The Washington Post reports what was predicted months, if not years, ago. Even Joe Biden knew. There's a "rift" in Iraq. Who would have thought? A rift in Iraq? Political differences in Iraq? Shocking! The Washington Post is reporting:
Iraq’s Kurdish region has begun to sell oil independently of the
central government, a move that is exacerbating divisions in the country
as it struggles to turn back Islamic State militants.
The Kurdish region last month stopped transferring oil to the state as it had promised to do under a landmark deal
in 2014. Kurdish officials argued that payments from Baghdad had not
been sufficient. Instead, the region exported more than 600,000 barrels a
day itself, Kurdish and Iraqi officials said, a step that Baghdad
considers illegal.
The dispute threatens to widen differences in a
country already effectively split into three parts: the Kurdish north,
areas in southern and central Iraq controlled by the Shiite-led
government, and territory in the north and west seized by the Islamic
State.
The collapse of the oil deal also risks ruining one of the
key achievements of Prime Minister Haider al-Abadi, who was credited
with improving relations with the Kurds after years of acrimony.
A landmark deal in 2014. If you can't trust the Kurds, who can you trust? Iran? LOL.
This is going to really screw up the OPEC numbers. When we see Iraq's exports decline will we know how much is due to the Kurds? Will the Kurds become part of OPEC and get their own export number published? Does this make it more difficult for Iraq to meet its payroll? Pay for its military?
I've posted this before -- the link to the most recent Mike Filloon article, but if one is truly interested in "Bakken_101" this is an incredibly good article. The amount of information Mike has put together is simply staggering. Scroll through the production profiles he has provided. The production profiles will water your eyes.
As just one example:
22486, 2,421, EOG, Hawkeye 100-2501H, Clarks Creek, t9/12; cum 666K 6/15.
Other data points:
47 stages
14 million lbs of sand
the lateral is 13,700 feet long; a super-long lateral; extends the distance of almost three full sections
note the production profile below: as much as 55,000 bbls of oil in one month; if one adds up all the days the well was not in production, it adds up to almost a full year;
Other posts at the MDW where I talked about the Hawkeye wells
Hawkeye 100-2501H had some excellent early production numbers. From that
perspective, it is one of the best wells to date in the Bakken. It has
already produced 655,000 bbls of crude and 960,000 Mcf of natural gas.
It has revenues in excess of $42 million to date.
This includes roughly
four non-producing or unproductive months.
Crude production over the
first 360 days was 389,835 bbls. Over the first 12 months, this well
produced crude revenues in excess of $23 million. Decline rates were
higher, as the first full month of production declined 65% over the
first year. This isn't important as early production rates were some of
the highest seen in North Dakota.
It is important to note, decline rates
are emphasized but higher pressured wells may deplete faster depending
on choke and how quickly production is propelled up and out of the
wellbore. Any well that produces very well initially will have higher
decline rates, but this does not lessen the value of the well.
This
specific well is depleting faster, but no one is complaining about
payback times well under a year. Decline rates decrease significantly in
year two at 11%. This well saw a marked increase in production when
adjacent wells were turned to sales. The additional pressure associated
with well communication increased production from 20,000 bbls/month to
35,000 bbls/month on average. This occurred over a 6 month period.
My hunch is that this well is being choked back at the moment.
******************************************
Scout Ticket and Production Profile
NDIC File No: 22486
Well Type: OG Well Status: A Status Date: 9/23/2012 Wellbore type: Horizontal
Location: NENE 25-152-95 Latitude: 47.962526 Longitude: -102.774270
Current Operator: EOG RESOURCES, INC.
