Friday, July 12, 2019

Fourteen Permits Renewed; Nine New Permits; Seven DUCs Completed; And, A Pronghorn In A Wheat Field -- July 12, 2019

Note: some good comments from a reader in the comment section below. I accidentally deleted one of the reader's comments but was able to copy it and post it as coming from me. It is noted in the comments below that that particular comment is from the reader although it is published by me. Sorry about that. 

Original Post

US equity markets. At the close, going into a weekend when anything can happen:
  • S&P 500 surges: gains almost 14 points to close at an all-time high of 3,014
  • DOW surges: gains almost 244 points to close at an all-time high of 27,332 (day before Trump appears to have more electoral votes than Hillary: 18,259; that's a 49% gain since November 8, 2016)
  • NASDAQ: gains 48 points to close at 8,244
Shopping: I will buy Sophia a new pair of shoes over the weekend.

Back to the Bakken

Royalties: ND Supreme Court sides with state in suit between state and Encana/Newfield over deductions from natural gas royalties.

Active rigs:

Active Rigs5667582873

Nine new permits, #36726 - #36734, inclusive:
  • Operators: CLR (8), WPX (1)
  • Fields: Siverston (McKenzie County), Little Knife (Dunn County), South Fork (Dunn County)
  • Comments:
    • CLR has permits for a 5-well Vardon pad in section 14-150-97, Siverston oil field
    • CLR has permits for a 3-well Marshall pad in section 24-145-97, Little Knife oil field
    • WPX has a permit for a single Skunk Creek well in lot 2 / section 1-1-48-93; South Fork oil field
Fourteen permits renewed:
  • XTO (7): seven Prairie Federal permits in McKenzie County
  • Petro-Hunt (6): twoArsenal Federal permits; two Eric Stratton Federal permits, and two Mongoose permits, all in McKenzie County
  • Hunt: an Oakland permit in Mountrail County
Seven producing wells (DUCs) reported as completed:
  • 34559, 83, XTO, Bobcat Federal 11X-2F2-S, Bear Creek, t5/19; cum --; neighboring wells include #18112 (jump in production; #18089 back on line)
  • 34360, 83, XTO,  Bobcat Federal 11X-2E-S, Bear Creek, t5/19; cum --;
  • 34359, 456, XTO, Bobcat Federal 11X-2A-S, Bear Creek, t5/19; cum --;
  • 34356, 1,305, XTO, Bobcat Federal 14X-35A, Bear Creek, t6/19; cum --;
  • 34358, 30, XTO,  Bobcat Federal 14X-35EXH, Bear Creek, t5/19; cum --;
  • 34911, 2,137, Hunt, Halliday 146-93-13-1H, Wolf Bay, t6/19; cum --; some huge wells in the general area;
  • 34912, 1,134, Hunt, Halliday 146-93-13-1H, Wolf Bay, t7/19; cum --;
Projected Number of Permits for Calendar Year 2019

For the number of days in the calculations below, I'm using "number of days" through Sunday, July 14, 2019, this weekend.

It's possible I have made simple arithmetic errors.

The number of permits issued each month by the NDIC may differ from what I have in my database, but if so, it will be very, very close, and won't affect the overall results.

Based on the number of permits in each of the following months, the number in bold is the projected number of permits for calendar year 2019 had the rate for the entire year remained the same as that one month. For example, based on the number of permits issued in April, 2019, had that been the "rate" for the entire calendar year (2019), 1,578 permits would be issued for calendar year 2019.
  • January, 2019: 1,495
  • February, 2019: 1,434
  • March, 2019: 1,578
  • April, 2019: 1,582
  • May, 2019: 1,660
  • June, 2019:  1,557
  • July, 2019 (through July 14, 2019): 1,877 (it will be interesting to see if the number of permits for July, 2019, reverts to the "mean" so far this year)
Based on the number of permits issued for the first calendar quarter of 2019, the number in bold is the projected number of permits that would have been issued for the entire calendar year had the rate been the same as that for the corresponding quarter. In other words, based on the number of permits issued in 1Q19, there would be 1,497 permits issued for the entire calendar year had that rate remained throughout the year.
  • 1Q19: 1,497
  • 2Q19: 1,071
  • For the first fourteen days of 3Q19: 1,877
I've checked this several times and I believe the numbers are accurate.

One can check the above projections with the actual number of permits issued in North Dakota over the past several years at this site:
  • 2019 (estimate): likely to be somewhere between 1,400 and 2,000
  • 2018: 1,466
  • 2017: 1,189
  • 2016: 818 (price of oil tanked due to Saudi opening their spigots)
  • 2015: 2,055
  • 2014: 3,012
  • 2013: 2,671
  • 2012: 2,522
  • 2011:1,916
For newbies:
  • North Dakota regulators generally approve permit applications in about 30 days
  • permit applications should not be affected by the weather unless there is a lot of site visitation of which I am unaware, but certainly the 1,071 permits projected based on 2Q19 vs the 1,497 permits projected based on 1Q19 appears to validate that assumption; in ND, Jan-Feb-Mar are severe winter months; whereas Apr-May-Jun are much better weather months
  • a permit is "good" for one year, but is easily renewed
My hunch:
  • most operators determine CAPEX, number of rigs, permit applications, etc, six to twelve months prior to execution
  • CAPEX is adjusted semi-annually when things are going well; quarterly when things seem a bit more bleak; and monthly, when things are going to hell in a handbasket
  • the number of rigs and frack spreads correlate directly with CAPEX
  • permit applications may or may not correlate with CAPEX; I don't know
  • I would think operators would have a stack of permits in the hopper in draft status/nearly complete well in advance of submission; 
  • it appears NDIC can issue as many as 20 or more permits in one day based on historical data; in other words, it's not the NDIC holding things back once operators decide to proceed (obviously the NDIC is not accomplishing the entire process in one day, but the point is that the number of permits issued in one day is not capped by the regulator)
  • the weekly rig count, week-over-week, is meaningless in the Bakken
  • the monthly rig count, month-over-month, may be slightly more meaningful than the weekly change
  • the monthly permitting activity gives one a much better idea of activity (and dare we say, production?) in the Bakken
If I could only choose one metric to follow the Bakken, it would be the rate of change (increase/decrease) in number of permits on a monthly basis

