Ron Von–this isn’t Cathy again–price of oil or gas has nothing yo do with figuring your mineral interest, As I understand it, decimal figures are carried out to the eigth place to minimize errors, so–1 bbl x 3/16 lease (.1875) divided by well spacing permit (640) = RI (royality interest) per mineral acre owned. (.00029296) So–.00029296 X # of mineral acres owned = minerals owners claim to oil sold. (decimal interest) So–BOPD X RI X price of oil - taxes and fees = $$/day royalty check. If this is wrong or if there is an easier way to figure, please jump in and inform us first-timers before we get our division orders and have to verify information. Thank you.
I always have an addendum added to my leases stipulating that I won’t share operating expenses with the operator.Nobody has turned down my request yet.
Keep in mind the operator has a 3-4 million dollar investment in each horizontal well that they drill and we as royalty owners have zero investment and zero risk so they want to pay us as little as possible.
The royalty calculator link from MINERAL HELP tab above comes up with the same results as Cathy or whoever she is or not. The is a better calculator on web that calculates on a state by state basis with adjustments for matters specific to each state.
Yeh right Claude, I think you are right. But when the check arrives, and they have plucked your feathers all thaey can, what money they deposit into your checking account is dependent on the price of oil on the market. Is this not correct?
I really like Virginia’s method whatever it is, but I do believe the example she gave us at the time was based on oil going for roughly 90.00 the barrel? The way I see it right now is that the example gave some lucky mineral owner $150,000 from 3/16 640 acres getting 100 BOD, and so when the market price goes to $150.00, that would be increased by 60 percent at the bottom line. Is this not correct??? I like it.
If your lease says “net” expenses, you are paying for “transportation costs”, however vaguely they may be calculated and it is usually for the gas, not the oil. It is to get the gas “ready for market.” Not the well drilling expenses-those are separate. Be very careful about company leases that they present to you, because this net clause is usually in there. You have to protest and get “gross” clause put in. Also make sure you get a depth clause.
Go to the Stephens Co page and open up all the comments at the Top and look for the Calculating NMA’s section if the following link does not work.
NMA%20Calculation%20Stevens%20Co…xls
Download it and fill in your acres for both oil and gas. You can input different rates for oil and gas (use your royalty statements). You can change the market price. This one is for 3/16, but you can change the math and put in different percents. Also be careful. This one is for 640 spacing. Yours might be different depending upon the well. This will give you a month of proceeds. Don’t forget you get paid on both oil and on gas. Usually the oil is gross proceeds (check your lease) and gas should be gross unless you signed a “net” lease. Each month will usually decline which is perfectly normal and expected.
Ron Von—yes, the price of crude determines how much money goes in the bank, but the % you get per bbl is going to stay the same. And, if the price of crude goes from $90 to $150, that is not an increase of 60%, that is an increase of 67%.
No link to website. I made the graph based upon public production data. The bottom axis is months of production, no matter the actual start date. I took some of the longest lived wells and posted them. I was curious as to how the CANA Woodford was performing versus the SCOOP Woodford. I added in the Miss. Lime to see how it looks. I think that Logan will see more Woodford drilling, but it isn’t as thick as the other two. This play has only been around for about 4 years, so not much to go on for production to get a long term look. Cana wells are the oldest.
The earlier wells in Cana did not have the benefit of the extensive multifrac stages that are used now. Also, it looks like some of the oldest of them are shut-in as their new wells come on line.
The thickness is a factor, also the liquid Gas, Condensate or Oil. Condensate is the preferred liquid at the moment, followed by oil and then the dry gas out in the future. The wet gas coming with the oil and the condensate gets a better price due to higher BTU value. For the Woodford, thickness is a factor, because there are several more silica rich zones. Those areas that have an upper and lower zone with a more shaley zone between are candidates for drilling and producing in the upper zone and another set of wells in the lower zone. That is a few years away. Companies need to hold their massive leasehold with one well per section first. I don’t know how the Miss. Lime is going to pan out. I suspect that it will not be as productive as the Woodford. Different facies, so the porosity and permeability in the lime is different than the silica rich Woodford. They will respond differently to the frac jobs. I have a spreadsheet that I have made that helps me determine whether or not to take a bonus or which level of royalty. It is based upon a great spreadsheet posted in the Stephens site posted below. If I think there will be multiple wells, I will go for the highest royalty and the lowest bonus.
