Block 76 Section 25,26,35,36 and Block C-26 Section 24

Currently EOG has applied for 10 permits and 8 are approved and drilling is underway

for Block 76. EOG is also acquiring leases in Block C-26 where we have been under a lease for over 12 years as a tiny well still pumps. Offers to purchase my minerals have increases substantially over the past year and the offer amounts have gone through the roof. We are now sitting on an offer for over $65,000 per net mineral acre! I know that what they offer is not as high as they will go. I know that my father and grandfather said, "Never sell your minerals. Ever!" But, this is a lot of money on 22.5 net mineral acres. My gut says hang tight and throw the dice that these wells are big ones. We have considered hiring a consultant, but I don't know that I would do what he/she would recommend so it seems a waste of money. Does anyone have any advise?

I agree with the theory of "never sell your minerals" - but also remember that you can only sell a piece of the minerals and keep the rest.

EOG is drilling monster wells - and there may be multiple benches that can be drilled in the next 5-10-15 years.

You can check the Tx RRC yourself to see completion info in the area

A consultant will do a bunch of work to give you a theoretical estimate of ultimate reserves in the ground and a theoretical summary of what royalty interests payments can be assuming certain prices - the number will be very large.

And it all comes down to the time value of money - get lump sum payment now or spread out payments over the next several decades

Note that all these wells will have a very high initial rate for short term and then a very steep decline to a low albeit long term rate after the first 4-5 years

Congratulations on your good fortune. And good luck as you move ahead dealing with this.

P.S. Suggestion - look at the offers you are getting as equivalents to barrels of oil. The $65,000 per net mineral acre is equal to 1444 BO at $45 per BO price.

Just another way to look at what you are being offered.


That is a great area, and EOG is one of the best operators in the business. $65k/NMA is among the highest offers I've heard of, but 10+ wells drilled by EOG, with room to put many more, could justify that price, and perhaps higher.

Your father's and grandfather's advice was well-founded, as now you find yourself realizing what they had dreamed would happen. If I were in your shoes, I'd probably sell around half of the minerals at $65k+/ac. It would allow you to hedge your bet a bit, while still leaving lots of upside with the remaining half that you retain.

If a company's initial offer is $65k/ac, they may be willing to revise upwards. With offers already this high, if hiring a consultant to raise the sale price, I'd want them to be compensated solely based upon the amount they're able to add to the offers that is above $65k/ac. No reason for a consultant to make a commission or fee on your existing $65k/ac offer. I do think that it would be wise to engage the services of an attorney. If you decide to less than 100%, you want to make sure your deed doesn't convey everything. There are some attorneys recommended on the front page of the forum, with Wade Caldwell receiving a lot of positive feedback on this site, and there are consultants in the marketplace section of the site should you decide to see if they can raise the price.

Even with an offer as high as you have, I imagine you'll be receiving friend requests on this forum from people trying to buy your minerals.

Best of luck!


This Completion Report is on one of those EOG 'Monster Wells' that Rock Man was mentioning. Well 301-32738 located in Section 47/Block 76::::2,477 Barrel Oil Per Day/3,483,000 Cubic Feet Gas Per Day


Clint Liles

I own minerals in several areas of this county and $20,000 is the best offer to date that I have received. I have SWEPI permits on each of my sections to the north as well. My advice is to hedge your bet. Sell 1/4th, 1/3rd or 1/2 for that price and retain the rest. If you put the sales proceeds to work in another asset then you can parlay that into something greater. Another issue is what your capital gains tax rate will be. Currently Obama jacked it up to 28% for the highest brackets so you may want to wait until Trump gets it down to 15% again. Just food for thought.

Hi, Lisa: Thanks for your post. I also have mineral interest in Sec. 25,26,35,36, Blk. 76 PSL that we leased to EOG recently. Altogether, my family owns about 90 net mineral acres (nma). I did not know they had actually started drilling on our acreage. Could you be anymore specific as to what location(s) they are drilling and when they started?