Current Well Name: HAWKEYE 100-2501H
Total Depth: 25101 Field: CLARKS CREEK
Spud Date(s): 4/19/2012
Completion Data
Pool: BAKKEN Perfs: 10812-25101 Comp: 9/26/2012 Status: AL Date: 7/10/2014 Spacing: ICO
Cumulative Production Data
Pool: BAKKEN Cum Oil: 666,340 Cum MCF Gas: 997053 Cum Water: 259235
Production Test Data IP Test Date: 9/26/2012 Pool: BAKKEN IP Oil: 2,421 IP MCF: 5232 IP Water: 1410
Monthly Production Data
Pool
Date
Days
BBLS Oil
Runs
BBLS Water
MCF Prod
MCF Sold
Vent/Flare
BAKKEN
6-2015
26
4513
4553
3690
14977
11931
384
BAKKEN
5-2015
31
6287
6306
5136
21724
17829
653
BAKKEN
4-2015
30
7235
7225
5685
24752
21414
227
BAKKEN
3-2015
31
8459
8504
6501
25171
20828
1127
BAKKEN
2-2015
28
9344
9510
6414
20654
16390
1349
BAKKEN
1-2015
13
4427
4397
2659
9918
8115
605
BAKKEN
12-2014
30
15487
16187
11616
49147
42605
3509
BAKKEN
11-2014
11
7769
7012
4962
15996
12767
2269
BAKKEN
10-2014
1
2
2
0
4
0
0
BAKKEN
9-2014
22
12617
13182
8444
32742
23543
7469
BAKKEN
8-2014
31
31155
32052
19754
98086
22466
75469
BAKKEN
7-2014
8
7229
5927
9843
12565
112
12420
BAKKEN
6-2014
29
27554
27469
11865
49551
21146
28272
BAKKEN
5-2014
31
35267
35307
15480
61543
23203
38185
BAKKEN
4-2014
30
39782
40933
18472
32696
32227
319
BAKKEN
3-2014
23
29699
28444
19310
23822
22827
883
BAKKEN
2-2014
0
0
0
0
0
0
0
BAKKEN
1-2014
0
0
0
0
0
0
0
BAKKEN
12-2013
0
0
0
0
0
0
0
BAKKEN
11-2013
12
6418
6478
1182
9214
0
9161
BAKKEN
10-2013
31
21325
22275
4583
31678
0
31524
BAKKEN
9-2013
24
15486
14831
3590
22352
0
22242
BAKKEN
8-2013
31
19647
19626
4492
28746
0
28591
BAKKEN
7-2013
31
15872
15998
4079
23600
0
23445
BAKKEN
6-2013
30
17544
17699
4171
25794
0
25644
BAKKEN
5-2013
31
22210
21897
5430
33351
0
33198
BAKKEN
4-2013
30
29075
29142
6968
32696
32227
319
BAKKEN
3-2013
31
36631
37198
8201
57544
0
57404
BAKKEN
2-2013
28
22100
21977
5978
32810
0
32671
BAKKEN
1-2013
30
33396
32927
9032
55877
0
55739
BAKKEN
12-2012
31
55367
55608
14629
92144
0
91989
BAKKEN
11-2012
27
47557
48594
10382
57300
0
57178
BAKKEN
10-2012
31
54927
54053
15906
155
0
0
BAKKEN
9-2012
9
21959
20698
10781
444
0
402
Graphic of the super-long laterals on the day the above note was posted:
17011, IA/1,663, EOG, Parshall 4-20H, t8/08; cum 415K 6/15; inactive since 5/14;
27444, TATD, EOG, Parshall 78-20H, perfed,
27445, TATD, EOG, Parshall 158-20H, perfed,
28728, SI/NC, EOG, Parshall 28-2928H,
28727, SI/NC, EOG, Parshall 85-2928H,
28726, SI/NC, EOG, Parshall 29-2928H,
28725, PNC, EOG, Parshall 142-2928H,
17294, 1,718, EOG, Parshall 11-28H, t12/08; cum 354K 6/15;
28638, 587, EOG, Parshall 91-28H, t1/15; 25 stages, 5.8 million lbs; big well, choked back now;
28639, 848, EOG, Parshall 92-28H, t2/15; 34 stages, 6.8 million lbs; cum 55K 6/15; choked back now;
28714, 541, EOG, Parshall 93-2827H, t2/15; 41 stages, 8 million lbs;cum 51K 6/15; choked back now;
*************************
Updates on selected wells noted above.