This Royalty Calculator causes one to think about the Rate of Decline which I think is a major issue on these H wells. It seems to in the 70% or more range in the first year. http://www.shalebiz.com/pages.php?page=6
Harley, You are correct. Decline over the first year is 50-80% from peak. The wells tend to stabilize at about a year and then run at a low rate for many years. I am attaching a graph for gas rates that has a selection of wells from the CANA & SCOOP & one Logan well. Oil is similar. I think the Wooten was the Miss. Lime well. The others are Woodford. Gives you a feel for what to expect. If you add wells to a 640 spaced section, you will get a stacked effect for a brief while. Note the Cana wells that decrease when new wells come on line. (Reimers, Austin, McCray). They may have been shut in for micro-seis or some other reason. We will see if they come back on line. Their sections have up to nine wells each in them which all came on line within a few weeks of each other. (The graph is normalized to put the “starting date” of production all at month 1, not their actual dates.) Makes it easier to compare the declines. Those early Cana wells have been on line since 2009-10 and are in a very thick 250’ part of the Woodford.
M barnes. Thanks. Please provide link to website if you have it. Bottom axis is unclear. is it months? My observations are anecdotal and all oil related in Logan county. Have been using the Oil-Law database which seems very incomplete and perhaps sloppy. Also the longest running to date is only 18 months or so. The issue of thickness of the shale causes need to look carefully at the permits if one wants to make predictions of future revenue.
The 6:1 mcf to oil ratio is industry standard. The actual ratio depends upon the BTU value, but 6:1 is close. It is really closer to 1bbl oil = 5800 cubic feet of gas (depending upon BTU value) Here is a graph of the BOE (w gas) declines of some wells in the CANA and SCOOP and Logan area. It is the combined oil and gas. I posted just the gas graph earlier today. The Wooten is a Miss. Lime well in Logan. If anyone has the name of a long-lived Miss. Lime well or two, I can add a few others. As you can see, the Woodford is much better in this comparison. 
This is in regards to our leases in southern Grant and northern Garfield,not Logan county.
So I figure around 25% of initial production figures as to what I can expect.
Here is what our operator says as it pertains to present Miss wells being drilled:
Using a 6:1 gas to oil
conversion rate (which I personally hate but the industry seems to hang on to
it), the expectations for this and other wells is to start out at or above 200
BOe/day for the first month, stay above 150 BOe/day for the second 30 days,
dropping from 150-100 BOe/day over the next 5-6 months, then dropping from 100
to 50 BOe/day over the next 12 months. We ultimately expect these wells to make
125 MBO and 0.4-0.5 MMcf. Hopefully, this paints a general production profile
for you. If you have any other questions, please let me know
Linda, pardon my ignorance but math is not my strong suit. What does 125 MBO mean, 125,000 barrels of oil over the lifetime? And what does MMcf mean?
Just curious what’s happened to all the Drilling Permits, Drilling Permit Approvals, Permit Changes, etc.? Aug. 1 was about the last such entry showing in the above Discussion Forum. Seems they’ve all ground to a halt. Is this a sign of a slowdown in drilling or am I missing something?
Can’t seem to get too excited until I hear of some activity on 36-17N-3W. Seems like neighboring sections 26 and maybe 25 are as close they get to us. Feeling like we’ve fallen over the ‘edge of the earth’…maybe Columbus was wrong!
Thank you, M Barnes!
Linda, your operator sent you the great info that you posted. Do you know what a lifetime Mississippi well would entail in terms of time to make that 125,000 barrels of oil?
well guess whut Tim WEST…,my math are not no better thanmy Albegra which I almost flunked except the teacher liked me a lot. So Catherine or Claude, that 50% I guess is really 57%? I can live with that. LOL