By the way, my grandfather, father, mother and uncles always said "when you sell land, always keep at least half the minerals and if you buy land, always negotiate for at least half the minerals, if still attached". So I am considering selling up to half my Loving Co. minerals if the price is hefty enough, as I am getting up there in age and have no descendants. However, I will definitely keep at least half of them to pass on to the beneficiaries I do have designated in my will.

$65,000.00+/nma is $25,000.00+ higher than the best offer I have received. If you wouldn't mind passing on the contact info for the buyer, I would be VERY grateful (I am not a buyer). I am new to this site and don't know if you can do that. However I know we can if we are "friends" on this site. I will try to send you a "friend request" but am unsure how to do that, so if you don't receive one from me, I would be extremely appreciative if you would be so kind as to send me one so we can exchange information.

I ran some rough numbers and, assuming $45.00/bbl oil and 25% royalty, our 4 sections would have to sell approximately 15 million barrels of oil equivalent (BOE) to pay us $65,000.00/nma in gross royalty checks. That is a LOT of oil and it will in all likelihood be quite a number of years before that mark is reached, if ever. I think our acreage has the POTENTIAL to make that much and more, but there are absolutely no guarantees that it will.

However, there are two horizontal Wolfcamp wells offsetting our acreage (EOG's locations on our acreage are permitted for the Wolfcamp formation) operated by EOG that start in Sec. 47 with the terminus of each lateral in Sec. 38 only a very few hundred feet south of the south line of the SW/4 of our Sec. 35. Production figures are as follow.

The #1H (API #42-301-32738) Brunson 38 Unit (TRC lse. #48158) on 6/11/2016 tested 24 hr. Initial Potential flowing 2477 BOPD and 3483 MCFGPD plus water on a 68/128" choke. During the period from 6/2016 to 2/2017 it has sold 261,287 BO and 354,559 MCFG. For the month of 2/2017 it made 16,287 BO and 24,866 MCFG. (This is the well referenced by Clint Liles in an earlier post)

The #1H (API #42-301-32493) Whitney Brunson Unit (TRC lse. #48164) on 6/11/2016 tested 24 hr. Initial Potential flowing 1882 BOPD and 2958 MCFGPD plus water on a 68/128" choke. During the period from 6/2016 to 02/2017 it has sold 203,287 BO and 337,998 MCFG. For the month of 2/2017 it made 13,488 BO and 23,887 MCFG.

As you can see, while these wells are definitely "big ones", they do have a very rapid decline, as one would expect given the nature of the reservoir and the huge multistage frack completions. Still, Estimated Ultimate Recoveries (EUR's) I've seen reported per horizontal Wolfcamp well in this general area range from a low of ~1 million BOE to 2+ million BOE.

Further, our acreage is highly prospective for at least one sand in the shallower Bone Spring formation, although the very few horizontal Bone Spring wells I've checked out are northeast of us and have been gas prone w/some condensate.

There is, however, an old vertical Bone Spring oil well (the Madera 26-76 "A" #1; API #42-301-31087, lse #35847) drilled in the 1990's actually still producing in the SW/4 of our Sec. 26. Currently operated by Energen, it has only made a little under 13,000 BO to date and very little, if any, saleable gas. It is clearly only being produced to try to keep some acreage held by production (HBP). I was told by an EOG representative that they have reached an agreement with Energen and it will not hold up development of our acreage. What is significant to me is that it does prove that there is producable oil in one or more Bone Spring sands on our acreage.

There are numerous other formations/zones that may be prospective for our acreage that will probably be drilled on, or at least relatively near us in Blk. 76 PSL, at some point well into the future. Stable higher prices for oil and/or gas--in combination with results of first tests of these reservoirs in our general area--will probably be the determining factors. This is, of course, only my opinion. Although "mostly retired", the bulk of my career (almost five decades) was spent as a petroleum geologist and I still hold the title of Exploration Director Emeritus with the small E&P company I founded almost 40 years ago!

