term impact could loom just as large. If producers steer too much capital away from drilling, and instead harvest DUCs to maintain production and cash flow in 2016, the human capital behind the rig fleet could be lost to other industries, making service cost inflation all but guaranteed when US supply growth is again needed. It looks like this hangover will be felt for years to come. ..."
    "... This sharp downward trend has to have a direct effect on the Bakken oil production, in the shorter time frame, rather than the longer term. ..."
    Peak Oil Barrel

    In the shale plays a drop in the rig count does not mean a drop in well completions. And except for the Bakken, we have only a vague idea how many wells are being completed each month. We know that the inventory of DUCs, (drilled but uncompleted wells), is quite high. But if so, why are any shale wells being drilled at all? Well here is one reason:

    DUCs in a Row for 2016: It's Anybody's Guess

    Jeb Armstrong, Vice President of Energy Research for the Marwood Group, doesn't expect most producers to have a large inventory of DUCs. Instead, he sees the backlog as a matter of circumstance rather than a way of loading up on potential volumes. "The only reason why I can see a company willingly drilling DUCs is because they have a rig contract that's too expensive to cancel," he said in an email to Oil & Gas 360®. "Might as well keep the rig operating and plow the capital into the ground than pay a penalty to the rig owner."

    Raymond James analysts shared a similar viewpoint, noting a certain dynamic on the oilservice industry. "Lower returns and crimped cash flow lead operators to slow activity and conserve cash in any way possible," the note said. "Since many of the land rigs had longer-term contracts and the frac crews didn't, the quickest way to conserve cash is to drill but not complete."

    But wells are obviously being completed. In fact more wells are being completed than being drilled but we obviously don't know just how many. And…

    DUCs to Prolong Shale Boom Hangover

    Many prognosticators of oil and gas markets have found themselves on the wrong side of US production calls throughout the shale era after failing to understand and model the risks associated with operational momentum. Increases in well productivity brought higher potential returns, and every company in the oil patch scrambled to gain the assets, people, and infrastructure to grow production (and hopefully cash) in the future. As supply growth outpaced demand, prices sank, but production hasn't responded with an equal intensity. Why doesn't production respond accordingly? The same reason you can't turn around an aircraft carrier on a dime, momentum.

    The momentum of the shale boom can be seen in the large overhang of drilled but uncompleted wells (DUCs) sitting out in the field today, looming over the market and weighing on any potential oil price recovery…

    Until the number of DUCs returns to levels more aligned with historical working inventory levels (3-6 months of drilling), we expect their threat to loom large over the market and have a dampening effect on any near-term price recovery. But their longer term impact could loom just as large. If producers steer too much capital away from drilling, and instead harvest DUCs to maintain production and cash flow in 2016, the human capital behind the rig fleet could be lost to other industries, making service cost inflation all but guaranteed when US supply growth is again needed. It looks like this hangover will be felt for years to come.

    Conclusion

    The decline in the oil rig count cannot, in the near term, be directly linked to a decline in oil production due to so many DUCs. But eventually it must. Steep declines in oil production must eventually follow steep declines in the rig count. And as we see a drop in production we will see a corresponding rise in prices. This, in turn, will cause an increase in well completions, knocking the price back down again.

    So don't expect any quick recovery of either oil prices or production. Yes, it looks like the hangover will be felt for years to come. And in the meantime peak oil will be in the rear view mirror. But no one will notice for years to come.

    AlexS ,

    02/29/2016 at 11:28 am
    Thanks for the post, Ron

    This chart from Rystad Energy indeed shows that the number of DUCs was rapidly increasing during the shale boom, when oil prices were around $100. It has peaked in late 2014 and was decreasing since then

    Ralph , 02/29/2016 at 11:47 am
    If the number of DUCs is almost unchanged for the last 9 months it implies the number of completions is falling in lock step with the number of wells being drilled. Drill rigs are becoming more efficient on average, but it still implies a very rapid fall-off in production in the coming months.
    Dennis Coyne , 02/29/2016 at 4:39 pm
    If no wells are completed in 2016, output in the Bakken drops by roughly 40%per year in the first year. Not a very realistic scenario, though. If an average of 35 wells per month are completed, the drop is about 25%/year. If 60 wells per month are completed, output drops about 20%/year and 70 wells completed per month results in about a 15% drop in Bakken/Three Forks output.

    I have no guess about how many wells will be completed, but somewhere between 0 and 70 new wells per month on average for 2016 will probably cover it.

    Toolpush , 02/29/2016 at 11:57 am
    Bakken rigs down to 35, with one to lay down/stack.