17011: went inactive 5/14; still inactive;
From sundry form received August, 2014 -- EOG is currently executing a downspacing and infill drilling program. During this process the new infill wells are being hydraulically fractured offset to existing/producing wells. The existing wells in close proximity to the new infill wells are shut in during the drilling and completion process.
Pressure pulses have been noted in the existing shut in wells during this process. Due to the pressure pulses, sand from the completions in the original wells can become dislodged and enter the wellbore. When wand enters the existing wellbore it can damage pumping equipment and/or plug the wellbore. When this occurs wellbore intervention is required to replace the damaged pumping equipment and may also require the wellbore to be cleaned out, both operations are costly and slow the process for returning the offset wells to production.
Proposal: as a mitigation measure, EOG is requesting approval to fill the existing wellbore with produced water from nearby producing wells. The fluid would increase the hydrostatic pressure in the existing well and assist in counter acting the pressure pulses and sand influxes impacting the well from the drilling and completion process of the infill wells.
The fluid will be pumped at a very low surface pressure with a non-positive displacement pump. Pumping pressure are planned below 500 psi. At or before reaching 500 psi, pumping would cease keeping the pressure below fracture pressure.
27444, TATD: from a sundry form received May, 2015 -- future use of the well will be completed once oil prices improve; the well will be inspected at least annually ... and will be reported on the TA extension if one is requested.
27445, TATD: from a sundry form received May, 2015 --
future use of the well will be completed once oil prices improve; the
well will be inspected at least annually ... and will be reported on the
TA extension if one is requested.
30074, 981, Slawson, Howo 2-4-33MLH, Big Bend, 31 stages, 4.5 million lbs, t4/15; cum 9K 6/15;
30420, SI/NC, XTO, Evelyn 31X-3DXA, Lindah, no production data,
Sunday, August 9, 2015
27646, 2,511, HRC, Fort Berthold 148-95-26A-35-14H, Eagle Nest, t2/15; cum 93K 6/15;
28638, 587, EOG, Parshall 91-28H, Parshall, one section, 25 stages, 5.8 million lbs, t2/15; cum 78K 6/15;
29728, 892, Hess, EN-Weyracuh B-154-93-3031H-9, Robinson Lake, t7/15; cum 5K 6/15;
29904, 1,066, XTO, Elk Horn Federal 44X-36BXC, Morgan Draw, 4 sections, t5/15; cum 19K 6/15;
30256, SI/NC, XTO, Tobacco Garden 11X-17E, Tobacco Garden, no production data,
30330, DRL, SM Energy, Beth 4B-14HS, West Ambrose, no production data,
Saturday, August 8, 2015
25362, 1,933, Whiting, Smokey 4-15-22-13H3, Pembroke, t6/15; cum 20K 6/15;
27275, drl, Petro-Hunt, Klatt 145-97-18A-19-2H, Little Knife, no production data,
27703, DRY, Ballard Petroleum, Middaugh 33-23, wildcat, a Madison well, north and east of Minot;
29288, 437, CLR, Raleigh 6-20H1, Dollar Joe, pt3/15; cum 29K 6/15;
30329, drl, SM Energy, Maria 4b-14HN, West Ambrose, no production data,
30566, SI/NC, Statoil, Folvag 5-8-XW 1TFH, Cow Creek, no production data,
When you look at this list, some things to think about:
the length of this list is pretty impressive; compare to the early days of the Bakken boom when they were drilling as fast as they could to hold leases by production; that urgency is no longer needed, and the list is still pretty long
October, 2014, is when things started breaking down; these wells were put on the confidential list 6 months ago (usually about the time they were spud); six months ago was February, 2015, middle of winter, and well into the slump in oil prices, and yet the list if pretty long
note the breadth of names; not just EOG and CLR, but also BR, SM, Oasis, Slawson, Ballard
look at the number of wells now reporting an IP; a huge change from just a month ago; take BR out of the equation (they almost always got to DRL status and Ballard, and we have eleven (11)
out of 20 wells with production numbers (maybe more when we see the list tomorrow); they're starting complete more wells
the production numbers are very, very good
the breadth of the oil fields involved; not just the Parshall and the Sanish, but some we haven't seen in a long time: Cow Creek, Morgan Draw, Pembroke, Big Bend, Foothills
I happened to talk to two folks working in the oil business in Texas (both small independents; one public, one private): one is involved in a pretty big acquisition deal in the Permian, and the other is hiring geologists to focus on the Permian. This doesn't sound like a depression; maybe a severe recession, but the US oil and gas industry is pretty solid, based on the little I know.
