We are unleased mineral owners (not by choice as it was UNO when we purchased property) and need a lease. 3 new wells permitted to be drilled. Any advice

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You have zero negotiating leverage so offer to sign the operator's standard lease form with no Exhibit A, no bonus and a 22.5% royalty.   If that doesn't work, offer to sign for 20%.  If that doesn't work check the unit survey plat to see if any mineral company owns an interest in the unit.  If so, offer to sell to them for $2500/acre.

I don't expect a bonus, would love a 25% royalty but would gladly take 22.5%. Today Chesapeake offered 12.5%. I thanked them and said no thanks. I think they said 'take it or leave it."

 Skip as an unleased mineral owner, isn't the operator of that well obligated to send me FULL reports on the well--what they are paying for gathering fees and to whom they pay that, what they pay for transportation costs and to whom they pay that?? As a mineral owner don't I have the right to that knowledge?

Yes, you have a statutory right to quarterly reports on income and expense.  Operator's do not send those reports of their own volition unfortunately.  You have to make a written demand and be prepared to provide documentation as to your ownership.  In your case, not just that you bought the mineral interest but that your seller had good title to it.  The report must include certain income and expense information by statute.  I'm unsure if that would cover all the transparency you are looking for. 

Skip, would the Operator be required to demonstrate that they made a bona fide offer to lease the tract that was turned down by the then present mineral owner.  I would not think that an offer of 1/8 royalty with no bonus would be a bona fide offer!  If these new era wells with their big fracs have such a great IRR, why would an operator not be willing to lease for fair terms (which is not 1/8!!!)

Of course the obvious answer to my question is that the Operators (as in CHK) have an uncanny ability to exaggerate the expenses and minimize the revenues to prolong well payout to infinity!!!

I have been an unleased mineral owner on this property since 2012 with confirmation from the company back then and I get monthly SMALL reports and a monthly check. The thing I have never understood is that since I have a lease with same company in same section, they take money out of the leased property and apply to the unleased property to cover expenses. Does that seem right. It has been small amount and I have been too busy to worry about. Not anymore. If they want to offer 12.5% lease then I want them to provide every documentation possible for that unleased mineral ownership. I did not cause the unleased mineral ownership. The man who owned it was alone and fighting cancer when they were leasing. They didn't deal with him as he only had 1.06 ac. Imagine how much a little lease bonus would have helped him the last few months of his life. When we bought this property we let him live there cost free until he went into hospice. I am dealing with the same guy at Chesapeake that the sick old penniless man dealt with. So some of this work is in his memory.

Spring, I know of no statutory requirement for an operator to offer a lease to any mineral interest in a compulsory drilling unit.  So obviously there is no test as to what would constitute a "bona fide" offer.

kcm, considering the apathy of LA mineral owners regarding questionable royalty deduction issues and deductions from production payments for UMIs, the only current option is an O&G attorney.  Most of them will inform you of the very low odds of prevailing in a law suit.  And the good ones don't send demand letters unless the client has committed to follow through with a suit should the demand be ignored.

There is one possible avenue to pursue enforcement of the statutes regarding how operators treat UMIs.  It's in the works.  It's a little too early to post that information but I will do so when the appropriate time comes.

Skip, here is one for you.  On 1/17/12 Chesapeake completed a well in 016-12W-14N (pad in 009) Sonris s/n 243638.  On 10/19/16 they redid the survey.  On that survey they included 1.209 acres of section 009 in DeSoto parish but did not draw the line across to the edge of the section to include the Red River acreage (owned by the state). 

The 009 land has changed hands and I was finally to get them to recognize and pay (more or less) the new owners, but have several questions.

1.  I was under the impression that all Hanesville units conformed to the section lines.  How did they do this? If they can how, can they just lop off a corner that the state owns?

2.  While my interest decimal is correct the payment decimal is different (larger) and the volume on the check does not match Sonris.  Sonris is much (about 40%) larger.  When I proportion out the difference between the interest and payment decimals to come up with a revised volume I am still about 10% short. I have had this with other companies and always have been able to make everything match.

I called Chesapeake and they said the difference was due to additional partners in the well.  After some period of time they sent me the partners names (Exco, BG US Production Co. LLC, and Texla Energy Management, Inc.) but no contacts or percentage of ownership.  Despite multiple contacts there has been no further information.  Is there any way to force this short of a law suit?

3.  The amounts are low and not worth a lawyer.  Is it possible to sue them is Texas small claims court? 

HA unit boundaries are not confined to section lines.  There are numerous units that include more than one section.  Units including partial sections along the Texas state line are common as are the ones along the Red River where there are fractional and irregular sections.  Basically an operator can apply for any size and shape unit.  The state more often than not approves them as submitted unless another operator makes a formal objection.

If your payment decimal is different, seek an explanation from CHK.  If a company other than CHK holds your lease, send a copy to confirm your royalty fraction. Although EXCO is in bankruptcy proceedings, they should be paying their royalty commitment.  BG owns a one half interest in the EXCO leases and was bought out by Shell. Shell is paying royalty on that half.

The production volume on your CHK royalty statement will never match the volume reported on SONRIS.  The state has reporting requirements that call for a specific pressure and temperature adjustment for volume.  CHK uses the Oklahoma reporting requirements for the volume on your royalty statement.  It would take an engineer to ascertain whether the volumes are the same after adjustments for pressure and temp.  Far above my pay grade.

Skip,

Thanks for your answers.  Informative as always. Do you by chance know where I can get the Pressure, Temperature used by SORNIS and Oklahoma?  I am an engineer.

I don't have the temp regs in my notes.  Louisiana requires volume reported at 15.023 psia.  I believe that Oklahoma, and indeed most pipelines, use 14.73 psia.  I can send a question to the SONRIS staff for the full details when I get time if those pressures don't explain the discrepancy.

Skip,

Thanks for the pressure information. 

Assuming the temperatures do not very more than 10-15 degrees F  this means that Chesapeake numbers should be about 2% higher than SONRIS.

Here is a little light reading if someone wants to get into the details.

https://www.springer.com/cda/content/document/cda_downloaddocument/...

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