    McKenzie county, makes up 19 of those 35 rigs.

    Mountrail and Williams are at 5 and 4 respectively, with Williams about to go to 3!

    Dunn Co at 6.

    I have to agree with Ron. This sharp downward trend has to have a direct effect on the Bakken oil production, in the shorter time frame, rather than the longer term.

    [Feb 28, 2016] Eagle Ford rig count down 70 percent in the last year

    fuelfix.com

    Jennifer Hiller

    The number of drilling rigs working in the Eagle Ford Shale is a fraction of what it was a year ago, down 70 percent. There are 47 drilling rigs still working in the South Texas field, which arcs from the border near Laredo toward the College Station area on the eastern edge of the field.

    [Feb 28, 2016] Oil Giant Cuts Budget By 80 percent And Suspends Fracking

    Notable quotes:
    "... Whiting Petroleum Corp. (NYSE:WLL), the largest oil producer in North Dakota, has announced that it will suspend all fracking in the state and cut its budget for this year by 80% ..."
    "... As of 1 April, Whiting will halt all fracking and stop completing its wells at 20 Bakken and three Forks sites. By this summer it will cut spending to $160 million for the rest of year to fund maintenance. ..."
    "... The news comes along with Whiting's fourth-quarter results, which posted a net loss of $0.80 per share and revenues of $2.05 billion compared with 2014 EPS of $4.15 and revenues of $3.09 billion. ..."
    "... It's also in a better position despite all the setbacks because it doesn't have any bonds maturing until 2019 ..."
    OilPrice.com

    Whiting Petroleum Corp. (NYSE:WLL), the largest oil producer in North Dakota, has announced that it will suspend all fracking in the state and cut its budget for this year by 80% in a move that sent its shares up 9% on Wednesday, back down to a record low on Thursday, and $4.02 this morning.

    ... ... ...

    As of 1 April, Whiting will halt all fracking and stop completing its wells at 20 Bakken and three Forks sites. By this summer it will cut spending to $160 million for the rest of year to fund maintenance.

    ... ... ...

    The news comes along with Whiting's fourth-quarter results, which posted a net loss of $0.80 per share and revenues of $2.05 billion compared with 2014 EPS of $4.15 and revenues of $3.09 billion.

    In an earnings call on 25 February, Whiting noted that its production for the fourth quarter averaged 155,210 barrels of oil equivalent per day, and that enhanced completion designs in the Williston Basin drove performance by delivering 22% production increases quarter over quarter on a per well basis.

    "Despite the sharp drop in commodity prices, our proved reserves increased 5% to 821 million barrels of oil equivalent, even after 53 million barrels of oil equivalent of asset sales which equated to almost 7% of our year-end 2014 reserves," Whiting executives noted.

    The company sold $512 million of assets last year, ending the year with $2.7 billion of liquidity. It's also in a better position despite all the setbacks because it doesn't have any bonds maturing until 2019, and will not be negatively affected by the "March madness" that is threatening other producers.

    [Feb 27, 2016] The Oil Drum Modeling Bakken Oil Production The Oil Shock Model Explained

    Notable quotes:
    "... Once that pressure is down the dribbles that gravity will draw through those tiny cracks will still be tiny dribbles with twice as many cracks. Refracking wont do much to increase the gas pressure around a gas depleted horizontal run. ..."
    www.theoildrum.com

    Posted by JoulesBurn on August 30, 2013 - 11:25am
    Topic: Supply/Production
    Tags: bakken , webhubbletelescope [ list all tags ]

    This is a guest post from WebHubbleTelescope . Here he provides a simplified explanation of his Oil Shock Model as applied to oil production from the Bakken formation. Previous contributions to THe Oil Drum from WHT can be found here and here .

    My premise for participating was that I wanted to see how far I could get in understanding our fossil fuel predicament by applying the mathematics of probability and statistics. There were enough like-minded individuals that it turned out to be a productive exercise, and I found that even the contrarian and cornucopian viewpoints could add value.

    This was an ongoing process and I documented my progress with occasional posts on TOD and regular posts on my blog http://mobjectivist.blogspot.com . I treated the process as an experiment and as I collected more pieces of the puzzle, I realized that I had collected enough information to aggregate it into a more comprehensive format.

