Any large buyers in Hughes county anyone has worked with, that made good offers and quick easy close?
What did you get offered and where were yours located?
Hundreds of acres across a couple townships, trying to get a feel for what the going rates are to sell.
There is a big difference between vertical and horizontal wels… If the lease bonus is $200-300/acre in a place then for a horizontal well 2-3 year term lease bonus is $1500 to 2500 plus one-fifth royalty. In places where vertical wells produced 3-4 BOPD the horizontal wells produced 1,000 to over $ 3,000 BOPD. A good nearby example is STACK and SCOOP play where the vertical wells produced 4-5 BOPD. But the horizontal wells produced in multiples of 100 and 1,000 BOPD. I was talking to a mineral company yesterday. They said they recently paid over 27 thousand/acre in the Kingfisher County. The geology of Hughes County seems to have better potential than STACK and SCOOP. I am going to hold off until horizontal drilling is well underway.
The following link should help you.
https://www.upstreamdb.com/oklahoma/hughes-county
Average production per lease has been 825.386 BO plus 1,427,100 MCFG.
I would like to have $2500/acre plus one-fifth royalty
blanket and generic summaries/analysis like that is dangerous and can be very misleading. You really need to look at the specific part of Hughes you are located in as formations come and go and well productivity varies wildly.
I agree with Jeffrey. Generic databases like the one you shared need to be verified, price adjusted, reservoir adjusted, completion type, vertical vs horizontal, time frame identified by well, etc. Very dangerous to use without knowing what the data is and where it came from. Statistics can lie so easily.
For example, that screenshot from the generic website has 1737 leases “in the database” supposedly from 7/1/1990. There are actually over 5000 leases in another data base just from 4/20/01 to 12/23/05, so you can see there is a huge problem with the generic data base number of leases and every calculation that might be based upon it.
I would not trust that generic data base oil number at all… For example, I queried a different database on production from all wells in Hughes county from 7/1/1990 to 5/1/2018. And cum oil was 3,179,182 bbls and 873,648,446 mcf gas from 1599 wells. (643 were listed as Woodford wells with 247,518 bbls oil and 747,383,366 mcf of the total) Horizontal drilling is well underway already. Vastly different than the numbers from the generic website. For the most part, Hughes county has historically produced primarily gas with associated liquids. Those liquids were usually reported in the “oil” column in older wells. More recent production puts the NGLs in the their own category and puts condensate in the oil category.
I would refer you to a good summary article https://info.drillinginfo.com/arkoma-basin-next-scoopstack/
It has a nice comparison of leasing prices in the Arkoma versus the STACK. They are from 2017, but horizontal Woodford drilling was already in full swing. Lease prices in 2018 are up a bit from then since gas prices are a bit up, but the highest I have been offered so far this year is $500 3/16 which is reasonable considering that the product is mostly gas. I prefer to 1/5, so my leasing bonuses have been a bit lower for that. You can want $2500 and 1/5th, but you will probably not get it in the near future for a lease and the poolings will probably not get to that level in the near future either. I hope you do, but given the product and price, not likely. If gas goes to $15-20/mcf, then maybe…
The conventional reservoirs have been producing since the 1950s. Since they are so gas rich, they have produced for a long time. The Woodford is the newer play at deeper depths and is also gas prone-even more so, since it has a higher level of maturity and is also the source rock for the shallower reservoirs.
The article has a nice map showing the main reservoirs and where they have produced. The leasing is driven by the preferred economic reservoirs. The Rate of Return is highly dependent upon the price of gas and that drives the lease bonus offers.
I used my database to sort by gas and oil wells. The “oil” wells are on the west side of Hughes in the old conventional reservoirs. The “gas” wells are mostly on the east side of the county in the Woodford with the best wells in the SE townships (hence probable slightly higher bonus values).
Here is an older map from the USGS https://www.eia.gov/oil_gas/rpd/shaleusa6.pdf
It is a bit confusing, but the Ro 1.4% orange line is the important one. Woodford to the left will be wells with condensate (in purple) and wells to the right in red are gas only (in red). Most of Hughes Woodford is gas. The map also shows the regional Woodford depth and thickness.
For those of you who would like a strat column for the Arkoma basin. Here is one:
If you want a good geologic summary of the Arkoma basin, then here is a good article with some great pictures. The file is too big to upload, but the reference is Shale Shaker, Vol 63. No 1 July-August 2012 Issue. Arkoma Basin Petroleum-Past, Present, and Future, A Geologic Journey through the Wichitas, Black Mesa Basalt and much more by Neil H. Suneson.
Hope this helps you have a better feel for the Arkoma Basin.
daaaaannnnnggg! your posts are getting to be as long as mine. Nice info Martha!
Is there a kind soul out there who cam help? I just received a division order from vanguard for my family and me but the amount is psltry 300 dollars! Is this posdible can I check whether the company is being honest? My name is Archibald Peisch
Your division order is calculated by the following formula: net acres/spacing acres x royalty x % of perforations in your section. (the last term is used for multi section horizontal wells.)
