Sunday, August 9, 2015

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.

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