A closer look at the 70-acre parcel for which Whiting paid $2.346 million.
Operators target EURs of one million bbls/well.
But let's take a look at wells with EURs of 500K.
1280 acres 500,000 bbls $100 / bbl $50,000,000
70/1280 = 5%
5% x $50 million = $2.7 million
12 wells x $50 million = $600 million
5% x $600 million = $30 million
Paid $2.346 million for the 70-acre parcel.
Disclaimer: this is not an investment site. Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here.
All my posts are done quickly: there will be content and typographical errors. If anything on any of my posts is important to you, go to the source. If/when I find typographical / content errors, I will correct them.
August 13, 2019: a reader responded to my rambling note below. The reader brought up some incredibly important notes, some points that I had forgotten, and thoughts on the Rystad analysis. Most important:
right now, the length of laterals in the Bakken are longer than the "average" horizontal in the Permian (which, by the way, would lead to another discussion, but for another day; so comparing the Permian with the Bakken is comparing apples with oranges; and,
the CXO Dominator project was a test project; testing to see what optimum spacing might be in that area of the Permian
Here is the reader's remarks:
I wanted to comment on your latest post on Permian and Bakken EURs -
in my opinion one needs to have more context before making any
assumptions from those graphics:
1) The Dominator Project referenced in
the Rystad graphic are 1 mile long laterals that costs 40-50% less than
the typical 2 mile laterals in the Bakken or 2 mile Permian so payout
isn't apples to apples
2) The Rystads type curve graphic looks extremely
misleading. This is a very misleading graphic for attempting to prove
Permian shale wells aren't meeting expectations - where did these
expectations originate to begin with ?
Type curves in tight oil are
driven by spacing so without knowing the spacing assumption behind the
Rystad Type Curves, there is no way to find this credible.
Permian
operators are still experimenting with spacing and this latest
"Dominator Project" from Concho was a spacing experiment that didn't
pass the economic test. They were testing the upper bounds of spacing
and it didn't work out but from what I've seen, they in no way were
claiming this spacing was verified as optimal or a base assumption for
their acreage
Could spend hours discussing this topic but all I have for now
This will be re-posted later as a stand-alone post. It's that important.
Original Post
I never tire of comparing the big three, the EIA dashboards:
Lynn Helms once said that going head-to-head, mano-a-mano, Three Forks wells might be better than Bakken wells.
I don't know the Permian well enough to really say, but based on very limited data, it certainly appears that going head-to-head, mano-a-mano, the better Bakken/Three Forks wells might be better than Permian wells; and, taken as a whole, the Bakken might be better on a "per acre" basis if that makes sense. I don't know. Just idle rambling.
What got me to thinking about this (again), were these graphics over at #OOTT this morning:
The graphs above are for CXO in the Permian.
I am not aware of having seen similar graphs in the Bakken.
On the contrary, it seems that "EUR type curves" in the Bakken show/showed better production with current spacing. Spacing does appear to vary across the Bakken which, of course, makes sense. Those who have followed the Bakken from the very beginning are very aware how the EUR type curves have changed over time. An excellent example of a Bakken EUR type curve from November, 2016:
Clearly, in the better Bakken, operators are "demanding" 100K wells in the first top three months of production.
Over at "wells of interest," I go through the wells by permit number: the 16xxx permits; the 17xxx permits; the 18xxx permits; etc. I don't have the statistical data, but it certainly look like ther was a huge jump in production in wells in the 21xxx series. Going through the 16xxx - 18xxx, I don't see a lot of wells approaching 400,000 bbls crude oil (cumulative/total production) but already there are many, many wells in the 21xxx series that are are approaching 500,000 bbls.
I think CLR shows it best in their "EUR" slides which they generally show in their corporate presentations. The latest presentation is at this link.
The "EUR graph" from the September, 2018, presentation:
I'll correct this if I find I'm wrong, but it appears the 21xxx permits were drilled in the 2012 time-frame. If so, look at the EUR line back in 2011 and then in 2014 in the graphic above.
I think most readers remember when we started out in the Bakken -- we were looking at EURs of 375,000.
I think a lot of folks thought Mike Filloon was nuts when he was suggesting 1 million bbls will be the next EUR milestone and that was years ago.
In the graphic above, Harold Hamm is shooting for EURs of 1.2 million boe in the Bakken. Early production in the Bakken is 94% crude oil; as time goes on, the percent of crude oil declines a bit but not by much.
Let's look at the last Director's Cut, data for August, 2018:
crude oil: 1,291,496 bopd (new all-time high)
natural gas: 406,226 boepd
total:1,697,721 boepd
406,226 / 1,697,721 = 24%
Color me surprised: assuming I did the math correctly, as much as 25% of production coming from the Bakken is now natural gas. I'll have to check that again; that seems really, really high but it looks right.
Later: see first comment regarding natural gas and energy / cash equivalence factors ---
6 MCF/bbl is an energy equivalence factor. It might be more appropriate
to use a value equivalence factor to account for the current oil and
gas prices. A factor of 20-25 MCF/bbl would yield around 100,000 boepd
for the gas production.
I've been waiting for this presentation for quite some time with all the recent activity in the Bakken -- CLR's most recent presentation, link here. Quickly, because I have more important things to do, the things that caught my attention that are new:
34 slides
2018: a breakout year for CLR
100% funded from internal cash flow
$2 billion for D&C
78% of D&C targeting the Bakken and the Springer (SCOOP)
targeting 17% to 24% YoY production growth; targeting annual 285K to 300K boe per day
up to $1 billion (rounded) in free cash flow with $60 WTI and $3 Henry Hub
continue to reduce debt
free cash flow to reduce debt
additional non-core asset divestitures
net reservoir acres / hbp
Bakken: 802,000 net acres / 90%
STACK: 409,500 net acres (I did not realize it was this much, compared to the Bakken) / 60%
SCOOP: 724,000 (ditto) / 60%
production
north (North Dakota): 175,563 boepd
south (Oklahoma): 111,422 boepd
Bakken continues to deliver record results (well / 30-day avg boepd / % oil / formation)
Tarentaise Federal 1-19H (2,126 / 79% / MB)
Tarentaise Federal 3-19H (2,074 / 805 / MB)
Tarentaise Federal 5-19H (2,034 / 79% / MB)
Tarentaise Federal 12-19H2 (1,848 / 79% / TF2)
Holstein Federal 8-25H (2,015 / 83% / MB)
Wiley 7-25H (1,966 / 76% / MB)
Akron Federal 7-27H (1,853 / 79% / MB)
Radermecher 2-22H1 (1,833 / 79% / TF1)
Monroe 7-2H (2,055 / 80% / MB)
Monroe 6-2H (2,869 / 79% / MB)
EUR type curves: 1.1 million boe
134 optimized completions
125% ROR
PV-10 up 47% per well compared to previous type curve
interesting term on slide 16: "children wells" / "parent well"-- we've blogged about that only once or twice in the past; a reader working for HAL alerted me to that "new term" maybe a year or so ago
children wells are producing 20% higher than parent wells (we've seen something similar in the Bakken); 50% reduction in drill time; 20% reduction in CWC
history of EUR type curves:
2011: 430 mboe
2014: 603 mboe
2015: 800 mboe
1H17: 980 mboe
2018: 1,100 mboe; payout period down to ten months
************************************
Notes to the Granddaughters
Close Encounters With Humankind: A Paleoanthropolgist Investigates Our Evolving Species
San-Hee Lee with Shin-Young Yoon
c. 2015
Chapter 1: Are We Cannibals
there may be cannibalistic behavior, but there are no cannibals
Fore, Australia, in the 1950s
the spread of an unknown disease
tremors and convulsions: kuru -- "shaking" in the indigenous language
also called "laughing disease" because patients would fall into fits of nonstop laughter
a very long incubation period: normally five to 20 years
the last reported person to have the disease died in 2005, but he was infected in the 1960s
after the incubation period, the patient usually dies within a year of the first symptoms
Daniel Gajdusek: documented the existence of a prion disease for the first time
another prion-related disease: Creutzfeldt-Jakob disease
Gajdusek: Nobel Prize in Physiology or Medicine in 1976
currently, scientists hypothesize that the kuru epidemic started with the funerary rituals for one person who must have had kuru, which was endemic to the population
Chapter 2: The Birth of Fatherhood
there is no question that the human family is unique: human families involve adult men
"couvade syndrome": sympathetic pregnancy and labor experience among (prospective) fathers
Chapter 3: Who Were the First Hominin Ancestors?
