Jonni, Marathon has horizontals drilled and planned for that area. Most likely, you are already held by the terms of the original Northeast Purdy Springer unit and you will receive royalties based upon the old leases. Are you already getting checks from Marathon or Merit (most likely Merit) ? If you were in the original unit no leasing is available to you if your ancestor leased. If you have an offer to lease, then they will have a title opinion that will tell them whether your ancestor leased or pooled back then.
Dear Mark,
You should contact Rimrock to clarify what is happening to their bonus payment. Several persons on this pooling order are listed as no address, deceased or both. Rimrock may be holding the money in escrow. You may need an attorney to help you make an affidavit of heirship if you relatives did not have a will.
** **The Oklahoma Tax Commission said SB 867 could bring in another $19 million in revenues for the state in fiscal year 2018 from gross production taxes. About half that would go to the general revenue fund, with the rest to counties and schools.
Yes, it would allow companies to drill in regular sandstone and limestone or siltier formations. The high porosity ones may be drained fairly efficiently by vertical wells, but this gives the low porosity and permeability ones a great chance to be productive. They are drilling these kinds of wells next door in Texas and they are quite effective. The mineral owner will benefit from additional wells in conventional reservoirs that would have never been drilled due to the low poro/perm. They would want to drill in reservoirs that are slightly brittle since they will take the hydraulic fracturing better. Soft formations will not work.
Just in:
Oklahoma House passes extended lateral drilling bill in close vote
The Oklahoma House narrowly passed a bill Wednesday that would allow longer drilling in nonshale formations, with the vote held open for more than 30 minutes after an apparent deadlock.
Three members switched their votes on Senate Bill 867 in the last few minutes, giving the bill 51 votes and securing its passage. The final vote was 51-46, with two members claiming constitutional privilege. The bill now goes to Gov. Mary Fallin.
In its first year, SB 867 is expected to generate approximately $490 million in new royalty payments, raise more than $229 million in new state and local revenues and create nearly 6,000 new jobs in the oil and gas sector. Additionally, the measure is expected to spur nearly $6 billion in investment from oil and natural gas producers.
Martha, what is the impact on typical mineral owner from this new legislation? I’ve read about this coming but never grasped what it is really allowing that was not allowed before. Does it mean we will see horizontal wells in the traditional sand formations?
M Barnes, are there any of the new potential formations located in SCOOP
View Discussions My family is not being responsible enough to talk to me about who is the leader of what’s going on cuz im discovering that section 20 3N-4W is being sucked dry from CONTINENTAL RESOURCES cuz the production being pumped has gone from a few hundred barrels monthly being sold to a couple 10’s of thousands due to their ecoPAD wells on the mineral property and I fear that we are being robbed blind, the 3year lease has expired already… Please shed some light on my situation please and thank you
Chris,
With my leases, I would tell them to shove it! If you are parcipating, a different story.
Question on Division Orders – I have been in the practice of not signing division orders based on the Oklahoma rulings that purchasers cannot withhold payment for a division order. I have a purchaser who is asking, in lieu of a DO, that we “certify” that our interests are correct. How do folks handle this?
I understand that the purchaser wants to avoid liability in the event there is an error, but that is exactly why we do not make a practice of signing them. We think we know our interests but we didn’t do a full title report.
Just looking for opinions/experiences on handling this. Thanks!
Dear Mr Camarillo,
Most oil and gas leases provide a primary term during which time the lessor has time to look for and develop any oil and gas. If you lease has a primary term of 3 yrs but is already producing, then the lessor will have to keep paying the same royalty after the end of the primary term. The lease is “held by production” outside the primary term as long as it is producing. I think that Continental currently has two wells and you will get royalties as long as they produce. Does that answer your question?
Steven, you have several factors that are affecting your checks. The first is the natural decline of a horizontal well. They come on at a high rate and then rapidly decline to a lower rate during the first few years, then they can stay at that low rate for decades. The reason is that the perforations and frac act like a giant tree root system. The larger roots (fracs) are closer to the well bore and the hydrocarbons drain from the larger pathways early in the life of the well, then over time the medium size ones but farther away add to the contributions and then the smaller ones very far away but very widespread join in. The second factor is the price of oil two years ago was close to $100/bbl and gas was high as well. Both prices plummeted and hit a low in February of 2016. Gradual rise to about $52 or so and now we are hovering at about $45. So quite natural. Think of a hockey stick lying on its side with the blade up as the start of the well and the stick the next four decades. Over the next few years as world wide demand evens out, the prices are predicted to go up slightly, so you have a long time of a lower but steady payout. This is perfectly normal.
