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Permalink Reply by Quattro on Thursday

So Page 5 - is that saying they have drilled that many Bossier wells?  Or is that possible to be drilled?  I am a little confused (as usual).

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Permalink Reply by Skip Peel - Mineral Consultant on Thursday

Quattro, it is easy to be confused but we are here to attempt to make it a little less so.  Yes, there have been a significant number of Bossier wells drilled on the LA side of the fairway.  I'll apologize in advance for the length of my reply.

Here is my takeaway from the Page 5 data.  Every unit has an operator that drills, operates and reports the wells.  I can not think of any instances, although there may be a few, where an operator holds all of the mineral leases in a drilling unit.  If a company, in this case Comstock (CRK), has 878 Haynesville (HA) wells they operate, they hold ~73.5% of the leases in those units while others hold 26.5%.  CRK holds lease rights in units drilled, operated and reported by other companies where they are a non-operating working interest. In that case.  The hold 14% in those 700 HA wells listed as “Non-Operated”.

CRK operates 820 Bossier (BO) wells in units where they are the operator and hold a ~79.76% of the mineral rights.  Comstock likely designed and drilled the vast majority of these wells but Haynesville companies regularly swap or sell unit operatorships so the number drilled is likely a little less than 100%.  Since the Office of Conservation did away with its one operator per unit rule, there are also a number of units where two companies operate.  The original unit operator operates and reports the original unit well and possibly additional unit wells (short laterals) and an operator from an adjoining unit that drilled long lateral (HC) wells that include the other operator’s unit operates and reports those HC wells.

On the Louisiana side of the Haynesville fairway, the state does not require that operators designate which wells are HA and which are BO.  The depth definition of every HA drilling unit, with a handful of exceptions, includes the Mid-Bossier Shale and the Haynesville Shale.  Since shale wells are different from conventional reservoir wells, it makes sense to group the two together for the purposes of regulations and reporting.  This of course makes it challenging to know which horizontal wells are landed in the BO and which in the HA.  They are all considered and labeled as HA by the state.  The only time that an operator may choose to label which wells are HA and which BO is in their applications for alternate unit wells.  It makes sense and saves money for a company to apply for a group of alternate unit wells at the same time although there is no plan to drill them all together at one time.  When a company applies for a group which has both HA and BO laterals, they can choose to label the laterals to avoid any confusion in regards to mandatory minimum setback requirements.  No HA well may be closer than 330’ from an east or west unit boundary line and no closer than 660’ from the closest HA well.  Since an alternate well application is a flat, two-dimensional representation of the lateral paths, a well group with both HA and BO wells will have well paths too close together to meet the setback requirements.  Therefore, some applicants choose to label the laterals (HSV or BSSR) to make it clear that the laterals are separated in depth.  Not all companies do this but those of us that look at alternate well applications on a regular basis can tell when two laterals are too close to one another to meet regulations and one or the other must be a BO lateral.

Since the graph includes a break out of lateral lengths, I take this to be wells that have been drilled although it is possible that it combines wells that have been drilled with wells that are permitted to those lateral lengths.  BO wells have been drilled for years but fly below the radar of mineral owners because they are not designated differently from HA wells.  It makes sense for companies like CRK who have been drilling the shale since the play’s beginning to have high numbers of BO completions since they have fewer operated drilling units.  I suspect that CRK’s ratio of BO to HA wells is the highest in the play.

Mineral owners considering a sale should have a grasp of BO wells in general as a section/unit with both Haynesville and Mid-Bossier shales will have twice the well laterals as a section/unit that only has economic Haynesville shale.  Mineral buyers are looking for long term investment opportunities that include all the wells they expect to be drilled in a unit.  For that reason, they closely scrutinize the production potential of BO wells by location.  Buyers do not want to discuss or debate the value of those BO wells with mineral rights owners.  They prefer to ignore them in their valuation calculations and their purchase offers.  Buyers look to acquire mineral rights that include economic Mid-Bossier rock because it increases the potential profit of their investments. At this point in the play much of the northern half of the LA Haynesville fairway, the part that does not have economic Mid-Bossier rock, is much more developed than the southern half.  The dividing line between economic and non-economic Mid-Bossier is difficult to define because it is dependent on the price of natural gas.  For example, if the breakeven price for a HA well in a given section is $3 per mcf, it may take a price of $4.10 for a BO well to breakeven.  Of course, to make are decent rate of return, either example would need to be greater by a factor of 10 to 20%.

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Permalink Reply by Ryan Howrish on Friday

I will try and add some additional context to Skip's answer.

• Slide 5 only discusses future drilling locations/inventory across Comstock's acreage in Texas and Louisiana.  It does not reflect any of the wells that they currently operate and produce or producing wells that they have a non-operating WI% in.
• Based on their current activity, they say they have over 30 years of future drilling inventory from June 30, 2024, forward.
• A GROSS location or well is a whole well without factoring in working or after-royalty interest.
• A NET location most likely factors in the after-royalty interest but may also be calculated using working interest. (If you ever work in Canada, a net location is referred to in terms of working interest, not after-royalty)
• CRK's future Haynesville inventory is:
  • 878 gross-operated future locations with an average net interest of 73.5% (646 NET / 878 GROSS).  Read this as Comstock says they have an additional 878 Haynesville whole wells to drill where they have enough leasehold to be the unit operator.
  • 700 gross non-operated Haynesville wells with an average net interest of 14% (98 NET / 700 GROSS).  CRK will participate in 700 total wells, but their average net interest in the 700 wells is 14%.
• CRK's future Mid-Bossier inventory is shown the same way:
  • 820 gross-operated future locations with an average net interest of 79.8% (654 NET / 878 GROSS).
  • 527 gross non-operated future locations with an average net interest of 13% (159 NET / 1227 GROSS)
• The lateral length breakdown of future drilling locations will be calculated from an internal development map that has every operated well that CRK currently thinks they can drill, along with an assumption of every non-operated well that they think will be drilled across their leasehold.