Propconsul and Ramapithecus: first candidates; subsequently, the DNA said "no"
Australopithecus africanus: DNA, yes, but fossil record dated A. africanus to only 2 - 3 million years ago; too recent
then, Mary Leakey and Donald Johanson: A. afarensis found to be 3 - 3.5 million years old; "Lucy"
walked upright before developing an enlarged brain
"Lucy" resulted in a paradigmatic shift
bipedalism, not enlarged brains, would be the defining characteristic for an ancestral human
mid-1990s: several ancestral hominins much older than A. afarensis; also bipedal
Australopithecus anamensis, 3.9 - 4.2 million years ago
heated debate whether to add a third candidate, A Anamensis to A. afarensis and A. africanus
it's possible A. anamensis might simply be another A. afarensis
issue becomes more complicated in the early 2000swith three new candidates for "earliest ancestor"
1999: two new candidates
Sahelanthropus tchadensis, discovered in Toumai, Chad (central Africa); 6 - 7 million years go; too little fossil to be more sure
Orrorin guenensis (no doubt named after a fossil of a senator in the US Senate, LOL), Tugen Hills, Kenya, East Africa; also 6 - 7 million years ago; femur shows traits of bipedalism
most recent addition: Ardipithecus ramidus, discovered in Aramis, Ethiopia; 4.4 million yeas ago
another reversal: bipedalism in doubt
the problem: A. ramidus may have been a tree-climber
one possibility: the three candidates may be members of the various ape lineages that roamed before hominins began, instead of being the earliest member of the hominin lineage
Chapter 4: Big-Brained Babies Give Moms Big Grief
childbirth in humans cannot (as a rule) be done alone: "social" childbirth
origin of "social" childbirth goes back at least 50,000 years; CT scan of Neanderthal newborn
Chapter 5: Meat Lovers R Us
first source of "meat" for hominins -- bones
Chapter 6: Got Milk?
co-evolution of humans and cows
in the last 10,000 years, humans evolved the ability to drink milk into adulthood from a series of genetic mutations in the lactase gene
but also, milk itself has changed; the genetic makeup of the cows that produce milk has changed through domestication
genetics and anthropology have shown that humans have continued to evolve recently, at an even faster rate than we did over the previous 5 million years (author will come back to this later)
Chapter 7: A Gene for Snow White
lighter skin among humans
Chapter 8: Granny Is an Artist
when did longevity begin? with sapiens or with erectus
longevity and the blossoming of art
Chapter 9: Did Farming Bring Prosperity
Chapter 10: Peking Man and the Yakuza
yakuza: the notorious crime organization of Japan
Peking Man was discovered in Zhoukoudian, China, in the 1920s
fossils vanished at harbor of Beijing, 1941, in preparation for transportation to the US; last time they were ever to be seen
now, ten years earlier, the author was told a yakuza rite would include Peking Man fossils
if legitimate --- wow!
author declined the invitation -- wow, even sadder (too dangerous to accept)
the Peking Man fossils have never been rediscovered
the molds still exist
argument that Peking man is not Homo erectus
Chapter 11: Asia Challenges Africa's Stronghold on the Birthplace of Humanity
the Dmanisi fossils
Chapter 12: Cooperation Connects You and Me
is helping others written in our DNA?
1.8 million years of altruism
Chapter 13: King Kong
was King Kong real? Gigantopithecus
Chapter 14: Breaking Back
Chapter 15: In Search of the Most Humanlike Face
Homo rudolfensis
what makes a face "humanlike" anyway
KNM-EM 62000: discovered in Koobi Fora, a renowned paleo-anthropological site in northern Kenyz
the most famous family in the field of anthropology: the Leakeys
Chapter 16: Our Changing Brains
adult brains and child brains are different
growth -- not physical size but the number of synapses
big brains need lean faces
"...for the skull to get bigger, the muscles holding down the bones that make up the skull have to become smaller first, to allow the skull to grow unencumbered. The biggest muscle connected to the skull is the masticatory (chewing) muscle. In other words, for the brain to get bigger, the masticatory muscles have to get smaller. Interestingly, a paper published in 2004 featured an experiment showing that a mutation in a gene (MYH16) to make the chewing muscle small led to an enormously big skull in mice, making this hypothesis more plausible."
there are indications that in the last 50,000 years, human brains might actually be getting smaller; if true, no one knows why, but that's where research is headed
Chapter 17: You Are a Neanderthal!
Chapter 18: The Molecular Clock Does Not Keep Time
come back to this chapter later
Chapter 19: Denisovans: The Asian Neanderthals
come back to this chapter later
Chapter 20: Hobbits
Chapter 21: Seven Billion Humans, One Single Race?
it is not clear when and where the concept of race originated
if a race is not like a biological species, researchers keen on proving that race exist as a natural category might then consider subspecies, a subclassification within the same species. A subspecies is a population that has been isolated to the point that it is on a trajectory to become a different species if the isolation continues. Subspecies are sometimes defines as sharing less than 85% of their genes with the other subpopulations of their species designation (don't humans - chimps share 99% of their genetic material?), in order to be considered on their way to becoming a different species.
Two plays: the Permian and the Bakken. Highlights that I have posted here are mostly on the Bakken; see the link for everything, including the Permian.