    This work eventually went into an online book, which is available via Google Books at the link below, which you can also download as a PDF for a Kindle: http://books.google.com/books/about/The_Oil_Conundrum.html?id=oY2ZPn5EOTQC

    After I finished the book (which incidentally I titled The Oil ConunDRUM as a nod to The Oil Drum) the mobjectivist blog went dormant. I essentially treated that bog as a lab notebook, and I considered that notebook was complete and finished as a historical record of what went into the book. So everyone that mourns the closing of The Oil Drum has to remember that progress marches on, and something else will spring from the analysis and research that went on here.

    In passing, and as a short note to what one can do with some of the research that went into The Oil Conundrum book, I thought to consider explaining how we can apply the Oil Shock Model to projecting future Bakken formation production rates. Several TOD commenters have asked for a simple and intuitive definition for how the shock model works, and it has always been a challenge to express it concisely. In mathematical terms, it is simply the application of the convolution function to a model of the statistical flow rate operating on the reserve potential of the reservoirs of interest.

    The problem in casting it in this stark a mathematical form has been that the concept of convolution is neither intuitive nor readily available to the layman. For example, the Excel spreadsheet application does not have a convolution function in its toolbox of statistical operators. This is odd considering that the great statistician William Feller once remarked that "It is difficult to exaggerate the importance of convolutions in many branches of mathematics."

    The best intuitive explanation that I can come up with is that a convolution (in the oil production context) is a "sliding" summation of extraction applied to reserves.
    Thus, the convolution algorithm automatically keeps track of older reserves as well as new reserves as the total production accumulates with varying levels of extraction over time. Whether this is completely intuitive to the layperson, we can always remember that a convolution is largely a cookbook accounting exercise and once the form of the two inputs are known, a simple algorithm can be applied to obtain a result.

    For modeling the Bakken ala the convolution-based shock model, the inputs are two time-series.

    1. The forced input is the time series of newly available wells.
    2. The response input is the time series of expected decline from a single well.
      The convolution function takes the forced input and applies the response input and generates the expected aggregate oil production over time.

    DC at his blog http://OilPeakClimate.blogspot.com/ has used this approach to good effect in modeling historical and projecting future Bakken production. I apply a slightly different response function than DC and get this shock model output:

    Month #714 on the time series is essentially up-to-date, so that this is a modeled profile of the past 60 years of Bakken activity, using the historical monthly well numbers as input (from http://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf ).

    The two curves correspond to (1) the actual production data and (2) that which is modeled after applying the convolution-based shock model to the well build-up, assuming a fairly rapid decline response per well. The decline after month 714 would show what would happen if no new wells were added. That of course won't happen, but it illustrates the Red Queen effect that Rune Likvern has argued on these pages. The Red Queen hypothesis is that production will continue to increase as long as a fresh supply of new wells with nominal reserve potential comes on line at a good pace.

    As a detail, where DC and I differ is in how we apply the response model for the average well. I have been applying a diffusional model based on the physics of flow, whereas DC has been using a hyperbolic decline model which is favored by reservoir engineers. Not much of a difference between the two, apart from gaining an understanding of what is actually happening underground, which is likely an initially rapid diffusional flow followed by a the long tails of a diffusional decline.

    As a caveat, the model would likely work even better if the North Dakota Department of Mineral Resources had kept a cumulative total instead of an active count in their PDF table --
    but as is the case with most of the data, you use what you can get.

    The take-home point is that analysis approaches do exist outside of the insider oil patch knowledge-base. Us mere mortals can formulate and apply these simple models to at least try to get a handle on future fossil fuel supplies. That was the objective that I had when I started my blog and followed along with TOD as we watched crude oil production plateau the last 9 years.

    ---

    Doing this work on applying probability and statistics to the energy predicament has opened up other possibilities which I have since pursued. Recently I have started up another blog on general environmental modeling called http://ContextEarth.com . This has an associated interactive modeling web server called the Dynamic Context Server, which builds up from a semantically-organized knowledge-base of land, water, and atmospheric information.

    I have incorporated the shock model as one of the functionalities in the server and intend to maintain other capabilities to make it useful for environmental model activities, such as wind, solar, and transportation simulations. Comments and collaboration opportunities are welcomed.

    As you can see, The Oil Drum is only a start to the on-going energy transformation that we are going through.

    Modeling Bakken Oil Production: The Oil Shock Model Explained

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    Nick on August 30, 2013 - 12:24pm Permalink
    WHT,

    Any thoughts on how to incorporate price effects - e.g., the effect of the recent price hike, which took Bakken production from it's former peak to a new growth phase?

