Expected Increase in Offers to Purchase Minerals - Know your Property!!!

The combination of reduced new drilling plus lower O&G prices will be leading to a continued decline in monthly royalty payments. In unconventional O&G plays (I.e. Shale Plays like the Eagle Ford, Haynesville, Bakken, Permian Basin, Niobrara, etc.), we all know that production decline is rapid after a well is put to sales and that production will settle in at rates that are only 80 to 90% (or less) of the initial rates.

  • The plus side of this "80-90%" volume is that it should last for years (10,20 or more) assuming no mechanical problems. Nice consistent mail box money.
  • The negative is that this isn't a lot of money coming in on a monthly basis.

Operators have no reason to drill up their undrilled locations in a unit if there is a single well holding the unit by existing production (HBP). And there is no reason for them to drill new wells and tap new O&G reserves unless there are some good financial reasons to do so.

  • And prices will be a major factor in this decision.

Companies that purchase minerals will use this time as an opportunity increase their efforts in bombarding mineral owners with offers for their minerals.

  • And some mineral owners will have some tough decisions to make as to "sell, keep or sell some / keep some."

I would encourage all mineral owners to "know their position" so that they can make informed decisions as to their and their family's O&G assets.

Following are the three major issues I would want to know as a mineral owner (which I am):

  • How may productive intervals or target zones / benches are in the unit?
  • How many vertical or lateral wells can be drilled in the unit per bench / target interval?
  • Approximately how much recoverable O&G is left to produce in the unit?

Either through individual research or via use of a consultant, it is time and money well spent to understand your potential assets.

As always, this is just my opinion on this situation.

Tags: assets, evalaution, minerals

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Thanks, Rock Man.  A good time to review.  If you are in LA, there are two some what distinctive areas.  The northern one is proven for Haynesville Shale but not for Bossier Shale.  If you are in a township 16N or further north, you have only Haynesville Shale.  If you are south of 13 North townships you have both Haynesville and Bossier.  For townships 15 north and 14 north, it depends on your specific location east to west.  Now to follow up on Rock Man.  Currently, with high intensity fracks, operators are spacing laterals six to the mile or six in a standard section of ~640 acres.  Therefore if you have both shales, you have a maximum of 12 horizontal lateral slots.  If you have only Haynesville, you have six.  As a general rule of thumb, excuse me reservoir engineers,  you can subtract the number of existing producing wells from either six or twelve depending on location at that is the approximate remaining reserves in your section/unit.  The more remaining slots, the more the potential value for a buyer.

As Rock Man says a new, modern design well can hold all leases in a unit for a long period of time without an operator having to drill more.  For this reason, buyers are focused on sections with some evidence of near term intent to drill new wells.  Hopefully most of our members have gotten over the desire to see what kind of royalty revenue they will get from a new well.  Those who are looking to sell should consider giving a buyer 100% of production from new wells from first production if they want a buyer to be aggressive with a purchase offer.  Obviously the more new wells permitted, in a group, the more attractive to a buyer.  We are in the age of buyers' focus on ROI (Return On Investment), sooner the better.

Development patterns have changed.  For all of 2018 and much of 2019, the pattern was for an operator to permit a group of wells, 2,3,4, etc.  This is because the focus was on producing an mcf of gas for the lowest cost.  Pad drilling (one or more rigs moving a short distance without having to disassemble and go on the road to drill multiple wells, frack crews performing zipper fracks on paired wells or sequential fracks in the same general location - one pad or two closely spaced) predominated.  Now I am seeing one well permits for a alternate unit well (lateral stays within one section) or one HC well (lateral drilled through two or more sections).  My take on this is that now the focus is on drilling the fewest wells that will effectively HBP (hold the leases in force) as much acreage as possible.  As long as the price of natural gas is below $2.50/mcf, this should be the prevailing pattern.

I am seeing very little interest in sections where existing wells will hold leases for an extended period (over a year).  Any offers for those sections will likely be low ball.

Good comments but I will say that in Tx Eagle Ford (and I am sure other areas), mineral buyers have been chasing units where operators have had no apparent interest in drilling new wells for years.

I believe that many of these groups are in for the LONG haul / or are willing to a certain percentage of their acquired minerals into a long term pay back bucket.

I stick to what I know, Haynesville/Bossier shale, LA & E TX.  Rock Man I suspect that your statement regarding the Eagle Ford and other oily basins was correct prior to the correction.  I expect the crash has given many pause although some will look to buy the dip.  What is becoming a concern for some buyers with long term perspectives is the life span of crude as an attractive investment.  Every time there is a set back they can look over their shoulders and see renewables gaining on them.  See Private Equity firms.  Many are listening to Blackstone.

Potentially, some of the best investments in the oil field right now may be tied to water hauling and disposal. All those frac'd laterals make "x" BW per day and they won't stop making water over time.