Oasis says it still has 518,000 net acres in the Williston Basin; pending acquisition of 20,000 acres in the Delaware (Permian); I assume this number will decrease once sale of non-core assets in the Williston Basin is closed
my estimate: $500 million in non-core asset sales / $5,000 acre = 1 million acres ("Montana"?; maybe some Foreman Butte)
Williston: > 90% held by production
1,614 location economic at $45 WTI in the Williston
770 core locations: 1/3 in Wild Basin
equates to more than 20 years of remaining highly economic Williston inventory at 2017 pace of completions
further upside with increasing frack intensity in all three areas
over 600 core Delaware locations
active rigs: 5 in Williston; 1 in Delaware
Williston:
core: north-central McKenzie, south-central Williams straddling the river -- Indian Hills (1 rig); Alger (2 rigs); Wild Basin (2 rigs)
extended core: north into west Williams and west into Montana, mostly Roosevelt, some Richland -- Montana, Painted Woods, Red Bank
fairway: farther west -- into west McKenzie and along Montana (Roosevelt)/ND (Williams state line; and then huge fairway parcel in Mountrail/Burke -- Cottonwood, Foreman Butte, Montana
drilling time: decreased from 22 days (2014) to 14 days (2017) -- spud to rig release
frack efficiencies with large pad development around zipper fracks
production, November:
Williston: 72,000 boepd
increasing guidance form 69 - 72 to 71 - 73 thousand boepd for 4Q17
Delaware: 3,500 boepd
Other revenue streams
Oasis Midstream
Oasis Well Services -- currently two fracking spreads in Williston
2018 development plans
5 rigs
complete 100 - 120 operated wells; about 70% working interest
cost, slickwater well costs:
2014: $10.6 million
2017: 4 million lbs: $6.8 million
2017: 10 million lbs: $7.7 million
targeting $500 million of non-core asset sales in 2018
From the presentation, the Bakken play:
Now, this -- this is absolutely incredible: when we first started covering the Bakken, the EUR for Bakken wells were said to be 350,000 bbls (oil/oil equivalent?)
Then we saw guys like Mike Filloon / Richard Zeits (I forget which) was the first to notice EOG wells with EURs of 750,000 and then as high as one million bbls (again, oil/oil equivalent). Now, look at the Oasis type curve below -- 1.550 million boe and for some folks, an even more important data point: at 350 days, the type curves show a jump from 200,000 boe to 300,000 boe. I may be misreading the graphic a bit, but you can see it here and/or go to the source.
Now, this: the USGS bases its reserves assessments in a given basin based on production of existing wells. The last USGS survey of the Bakken was accomplished in 2013; and there results would have been based on entirely different well type curves, probably in the realm of EURs of 500,000, or a third of what Oasis is showing in this slide (yes, I am aware of tier 1, tier 2, tier 3 locations in the Bakken).
Disclaimer: in a long note like this there will typographical and factual errors. In my notes above, I will interject my comments (facts and opinions). It is difficult to tell where I may have interjected my own comments. I often make simple errors. I often misread things. I correct obvious errors when I see them. Do not make any investment, financial, job, travel, or relationship decisions based on anything you read here or think you may have read here. If this is important to you, go to the source.
Remember: this article is from a year ago, during the early stages of the "depression."
It's a long article and covers many areas, so let's go through some of the data points with my comments thrown in.
Most remarkable prognostication from the article, from Mark Papa, "a legendary figure in the shale fraternity and now at Riverstone Holdings":
“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said.
Most interesting comment from the article, also from Mark Papa:
Mr Papa said it will not be long before engineers work out how to double the efficiency of shale extraction to the 50 percent levels seen in conventional oil wells. "It'll probably come in the next ten years. That's the next big break-through," he said.
For newbies, as I understand it, Mr Papa is talking about "primary production" and does not include enhanced oil recovery using waterflooding or CO2 injection.
This raises the question: what is the current primary production estimated to be in the Bakken? At the beginning of the boom, it was widely accepted that primary production would range between 1 and 3 percent. For a 500-billion bbl original-oil-in-place reservoir, that worked out to 5 to 15 billion bbls.
Around 2014 or so, Whiting and others were suggesting that operators were achieving 7% primary production in the Bakken and reading between the lines, it appeared that some operators might have been achieving as much as 12% or at least trying to hit that target.
At 10% primary production, a 500-billion bbl original-oil-in-place reservoir works out to 50 billion bbls of recoverable oil.
Currently, the Bakken is producing about 350 million bbls annually, or 1
billion bbls every three years. Unfettered, Bentek estimated (and some
continue to estimate) that the Bakken can produce 2.2 million bbls daily
if the "price was right."
The second most interesting comment from the article: I vividly recall analysts saying that it was impossible for frackers to "turn on a dime," that it would take months for frackers to spud a well and bring it to production. I remember that vividly because I was not seeing that in the Bakken. From spud to production, operators could measure it in days -- generally about 30 days. And bringing in more rigs was not all that difficult. The biggest problem for the Bakken was competition from the Permian for skilled work crews but with things starting to turn a bit sour in the Permian, the Bakken may have some relief. But I digress. From the article:
"Restarting production may be easier than people think. Everything is ready to go. There are plenty of rigs. All the ingredients are there. There is a lot of money looking for the bottom of the cycle, waiting to get back in," he said.
In the first two or three years of the Bakken boom, there was minimal infrastructure and constrained takeaway capacity. Both of those have been resolved.
Not mentioned in the article, in the Bakken alone:
850 DUCs
1,500 wells that are shut in for various reasons
At the end of this quote, IHS was thinking specifically of the Bakken, but since 2016, everything changed when the DAPL came on line (early 2017):
IHS said there are three groups of 'invisible barrels' likely to bear the brunt as the market stabilizes: small-scale 'stripper wells' of around 2m b/d, half of them in the US; those with high-fixed costs in North Sea and the Gulf of Mexico that are going into steeper decline; and those in remote locations or with long pipelines, and a $10-$12 disadvantage. "
They are in the eye of the storm," it said.
Hess disagrees:
The great unknown for world oil markets is how fast the frackers will come back. John Hess says it will take two years once prices recover.
"It is a big logistical undertaking. You've got to mobilize rigs and find people. Assets need permits in the US, and that takes 90 days," he said.
"Balance sheets are in disrepair and there is too much debt. The high-yield market has basically dried up and that was the primary source of financing for the shale boom. Debt agencies are in a panic and running everything through $30 oil for the next few years," he said.
I think where Hess and I disagree has to do with the definition of "recover." It may take two years for E&Ps to return to historical levels of prosperity (as measured by share price or market capitalization) but it certainly won't take two years to see an incredible rush back into the Bakken if oil prices a) began to trend toward $60; and, b) tea leaves suggest that the trend would continue.