Having said that, even the number of permits issued each year is coming down, and production continues to rise.


  1. I think permitting is a lot more variable and means a lot less (it's just paper). Sure, in the end every well needs a permit, but they also routinely permit more than they drill.

    Rigs on the other hand are burning money.

    The week to week CHANGE means little. But the LEVEL means a lot. IOW, if rigs dropped 5 from 60 to 55, this doesn't mean as much as the fact that you are at 55 (or 60) compared to being at 30 (crash) or at 180 (boom). It's like prices. Dropping $5 from $60 to $55 is still better than going up $5 from $25 to $30. I mean, 55 is almost twice 30! Level is what matters, much more than change.

    1. I'm looking at longer term trends. If I see permitting trending to zero, I would start to be quite worried.

    2. With regard to permits are "just paper," I refer readers to this post in which I recently went through every permit issued in calendar year 2017:

      I picked calendar year 2017 for a specific reason: a recent year but not so recent that there were still a lot of DUCs.

      Of the 1,189 permits issued in CY17, only 56 permits were canceled (56/1,189 = 5%). In other words, 95% of issued permits are eventually drilled (there are still some permits that have not yet been drilled and those permits could be canceled, but in general, it is safe to say that an issued permit will eventually result in a drilled well.

      TA: 2
      SI (DUCs): 87
      PNC: 56
      loc: 111
      dry: 12
      drl: 26
      conf: 166
      with IPs: 729

      Permitting activity remains my #1 metric. If permitting trends to zero, it would be very concerning. Even when active rigs trended toward 20 just a few years ago, I was not concerned; there was too much permitting still going on.

      Right now there are enough "outstanding permits" that if permitting were to trend to zero, there would still be a lot of wells to drill BUT if permitting trends to zero, it pretty much tells me all I need to know about the basin.

  2. They should just write the leases to be for HH gas and for WTI oil. Yes, there is processing and transport required to get it to that. But the companies can just lower the % to account for that (and take the risk). In addition, there is the value of the NGLs to help compensate the companies. There's just too much lack of transparency otherwise and too many ways the companies can play games with the midstream otherwise.

    I really do think this is the fairest way to do it and I would just negotiate for that if I had a large lease (large enough and the companies will cooperate.) Again, it's not even about getting more money out of the operators, because sure they would give a lower percentage if forced to do without the deductions. But it's about transparency and accountability. Companies are much more able to take midstream risk than leaseholders. And it would also stop some questionable partnerships with midstreamers.

    1. Noted. I don't know enough about the subject to comment. When it comes to finances / money, I would be the wrong one to ask or to explain.

    2. The reader added another comment which I accidentally deleted (once deleted, I can't get it back). Sorry about that. Here is what the reader wrote:

      It's basically just extending the idea of "top line percentage". Any time you have an offer to do profit sharing or the like, try to get the split off of the top line. It's not trying to get more money (the percentage can be adjusted to reflect coming out of a bigger number). It's just that it's a lot harder to manipulate the top line than the bottom line. The whole philosophy of lease contracts has been to take the percentage "off the top". Companies are trying to play games to take it off the bottom. Again, it's not even to try to change the amount allocated per se, but just to control companies from doing things that are wiggly that landowners can't anticipate.

      When you go to lease the mineral rights, you can still have different companies compete. And no company has to sign for something that doesn't give them a return. But just constructing the contract so that the leaseholder doesn't need a lawyer and an auditor AFTER the lease is signed makes everyone's life easier.

    3. Again, I don't have enough experience in this arena to make any comments. But it's my experience that the reader reflects what 99% of mom-and-pop mineral right owners have told me. And that's why early on I suggested that anyone who has mineral rights in four or more wells needs to be represented by a professional before signing additional leases, etc.

  3. If you want to make it really clean, just auction off your mineral rights (sell them). It's one number and less risks for the future funny business. The downsides are that sometimes separating mineral rights and surface rights can cause issues down the road because there's no longer a shared desire by the leaseholder to have development proceed. Also, you have to see if the taxes will kill you.

    But if you just want a super clean deal, selling the minerals is the way to go.

    Still have an attorney represent you and look at any land use issues. But at least you don't have to worry about games with the measurement of the volumes or the prices obtained for them or the midstream costs sneaking into what is supposed to be a topline deal.

    1. ... or just sell everything and move to Phoenix.

    2. Not a bad option either. Put grannie on the truck and move to Beverly, Hills that is.

    3. Pretty funny... glad to see you are putting all this into proper perspective.