My neighbor and I have been offered a lease with primary and option terms of $800 per net mineral acre and 1/5th royalty at "market value at the mouth of the well". Based on discussions in this forum, this seems like a good offer, especially since I only have 24 acres. Is it?
Your area is not in the best part of the ongoing trend, but I would push for 25% royalty which is more the norm in today's world. The $800 is probably OK but I would defer to others as to this part of the offer.
The "market value at the mouth of the well" may be an issue - does this constitute a "cost free" lease where there is no deduction from your royalty payment tied to transportation, processing, marketing, etc?
I would also want a depth severance or Pugh clause included if I were you. This means that even if there is a producing well that keeps your acreage HBP, the deeper rights are released after the primary term of the least has expired.
24 acres is on the small side, but still a decent sized piece of any proposed drilling / production unit. Assuming 320 acre units, you can figure out your share of the production and potential payments.
Thanks, Rock Man!
I'm still trying to educate myself on the terminology and subtleties of this business, as I have not had any involvement with oil leases before now. My neighbor and I have both received the same offer, and he has 57 acres (incidentally, these are surface acres, not "net mineral acres"). When you refer to 320 acre units, is that what an oil company normally tries to accumulate with pooled leases? We didn't know how many others might be involved or how to find out.
A couple of clarifying questions - do you own 100% of your 24 acres? Or just a part of that total? Has the broker told you what you own?
Depending on the length of the lateral / horizontal well (which is what is being drilled in your area), the "units" are in the 160 to 640 acre range.
In this part of Texas, individual mineral rights are usually on the small side (less than 100 acres for sure and mostly less than 50 acres). And there may be many owners of the same acreage tract (e.g. a 50 acre tract may have 25 different owners with a small percentage each). Broker effort can get very expensive finding these owners and negotiating leases.
By the way, attached is a map of the A72 survey area in Brazos Co. All the green dots (about 20) are historical producing wells in this area.
Note that none of these wells are producing today as per the records I am seeing.
By the way, is it a Broker or operator that is trying to lease you?
Odds are it is a broker - individuals normally are OK with naming who they are dealing with on these and other sites but it is your call on that issue.
Always good to know who you are talking to.
Brokers do the leasing for the operator who is "stealth" - it is then the operator doing all the drilling work (and paying the broker bills).
Suggest you ask the person you are talking about the offer this:
- Who is the operator?
- What are their plans (vertical or horizontal drilling)?
- Size of proposed drilling units?
- Target formation(s)"
Then may not answer anything but you never know what they may tell you (which may also be a bit off base and inaccurate).
I own all of my 24 acres and my neighbor owns all of his 57 acres. We both own 12.5% of our minerals. These are small ranches. I produce hay and he has cattle, so it isn't subdivided.
The Landman is Walker Land and Minerals out of LaGrange, TX. He has not mentioned who the Operator is or how many other leases might be included. In fact, I have not responded to the original letter yet, so I haven't had a chance to ask questions.
My neighbor is taking the lead and has already received a full lease contract to consider. He has shared that info with me. It has an attachment "Exhibit A" with some language that seems to contradict the base lease in some areas, so I need to know if that takes precedence.That attachment includes a Pugh clause, limits minerals to oil and gas related products, and details damages that will be avoided. There is also a specific topic which states that shut-in royalty payments are not sufficient to keep the lease in force after a period of time.
OK, Walker is definitely a broker. The "Exhibit A" will take precedence and appears to contain a lot of key issues. Pugh clause is good - assume it is 200' below depth of deepest producing horizon? Or Perforations?
Damage comments are good. But Is there anything about you being responsible to pay our share of marketing, pipeline. transportation, compression, processing et al costs associated with your royalty production? You are in a gassy area and that is where a lot of the extra charges can come into play.
From my own personal experience, this can add up to 15-17% of the gross value of your royalty total.
Have you considered getting a lawyer to look at your leases? Between you and your neighbor you only have 10.125 net mineral acres. May not be worth the cost of legal involvement.
But let's look at it this way. Assume a 320 acre unit- your combined 10.125 net acres is 3.164% of the unit. Assume a 25% royalty and your share of the production is 0.79102% of the gross production (before taxes).
Assume a single horizontal that will make 4 BCF of gas and 400 MBO plus 200 Mbbls NGLS over it lifetime (let's say 30 years). Using values like $2.75 per MCF, $55 per BO / BC and $20 per bbl NGL, you get gross pre tax production revenue of $37,000,000. Not assuming any inflation or price increases.
The percentage of you and your neighbor (0.79102%) gives you a combined $292,675 pre tax. If you don't have a cost free lease, you could be billed 15 to 17% of this total and not get paid that amount.
Of course, this is over 30 years. Production will be higher in the first 1-2 years than drop to a low but steady rate after 5-6 years.
And there could be 3-5 total wells drilled in any 320 acre drilling unit. So you can multiply that total number by 3 to 5 times.
Lots to think about - and assuming that operator will be 100% successful in any drilling operations.
