RECIEVED NOTICE ON TWO HORIZONTAL IN SECTION 33 GREENWOOD WASKAOM FIELD.  I WAS TOLD OWNER WOULDBE PAID ON HALF PRODUCTION FROM EACH HORIZONTAL. IS THIS CORRECT AND OW IS THE PRECENTAGE ESTABLISHED

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katherine, I am in the Broadmoor neighborhood of Shreveport.  :-)

Katherine, I think I'm a minerals neighbor of yours. Check your Inbox. We've met a few years ago. I live in Oregon.

hey of course I remember you. Things are getting very interesting. good to hear from you

Jesse, you are correct about LA law not requiring a mineral lessor to sign a DO but that is immaterial to the discussion.  The decimal interest remains the same for an ownership interest in a drilling unit regardless of how many wells are drilled or how many feet of the lateral lie within that unit.  The decimal interest can only change if the operator updates the unit survey and there is either a change in the acres assigned to your mineral tract or the overall acreage of the unit changes.

Skip, as I've stated before, us landowners/mineral owners are lucky to have your advocacy on GHS in regards to protecting our rights, along with the counsel of top-quality O&G lawyers such as Randall Davidson. He's a sharp guy, whom I've spoken with and whom I've recommended numerous times to others, even large landowners in south Louisiana. So I guess we'll have to agree to disagree on this rather minor issue. I'm not a lawyer, yet I'm simply telling the truth as to to the practical reality of what actually happens with D.O.s, which are quite important to landowners so they can vet their percentages on wells. Most landmen don't deal with these issues, as you know. It's not in their wheelhouse. The division order analysts do this mundane paperwork. Plus, most landowners who've been in pay for many decades, such as myself, what we're focused on is an honest accounting by operators in regards to our royalty statements each month. Glad to see someone, like you, leading the charge to make sure the survey plates are, indeed, correct. Because if an operator starts with bad math, then our royalty percentages on the D.O.s can be off. True.    

I think Skip and Jesse are talking about two different things. What I believe Skip is trying to say is that a mineral owner's share of production obtained from a unit always stays the same, regardless of how many wells are in the unit or how many feet of CUL is in your unit. The formula for calculating a mineral owner's share of unit production is (net mineral acres/unit acres) X lease royalty = net revenue interest (NRI), and as Skip said, the NRI should not change from well to well. Thus, you should have the same decimal for every well that is 100% inside the unit. 

When CULs are drilled between two (or more) units, production is allocated between the two units based on the percentage of the perforated lateral that is in each unit, which is called an "allocation factor." Thus, if exactly 50% of the perforated lateral is in each unit, then 50% of a CULs total production is allocated to each unit. Once the production is allocated to the unit, revenue from that production is paid to the unit owners based on their unit NRI.

However, it is common practice among operators to pay their royalty owners on CULs by multiplying their unit NRI by the allocation factor for their unit to create a new decimal for the CUL. Because CULs don't always have the exact same amount of perforated lateral in any given unit, this means in practice that you should have a different decimal for every additional CUL in your unit.

I typically get a new division order for all CULs. I know off the top of my head that Chesapeake includes a letter with their DOs explaining how decimals on the CULs are calculated, which includes the actual feet of perforated lateral and allocation factors for each unit in your specific well.   

Thanks for the attempt at clarification, Andrew.  Can you upload a redacted copy of the CHK letter you mention? 

See attached. 

Attachments:

Thanks, Andrew.  What a Chinese fire drill.  The decimals in the CHK letter are simply another means of expressing the percentage of the total linear lateral feet that are allocated to each unit.  52.5% is the same as 0.525 for example.  To go further and then turn that into a decimal interest per well seems a waste but you must keep in mind - this is Chesapeake.  There is always a method to their madness whether it is obvious out right or not.

Do other operators break down their CUL production in this manner?

Andrew, thanks for the CHK D.O. pdf. In the past I've negotiated with CHK and was skittish per their bad rep. I've heard the horror stories. For example, landowners know they're in deep doo-doo when they ask for a lease addendum with a Free Royalty Clause and get screwed by one that doesn't hold up legally. The no-deductions clause that I used in my family's last lease has held up. It helps to have a good operator to work with. Still, I personally like the way CHK walked through the math on your D.O. I've had to run such calculations myself on my D.O.s from other operators. Having had numerous CULs drilled over these last few years, a landowner gets a sense of what to expect from each operator's land department. Some are better than others. Oh, and as you might know, signing or not signing a D.O. does have some legal consequences. That's why operators ask that they be signed. We're lucky to be under Louisiana's favorable mineral code and can garner royalty pay without having to sign lopsided D.O.s.   

Jesse, do you get similar decimal interest letters for CUL wells from operators other than CHK?

Skip, I've never received such a detailed letter from one of our operators. Years back, when we had the first wave of CUL drilling, I had to contact that operator's land department via email in order to get an explanation on how they calculated the math. This was a high-quality top company, and I'd previously exchanged info with a senior landman. Sharp guy. Helpful attitude. Spot on. He took the time to walk me through the math via email. Then as the years advanced and we had more CULs drilled, I'd just get D.O.s with the royalty percentages for each new well, and I could vet the math myself, knowing my royalty for each section per all of the previous wells in a specific unit/section, which included many old verts. Again, once the senior landman had initially explained how a CUL's percentages were derived, such as CHK did for Andrew, I've been able to check the math without any trouble. Again, I've been pleased with all of our operators and the regular royalty payments each month. Overall, as best as I can audit their math, etc. -- I haven't seen any glaring problems. If anything, they could be picking our pockets ever so slightly on the deductions, since not all of our wells have the Free Royalty Clause. Before the HA, I was savvy enough to be able to insert a no-decustions clause into a few of our section locations, but we also have old HBP leases were we are paying for processing, transporting, compression, etc. So some of our CULs are burdened with deductions. Yet I've come to accept these % bites as standard operating procedure. Back before the HA, we didn't have so many chomps out of the pie. But after years of auditing the royalty statements and speaking to various land departments, I eventually threw in the towel and rolled over. It's a small price to do business, and I feel my family is lucky to have such reasonable and well-managed operators that aren't out to squeeze us, such as I've heard with CHK.

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