Possibly the most incorrect prognostication:
Scott Sheffield, head of Pioneer, expects trouble in the Eagle Ford and Bakken fields, but it is a different story in the lucrative Permian Basin of West Texas, the "crown jewel" holding steady at 2m b/d even at current prices. He claims it is as big as the giant Ghawar field in Saudi Arabia, and could eventually produce 6m b/d.
I agree that production will remain steady (or grow) in the Permian, but it may be more financially challenging than first expected. Paying $60,000/acre in an era of "lower for longer" is not going to cut it, as BHP found out.
Break-evens for US operators: no one knows. The "number" is all over the place. Everyone agrees that "very few things make sense at $30. It's better to leave the oil in the ground."
David Hager, head of Devon Energy, said shale frackers have slashed cuts costs way more than outsiders generally realize since the heady days of the boom, when service fees and wages were rocketing.
"A lot of plays work at $45-$50, and the vast majority from $55-$60. They certainly don't need $90," he said.
This is optimistic. A study by Rystad consultants in Norway puts the break-even price at $68, but nobody knows for sure and frackers disagree among themselves.
Shake-out: again, Mark Papa -- Mr Papa said the 70 percent crash in oil prices since mid-2014 will wipe out those companies that leveraged to the hilt betting that crude prices would stay above $100 forever.
BHP Billiton is a great example. The company itself agrees that it overpaid when it spent $20 billion to enter US shale plays (the Eagle Ford and the Permian), previously posted/linked. Only because of its size and other mining businesses did BHP survive (and thrive, for that matter).
Re-Balancing: perhaps by end of 2016, into 2017, but difficult to predict. This is what caught my eye, and many readers say the same thing. A new bust-boom cycle:
Mr Papa expects the global balance of supply and demand to tighten by 1.6m b/d this year. This would mop up the glut, before gradually eating into record stocks next year.
"The market is going to grow to 100m b/d. Where is the quantity going to come from? Capital spending on mega-projects has stopped cold,” he said.
“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said.
By the way, I disagree with Mark Papa on this point:
"The
market is going to grow to 100m b/d. Where is the quantity going to
come from? Capital spending on mega-projects has stopped cold,” he said.
The tea leaves suggest there is more than enough oil out there to preclude that concern. But the tea leaves also suggest I am in the distinct minority. Most agree that shale cannot make up for all the off-shore CAPEX that has been deferred or canceled. The reason I disagree: Mideast potential, especially Iraq. Much could be written but perhaps for a different day.
Not just shale.
"Most companies will survive to take advantage of the recovery. We will ramp up, stay alive, meet the challenge, and look forward to a brighter day. It is not just shale that doesn't work at today's prices, nothing much at all works," said Mr Hager.
I did not post it but there was a recent article suggesting that "stripper wells" are returning. Operators that had shut down stripper well operations are are now returning. I didn't post the story because it seemed to be a press release from oil companies in California where fracking is not panning out for political and geologic reasons. But if I'm wrong, and strippers are coming back, that speaks volumes for the oil sector.
Not mentioned in the article: fracking strategies. Sand is getting more expensive; ceramics remain very expensive. The trend toward ever-increasing amounts of proppant to complete a well seems to be coming to an end. Much more sand is being used, but more sand is being mined, and, either God or nature again seems to smile on the US frackers: huge amounts of fracking sand have been discovered in west Texas, in/near the Permian. Rail won't be required; truckers will do the job. Ceramics appears to be "out" -- too expensive and experience suggests sand does just as well. All those concerns about sand "not holding up" may have been more marketing than real. The big change in sand has to do with size of sand. Operators are going to "smaller" sand.
****************************
*****************************
Addendum
Playing Around With Numbers
In the examples below, one can pick whatever numbers in bold one wants.
The North Dakota Bakken (middle Bakken plus Three Forks first bench)
Williston to Minot: 120 miles
Williston to Belfield: 100 miles
100 miles x 100 miles = 10,000 square miles -- the North Dakota Bakken
78,125 bbls OOIP/acre x 1280 acres/drilling unit = 100 million bbls OOIP / 1280-acre drilling unit
500 billion bbls OOIP / 5,000 1280-acre drilling units = 100 million bbls OOIP / 1280-acre drilling unit
12 wells / 1280-acre drilling unit
100 million bbls OOIP x 7% production rate = 7 million bbls recoverable oil / 1280-acre drilling unit
7 million bbs / 12 wells = 583,333 bbls / well
Summary: at 7% production rate across the middle Bakken/Three Forks first bench yields: 583,333 bbls/well
Whether one agrees with the assumptions or not (the numbers in bold) it is amazing that the law of large numbers seems to work. I think everyone agrees that EURs of 600,000 bbls is not unrealistic (yes, I know there are a lot of poor Bakken wells out there, but one can also argue that a lot of those poorer Bakken wells were drilled under less than optimal conditions, beginning with poor understanding of the geology and extending through inexperienced roughnecks.
If, in fact, operators are approaching 14% productivity rate in the Bakken, then one can expect million-bbl EURs.
Idle chatter but it helps me validate OOIP estimates; company talk about production rates; and, EURs of wells that are being drilled over time.
26521, 2,661, QEP, TAT 4-33-28BH, Grail, API: 33-053-05290, t5/14; cum 318K 3/17;
Recent production:
Pool
Date
Days
BBLS Oil
Runs
BBLS Water
MCF Prod
MCF Sold
Vent/Flare
BAKKEN
3-2017
31
25275
25173
6911
40683
33401
7057
BAKKEN
2-2017
28
24675
24865
12533
34884
32468
2219
BAKKEN
1-2017
23
21975
21574
20817
31513
27842
3533
BAKKEN
12-2016
21
5972
5853
5829
8824
4812
4012
BAKKEN
11-2016
1
6
5
2
13
13
0
BAKKEN
10-2016
0
0
148
0
0
0
0
BAKKEN
9-2016
8
1128
1115
340
2028
2003
25
BAKKEN
8-2016
31
3053
3093
1286
4674
4511
58
BAKKEN
7-2016
31
4116
4050
1263
5983
5794
6
BAKKEN
6-2016
30
3580
3630
1355
6419
6419
0
BAKKEN
5-2016
31
5000
4947
1447
6945
6828
117
BAKKEN
4-2016
30
3679
3706
1009
6394
6163
155
BAKKEN
3-2016
31
4466
4520
1251
7687
7357
228
Comment: regardless of the reason for this jump in production, there are many, many examples of (unexpected) increased production in "older" wells in the Bakken. One has to laugh: "older wells" in the Bakken -- only two to three years ago in this case and many other cases; this could greatly affect EURs; and is certainly a component of Bakken 2.0.
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The Literature Page
This is from Ingrid D. Rowland's essay, "Martin Luther's Burning Questions," in the current issue of The New York Review of Books.
2017 is the 500th anniversary of Martin Luther posting his "95 theses" on the door of the church attached to the local lord's castle.