    WebHubbleTelescope on August 30, 2013 - 12:41pm Permalink
    Nick,
    Both DC and Rune Likvern are trying to incorporate pricing into the Bakken model.
    DC talks about price pressure here:
    http://oilpeakclimate.blogspot.com/2013/06/future-bakken-crude-oil-outpu...
    RL here, where he shows negative cash flows
    http://www.theoildrum.com/node/10102

    The thinking is that the profit margin isn't that great and some have even speculated that many operators will lose money. It sounds very similar to making a Hollywood movie -- all the costs are eaten up during production with few films actually making money.

    The early days include some wells that were borderline conventional wells, which made them more competitive with other conventional wells in that timeframe. But there weren't many like that, and it took the price increases to open up the rest to hydrofracturing technology.

    WebHubbleTelescope on August 30, 2013 - 1:13pm Permalink
    Correction, in the last sentence: "But there weren't many like that".

    I didn't want to edit and send it back into moderation. Sorry for delays in responding if I include links. I have today off from work so can respond to questions quickly if no links are involved.

    Nick on August 30, 2013 - 4:18pm Permalink
    In an ideal world, we'd have a single model that could project production for multiple price levels. That is to say, something that in 1980 would have projected a ND peak of around 150k bpd under a regime of $25 oil, and in 2007 would have projected a peak above 800k bpd for $90 oil.

    A "supply function": supply vs price.

    WebHubbleTelescope on August 30, 2013 - 4:29pm Permalink
    My suggestion for these Bakken wells is to have a good model for when they get shut-in. That would suggest the minimum level of production while still maintaining profitability.
    Nick on August 30, 2013 - 6:34pm Permalink
    Can these wells be refractured after production falls? IOW, is EOR possible?
    Luke H on August 31, 2013 - 2:58am Permalink
    You had the right scent when you brought up price but lost the trail with this last question. It is the strong gas drive that makes these Bakken wells pay off quickly. Once that pressure is down the dribbles that gravity will draw through those tiny cracks will still be tiny dribbles with twice as many cracks. Refracking won't do much to increase the gas pressure around a gas depleted horizontal run.

    On the price thing, we can certainly evision that once a certain price threshold is achieved somewhat less sweet spots will begin to pay and that those less and less sweet spots will encompass greater acreage. More or less an inverse relationship between sweetness and area...but what we can envision and the real facts under the ground might diverge wildly.

    Oh and Web's diffusion light bulb came on when I posted this chart from the Great Bear site

    Rock's comment on the chart was more or less that is was a crock as below a certain size crack oil just wasn't going to have a significant increase in flow...but he kind of skipped mentioning that gas flowed through those smaller cracks quite readily and that the increased gas drive those cracks create might be the the real pay off.

    WebHubbleTelescope on August 31, 2013 - 11:12pm Permalink | Subthread | Parent | Parent subthread | Comments top
    This is a representation I made of the diffusional model:

    The fissures are truly random pathways and the oil randomly walks to the collection point as shown. They could just as easily travel away from the intended direction. It is true that the pressure release enhances the flow but this flow is not as direct as a straight line. There is really no control over the fissure formation.

    The substantiation of this model is that the production follows a type of inverse square root of time dependence, which is the signature of Fickian diffusion.

    Look at the diffusion paper on the ContextEarth blog linked to above (go to Figure 17 shown above to find the right section). Diffusional models are fairly general and can be used to describe lots of applications. One of my favorite recent ones is that of Lithium ion battery charge and discharge.

    The math is very similar to oil flow, ions in the Lithium composite have to follow a random walk to move between the anode and cathode. The random walk helps prevent the battery from discharging (or charging) all at once.

    WebHubbleTelescope on August 31, 2013 - 10:04am Permalink
    It is really diminishing returns after the first fracturing attempt.

    The model is one of diffusive flow, so if the volume is fractured one time, the second time the fluid gets even more dispersed to points even further away from the collection points.

    I have a paper describing diffusive flow on the ContextEarth server linked above that describes the math.

    Alaska_geo on August 31, 2013 - 2:34pm Permalink
    They do refrac in some cases. While it is "diminishing returns", sometimes a refrac can increase production enough to be worth the expense to the operator. However refracs probably won't change the "big picture" of Bakken production all that much.

    The technology of controlling fracs has become sophisiticated enough that in some cases the refrac can open up new rock that wasn't fractured in the initial job. Or a refrac may help when the original frac wasn't optimally done. See for example Restimulating the Bakken: What have we learned?

    Luke H on September 1, 2013 - 2:21am Permalink
    The model is one of diffusive flow, so if the volume is fractured one time, the second time the fluid gets even more dispersed to points even further away from the collection points.