Is the $300 for a royalty payment or for a late paying interest payment?
For M Barnes: Do you have a special link to speak directly with you? What I wanted to tell you M Barnes is that after 3 attempts I heard back from Trinity Operations re the 4 new DORA (WELL NAME) wells. I wanted to know the status if those wells. So happy to hear today, i.e. from Trinity: “Dora 4 and 5 started producing Dec. 24. Dora 1 & 2 are expected to start producing soon.” Unquote.
My Question M Barnes: There was no feedback on Dora 3. What does that mean? For a good while I have already received small ROYALTIES for couple years. Does this mean that the Operator is expecting more volume?
Leta C. MONTANA (Big Sky and grizzly Bear Country)
M Barnes, message just sent to you. Only DORA 1 (one) is the small Royalty I have received. Forgot to say above that Dora 1 is the only one I have received royalties from for the last two years. 2 3, 4 & 5 are the new wells.
Leta C MOMTANA
MONTANA was misspelled above…not MOMTANA! 
Leta C. MONTANA
You can send me a private message. If you hold down your cursor over my name, it will pop up.
However, your questions are probably interesting to other folks in the section, so I can answer them here.
21-7N010E
Dora 1-21H first sales 5/27/15 Dora 2-21/28H spud 9/8/18 probably online in January 2019 Dora 3-21/28H spud 9/10/18 probably online in January 2019 Dora 4-21/28H spud 8/9/18 first sales 12/22/18 Dora 5-21/28H spud 8/9/18 first sales 12/22/18
I think the person meant 2 &3. Well 1 has been online since 2015. Since 2 & 3 were spud a month after 4 &5, they should be a few weeks later for first sales.
To your questions, yes, you will receive more volume since you will have four new wells. Yes, you will probably get a new Division Order for each well. They are drilled across two sections, so the percentage of perforations in your section may be slightly different for each well. The equation is: net acres/gross spacing acres x royalty x % perforations for each well.
The Division Orders usually show up about five months after first sales. The royalties are required by statute to be paid six months after first sales. There can be some delays on sections like this as they have to calculate hundreds of owners decimal interests over two sections for four new wells. If they are late, they have to pay you interest of 12% if you title is clear. You may have to ask for it. They tend to “forget”.
Another thing to be aware of… the first checks on these wells will be for six months so will be the largest that you receive. The next checks will be monthly so much smaller. You may want to talk to your accountant about tax planning if the amounts are going to put you into a new tax category. The first two years of a horizontal well are usually the most prolific, so tax planning can be necessary. After about about two years of production, the amounts will be more predictable, but smaller.
M Barnes, (this name flows; please continue to use.)
What would we FORUM MEMBERS do without you? Do ‘not’ run away. Your RESUME is impressive. As a Novice, I get lost very fast in this exciting Oil & Gas world.
Leta C. Montana (Big Sky & Grizzly Bear Country)
Yes, I am following this post closely and interested in all the information. So, thank you, Martha.
We have multi-section horizontal wells in Hughes County, Section 36 (Keller 3625-1HX and Keller 3625-2HX) and both pads are on our surface. During initial negotiations, we were told we would receive royalties on production from all sections which these wells drew from.
Then, to our surprise, we received DO’s stating that we would not receive royalties from any other section than 36, and even in our own section, off our own land, we would only be allocated 61% of the royalties. This is from Antioch: “So, we allocate how much of the total well is completed within the section where you own. In this case you are being allocated 61% of the total well-bore because that’s how much was completed in the section where your minerals are located.”
Seems like highway robbery to me, but then, any O&G negotiation does. 
KC, That is correct. You only get royalties from the section that you own. Otherwise, it would be robbing from the other guys in the other section. For the Keller, you had the benefit of the higher percentage. Sometimes, it goes the other way.
Yes, ma’am - it does make perfect sense that we don’t benefit from the other section. On the other hand, it also seems we should get 100% from our own section.
You do get 100% of what you own in your section; it is 61% of the well which goes into two sections. 61% of the well is on your side and 39% of the well is on the other side.
THANK YOU for explaining that so clearly, as no one before has been able to. It all makes perfect sense now and I feel much better. Thank you, thank you, thank you!
If you go to the OCC well records site, (Test) you can find the completion report for the Keller 3625-1HX. Put 3610N08E in the Legal Location. The 36 being first tells that the well is spud in 36 and goes north into 25. The perforation interval is from 5058 to 11991 MD (measured depth). Near the bottom, you can see the Deviation and the radius oft run. Total length was 6742 which was a bit shorter than planned. If you open the survey for the well, you can see where it crossed the 36/25 border. That is what the OCC uses to calculate the percentage in each section. If you go to the case dockets site (OAP), put in the case docket number that goes with the well (201702370) and pull up the exhibit from 4/2/18, you can see a map of the final well location and the percentage assignments. This is what the operator uses to assign the decimal values. (http://imaging.occeweb.com/AP/CaseFiles/occ30061641.pdf). Often, a picture is worth a thousand words, so now you can visualize the split. You might want to print these out and put them in your files.
