We have also seen our mineral royalties go down over the past year. We were surprised at this. Not sure if it is part of Bob McCorkle’s comment or not.
In general, royalties will go down over the course of a year because the well’s production will be declining. It also depends upon the price of oil and gas, so you have to take that into consideration as well. Those are natural factors.
If you have mainly gas wells and do not have a “no-post production deductions” clause in your lease, you will generally see an increase in those fees as time goes on. They can seriously erode your royalty checks. “Certain” companies are really getting into trouble over excessive fees. Keep a very sharp eye on them. There have been quite a few class action lawsuits recently over excessive transportation fees, but it is a hard nut to crack.
Thank you M Barnes
Scott, who is the operator on the DO? That well has a dual history. Comanche is 2008 perfed but no production from 12,238-13,148’
Questa in 2010 perfed 10,394-10,408 no production, so am wondering who has it now and what zone.
M. Barnes - Received the division order from Questa. Don’t really know what you mean be “perfed”, nor do I know what zone it is in. The division order shows effective date 2/2014 plus accruals. Don’t really know if there is anything there or not. Thank you, Scott
Have received a division order for property in Section 13T19NR21W. This is for Ramona #1-13, Prop number 156500. Does anyone know anything about this well. Would appreciate any information. Thank you. Scott Steele
Scott, I guess Questa went back in and did some more work on the well. Perfed is shorthand for perforations. These are the holes they shoot through the casing so the oil and gas can enter the well bore and be produced.
If you haven’t checked already, you need to find your mineral deed and your lease to make sure that the royalty interest that is on the division order matched what you have. If the DO is not on the NADOA form, then do not sign it. Friend me if you have questions and I can explain more offline.
I have a 120 acres in 11/18N/24W leased to EOG, which recently filed a completion report for 367 BBLs. I have noticed that there is wide variation in production, even among adjacent sections, and also that some sections with relatively small production units have multiple wells. Does anyone know if there is a relationship between production size and number of wells, that is, why some sections have multiple wells and others don’t? Also, does anyone have any idea about average depletion rates for wells in this area? Thanks very much. B Mills
Brad First of my perspective is that of a retired bond trader and in the parlance of a professional trader, I would would put this in the realm of a patience trade - meaning give things a chance to develop. At the end of the day it depends on who the operator is and rig availability. If it gives you any comfort - we’re involved in sections 7 & 8, very close to you and between the two sections there are 6 producing wells
Thanks Bob. Of course you are right about having patience. My questions arise from being clueless about the oil/gas business, and, not knowing the rules, wanting to learn as much as I can so I know what to expect. There is a lot of conflicting information out there about depletion rates, the number of wells per pad, etc. Thanks for your insight.
Brad,
As a geologist, there can be several reasons for the different number of wells. It can depend upon which company is the operator and what their drilling strategy is. Some will drill one well in each section (or two) to hold the acreage by production. They may come back in a few years and do the infill drilling. Another reason may be which reservoir they are targeting and the quality of the drainage for that well. If it is not economic to drill another well, they will not.
It will be very helpful for you to go onto the websites of the major operators in the area and read their recent investor presentations for the last year. Continental Resources, Chesapeake, Marathon Oil Co, Newfield, Apache, etc have some very good slides that explain their philosophy of infill wells. Continental has some of the best pictures as does Apache. Read the last six months or so of comments on this county and get up to speed.
Ellis: EOG Resources Inc.; Little Turkey No. 17-2H Well; SW/4 SW/4 SE/4 SE/4 (SL) of 17-18N-24W; 692 barrels oil per day, 785,000 cu-ft gas per day; TD 13,905.
EOG Resources Inc.; Roberta No. 35-2H Well; NE/4 NE/4 NW/4 NE/4 (SL) of 02-17N-24W; 575 barrels oil per day, 439,000 cu-ft gas per day; TD 14,160.
PPP Petroleum LP; Shrewder No. 2-20H Well; S/2 S/2 SE/4 SW/4 (SL) of 20-18N-23W; 268 barrels oil per day, 600,000 cu-ft gas per day; TD 13,800.
Brad All the comments to your query, ring true. From a personal point of view, I also have struggled with getting my brain around depletion rates and have found no good answers. But in my own holdings, including those in 17N 24W have taken a little comfort in the fact that while the initial flurry of drilling has subsided, there seems to be a slower flow of follow on drilling, which leads me to take a long view of the prospects that remains positive.
Ellis: Apache Corp.; Stucker Unit No. 1-5H Well; W1/2 NE1/4 NE1/4 NE1/4 (BHL) of 05-18N-26W; 235 barrels oil per day, 391,000 cu-ft gas per day; TD 14,613.
Not much going on but chesapeake has a lot of leases that expire this year .
Any info on activity in Sec. 21, T’ship 19N, Range 21W ?
Ellis: Mewbourne Oil Co.; Miskel 14 No. 1HT Well; N1/2 N1/2 NW1/4 NW1/4 (SL) of 14-17N-22W; 378 barrels oil per day, 1,114,000 cu-ft gas per day; TD 12,490.
Would like to meet others owning mineral rights in Sec. 21-T19-R21. well named Turner 21-1, Unit Petro.
Ellis: EOG Resources, Inc.; Berryman No. 23-3H Well; SW1/4 SW1/4 SE1/4 SW1/4 (SL) of 14-17N-24W; 881 barrels oil per day, 1,746,000 cu-ft gas per day; TD 15,029.
I have a Completion Report dated May 2006 for a drill to the Lower Morrow Formation. Eight years seems like a long time to wait for production. Is this unusual?