    Your model may be diffusive flow and it may well mirror the actual oil and gas flow rates, but what you must realize is the diffusion in fracking is the creation of the fractures themselves. Once the big frac pumps shut down the fluids are not diffusing anymore, they are all following the path of least resistance from a high pressure environment to a low pressure environment. And that path is always little cracks feeding bigger cracks because bigger cracks relieve pressure faster...as long as they stay open.

    Wouldn't that be more like the reverse of diffusive flow just as much as tributary springs flowing into brooks and creeks creeks, flowing into rivers and ultimately into the ocean is the reverse of diffusive flow. Of course evaporation from those water courses and bodies is diffusive flow and it does keep the cycle going but that is another story and is not what is happening in a fracked well.

    The pressure from the over burden is relentless and is always closing down fizzures pores that no longer have enough fluid in them to push back. Its always a big squeeze out of any fluid that can escape to low pressure areas just as long as the channels stay propped open. Refracking will still have the liberated fluids attempt to leave high pressure environment for the low not disperse them away from collection points for just as long as the refracking leaves open paths to the low pressure zone.

    WebHubbleTelescope on September 1, 2013 - 2:06pm Permalink
    I responded yesterday with an image from my paper but that got held up in moderation, so this is what I said without the Figure 17 from the paper.

    The fissures are truly random pathways and the oil randomly walks to the collection points. They could just as easily travel away from the intended direction. It is true that the pressure release enhances the flow but this flow is not as direct as a straight line. There is really no control over the fissure formation.

    The substantiation of this model is that the production follows a type of inverse square root of time dependence, which is the signature of Fickian diffusion. I add an element of dispersion to the flow which allows a range of diffusivities to the mix.

    Look at the diffusion paper on the ContextEarth blog linked to above (go to Figure 17 to find the right section). Diffusional models are fairly general and can be used to describe lots of applications. One of my favorite recent ones is that of Lithium ion battery charge and discharge.

    The math is very similar to oil flow, ions in the Lithium composite have to follow a random walk to move between the anode and cathode. The random walk helps prevent the battery from discharging (or charging) all at once.

    "Wouldn't that be more like the reverse of diffusive flow just as much as tributary springs flowing into brooks and creeks creeks, flowing into rivers and ultimately into the ocean is the reverse of diffusive flow."

    Once it gets to a river, that is definitely a gravity-fed flow. However, for tracing of flow through porous media, hydrologists measure what are called breakthrough curves, and these are largely diffusional flow with some gravity feed as well. I solved these dispersive transport equations in The Oil Conundrum, and that is why it was fairly easy to make the connection to the Bakken flow rates.

    The Bakken flow is extremely diffusional because it has the strong diffusional spike at the beginning followed by the fat-tails. Reservoir engineers use a heuristic curve called hyperbolic decline, which happens to match the dispersive diffusional flow for a specific set of heuristic parameters.

    I could post some diagrams, but that would just go back in moderation, so I suggest you look at the diffusional paper on the ContextEarth site and also The Oil Conundrum book where I have a chapter on porous media dispersive diffusional flow.

    Luke H on September 1, 2013 - 9:44pm Permalink
    The fissures are truly random pathways and the oil randomly walks to the collection points. They could just as easily travel away from the intended direction. It is true that the pressure release enhances the flow but this flow is not as direct as a straight line. There is really no control over the fissure formation.

    I never claimed the flow to be a straight line, the randomness of fissure direction is what makes your diffusional flow math work, however the flow is not truly random. The fluids are moving from high pressure to low pressure zones following the path of least resistance through open pathways many of which only remain open because of the propant injected into the them.

    The high initial flow after the first frac' job is generally very dependent on the gas drive. That was my quibble when you described the diminishing returns of a refrac job to Nick. The first frac' job will have found most of the larger natural fissures thus the bulk of the mobile fluids in the horizontal well's sphere of influence. That is the main reason a second frac' would have diminishing returns--there just won't be that much mobile gas and oil left for the horizontal run to liberate--it wouldn't be because the new pathways opened will offer even longer routes from high to low pressure zones or even that some of those longer routes lower pressure zones will lead to already drained dead ends--though both are likely results of a second frac' job.

    Unlike near surface water moving through porous medium fluids trapped in the Bakken medium won't move much at all until a pressure differential is made available to them--a pressure differential like the one created by frac'ed pathways leading to the horizontal collection pipe. As long the pathways from higher to lower pressure remain open, the fluids will be travelling to low pressure from high regardless how random the the direction of the pathway looks.