Wow, that is a lot to think about! I really appreciate those insights!
I did find a sentence in the royalty payment section that states "Lessor shall not have to bear any of the usual and customary costs of producing, gathering, treating, and storing oil or gas production. "
Does that satisfy the intent to make this a "cost free" lease?
My neighbor is going to get a lawyer friend to look at his lease tomorrow, so I may know a little more after that. I'm waiting for feedback before contacting Walker.
Thanks again for the great information. This whole process becomes a little more understandable when put into dollars and cents!
No problem, glad I could help. The concept of "time value of money" comes into play big time here. Plus "mail box money" that may be on the low side but consistent over many years.
The clause you mention should suffice to make this a "cost free lease" but I am not a lawyer so please take that into consideration.
Hopefully the lawyer will give you some good input tomorrow.
Good luck on all this!
As a follow-on to previous comments, I have found out from the broker that he is trying to collect leases in our area for Apache Corp. Only three of my four neighbors are interested in leasing, so we have only about 93 (surface) acres among us and none of us want to host a drill rig on our property. At my request, the broker has agreed to ask an oil company rep to accompany him to a meeting with us next Friday so we can ask questions. We are obviously concerned about the oil company intentions and what conditions they are willing to accept, both monetarily and otherwise. I am looking for questions we need to ask them. Any suggestions?
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Interesting to see Apache leasing to do more drilling - they were a very active player in this area in the past but have geared down for the most part in recent years. They do have a lot of old wells that are holding acreage throughout this area.
Questions to ask????
In no priority order:
- Target formation
- Vertical vs horizontal (probably Hz)
- Horizontal length planned
- Drilling / Production unit size
- Lateral orientation (e.g. NW to SE)
- Working interest partners
- Who operates (Apache or partners)
- Size of surface location while drilling
- Time needed for drilling and completion
- If well to be frac'd, size and location of frac pond
Those are my early thoughts on this.
Good luck as to this meeting!
Thanks, Rock Man! I’ll report back what we find out!
My neighbors and I met at my house with Mr. Tom Walker, President of Walker Land and Minerals. Although the Apache Oil Co. representative could not make it, Mr. Walker was very forthcoming in answering all our questions. The three neighbors only have a total of 93 (surface) acres of land, and none of us want to host a drill site, so specifics of the surface location were not discussed. Even so, Walker said that he would continue to look for an existing drill site in the area that they could use to drill in horizontally, so he expected that Apache would still be interesting in our leases.
Walker told us that most of the land in this part of Brazos County is already under lease, so our "production unit" should be fairly small, as the unit needs to consist of contiguous parcels. (True? I don't know). He also said that Apache would indeed be the "operator" and would probably opt to drill for the Austin Chalk first. However, they would have the option in the lease to access Eagle Ford Shale or anything else at other depths. Under the surface limitations we offer, we assume it would be to our advantage for Apache to drill at whatever depth is most productive.
I think we all came away with the idea that the only thing we would probably get out of this would be the bonus money. Walker emphasized that possibility, and carefully explained that with just 12.5% of our mineral rights on small amounts of land, our production royalties would likely be very small under any circumstance. Whether that was just good salesmanship or an honest assessment, I couldn't say, but it sounded reasonable.
You can add a provision in the lease that your surface will not be used for a well pad, pipelines, roads or related activity. Given that you only own own 12.5% of the minerals, your surface use is very important for you. Without a specific clause prohibiting surface use or limiting the well to a corner or other spot and roads to the edges or to existing roads on your property, you will have no control over your surface. You will have a problem even if you do not lease as Apache will get the other 87.5% of minerals under lease and be able to use the surface at will. So maybe leasing will help. And be sure to state that any use of water is to be paid and cannot be taken for free.
You must change the royalty clause to delete the phrase "market value at the well" if you do not want to be charged expenses. The Texas Supreme Court has held that the term "market value at the well" means by its very definition, the market value at the point of sale less all costs back to the well. This includes transportation, gathering, processing, marketing, etc. Ask for the royalty to be something like the market value at the point of sale to an unaffiliated entity. This would also jump over any below market sale by the operator to its affiliate and let you be paid the ultimate sale price. Then the cost free language will be effective. See Heritage case in 2015.
Thanks, TennisDaze!
I'm always interested in insights from those of you who have detailed knowledge in this area, because from personal experience in other areas, I never trust the tricky legal wording!
That said, I am looking at wording from one of the proposed leases which says:
"Royalties on covered minerals produced and saved from the leased premises and used off the leased premises or lands pooled therewith or sold (whether to an affiliated or non-affiliated purchaser), shall be paid by Lessee to Lessor as follows: (a) For oil and other liquid hydrocarbons, the royalty shall be 20% of the market value at the mouth of the well of such production."
That said, a later entry specifies:
"Lessor shall not have to bear any of the usual and customary costs of producing, gathering, treating. and storing oil or gas production."
Does that eliminate the concern you identified about establishing the value for royalty purposes? Of course the comment about sale to an affiliated purchaser needs to be dealt with.
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