Martin Luther focused his ire (and most of the ninety-five theses) on one particular practice of the institutional church: the sale of indulgences.
These papal dispensations, confirmed by paper certificates, grew out of a traditional medieval conviction that prayer, repentance, good works, and pilgrimage could atone in some measure for sin. It was even possible to do penance for someone else ... giving alms or endowing a church could also earn remission from sins, reducing the amount of time ... [one's soul] would spend in Purgatory...
By the late fifteenth century, however, remission from sins could simply be purchased from a papal agent, for oneself or for another person, whether alive or deceased.
The sale of indulgences became an industry only in Luther's own lifetime and in his own lands, put into place by Pope Julius II and the Augsburg banker Jakob Fugger.
After 1506, pope and banker directed the revenue from German indulgences toward the rebuilding of Saint Peter's in Rome.
Huge amounts of [German metal [gold, copper, lead, iron] was being sent to Rome and Germany was] receiving printed slips of paper in return for the equivalent of checks that drew on the currency of heaven rather than Earth.
Jakob Fugger [the Augsburg banker] took a 3 percent cut -- in coins, not release from Purgatory -- on every every shipment south.
It is any wonder that the man who finally pulled the plug on this improbable trade knew a thing or two himself about the value of metal?
*********************************
Nice Work If You Can Get It
From "The Big Thing on His Mind," Andre Bleikasten, in The New York Review of Books, April 20, 2017, an essay on William Faulkner, born in Oxford, MS, 1897; alcoholic, died in 1962, horse-riding accident, Virginia.
These three (at least) favored mornings-only writing schedules: Sherwood Anderson, Ernest Hemingway, and William Faulkner.
Sherwood Anderson was the "old man": 1876 - 1941. Faulkner and Hemingway almost exact contemporaries, Hemingway, 1899 - 1961. Graham Greene was a bit younger, 1904 - 1991.
Faulkner and the "n-word." In Faulkner's world, everyone was on one side of the line or the other: the great social divide was marked by the word "nigger." On one side of the color line in Faulkner's world people can call others "nigger" with impunity; on the other [side of the line] they must submit it to silence.
It appears Faulkner considered himself on the side of the line in which he could use the word with impunity.
Other quick notes, all from the article, not my words:
The writer mentions Mary Chesnut who wrote the "great diary before the Civil War" -- a copy of which I have, but it's out in California.
Terminology:
octoroon: one-eighth Negro. Indistinguishable from no African ethnicity; one Negro great-grandparent
quadroon: one Negro grandparent
mulatto: one Negro parent
One last note: either incredibly coincidental or very, very well planned by TNYR -- just a few pages later, in the same issue, a selfie/photograph of Mary Miller, in front of a pond in Oxford, Mississippi. Mary Miller is a "minimalist" author, contemporary. The essay was written by Joyce Carol Oates. It was probably not coincidental. Mary Miller's three books: Always Happy Hour, The Last Days of California, and, Big World.
NOG: Worth repeating. This is from NOG's 1Q17 press release. Note the EURs for new wells:
production: averaging 13,299 boepd
producing wells with a 30-day IP average of 1,485 boepd; a 34% increase over the 2016 additions
2016 producing wells are tracking a 1 million boe average type curve, a 59% increase over the 2015 additions
***********************************
Skarston Wells Update
Some of the Skarston wells that had been taken off-line are now coming back on line. I track the Skarston wells here but this page has not been updated.
To the best of my knowledge, this well was fracked only once. FracFocus has data for only one frack: September 17 - 23, 2015. This is the well's entire production history. Note the jump in production after being taken off-line for a couple of months in late 2016, a year after the original frack. The 5,464 bbls over 4 days extrapolates to 41,000 bbls over a 30-day month. This well continues to flow on its own according to the scout ticket. I follow this well and the other Whiting Flatland Federal wells here.
The well:
30774, 1,844, Whiting, Flatland Federal 11-4-5TFH, t10/15; cum 473K 1/17:
there is no doubt that
newer well designs in the Permian continue to decrease breakevens, which
should improve US production as OPEC production cuts are applied
although Permian production will continue to increase, at today's prices this production will not totally offset cuts
as Permian breakevens lower, the same could be said about other plays which could spur production higher in other states
as
the marginal producer, US shale will not increase significantly as a
whole, but the Permian should continue its upward momentum
I was hoping Mike Filloon would see the recent article by Oilprice.com, and respond to it. I would have liked to have responded to that article, but I could be nowhere near as articulate as Mike. Mike pretty much says it all early in the article:
Play breakevens continue lower. Higher oil prices will
spur oil production increases in the US. The Permian should realize the
greatest increases. Some have said US unconventional oil is a Ponzi
scheme. Those who surmise this rob Peter to pay Paul conspiracy, may not
understand the complex realities of oil exploration and production.
It's a different type of investment. Oil production has high initial
costs. Some operators pay high acreage prices to get into plays late.
D&C costs can be high initially, but as with most businesses, costs
decrease. LOEs are also key, as those costs are stripped from revenues
from the well head.
This complicated industry has become more so through
unconventional designs.
The Peak Oil theorists were wrong, as
unconventional production was great enough to effect the world's supply
and demand balance. It took time, and high oil prices, but US producers
got the job done. It may have gotten the job done too well.
Conventional
wells contrast horizontals with respect to production. Production
begins and declines at a relatively low pace month over month.
Horizontals produce an immense volume of resource in the first month,
followed by a higher decline rate. While conventional production
declines are easily calculated, it takes an engineering degree to
estimate unconventional curves. The decline is not constant. Decline
rates are exponential over several years then change. Initial horizontal
production is created through induced fracs and the interconnected
natural fracturing within the interval.
After 3 to 7 years, induced
frac's stop producing, and we enter matrix production. Although a
simplistic explanation, it is what many bears get wrong. Matrix
production declines are much like a conventional well. Estimates vary at
3% to 5%. So if a horizontal is modeled to decline exponentially, and
matrix production is not accounted for, one could model that well to
zero in a shorter time.
There is another difference between conventional and unconventional production profiles, something that has not yet been addressed by many but will become more obvious in the out-years. This has to do with re-fracking unconventional wells and re-working unconventional / conventional wells.
Unconventional oil: "After 3 to 7 years, induced
frac's stop producing, and we enter matrix production." When we enter matrix production, the jury is out whether a re-frack will change the production profile for all fracked wells. A re-frack will certainly change the production profile on a poorly fracked well, or a fracked well using "old" completion techniques.
Conventional oil: "re-working" a conventional well, will, at best, maintain the predicted production profile.
Mike goes on to discuss EURs and models.
He also suggests that the upcoming "driving season" in the US could push WTI to $60/bbl.
Maybe that will be the new 30-second soundbite for the Bakken: "$50-oil, 50 active rigs in the Bakken; $60-oil, 60 active rigs in the Bakken; $100-oil, 100 active rigs in the Bakken."
