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Permalink Reply by Skip Peel - Mineral Consultant on May 8, 2013 at 12:34

The following is based on cross unit laterals as approved by the Louisiana Office of Conservation.  Regulatory statutes vary by state.  LA cross unit laterals are roughly equivalent to PSAs.

Cross unit laterals are becoming more common.  Operators want to drill longer laterals because it helps to lower the cost of production per hydrocarbon unit produced.  And makes very expensive horizontals wells more economic.  The state has been approving a growing number of these cross unit laterals and the precedent has been set.  Just as all mineral interests in a drilling & production unit share in production based on their proportional share of acres in the unit even when a producing lateral is not located under their lands, all mineral interests in units traversed by a cross unit lateral share in the production of the well based on the linear feet of perforated well bore in their existing unit.  For example if the perforated portion of a horizontal wellbore is 9900' and traverses two 640 acre units and 4950' is located in each unit the split on production would be 50/50.  If a mineral interest was 80 acres half of the production would go to their unit and they would receive one eighth of that production times their royalty interest.

Is this fair?  In theory, probably yes.  In practice, I don't think anyone knows.  This is one of the latest twists in the evolution of technology and regulatory oversight concerning the new world of horizontal development.  An operator would probably argue that everyone benefits from fracturing and producing more rock per lateral as cross unit laterals eliminate the 330' no-perf zone of each unit that previous rules have left unstimulated to guard against laterals producing rock outside of its unit boundary.  That one 9900' lateral in two units would have been two separate 4,620' lateral or a total linear length of 9,240' without the cross unit lateral.  The Louisiana State Office of Conservation is charged with forming rules that promote efficiency in hydrocarbon recovery.  The energy industry has made the case to them that there are hydrocarbons going un-produced in those set back zones between adjoining units.  The Office of Conservation has the authority and has allowed the use of cross unit laterals so until something changes mineral owners are along for the ride

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Permalink Reply by 1kw6x71km1v37 on May 8, 2013 at 13:24

Elimination of waste, in this case via the most economical production methodology, is the primary statutory charge of the Office of Conservation. Everything else is secondary, including individual correlative rights to production from common formation.

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Permalink Reply by Howard on May 14, 2013 at 5:05

Thank you for explaining the cross unit laterals.  However, I'm confused about how to interpret the SONRIS production data with cross unit laterals.  Assume you have three wells.  Well A and B are cross unit laterals in S24 and S25.  Well C is a single unit lateral in S24.  SONRIS reports the following production data for these wells (the LUW Code is representative but not factual).

How does one determine the production for each of the three wells?  Do the MCF values show total production for the three wells combined?  Why are there MCF values with a Well Cnt = 0?  Why do the 11/01/2012 entries for Well A and B both show a Well Cnt = 3 with different MCF values? How does one use the percent of perforated length per section with the data provided?

I hope that this is an appropriate comment/question for this discussion.  If not, please suggest a different forum.  Given the fairly recent advent of cross unit laterals, perhaps there are others that are a little unclear about how to interpret the production data available through SONRIS.

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Permalink Reply by Skip Peel - Mineral Consultant on May 14, 2013 at 10:51

Operators report total unit production to the state no matter the number of unit wells producing under a single LUW Code number.  So you can't determine the production per well from SONRIS. That's been the case historically and prior to the advent of cross unit lateral wells. Production per well should be broken out on your royalty statement.  I have not seen a royalty statement for a well with cross unit lateral production as they are still relatively rare.

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Permalink Reply by tc on May 8, 2013 at 12:34

Look at it this way, if your 68 acre well was a poor well you are out of luck, but with the larger units they will drill 16+ wells and you will get a piece of all 16 wells.  One of the benefits would be less variability and having all your production produced at a low NG price, one of the drawbacks would be that you will most likely have to wait longer for the full payout as it will take time for all those well to be produced.  Of course time can also be a benefit when you consider the improvements drilling/completion technology has done to EURs.

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Permalink Reply by Andrew on May 8, 2013 at 13:09

TC makes a strong point, as any "infill" drilling in a unit just limits exploration and execution risk to the mineral owner without diminishing his potential share of production.