***************************
She Has Four Front Teeth Two On The Top, Two On The Bottom
After eating most of my potato salad, she then wanted my ear of corn:
Despite strict
emissions limits, concerns about climate change and unpredictable
gasoline prices that would make a '60s hot rodder pull over and weep,
Detroit''s modern performance cars could run rings around the classics.
And they're surprisingly affordable when compared with price tags of
some exotic cars with similarly high-performing engines.
"Back in
the 1960s and '70s, we were looking at 300-, 325-horsepower engines. Now
you've got 500-, 600-, even 700-horsepower," said Ken Gross, an
automotive historian, museum consultant and journalist. "Never in my
lifetime did I think I'd see the day when I could drive a 700-horsepower
street car."
Even the least powerful of today's sporty cars — say a base V-6 Chevy Camaro, Mustang or Charger
— could probably out-corner most 1960s muscle cars, which were renowned
for their ability to accelerate, but not to turn or stop.
"We are living in the Golden Age of the performance car," said Matt Anderson, curator of transportation at the Henry Ford Museum and Greenfield Village.
"The cars from the 1960s and '70s were good cars, but basic. Not as
fast or sophisticated as today's cars. With new technology, improving
fuel economy and reasonable gasoline prices, there's no end in sight."
Fiat Chrysler's Dodge Hellcat engines cram 707 horsepower into the Challenger coupe and Charger sedan.
The 2016 Chevrolet Corvette ZO6 produces 650 horsepower and accelerates to 60 m.p.h. in 2.95 seconds. Watching one launch has more in common with the Millennium Falcon shifting into warp drive than the Corvettes Chevrolet sold when muscle cars and "Star Wars" were new.
Ford is about to join the party with the 526-horsepower Shelby GT 350 Mustang, which uses a radically designed V-8 engine of a type usually reserved for six-figure exotic cars from Porsche and Ferrari.
If you want to see a lot of Ferraris outside of California driving around town visit Southlake, TX.
below the low end of our guidance on LOE (similar to EOG, CLR)
right on top of our internal CAPEX plan for 1H15; ahead of schedule on our plan to lower costs, live within cash flow
as a reminder, when we put together our 2015 budget, we used a $50 WTI price for the entire year
High-intensity completions
end of 2014: $10.6 million
goal: decrease to an average of $9.5 million
1Q15: $9 million range; around $7.8 million for slickwater completions in the core
half the cost reductions: efficiency gains; will likely remain regardless of price of oil going forward
Cash flow
1Q15: $100 million overspend
projected: breakeven
2Q15: positive to tune of $36 million
expect to be neutral or more likely to be positive for 2Q15
DUCs
elected to delay completion even though we expect to come in under our full-year CAPEX budget by about $35 million
Operations
experiencing out-performance on our high-intensity wells
remainder of 2015 will be focused on the core: Indian Hills, Wild Basin, and Alger
825 locations; 701 of those in the Middle Bakken or Three Forks B1
eight to ten years of inventory
efficiencies through pad drilling; drill highest EUR wells
Rig count
1Q15: dropped from 5 rigs to 4 rigs
2Q15: dropped to 3 rigs due to higher efficiencies; will stay at 3 for rest of year
drilling days (spud to rig release): from 24 days last year to 16 days more recently (Indian Hills)
Investor Presentation
updated out-performance on our type curves: 34 to 54 percent better
high intensity completions: $8 million
hybrid-style completion: $7 million
slickwater: $7 to $7.5 million which produces IRRs above 20% at $60 pricing
we can achieve 20 to 35% IRRs with our high intensity fracks in the core at $50 pricing
we believe the IRRs can increase even at $50 pricing
Montana, also; the Jimbo Federal was a slickwater style completion; save $500,000 -- no plans to move outside the core but just pointing out that opportunities exist for slickwater outside the core
we plan on completing some all-sand slickwater tests in 2H15 which could save another $500,000