Disclaimer: this is not an investment site. Do not make any investment, financial, travel, job, or relationship decisions based on what you read here or what you think you may have read here. In a long note like this there will be typographical and factual errors. My notes are taken from the linked article and may not reflect what the author of that article wrote or intended. I am posting this for my use; if this is important to you, I would recommend you skip this post and go to the linked article.
I'll have to come back to this later; family activities today. This is not a "Filloon" article but it is very, very similar to what Filloon does, so I will tag it with "Filloon."
Whiting's recent portfolio
of mega frac wells in the Bakken is producing impressive results among
wells with 3 to 12 months of production, tracking a 947 MBOE type curve
WLL's
more recent larger fracs of 7 to 15 million lbs of sand are clearly
enhancing the early track of MBOE, many of them tracking a 1,200-1,500
MBOE curve
Whiting's larger production numbers will stabilize the
production drops from its portfolio of 1,500 wells and push the company
to break even on a faster pace given NYMEX at $60/bbl
Curves:
750,000; 900,000; and 1.5 million boe EUR curves
the author's results line with up within 2% or better of the data Whiting presents
the curves assume a 30-year life-cycle for the wells
85-90% of the oil / gas will be produced in the first 15 years
Whiting has a number of older wells near 10 years old now that are producing 1,500 to 2,000 bbl/month on a consistent basis
many of these older wells will be re-fracked or worked over to enhance their current track of 300 or 400 mboe EUR
most important, these wells prove that Bakken wells have a minimum 15-year life minimum; some analysts suggest Bakken wells will only last ten years
Controversy:
apparently controversy regarding Whiting's December, 2016, presentation was focused on the company's use of the 900 mboe type curve and more recently its use of a 1.5 million EUR ttyp cure
anyone who has followed the Bakken since 2007 knows these EURs are "believable"
Data :
data has been collected on wells since 2015
Analysis:
what is clearly making a difference is doubling the amount of sand
operators doubling up on sand: Whiting, CLR, MRO, Oasis, Burlinton Resources (subsidiary of COP) and EOG
the whole industry is moving to the "mega-fracks"
Summary data points:
all Whiting wells that were fracked in 2016, the average mboe EUR is tracking 952,000, therefore in line with Whiting's claim of 900 mboe
The 1.5 million boe EUR controversy:
All this fuss in the December piece about Whiting's wildly inflated
claims of 1,500 MBOE carries some merit, but it's impact is very, very
small. Whiting never claimed that ALL of its production
would run at 1,500 MBOE, just some of the larger fracs from 2016.
Looking closer at the 1,500 club reveals some interesting patterns.
First, the 1,500 MBOE wells are actually popping up faster and more
frequently now, especially in the last six months of 2016. Below is the
table of the current members tracking a 1,500 MBOE curve and its current
production as of 12/31/2016. Some of the numbers are eye-popping.
Specifically, all of the Rolla wells seem to be screaming right out of
the gate in terms of performance, with monthly oil volumes of 45,000
bbls or greater.
But even back in 2015, there are a few scattered 1,500
MBOE babies, in particular Flatland Federal in TRUAX field in McKenzie
county. This well is a monster, generating nearly 600,000 barrels of oil
equivalents in just over 15 months. If every well in the Bakken behaved
this way, OPEC would be out of business tomorrow. Flatland Federal
could be tracking (continuing its current pace or slope) nearly 2
million barrels of oil equivalent or more once the data is all in. Keep
in mind the data behind these 1,500 MBOE wells is early, just 15 months
or less, but unless these curves all start rolling over (many of them
have not), it looks as though Whiting's production profile is going to
greatly benefit even with fewer wells being drilled under a constrained
capex/NYMEX environment.
As for Whiting's 1,500 MBOE claims, I would conclude this. It is early. That is the largest caveat.
I would have preferred if it jumped to claiming 1,200 MBOE before
making the leap from 900 to 1,500 MBOE! But, in its defense, it now has
20, that's right 20 wells that are tracking at or above 1,500 MBOE,
albeit with half of them producing for four months or less. Not many
operators can say that. Not Continental, and not Oasis. Yes, there is
more data coming in, but Whiting has a very good start. However, there
are some "doggy" or dodgy wells that were heavy fracs and are tracking a
600 or 500 MBOE curve with 10 million lbs of sand. Whiting should
explain what is going on with these.
It is mostly in areas of Stark and
Dunn Counties, and a few in Williams County. What this is telling me is
that even if you force 10 million pounds of sand down a hole with
massive pressures and temperatures, if the payzone/real estate was
average or non-prime, to begin with the larger frac just enhances the
original production profile. In support of this idea, if one looks back
at 2015, there are a decent number of wells that performed at 900 MBOE
or higher and only had fracs of 2 or 3 million lbs of sand. It wasn't
the frac that generated that performance, it was the shale/rock payzone
characteristics. Whiting needs to be careful of where it spends every $
of capex per pound of sand. Quantity is not always quality.
Summary:
In summary, if Whiting continues at this pace, its well performance per
well will have jumped roughly 100% on an average MBOE from 2015 wells to
2016 wells, from 560 MBOE TO 951 MBOE. The larger sand fracs have a
clear advantage in production, as evidenced by the recent set in 2016,
with some wells easily producing 1,200 MBOE (tracking after 6-12 months)
and others tracking north of 1,500 MBOE. The claims in prior articles
of Whiting's overstated data and inferior real estate look to be nothing
more than misunderstood statistics and superior short sightedness. As
more data arrives in 2017 behind this new crop of wells, it looks as if
the company will benefit greatly at both the top line and the bottom
line if the marginal frac cost is controlled on carefully selected
leases.
In the history of the oil and natural gas industry in the United States,
2016 will be remembered as one of the most eventful in terms of major
market developments, asset transactions and developments in public
policy.
The writer's top observations:
the Permian Basin exploded
costs of drilling plunged
EURs soared
hundreds of companies filed for bankruptcy
fracking was exonerated
anti-development moved from upstream to midstream
LNG exports ramped up
oil exports almost doubled
the US became a net exporter of natural gas
OPEC "surrendered"
And then this -- PEOTUS nominees:
Along with him will come nominees like former Texas Gov. Rick Perry for
Secretary of Energy, Montana Congressman Ryan Zinke for Secretary of
the Interior, Oklahoma Attorney General Scott Pruitt as EPA
Administrator, and ExxonMobil CEO Rex Tillerson for Secretary of State.
If that looks like a pretty pro-oil and gas lineup to you, trust me,
you are not alone.
The writer mentions only a very few companies by name. One that he mentioned: Oasis, with regard to plunging drilling costs.
Whiting is projecting 1.5 million boe EUR wells in the Bakken. Currently, the standard is 900,00 boe EURs.
