Sunday, August 9, 2015

There's A Rift In Iraq -- The Washington Post, August 9, 2015

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? 

Reminder: The Mike Filloon Article; EOG's Super-Long, Super-Productive Wells

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
 I track Clarks Creek here.


From Mike Filloon at the linked article:
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
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Graphic of the super-long laterals on the day the above note was posted:

Random Look At Several EOG Wells -- August 9, 2015; "TA" Will Be Inspected At Least Annually -- How Long Does EOG Expect Slump In Oil Prices To Last

For archival purposes. Bakken 101. Price slump.

A look at a few wells in the same local area:
  • 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.

28728, SI/NC, EOG, Parshall 28-2928H, spud date, 2/23/14; cease drilling, 10/2/14;
28727, SI/NC, EOG, Parshall 85-2928H, spud date, 9/13/14; cease drilling, 9/21/14;
28726, SI/NC, EOG, Parshall 29-2928H, spud date, 9/1;14; cease drilling, 9/10/14;

17294, 1,718, was off-line from 8/14 to 3/15; sundry form received August, 2014, identical to sundry form for #17011 above;

28638, 587,  production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

28639, 848, production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

28714, 541, production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

At time of original post:

Wells Coming Off Confidential List Over The Weekend, Monday -- North Dakota, August 9, 2015

Monday, August, 10, 2015
  • 27124, 1,053, EOG, Parshall 43-2117H, Parshall, ICO, 28 stages, 5.7 million lbs, t2/15; cum 62K 6/15; choked back
  • 28769, 941, Oasis, Langved 5393 12-3 7B, Sanish, t5/15; cum 43K 6/15;
  • 29289, 480, CLR, Raleigh 7-20H, Dollar Joe, 4 sections, t3/15; cum 30K 6/15;
  • 29433, SI/NC, BR, Kings Canyon 4-1-27MTFH, Camel Butte, no production data,
  • 29517, SI/NC, BR, LaCanyon 8-8-34MBH ULW, Blue Buttes, no production data,
  • 29626, 327, Oasis, Osen 6192 43-21T, Foothills, t3/15; cum 36K 6/15;
  • 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:

Reason #5 Why I Love To Blog -- August 9, 2015

Less than a week ago I posted this subject line: August 3, 2015 -- Part IV; Saudi Imports; Muscle Cars, Jeeps, SUVs Are Back.

Today, I see, USA Today has this headline and the storyGolden age of muscle cars is now.
The golden age of the muscle car is now.
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. 

Oasis -- 2Q15

Disclaimer applies. Some numbers rounded.

Opening comments
  • strong quarter
  • came in at high end of our production guidance
  • 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
  • elected to delay completion even though we expect to come in under our full-year CAPEX budget by about $35 million
  • 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
OMS (Oasis Midstream Services) discussions
  • 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.
  • " ... 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..
  • currently: 1-million-bbl range in Indian Hill; 900,000 bbls at Alger; modeling a 25% to 30% uplift
  • 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.

Meandering On The Bakken -- August 9, 2015

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

Recovery Rate

When I first started the blog, the published estimate of how much oil would be recovered from the Bakken/Three Forks was in the neighborhood of 1 - 3% of the original oil in place.
  • McKenzie: 2.0%
  • Williams:   2.5%
  • Mountrail:  2.0%
  • Dunn:         2.4%
  • Divide:       1.1%
  • Burke:        2.2%
Back on May 13, 2012, I suggested the recovery rate might be 8 percent.

And just two months ago, June 23, 2015, the estimate had moved to a staggering 15 - 18%.

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:
  • 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.

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 three four five six 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)
  • surface owners (mostly farmers, I suppose)
  • small retail investors
Well, that's it for now. Lots of meandering.