I'll be wishing you the best of luck!!!

This is a postscript to my initial post.

I checked a couple of horizontal oil wells in Sec. 27 and 34, a little over 3/4 miles west of our acreage, and learned that they are Bone Spring producers. I didn't pull up IP's but production data follows.

The XTO San Antonio 76-34 Unit #1H, for the period 4/2014 to 2/2017, has produced 136,031 BO and 193,728 MCFG. The XTO Santa Barbara 76-27 Unit #1H, for the period 11/2014 to 2/2017, has produced 169,565 BO and 212,976 MCFG.

While these wells are certainly not as good as the Wolfcamp producers offsetting us to the south, a lot has been learned since they were drilled in 2014. Much longer laterals and better frack design using a lot more sand or other proppant per foot of perforated interval are resulting in significantly better wells.


You stated that you recently leased to EOG minerals in Sec. 25, 26, 35, 36, Block 76. What royalty were you offered?

Hi, George:

I was offered 25% royalty right off the bat. I didn't have to negotiate to get it. Best of luck to you.

This attachment from DrillingInfo supplements Clint's posting / map. The 4 sections in question are centered in this map. The red dot is the vertical producing well noted in earlier posts. Note the laterals already in the four sections (section numbers in upper left corner of each 640 acre section). Also note other laterals in surrounding area.

With multiple benches and 6 to 10 laterals across per section, there is a lot of potential production that can take place here. But it may be 20-30 years before these laterals are drilled and drained (if not longer).

364-LovingCoMapPermits.pdf (861 KB)

Thanks to all for just great responses. I do want to clarify that this offer includes my minerals in c-26 section 24. in Block 76 I have 15.7 net mineral acres and the balance in the triangular piece to the south. This a huge decision. I have never been to Las Vegas, but this feels like gambling. This is the link that shows the EOG wells in Block 76: Rustler Units, 8 in total Wrangler Units, 2 in total

You will need to designate EOG, Loving county and the names of the wells. It will then click up all 10 wells. then click any one of them and scan down on the left side of the page and you will see a map icon. Click that and you will the layout of all 10 wells. I am probably telling you how when you already know how.

To clarify...Are you saying that this should not stop producing for 20-30 years? I have been told that most horizontal wells play out in 10 years if not sooner. But, I am just learning and really do appreciate all advice and knowledge.

I have been told by someone at EOG that they plan to drill all 10 wells before they bring oil to market and that I should not expect any income until the 1st quarter of 2018. Now whether I have spoken to the correct person, I don't know. He also said, " In 2018, you will have tax problems" and then he laughed. I told him that those would be problems that would be welcome.

The typical production life for these types of horizontal wells will be over 20 years and perhaps even 30 years. However, the max production will be in the first couple of years and after about year #5, the rates will drop to about 4-5% of the original rates.

Basically, about 50-55% of the total production from the well will come in the first 3-4 years, and then the balance will take 20+ years to be produced.

I have attached a PDF showing production decline for a typical Eagle Ford well from S Tx. This type of profile (in a frac'd horizontal well) is also what should be expected in any horizontal well in this area in W Tx. X axis is months of production. Y Axis is the decline % as to a percentage of the initial rate. So 90% = 10% of the initial production volumes.

363-EFdecline.pdf (109 KB)

Just remember that research and knowledge decreases the "gambling" factor and increases the probability of understanding what the future cash flow / activity will be in this area. Check out industry / operator presentations for this area (EOG, Concho, others) to see what they expect from their drilling here

Hi, Lisa:

What the person you spoke to at EOG told you sounds realistic, possibly even over-optimistic re: the timing factor of drilling, completing and starting to sell oil and gas from 10 wells. In the Wolfcamp these wells drill to total depth (TD), including the laterals, in a few weeks. However, based on TRC documents I've reviewed, completion appears to takes about 3 months or so, give or take, per well. If they are actually going to drill and complete 10 wells prior to starting production, it looks like they would have to be running multiple drilling and well service rigs on our acreage simultaneously in order to start selling oil and gas in the 1st quarter of 2018.