For newbies: search "EURS" at the blog. I have long forgotten but early on in the boom, EURs of 400,000 were the norm, but by 2014, we were talking some remarkably higher estimates. See this post: EURs in excess of 2 million boe?
Highlights:
3Q16 LOE below low end guidance at $7.98 / boe ("below" is good)
Williston Basin 5+ million pound completions: tracking 900,000 boe-type curves
Williston Basin 10+ million pound completions: tracking1.5 million boe-type curves
thirteen (13) new McKenzie County test at average rate of 3,727 boe/day
Whiting is focused on the Bakken and the Niobrara
positioning the company to be the operator in those two basins
Williston Basin: 106,000 boe/day
Niobrara (Redtail): 11,000 boe/day
Bakken acreage
738,479 gross acres
443,125 net acres
99% held by production
completed well cost: $6.8 million
Bakken development plan
1280-acre units
5,471 potential gross drilling locations
targeting 900,000 boe EUR wells in 2016
approximately 22 DUCs at end of CY2016
correction from original post (see first comment): Whiting's most recent presentation does not mention southwest North Dakota but a reader says that 6% of Whiting's locations are still in Stark County
most of Whiting's interests are around Williston, Watford City, Parshall
EUR s have jumped from 700,000 boe to 900,000 boe using "enhanced completion")
but look at this:
Record-setting production: According to their data, Whiting is the top producer in the Bakken based on initial 90-day production rate for wells completed between August, 2015, and July, 2016. Peer group includes Newfield, QEP, Oasis, XTO, Hess, EOG, BR, CLR, and SM Energy.
Drilling times -- Bakken -- Niobrara:
1Q12: 40 days Bakken; 16 days Niobrara
1Q13: 30 days Bakken; 18 days Niobrara
1Q14: 30 days Bakken; 12 days Niobrara
1Q15: 24 days Bakken; 15 days Niobrara
1Q16: 14 days Bakken; 7 days Niobrara
Note: the drilling times are "spud to spud" -- this is really quite amazing -- the time it takes a rig to drill a well and then move to thenext location and begin drilling the next well. When the Bakken boom began, it could take weeks to get a rig torn down, moved to a new location, and then set back up before beginning drilling again.
Cash flow:
According to their data, Whiting is the top operator based
on cash flow vs CAPEX. WLL cash flow/CAPEX ratio is 200%. The peer group ranges from 175% to a very, very low 25%. [100%: Cash flow = CAPEX; 200%: cash flow is twice CAPEX]. Peer group includes Noble Energy, Denbury Resources, CLR, Cimarex Exploration, EOG, SM Energy, Pioneer Natural Resources, Murphy OIl, Concho Resources, Oasis Petroleum, and Range Resources.
Very liquid balance sheet.
Hedges:
2016: $44 - $74
2017: $53 - $70
There is so much to write about / consider when discussing hedges that the actual prices are only a single data point, but I don't want to go down that road right now.
the STACK and SCOOP assets have prove to be Newfield’s core growth engines
the plays are still very early in their life cycles, with potential for significant performance gains
strong balance sheet enables an active drilling program in 2016
From Zeits:
The key factor contributing to Newfield's strong recent stock
performance has been the emergence of the company's SCOOP and STACK
assets as differentiated return leaders within its portfolio. After
several years of strategic repositioning and search for a competitive
growth engine, Newfield finally has "a horse to ride."
Tighter frack clusters in the STACK
oil EUR for a 30-year well is ~ 400,000 bo (950,000 boe)
60% produced in first five years
80% produced in first 10 years
STACK type curve wells estimated to "payout" in ~ 2 years ... tighter frack cluster wells sooner
Zeits compares STACK/SCOOP with the Bakken:
In the Bakken's core areas, several operators report exceptionally
strong early-time performance from enhanced completions. To illustrate, I
have included below two such examples, from QEP Resources at South Antelope and Halcón Resources at FBIR. In both examples, the wells appear to be on track to produce
200,000 barrels of oil on average - even more, in QEP's case - in the
first year on production.
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ISIS Bringing Down Russian Passenger Plan; Seven Coordinated Paris Attack Is Just A "Setback" -- President Obama
The White House was on the defense Wednesday morning for statements made
by President Obama -- who labeled Friday's Paris massacre that left 129
dead a "setback" -- and Secretary of State John Kerry's claim that the
terrorists who in January attacked Charlie Hebdo had a "rationale."
White House spokesman says we are paying too much attention to officials' words.
Note: in a long note like this, there will be factual and typographical errors. It has not been proofread. It is difficult to tell opinion from fact, either from the source or from my comments. Assume everything is irrational exuberance. I have no formal training or background in the oil industry. I have read The Prize but have yet to finish The Frackers. The easily influenced and gullible folks should probably skip this entire blog. There will be simple arithmetic errors. I often round numbers up or down, depending on my mood and hidden agenda. If this information is important to you, go to the source. This is not an investment site. Do not make any investment or financial decisions based on anything you read here or think you may have read here. By "here" I mean this entire blog, all 18,000+ posts.
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Maybe I will start here and see where this leads.
Look back at this post on July 21, 2010 -- five years ago? -- if the math was done correctly, this is what the NDGS estimated the EUR per section (640 acres) in the Bakken/Three Forks would be:
McKenzie: 257,602 bbls/section
Williams: 332,402 bbls/section
Mountrail: 296,754 bbls/section
Dunn: 228,146 bbls/section
Burke: 332,152 bbls/section
Divide: 154,560 bbls/section
Disclaimer: I often make simple arithmetic errors. It is possible the calculations and/or assumptions were incorrect. However, this post has been up since July 21, 2010, and no one has suggested they were wrong.
Fast forward to 2015: in general, operators won't drill a well in the Bakken if it doesn't have a EUR of at least 500,000 bbls crude oil. Using the numbers above, two sections in the best county (Williams) would get you 660,000 bbls/1280-acre unit (two sections).
Fact: the standard for almost anywhere in the Bakken is at least 4 wells per 1280-acre drilling unit, but for all practical purposes, it is at least 8 wells per 1280-acre drilling unit.
Staggering: 12 wells in a 1280-acre unit. EUR / well = 500,000 x 12 = 6,000,000 bbls / 1280 = 5,000 bbls/acre = 3,000,000 bbls/section. Compare with above (Williams: 332,402 bbls/section). But that's just 500K EURs. For at least two years now, we've known that the operators, whether they admit it or not, at looking for 1 million EURs in the sweet spots in the Bakken.
But for those paying attention, two years earlier, Whiting suggested that they could get 20%.
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We Interrupt This Post To Emphasize One Data Point
If you take a look at that last linked post, the Whiting/CEO said that they were not getting all of the oil that's out there with the current spacing in the Bakken. I'm assuming there are multiple interpretations of what he said.