Skip is right when he says it is difficult to differentiate between Haynesville and Mid-Bossier wells.  Broadly speaking, if you have multiple wells drilled in a unit or multiple cross-unit wells, and the reported true vertical depths are different by more than 300ft or 400ft, it is likely a safe assumption that the shallower well or wells will be Mid-Bossier and the deeper wells will be Haynesville.  This only works in a small area as the depths of the formations change across the basin; generally getting deeper as you move from the NW to the SE.

Another way to "guess" that two wells are landed in different target zones (HV or MB) is if you see wells on a map or survey that look like they are drilled on top of one another, it is safe to assume they are not drilled in the same zone.  The days of drilling 8-12 wells in the same zone in the same section are gone.  Generally most operators are drilling 4-5 wells per section in the Haynesville and 4 wells per section in the Mid-Bossier (there are some operators are planning for 5 wells in the MB as well).  These spacing assumptions are fluid because the economically "optimal" number of wells per section changes with gas price, but so far, I haven't met anyone who can predict gas prices 5-10 years in the future.

The MB is much more heavily developed in the Southern part of the basin in Louisiana (T9N to T11N), but you are starting to see it extend into T12N and T13N more and more (less so in T14N and T15N but there are a few wells).  On the attached map, the blue laterals are MB, and the red are HV wells.  You can see where the MB is much more developed.

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Permalink Reply by Skip Peel - Mineral Consultant on Friday

Thanks, Ryan.  Any thoughts on Page 9, horseshoe wells?

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Permalink Reply by Ryan Howrish on Friday

I know a few details of 1 that was successfully drilled in the HV. The cost per foot is higher than just drilling a straight 10,000ft lateral. The economics of a 10,000ft u-turn/horseshoe well seem more in line with a 7500ft straight lateral. The geometry of the well bore does introduce additional technical risk, but it has been done.

This design may entice operators to go back and develop single sections that for any number of reasons can’t be extended.

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Permalink Reply by Skip Peel - Mineral Consultant on Saturday

The risk of a mechanical problem would seem to be greater and the frack stages in the curve must be an additional challenge.  With the ability of operators of "stranded units" to drill HC wells through adjacent non-operated units or to allow another operator to drill through theirs, it would seem the two operator per unit approval by the OOC would be a better or at least safer approach to maximizing lateral length and stimulating the 330' unit setbacks. The horseshoe design doesn't solve the in unit setback on the north and south ends of the unit.

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Permalink Reply by Hale Yayuh on Saturday

One would hope that a horseshoe well with 10k ft of lateral would be more economical than two 5k ft laterals, perhaps, solving the issue of having potentially stranded sections due to 5k laterals not being economic. Of course, higher nat gas price is needed for any of this. EDIT: Disregard the first sentence... the presentation mentioned the numbers for this very thing.

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Permalink Reply by Skip Peel - Mineral Consultant on Saturday

The only seeming remedy for the 330' no perf zones in each section is to drill through them with an HC well.  Together those two zones represent one eighth of the rock in each section (80 acres).  In sections/units with economic Mid-Bossier rock, it is a loss of 160 acres that is not stimulated (fracked).  Considering just how "friendly" the Department of Natural Resources, Office of Conservation is with the O&G industry, I wouldn't be surprised if the current administration chose to simply do away with the no perf (set back) zones for HA units.  Mineral owner concerns/complaints about mineral trespass would just be ignored.

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Permalink Reply by Ryan Howrish on Saturday

I'm not convinced that the 330ft offset at the top and bottom of units in LA has technical justification. I think substantially more drainage occurs laterally (East and West) of the wellbore than North and South of the first and last perforations. I understand mineral owners may have concerns about drainage across these unit boundaries over the life of a well if the 330ft offset is reduced or eliminated altogether. Today, I think those sections of the wellbore that are not perforated are likely not contributing meaningfully to production and may be stranded forever.  I don't know what the right answer is. My personal opinion is that I think the 330ft offset at the heel and toe should be reduced, and the 330ft offset on the East and West of the sections/units should be increased. 

I think all stakeholders (operators, regulators that collect severance tax, and mineral owners) benefit from having more lateral length perforated in a section.

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Permalink Reply by Skip Peel - Mineral Consultant on Saturday

For me it's a question of waste.  There is a lot of gas in those north/south no perf zones. Where an HC well is not a possibility, the zones should be removed or greatly reduced in order to get as close as possible to 100% production of recoverable reserves.  With the increase in larger frack cylinders, many operators are moving their laterals away from the east and west unit lines.  It is not unusual where an existing unit well is not in the way to see a lateral that is 480' from the west or east line.  Many rules, created in the age of vertical wells producing from conventional reservoirs, are outdated and unsuited to the age of horizontal wells producing from unconventional reservoirs.  It is the mandate of the Office of Conservation (OOC) to eliminate where possible the wasting of natural resources.  The 330' no perf zones should have been eliminated years ago before the advent of HC wells or unit wells with two different operators.  That is income that operators, mineral owners and the state are missing.  Since the OCC basically approves whatever the industry asks, it begs the question whether this issue has been a priority.

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