    WebHubbleTelescope on September 1, 2013 - 10:21pm Permalink
    Without direct evidence that the flow is not random, the best we can do is look at the empirical flow rates of a typical well. This seems to fit best either a diffusional flow profile or a hyperbolic profile with a tuned exponent. The former is based on physics while the latter is a heuristic.

    That essentially describes my model of the initial fracturing attempt.

    Perhaps what happens on successive fracturing attempts is a moot point. The speculation is the amount of oil rapidly diminishes -- but without some data to analyze, we are guessing as to what the flow actually looks like.

    Nick on September 1, 2013 - 1:35am Permalink
    I guess the next logical question is: is there a price for oil at which it would be worth drilling new wells in between the old ones – In other words is there a price point at which well spacing changes?
    Nick on August 30, 2013 - 4:19pm Permalink
    Here's the history: https://www.dmr.nd.gov/oilgas/stats/DailyProdPrice.pdf
    WeekendPeak on August 30, 2013 - 3:27pm Permalink | Subthread | Parent | Parent subthread | Comments top
    I'd argue that production is driven by profit rather than price. Consumption however is likely pretty much a function of price.
    If one assumes a required minimum return on capital OVER TIME profit and price then should be causal but certainly not in the shorter run. What constitutes short run vs long run is related to the nature of the project. Short run for somebody selling oysters is different from somebody developing oil fields.

    Rgds
    WP

    aardvark on August 30, 2013 - 3:33pm Permalink
    Full disclosure: I failed Maths 101, so I find WHT's posts hard to follow.

    Wolfram Alpha has an animated explanation of convolution. I sort of understand the animation, but am not sure how to apply it. http://mathworld.wolfram.com/Convolution.html

    Correct me if I am wrong, but convolution is a cookbook technique for doing mathematically what could be done with a lot of patience and a spreadsheet.

    I produced this graph with a spreadsheet. Assume a well like the red line with production of 100, 60, 40, 30, 25, 20, ... in succeeding years (these numbers are just a guess for illustration, not based on any real well), and open one new well a year. Then production will be as follows:

    Yr 1: 100 total Yr 2: 60 + 100 = 160 total Yr 3: 40 + 60 + 100 = 200 total etc etc.

    
    
          

    If I could do convolutions I could produce the totals 100, 160, 200, ... mathematically without having to draw up a spreadsheet.

    The accuracy of the model depends on two factors:
    1. The correct shape of the well depletion curve.
    2. The correct prediction of the number of wells drilled.

    If sweet spots are drilled first one would expect individual wells to become less productive with time, and the number of wells drilled to decrease. I presume these changes over time can be modelled mathematically as well.

    So, assuming WHT has done his sums correctly, and I believe he has, one's assessment of the model must depend on one's assessment of how closely the depletion curves and drilling numbers match reality.

    I think these input factors should always be shown along with the final output curve.

    Final question: Why is it called a shock model?

    WebHubbleTelescope on August 30, 2013 - 5:10pm Permalink
    Aa, you have the algorithm down about right for convolution.
    In the context server that I mentioned, the calculation uses an expressive language whereby one only has to write the phrase, A convolve B, to invoke a convolution. It is commutative so that the order does not matter.

    It is called the shock model since one can add perturbations, or slight shocks, to the extraction rate as a final step. This is normally used for significant geopoltical shocks, as described in Stuart Staniford's last post.

    phil harris on August 31, 2013 - 5:14am Permalink
    WHT

    I am glad you got this piece written and my thanks to you and Joule for posting.
    I find it helpful and will be pleased to follow your future 'experiments' with data in a variety of fields!
    That DC and Rune take a very similar approach to data is encouraging.
    I await developments.
    Even if I can 'follow' your logic, it does not mean that I could engage in creative or critical discussion of methodology (!) but I am personally encouraged that you engage with 'entropy' as a basis for your logic concerning probability, and that you appeal to known physical processes such as diffusion in the case of tight-oil. All of which does indeed seem fundamental for the outcomes we are interested in, if and when as you say the numbers are available.

    Thanks again
    Phil H

    PS Can the 'shock' approach be used to test historical data retrospectively - e.g. perhaps looking at USSR oil production, to test assumptions about industrial / technological / political continuity, or indeed somewhat differently, effects of technology innovation? Perhaps to get a handle on the size of 'shocks' and their effects? For the latter there is the example of USA tight-oil extraction emerging during extraction from 'almost-conventional' oil-bearing formations, and then expanding into a new phase with a new territory of opportunity. This was itself a 'shock', no?