Although it's being changed on a case-by-case basis, the fact remains that there are NDIC setback rules for each spacing unit. The smaller the drilling unit, the greater the percentage of "lost oil" due to the setback rules. I don't know the rules but for argument's sake, let's say that the horizontal lateral must not come closer than 250 feet to the drilling unit line; that the heel of the horizontal (the kick-off point) cannot be closer than 250 feet to the edge of the drilling unit line; and, that toe of the horizontal (the end of the lateral) must stop no closer than 250 feet to the edge of the drilling unit line.
The point is this: the amount of recoverable oil is not due only to technology; it can be affected by man-made administrative rules which can be changed.
Think about the setback rules and the radial effectiveness of fracking. Yes, there's a disconnect there, isn't there?
Hold that thought: we might come back to it later.
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The EOG 2Q15 Conference Call
To understand the Bakken better there are only a handful of transcripts I am interested in regarding earnings for 2Q15. I've looked at two of them: EOG and CLR. The next one that I will be looking at is Oasis. Summaryy, notes, and comments on Oasis 2Q15 conference call here.
Before moving on to the Oasis transcript, I want to spend a bit of time rambling about the EOG conference call. Shortly after I posted my notes on the EOG transcript, a reader wrote, commented, and asked:
EOG said they would drill their
DUCs (fracklog) in 2016 no matter what, regardless if prices recover. Since half the money is spent, then it becomes the best investment
available to complete those wells. Fair enough...but then why not
complete them now?
Surely after this little flirt with $60+ and prices getting beaten down,
it is pretty clear that the big V shape ain't happening?
I also don't understand why they
did a short lateral, the #30286, Riverview in the Antelope oil field. Surely cost efficiency is better at long
laterals? If it was just a test, why not do it at the distance they
expect to do in the future? Or is all their acreage so old that they
can't run long laterals?
Comment: The easy question first, to get it out of the way: is their acreage such that they cannot run long laterals? Answer: No. They can run whatever they want. If they have don't have the "correct" spacing unit size, the NDIC will give it to them, if EOG asks nicely. With regard to the short lateral Riverview that appears to have set the Bakken/Three Forks record for first-month production: the Riverview 102-31H was drilled on an even smaller unit than a 640 -- it was a 320-acre
unit, going to the north. That half-section is also part of a 640-acre
drilling unit, and it is also part of a1280-acre drilling unit. So, they could have drilled a 320-, a 640-, or a 1280-acre spaced well from that location.
Comment: EOG's expertise in the Bakken, for whatever reason, has been short
laterals. If they wanted longer laterals they could always ask for
larger drilling units. And in fact they did just that in the January,
2015, hearing dockets. [Case #23595, EOG, multiple wells on 16 1280-acre
units; multiple wells on 15
1920-acre units;
Parshall-Bakken oil field]. That doesn't mean the horizontals will be longer. They could still drill short laterals on
bigger drilling units, of course. All those 2560-acre drilling units? They all have long laterals -- the very same length used on 1280-acre drilling units, even if the entire 2560-acre unit is a laydown or a standup.
Comment: the reader says, "surely cost efficiency is better at long laterals." I'm not so sure. I discussed that elsewhere. If folks are interested in my thoughts on this, I will talk about it again. I will probably have to talk about it again, just to refresh my memory and for archival purposes.
Comment: the reader asked why EOG is waiting until 2016 to complete the DUCs? I think one can come up with a dozen different, not necessarily mutually exclusive reasons. I will list some knee-jerk thoughts to remind me when I expand on this subject in the future:
CAPEX
survival mode
liquidity
time involved in studying off-set and existing wells
re-evaluating completion techniques
geo-political considerations (Harold Hamm says things are going to change as early as September, 2015, just a month or two from now)
EOG has a history of not fracking in cold weather; that may or may not be true; it is a fact that is is much more difficult and much more expensive to drill in cold weather
determining best wells to complete: flaring rules, transportation costs (moving oil from any given pad by truck or by pipeline)
I'm sure readers can come up with a dozen other reasons why EOG is waiting to start completing the DUCs in 1H16. I think the #1 reason is "re-evaluating completion techniques" -- the main theme that I took from the EOG conference call. I think the Riverview well was a huge test for EOG. I wouldn't be a bit surprised if there were competing views on how to complete the well with some geologists on the team really, really excited about trying something new, or doing the same thing just a whole lot better. And with the results, they were really, really vindicated. It's possible that a lot of thought went into that well ahead of time but no one thought it was going to be as good as it was. Analogy: you have five million dollars to build a house. You can build a 50,000 square-foot McMansion or a 5,000 square-foot house. Which house is going to be aesthetically the nicer home to live in? No right answer; it's in the eye of the beholder. I personally would go for a $5 million 5,000 square foot house. With a basement. Oh, and for the 50,000 square-foot McMansion, I give the architect six months to work on it. For the 5,000 square-foot house, I give the architect two years to work on it.
As Good As I Once Was, Toby Keith
Comment: the "V ain't happening." I don't know. It's hard to say whether the "V" will happen or not. Common sense says we won't see a "V-shaped" recovery in the price of oil, but neither the Mideast nor President Obama are known for their common sense. Regardless of whether a "V-shape" recovery occurs or not, remember what EOG said some months ago: they can make more money on $65 oil than on $95 oil. There may be some hyperbole there but it's not the price of oil that is important; it's the margins.
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With Regard To The Price Of Oil
I am always conflicted when writing about the Bakken. I started the blog to help me understand the Bakken, not for investment purposes. I still have little interest in writing about the Bakken from an investment point of view. That's why I have spent so much more time on the EOG conference call than on the CLR conference call. The CLR conference call seemed to emphasize the economics, the financial end of things. The EOG call seemed to be one of those incredible moments in time when the CEO admitted that he has to go back to the drawing board, to re-think everything he has thought about completing wells in the Bakken. Remember, EOG had the first "real" discovery well in the Bakken that set off the current Bakken boom (folks can disagree with me on that), and here we are, eight years later, not only knowing a whole lot more about the Bakken, but apparently seeming to know less than we thought. And in a conference call, we get hints that the light bulb just went really, really bright in the CEO's head. And I think some folks missed that. Mike Filloon certainly did not miss it.
Huge digression. Sorry.
The point I was going to make. I am always conflicted when writing about the Bakken. I started the blog
to help me understand the Bakken, not for investment purposes. If I wrote simply for myself, the blog would be a lot different. Based on feedback from readers, I have to keep in mind there are at least threefourfivesix seven audiences affected by the Bakken boom or interested in the Bakken:
everyday folks in western North Dakota, raising families in a boom-and-bust environment
the rough necks and truckers that make this all happen
the curious lookie-lou
royalty owners who still live in the Bakken and see first-hand what is happening
royalty owners who left the Bakken years ago (or never lived there) and have little understanding of what is going on; they just like their royalty checks
royalty owners who have inherited good fortune from "forward-thinking relatives" (see comment)