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Permalink Reply by Rodney Anderson on May 9, 2013 at 1:43

So according to these reply's I am looking at this from the wrong point of view.  I can see it benefiting all the mineral owners in a unit, if in fact the energy companies drill the 16 or so wells in this unit, but that is not a given.  One thing I am wondering is how many of you that have responded are actual mineral owners facing this situation or have personal knowledge of a mineral owner who has been involved with this situation.  Isn't this forced pooling?

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Permalink Reply by Skip Peel - Mineral Consultant on May 9, 2013 at 2:10

I'm unsure if there would be 16 wells.  There could be 8 or less.  However unless we are talking multiple units meaning multiple productive formations within the same surface footprint, the important metric is feet of perforated lateral per unit regardless of number of wells. 

The decision to drill alternate unit wells rests to a large degree on the economics of the unit well (first well drilled in the unit).  The state does not require that the operator of a unit drill alternate unit wells.  However if the unit well is economic the chances are quite high that an operator will drill additional wells.  If the unit well is not economic, they will not.  Then the question becomes will an operator attempt to maintain production in an non-economic well to hold leases in force or plug & abandon the well and allow leases to expire?  Too many variables there to speculate too far.  Generally if the operator expects that there are other productive formations under their leases they will drill different wells or assign the rights to specific depths to another company or companies that have experience developing that formation.  O&G companies generally do not like to operate wells that loose them money.  They abandon those wells and move on.  Once leases lapse any party may come in and lease the minerals and apply to the state to operate the existing unit or form units for other formations.  Sometimes they apply to dissolve an existing unit and reform a unit in a different size or configuration for the same formation.

My mineral ownership is limited to the rock under my house.  However I perform research and provide analysis and counsel for owners of a lot of rock including some with cross unit laterals.  They have no complaints to date as far as I am aware.  Force pooling is authorized in "compulsory drilling & production" units.  Therefore it would have existed prior to any PSA or cross unit lateral application.  I won't go into force pooling unless you wish to.

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Permalink Reply by Rodney Anderson on May 9, 2013 at 7:42

This issue seems to have come up because back when the minerals were leased in much of Panola county (where my dealing are) no one, even the energy companies ever expected to drill past the cotton valley and now, although they already have the minerals hbp they have run into a different problem with wanting to drill horizontals, that don't drain as much area evidently, and the easiest, most economical way to get that done is invent the PSA.  This allows them to drill without negotiating another lease, while actually forming smaller units within the already established larger units or across unit lines and diluting the royalty by paying everyone in the original larger units, as if the gas were being produced under their holdings, whether they are or not.  I still fail to see how this is more advantageous to me than being paid for what is actually produced from my holdings.  I see how it would be an advantage if the new wells they drill didn't include my minerals, but that is not the case.    That's sort of like me selling my house and because you live in the neighborhood I will be forced to share the proceeds, but if you never sell your house I'm just high and dry.  

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Permalink Reply by Skip Peel - Mineral Consultant on May 9, 2013 at 7:54

This issue has come up because operators have determined that longer laterals have better economics.  As a generalization it really doesn't matter whether it is the Cotton Valley, the Haynesville or the Travis Peak formation.  Horizontal wells are only drilled when it is determined that they are more economic than drilling vertical wells.  PSAs or cross unit laterals don't allow operators to drill formations other than those covered by the lease terms.  Any mineral owner who executed an all depths lease are subject to any and all units formed by the operator and approved by the state, at least during the primary term of that lease.  Houses are not unitized to facilitate development but minerals are.

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Permalink Reply by Rodney Anderson on May 9, 2013 at 13:09

All of this is well and good for the energy company, the question I have is why is it advantageous to me?  I really don't care if it is more economical for the energy company, how much they make, how much they save.  Why is a life long land man who is dealing with the same thing personally strongly recommend not signing the PSA?

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Permalink Reply by Skip Peel - Mineral Consultant on May 9, 2013 at 13:35

Because you get royalty on more linear feet of perforated lateral (which is where the hydrocarbons meet the royalty check).  And when the operator has an economic well, they tend to drill more of them.  And you get more royalty.  As to why your friend is not signing, I can't answer that.  I don't know him nor have a heard any of his reasons.  Many people are suspicious of things they do not understand.  And PSAs and cross unit laterals are very recent developments brought about by horizontal development.

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