    WebHubbleTelescope on August 31, 2013 - 9:31am Permalink
    Thanks Phil

    "Can the 'shock' approach be used to test historical data retrospectively "

    Certainly. In the book that I linked to, "The Oil Conundrum", I have more thorough examples of how the shock model applies to historical geopolitical situations.

    The Bakken example of this post is the simplest case of the convolution approach and so does not incorporate the shocks of sudden changes to production levels.

    A good example of a simple shock is looking at the historical UK North Sea production and then consider the Piper Alpha incident. This caused a depression in extraction levels that the shock model can approximate, resulting in the "dual hump" of UK oil production levels. This is also described in the book.

    WebHubbleTelescope on August 31, 2013 - 9:46am Permalink | Subthread | Parent | Parent subthread | Comments top
    This is an example of the shock applied to the UK production using the convolution-based shock model:

    The lower left is an extraction rate profile, which models the actual production level on the upper right. The main point is that relatively small perturbations on the extraction rate leads to noticeable changes in the production. The Piper Alpha caused both a reduction in that platform, but also an overall reduction in the North Sea extraction as safety concerns propagated down the line to other platforms.

    KLR on August 30, 2013 - 5:52pm Permalink

    As a caveat, the model would likely work even better if the North Dakota Department of Mineral Resources had kept a cumulative total instead of an active count in their PDF table --
    but as is the case with most of the data, you use what you can get.

    I'm puzzled by this - do you mean cumulative production, or something else?

    WebHubbleTelescope on August 30, 2013 - 6:13pm Permalink
    When a well stops producing it no longer shows up in the statistics. That makes it hard to tell what the true cumulative is and how many new wells are being added. In other words, the running total is new wells minus those removed, with no distinguishing between the two.

    If you pay the N Dakota Department of Mineral Resources you can get the detailed records from what I understand.

    jclaer on August 30, 2013 - 11:42pm Permalink
    The given link did not bring me to a pdf file of the book.
    (My books are free on line, but I'm a long ways up stream from you guys.)
    To find my books, Google for Jon Claerbout books
    WebHubbleTelescope on August 30, 2013 - 11:58pm Permalink
    You can also download it from the http://ContextEarth.com semantic web server

    Go to the menu item labeled The Oil Conundrum and that will take you to the PDF.

    "The aim of every political constitution is, or ought to be, first to obtain for rulers men who possess most wisdom to discern, and most virtue to pursue, the common good of the society; and in the next place, to take the most effectual precautions for keeping them virtuous whilst they continue to hold their public trust." -James Madison, FEDERALIST #57 (1787)

    This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License .

    [Feb 26, 2016] Individual Bakken wells have little long-term capacity, so that the decline effects are seen almost immediately

    Notable quotes:
    "... Lest anyone forget, if the number of additional wells does not increase in Bakken year-over-year, then the result will be as we showed in the last of The Oil Drum posts http://www.theoildrum.com/node/10221 ..."
    peakoilbarrel.com
    WebHubTelescope, 02/22/2016 at 8:39 am
    Lest anyone forget, if the number of additional wells does not increase in Bakken year-over-year, then the result will be as we showed in the last of The Oil Drum posts http://www.theoildrum.com/node/10221

    Individual Bakken wells have little long-term capacity, so that the decline effects are seen almost immediately.

    [Feb 25, 2016] Drilling with negative cash flow almost stopped

    Notable quotes:
    "... With those sort or numbers, we will nearly be able to count the number of rigs drilling in the Bakken, on our fingers and toes! And if XTO cut their 5 rigs to similar to their competitors, we will! ..."
    "... If these numbers hold, looking at as low a 900K bopd this summer from ND. ..."
    peakoilbarrel.com
    shallow sand , 02/25/2016 at 4:55 pm
    With Halcon and EOG releasing 2016 guidance, estimate the following companies:

    QEP, SM Energy, Enerplus, Continental, Marathon, Oasis, Hess, WPX, Whiting, Newfield, HRC Operating (Halcon) and EOG…

    will complete in between 200-250 Middle Bakken and/or Three Forks wells in 2016. This is just an ESTIMATE, as the companies report this guidance in many different formats, and in gross and/or net wells.

    The remaining companies with rigs running are XTO, Burlington, Statoil, Liberty and PetroHunt. I cannot find Bakken specific 2016 guidance for XTO (ExxonMobil) Burlington(COP) and Statoil. If anyone finds this, please post it.

    PetroHunt and Liberty Resources, I believe, are private companies. They each have just one rig running.