exited 2Q15 with only $155 million drawn on our $1.7 billion borrowing base
Comments regarding pricing:
Speaking of better differentials, in 2015, we've continued to see some
great pricing out of the Williston Basin. We were below our guidance
range of $6.50 per barrel to $7.50 per barrel in the second quarter
coming in at $5.90 per barrel off of WTI. We expect the third quarter to
range between $5.50 per barrel and $6.50 per barrel as we continue to
benefit from flattening production and additional takeaway capacity in
the basin. Conversely, natural gas price realizations came in a bit
light primarily driven by both lower Henry Hub and liquids pricing.
We
will likely see a slight step-up in the third quarter in natural gas
price realizations. We did see some oil price improvement in the second
quarter in WTI, and we were able to layer in some additional hedges for
both the second half of 2015 and in 2016. We've increased our position
to 28,000 barrels of oil per day at an average floor of $75.61 in the
second half of 2015 to 8,000 barrels of oil per day at $63.20 in the
first half of 2016, and 3,000 barrels of oil per day at $63.94 in the
second half of 2016.
Q&A
" ... ramp up the percentage of our completions that are high intensity 20%
last year. First half, it was 60%; second half, it'll be 65% of our
activity. If we continue to see this type of performance that we've seen
in these wells, we'll push that up closer to a 100% in 2016."
non-consent from partners? "We've got a few partners that have been going non-consent. And really as
the year has worn on, we've seen a little bit less of that. I think
that's probably a reflection of well costs coming down as much as they
have. But there is still a portion that we're seeing non-consent, but
we've planned for that within our budget numbers and we think we're in
good shape"
will look at modifying completion design after looking at new data by end of 2015
two techniques: slickwater, high intensity
Great question:
I'm looking at some of the enhanced completions both slickwater and high
proppant volume. It looks like you see a more consistent pickup in
productivity when these wells are drilled on tighter spacing? First of
all, do you agree with that observation? And if you do, I was wondering
what – is there an explanation of why that may be the case? Answer: I don't know that we've necessarily seen a higher pickup at tighter
spacing, but those really are the two things we've got to understand.
One is, what is the uplift, if we do these high intensity completions,
very importantly, what is the uplift when you do it in spacing, so
drilling out a full DSU and doing all of those fracs close together,
we've got to get that right and that's one of things we'll continue to
work on spacing with the high intensity fracs and it's – we think we've
got a pretty good answer right now and we'll continue to perfect that as
we go and every year you will see us modify that spacing plan a bit.....tighter spacing -- consistent uplift and so it would indicate no interference..
EURs:
currently: 1-million-bbl range in Indian Hill; 900,000 bbls at Alger; modeling a 25% to 30% uplift
CAPEX:
drilling vs completion in 2016? we've gone to a 3-rig program
New term: strip pricing
Infrastructure capital coming into the Bakken; mentions Hess; did not mention ONEOK
Gas ratio has moved up a bit; now about 12%
Final comment regarding the conference call: the Oasis folks seemed very forthcoming in all areas addressed until the question about tighter spacing and interference, and not only was it a non-answer, it was very short, as if holding something close to the chest. It was also near the end of the conference call; folks were probably getting tired, ready to go, and time may have been running out.
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.
*****************************
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%.
*******************************
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.
*********************************
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)