Part of the reason completion takes so long is that EOG is drilling much longer laterals (all the EOG locations on our acreage that I've reviewed are permitted for 2 mile laterals) than earlier in this play. They are also increasing the number of isolated stages along the laterals, each being perfed and individually fracked.

I was told a by a landman leasing for EOG a month or so ago that they actually had 2 permitted Wolfcamp locations they were anxious to start drilling, one on the Wrangler "A" Unit running north and south in Sec. 26 & 35, and one on the Rustler "A" Unit running north and south in Sec. 25 & 36. He also said that, after these 2 wells, they would at some point start drilling a well in each of the remaining 6 long, narrow ~320 acre units starting with the easternmost and moving from east to west. I really don't know if this is currently accurate information or not, especially given that some time has passed since I was told this.

Also, in answer to your question as to how long these Wolfcamp wells on our acreage will last, it is my best judgement, based on very limited data, that if the Wolfcamp is totally drilled up on our acreage, at least some of the wells will be economical to produce for 20-30 years, possibly even longer. The lease itself, given that 1 or more other formations/zones will probably be drilled up at some point, could wind up producing for a very long time, indeed.

Another issue to keep in mind as to these horizontal wells is pad drilling and how this restricts things.

With pad drilling, the surface locations / wellheads are only 20-30' apart. Because of this, if a well is being drilled, previous wells on the same pad cannot be produced for obvious safety reasons.

So if a well is frac'd and put on production, and then another well is to be drilled on the same pad, that first well is temporarily plugged to allow for the new drilling.

This is not a good way to handle reservoirs (i.e. shutting them in after being on production). So an approach that many operators (including EOG) are doing is to first drill up all the wells from a certain pad and then to frac each of these wells one after another or via zipper frac'ing (two wells at once). This is both very cost efficient and operationally efficient. It also takes some time to build the facilities and pipelines to take the O&G and produced water from a large number of stimulated laterals.

Hi, Lisa:

I was wondering if you received my "friend request"? If you did and are not comfortable accepting it, I fully understand. Thanks!!!

I am not sure of the significance of the red dot on well 30306 in the NE/4 of Sec. 35, but it isn't the producing oil well referred to elsewhere in this discussion. It is an old, plugged out Strawn gas well, though you couldn't tell it from the well symbol. Strange.

The vertical Madera 26-76 #1, operated by Energen and marked by the black spot SE of the dry hole in the C SW/4 of Sec. 26, is the old Bone Spring oil well. It is still producing a very small amount of oil (it sells about 180 bbls or so roughly every 3 months).

It appears that the black spots with the blue "P" next to them represent the terminus of permitted horizontal locations. It does not appear to differentiate between drilled and undrilled locations or even producing wells at those locations. What is even more confusing is that there are what appear to be 3 vertical locations marked with the "P" in the N/2 of the NW/4 of Sec. 40, but not elsewhere. It would be very interesting to see the legend of symbols used on this map.

Well guess what? I shared the source of this offer with another from this chat by scanning my offer letter and sending it to him. He called expressing interest and the man said, "Oh, that was not my offer to her." He responded by telling him that he had a copy of the letter. Then, he said that the offer was meant to be for her minerals and her brother's minerals, together!" Well, all I can say is that is not what the letter said. I assume that it was just poorly worded and it was not ill intent. I know if I had understood that the offer was really $32.50+/- per net mineral acre, I never would have reached out to you in this forum. and, I am so glad that I did! I have learned a great deal and will continue to ask questions and learn. I cannot thank you enough for your advice so please keep that coming.