That plus artificial lift (various surface pumping units, plunger lift, jet pumps, gas lift, etc) will be big long term success player in the oil field.

What about the Rapides Parish area guys?  Any hope of drillers coming back?

IMO, the chances will improve with the price of a barrel of crude.  My guess would be north of $60/barrel.  $65-$70 would be much better.  Now as to buying interest, there is unlikely to be any until such time as enough economic wells have been completed to give some reasonable idea of the prospective area.  Buyers have long memories and the Haynesville Shale haunts many of them to this day.

In my opinion, a LOT has to change in a positive direction to entire drilling back to Rapides for that expensive play. I don't see any group looking to purchase minerals there for anything other than peanuts. 

We will have a better view of how this play works once we get some more production, but I highly doubt that this info will end up supporting drilling at $30 oil and sub $2 gas.

Here is a theoretical example of what I think all mineral owners need to know about their interests in drilling / production units.

Assume you have an "x" percent royalty interest in a DSU (drilling / spacing unit). Two wells drilled there (using first generation completion technology) have paid you $85,000 since they started producing. And are presently making a consistent $200 a month.

  • One can find the total production for any well / unit on SONRIS of Tx RRC site (or in DrillingInfo/ENVERUS if you have a subscription). 

For the primary target interval, there is sufficient room for 4 to 8 new locations depending on infill drilling.

  • So assuming similar well performance and frac approach, another $340,000 to $680,000 in royalty revenue assuming similar commodity prices as seen on the first two wells.
  • And these are probably low numbers since more modern fracs should do better than first generation fracs

Now you find out that there is a shallower target interval that can support another 6 to 10 horizontal wells.

  • Assuming that these wells would make about 75% of the primary target zone production, similar pricing metrics will give mineral owner another$380,000 to $640,000.

Of course, the timing of this cash flow over so many years is a key factor - one that may not pay you but will pay your heirs and descendants. And no one knows when these new wells could be drilled.

This is what the mineral owners are playing for on the long run - picking up minerals while units are in the $200 per month phase so that they can eventually cash in when monthly revenues are over $10,000 to $15,000,000.

Suggestion.  Instead of "X" how about 1 acre.  A more useful metric which can be scaled.  And some specificity to basins.  Few plays have the number of benches that the Permian does.  Note to members, "benches" are equal to pay zones.  In the LA Haynesville Basin there can be 1, 2 or 3 horizontal targets depending on location.  In LA there are few companies currently drilling vertical wells for  shallow pay zones and their numbers decline each year.  E TX I think still has some Pettit and Travis Peak drillers.

A reminder that SONRIS production is reported by cumulative unit production.  So only the first well will give you a true reading.  Thereafter it is impossible to identify which well is producing which portion of the total reported volume.

I use my "X" since my example is a 0.5% royalty interest in 700 acre unit.

"X" can be anything - just need to do the math to determine what percentage of the production one is getting paid on.

Aside from the more pervasive Haynesville, Bossier and similar unconventional targets, more localized vertical drilling can be chasing anything from Nacatoch (1000') to Smackover (below the Haynesville) and everything in between. Lots of prospective zones - but not all of them work in any one area. Oftentimes, one is lucky to just have a single target zone associated with their minerals.

AN OBJECTIVE FOR EVERYONE - "Know your O&G mineral situation as well as possible!"

I would hope that all people getting paid O&G royalties have kept their check stubs - the info on these stubs will give you the info on production volumes and price trends.

If you know EXCEL or other data management programs, it is easy to set up spreadsheets to monitor this information.

It seems to me that a significant factor for mineral buyers to consider is what company is the current holder/operator of the lease on the mineral tract being evaluated.

I'm not interested in selling any of my minerals, but the situation if face is this:  I have one larger piece of property (large for me, not large) that is theoretically my best mineral tract, that extends into 2 Sections. Those 2 sections are contiguous in a north/south configuration, so ideal for CULs.  One 10 year old unit well in each.  Both sections are held by CHK, so it is totally up for question as to if and when further wells, but excellent prospect for both HA and Bossier.  I have several smaller tracts of minerals scattered around DeSoto and north Sabine Parishes.  Those leases are held by either Comstock or Vine, both of which are actively drilling CULs either in my units or adjoining units.  I've got several new unit wells by Comstock and Vine, and Vine has more permits for CULs.  So, my prospects for income in the next 5 years reside mostly with Vine and Comstock.  

I have no idea how to evaluate the prospects for the leases held by CHK.  Another operator drilled two CULs in the 2 units contiguous to the south, and after producing for a little over a year, they are excellent wells.  In short, this property is a much better prospect than the locations recently drilled by Comstock or Vine on my other tracts.  

Looking for that silver lining, maybe my largest interest won't be drilled for a number of years, and the price of NG will be higher at that time.  But I will likely be too old to enjoy any of those royalties.  My children will benefit, which is fine.


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