Replies to This Discussion

Permalink Reply by Two Dogs, Pirate on December 12, 2013 at 16:02

Sounds like, from your story, that you are held by production (HBP) and are governed by the original lease. You will need to contact an oil and gas attorney, not just any attorney, but one that deals with oil and gas issues to try to help you figure things out. 

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Permalink Reply by Dino Roberts on December 14, 2013 at 4:43

XTO/Exxon is taking 22% of my revenue for these type charges and then taxes on top of that;

we worked hard to negotiate a good royalty in our lease and now losing it back to them;

i feel like a working interst owner and not a royalty owner;

need the local politicians to investigate this, if they have the power !!

it might be better NOT to sign a lease lease and come back into the the well after payout; your decimal would be larger and not sure what the law allows for these type charges to unleased mineral owners, since there is no lease agreement if you chose to participate with your minerals in the well;

if you have 10 net acres in a 640 acre pool:

NOT LEASING Decimal = 10/640 = .02 decimal in the well treated like a working interest but you do not have to write a check up front to drill the well;

SIGN A LEASE for 25% royalty = 10/640 X .25 = .005 decimal in the well and treated like a royalty interest 

have a great day folks;

 

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Permalink Reply by Skip Peel - Mineral Consultant on December 14, 2013 at 4:51

Dino, one problem with that path.  The majority of Haynesville wells have never reached payout.  In those cases the leased mineral interests have received royalty from the first mcf of production while the UMIs have not received any return for their prorated share of production.  In the cases where wells are sufficiently productive to achieve payout UMIs begin receiving royalty when the well is 75 to 80% depleted.  For more on the headaches of going non-consent use the search box on the Main Page.  You will find a large number of archived discussions on the subject.

There is also a blog post on UMI which is quite comprehensive. 

http://www.gohaynesvilleshale.com/UMI-Basics

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Permalink Reply by Charles Shelor on December 15, 2013 at 9:22

All of this talk about unleaded mineral interests is useful; but it is WAY off topic.  I simply wanted to know if anyone on GHS has heard of any mineral owners with old leases have used precedence of earlier production without deductions to prevent current production from having deductions.  Basically, has this been tried recently?  If so, did it succeed or fail.  If I can point to a precedent, then maybe I can use that directly with the producer without having to spend significant funds involving lawyers.  If I have to go the lawyer route, I will; but I was hoping to get some information prior to reaching that point.

Meanwhile, please do NOT post any more UMI discussions on this thread.

Thank you, Charles

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Permalink Reply by Skip Peel - Mineral Consultant on December 15, 2013 at 9:34

Sorry, Charles.  Your lease language determines an operator's ability to deduct post production charges.  The fact that an earlier operator did not take specific deductions would have no bearing on what a successor operator might choose to deduct, IMO.  In other words there is no legal precedent set by the actions of the original operator beyond what is stated in the lease.

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Permalink Reply by Andrew on December 15, 2013 at 11:20

Charles,

I've never heard of anyone successfully raising this argument, nor do I think such an argument would be successful in the future.

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Permalink Reply by Dino Roberts on December 14, 2013 at 5:06

very good point and make sense;

for the most part, its probably best to lease, get the best deal you can and try and "contract" around those pesky post production charges;

i would be curious to learn if those type charges are fixed (a little better for us) or do they rise as the price of gas rises (worse, as its a losing battle no matter how high prices go);

thanks!

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Permalink Reply by Skip Peel - Mineral Consultant on December 14, 2013 at 5:22

I avoid delving too far into the arcane world of gas gathering, treating, transporting and marketing.  It is an area with few real experts and they all work for the industry.  The possible variations within all categories for gas produced in the same field is mind boggling.  At least some of the charges are fixed.  That is why there was little interest in deductions when gas was $8 to $12 per mcf.  That changed when the price dropped to the levels of the last 4 years and those fixed charges became a much greater percentage of the royalty paid.  A 70 cent charge on $10 gas is a 7% deduction.  At $3 it is 23.3%.  Those are costs fixed per mcf.  There are other deductions of course but the meaningful comparison for many is what they received when their wells were in their early days of peak production with higher gas prices and what they receive now with largely depleted production and depressed prices.  There are still a lot of royalty recipients out there that don't grasp just how quickly these wells decline.  In the early days of the Haynesville Play decline rates were a hot topic.  They are discussed only rarely now.

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Permalink Reply by 1kw6x71km1v37 on December 14, 2013 at 5:33

Beware the  operator who doesn't really want your lease if you won't sign the POS DOC some landman offered you. It is by design the operator gets all your share of the cash flow until payout. After that, who knows? Many folks have given up by then, and many just don't know what to do from day one.

In reply to the previous post, gas processing costs are set, but remain subject to inflationary and deflationary pressures. If you see them floating along as a percentage of gas prices, you are being had. One neat little trick is to vary the percentage periodically in an attempt to throw the fee owner off the scent.

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Permalink Reply by Skip Peel - Mineral Consultant on December 14, 2013 at 8:19

The Louisiana Mineral Code provides the operator the right to apply the UMI's prorated share of production to their prorated share of the cost to drill and complete the well.  However unlike other states the UMI is not assessed a risk penalty.  In some states that penalty is 400 or 500% of the UMI's prorated share of well cost.  In LA the operator must pay 100% of the UMI's prorated share of production after recovering 100% of well cost.  The UMI is charged certain lease operating costs defined in the Code going forward and the operator may recover 100% of their cost for each well drilled in the unit.  In the first wave of Haynesville Shale development some wells paid out in 3 or 4 months and many were on pace to pay out in a year.   Then the price of natural gas began a decline that continued into mid-year 2012.  Wells that may have paid out in 18 months then took six years to do so.  Operators were forced to drill non-economic wells to hold leases and that maintained the supply side glut.  All operators want to have 100% of the minerals in a drilling unit under lease if possible.  If they can't acquire enough of the acreage they will not drill.  If they can get something less than 100% yet enough to meet their financial projections they will drill.   In the instances where the mineral owner and the operator can not reach an agreement to lease the state defines how the operator is to treat the unleased mineral interest. 

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Permalink Reply by 1kw6x71km1v37 on December 14, 2013 at 10:26

A sleazy operator will welcome unleased landowners in a drilling unit in a area of proved undeveloped reserves. And there is no shortage of sleazeballs out there in the oil patch. Make that the home office.

What your summation fails to point out is that it normally takes a lawsuit on your part to enforce the Mineral Code on an operator. There is recourse through the Commissioner, but he cannot force payment like a state district judge.

You will need a judge to force the return of the repetitive drilling penalties the operator felt were his to take while you were laying down.

I'm looking right now at well cost data submitted by two different operators to drill the same formation to the same depth twenty miles apart. One has submitted a cost factor of $5,000,000 and the other says his cost are around $10,000,000, and I see a lot of duplication with the second, who happens to be a rather large operator domiciled in Houston, TX. You tell me who is lying with a straight face.

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Permalink Reply by Skip Peel - Mineral Consultant on December 14, 2013 at 11:10

I disagree as to operators "welcoming" unleased landowners in drilling units.  My experience is just the opposite.  There are a number of UMI's on GHS.  To my knowledge none have had to file suit to receive their proportional share after well payout.  Under the LA Code there are no drilling penalties. Only recovery of proportional well cost.  AFE's vary for a lot of reasons.  For example "the same formation" twenty miles apart can vary in True Vertical Depth by thousands of feet.  How a well is cased or completed in "the same formation" can be quite different.  The fact that the AFE's are different does not indicate that either operator is lying.

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