    The above companies, I believe, are the only ones running rigs in the Williston Basin at present. Clearly, there are other companies that have, and that could have DUCS to complete in 2016. Anyone with any information on those, please post.

    FYI, it appears the bulk of the completions will occur in Q1.

    Toolpush , 02/25/2016 at 10:21 pm
    Shallow,

    With those sort or numbers, we will nearly be able to count the number of rigs drilling in the Bakken, on our fingers and toes! And if XTO cut their 5 rigs to similar to their competitors, we will!

    shallow sand , 02/25/2016 at 10:59 pm
    Toolpush. Went over those numbers with Rune, he came up with a little higher number than me, so I will revise that to 250-325. Still a very low number for the large number of companies involved.

    If these numbers hold, looking at as low a 900K bopd this summer from ND.

    [Feb 20, 2016] There are 3100 wells in the Williston Basin that are producing 40 bpd and less and they are all losing money

    Notable quotes:
    "... There are 3100 wells in the Williston Basin that are producing 40 bpd and less, if they all are producing close to the forty barrels per day, the shutting of those wells will reduce the production by some 120,000 bpd, maybe. Daily production would fall to one million bpd and maybe even close in on 900,000 bpd with decline. ..."
    "... Bakken well horizontals are known to fill up with sand, so you have to keep pumping oil to prevent plugging the horizontal. ..."
    "... Madison Formation oil is a heavier oil than Bakken oil, the classic dark green gray color of the oil is there, it is oily oil, clings to the side of the jar, not the light stuff like Bakken crude. A distinct color difference between the two oils. ..."
    peakoilbarrel.com

    R Walter , 02/20/2016 at 9:15 am

    Year 2014 production by formation:

    http://www.dmr.nd.gov/oilgas/stats/2014Formation.pdf

    There are 3100 wells in the Williston Basin that are producing 40 bpd and less, if they all are producing close to the forty barrels per day, the shutting of those wells will reduce the production by some 120,000 bpd, maybe. Daily production would fall to one million bpd and maybe even close in on 900,000 bpd with decline.

    Madison Formation wells and Red River Formations have produced plenty of oil over the years, nothing like the Bakken though. If you view the pdf, the production for each formation is right there. Bakken well horizontals are known to fill up with sand, so you have to keep pumping oil to prevent plugging the horizontal. You will need two hamsters in the wheel to make it go faster.

    Madison Formation oil is a heavier oil than Bakken oil, the classic dark green gray color of the oil is there, it is oily oil, clings to the side of the jar, not the light stuff like Bakken crude. A distinct color difference between the two oils.

    ... ... ...

    [Feb 20, 2016] For those interested in Bakken economics, take a look at Enerplus release today

    peakoilbarrel.com
    shallow sand, 02/19/2016 at 4:55 pm
    For those interested in Bakken economics, take a look at Enerplus release today. Very good and detailed information.

    http://investors.enerplus.com/2016-02-19-Enerplus-Announces-Strong-2015-Results-Low-Cost-Reserves-Additions-and-Reduced-2016-Budget-and-Dividend

    likbez, 02/19/2016 at 5:34 pm
    The same pattern, yet another company. As in "No one wants to die" (Steve Jobs).
    http://investors.enerplus.com/2016-02-19-Enerplus-Announces-Strong-2015-Results-Low-Cost-Reserves-Additions-and-Reduced-2016-Budget-and-Dividend

    …Enerplus delivered fourth quarter production of 106,905 BOE per day, contributing to annual average production of 106,524 BOE per day, approximately 3% higher than 2014 and above guidance of 106,000 BOE per day. This strong production was despite a 39% reduction in capital spending year-over-year and over 6,000 BOE per day of production divested during the year which, given the timing of the divestments, reduced annual average volumes by approximately 1,300 BOE per day.

    …Fourth quarter funds flow was $103 million ($0.50 per share), down approximately 15% from the previous quarter primarily as a result of lower commodity prices and production volumes. Full year funds flow was $493 million ($2.39 per share), down approximately 43% primarily due to significantly lower crude oil and natural gas prices relative to 2014. Commodity hedging helped support funds flow during 2015 with cash gains of $288 million.

    …Enerplus reported a net loss of $625 million in the fourth quarter as it incurred non-cash charges including $266 million related to an asset impairment and a $426 million valuation allowance for deferred tax assets.

    Enerplus has also reduced its 2016 capital budget a further 43% to $200 million. This represents a 60% reduction from 2015 spending levels. The reduced budget is focused on balance sheet preservation and maximizing the long-term value of the Company's as