When you are in a waterflood unit, the unitization equations pertain to any new horizontals that are spaced “in the unit”, so the math is crazy. Some of the equations are about a page long and each unit is different. You still get paid, but it is complicated and you would have to contact the operator once the horizontal well is finished for the equation for your particular tract.
…by the way, this is a 3/16 interest.
To follow up on Darla, the formula for the Division Order is:
net acres/spacing acres x royalty rate x % of perforations of the well in your spacing
For a vertical well, the last term is a 1.00.
For a horizontal well totally contained within your section, it is also 1.00.
For a mult-section horizontal well, the last term is determined by the OCC based upon the feet of perforations in your section divided by the total feet of perforations.
The Royalty Interest or Division Order interest remains the same for each well over the life of the well, but due to pricing of product, amount of product, etc., the check varies from month to month.
If you had old production at 80 ac spacing for example, you will have a DI that is one value. If a new horizontal well comes in, the spacing is entirely different and the DI will change.
All this is thrown out the door if you are in one of the old waterflood units. Whole different ballgame…
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Help with a quick question on value:
My in-laws have a small 3+ acre of mineral rights in Garvin Co Sec 16 3N 4W. They are thinking of selling, but none of them have any sense of potential income. I understand that there are 8 wells being drilled currently. Is there any way to determine what kind of income to expect per acre? I have absolutely no reference to even guess. Are we potentially looking at hundreds per month? Thousands per month?
Thanks much,
Keith, they should already be getting a check for the existing Newfield well in 16-3N-4W (well name is Holinsworth). Newfield is in the middle of drilling 7 more Holinsworth wells in that section (all but one have been drilled, no completion work yet). In addition Newfield has pooled for the Springer formation in that section - no certainty they will drill it but that would be additional well(s).
Assuming a 3/16 royalty for their lease - I would estimate that 3 NMA they have would be paid a bit over $9,000 from the first well since its completion in late 2015 and about $260 a month now from the existing Holinsworth 1. O&G prices are currently higher than most of the operating history of the existing Holinsworth well - so consider that when trying to value the new wells.
Someone offering to purchase their interest knows all this is going on, knows the new wells are near well underway and headed for completion this year. Initial production on these wells, if successful is high (although it declines pretty quickly).
I am not in the business of buying or selling interests but I would consider something like 36 x current monthly production of $260 + $9K x 7 for the new wells first 3 years production (who knows - maybe it will produce more and prices are certainly higher now so the same production would be worth more). So maybe value their 3 NMA if at a 3/16 is $72,000??? At least I would feel pretty confident I was going to get that money, or more, if I held the interest for 3 years plus I’d still have income from it beyond those 3 years.
I’d be curious how others might look at this too.
Steven, I believe the confusion lays in the term royalty. Your royalty is determined on your lease or at the pooling. It will be 1/8, 3/16, 1/5 or something like that. After they drill the well they send you a division order that has a decimal where they have calculated your royalty against the size of the unit. Your checks will always be based on this decimal for as long as the well produces. However, the decimal is used as a multiple of the production. Thus your dollar amount changes every month.
These wells are in 3N-4W. It looks like the Ferguson’s are in Section 14 and 23 but then I will see paper work regarding the Tina’s and it says Section 23 and Section 26 of 3N-4W.
Val
All the Ferguson wells spud in the southern part of 23 from three different pads and go north into 14. The eastern most pad spuds farther north but not past the centerline. So each will have different percentages.
The western pad of the Tinas spuds in 35, the center and right pads are in 26 . All of them will drill north midway into 23 so about a 3/5ths in 26 and 2/5ths in 23 if I eyeball them.
You can find the EUR for Sec 23 under OCC cause 201701730. You can find the map for the Fergurson wells under 201701731. It shows the staggered pads. About 30 causes attached to section 23. About 14 with 26. Get your copy and paste ready to put them in your digital file cabinet.
You can find the map for the Tina wells under cause 201605456. It isn’t quite right since they laid them out straight instead of the actual pads, but you get the drift.
If you need the numbers, friend me and I can send the numbers to you.