Section 23-2N-4W Mineral Acre Valuations

I’ve been helping someone apply for Medicaid, but mineral rights are causing some issues. They have an interest in mineral acres located in several sections of Stephens county, and we believe DHS is way-overvaluing them, especially given the current economic situation. They’re valuing the non-leased/non-producing mineral rights based on the current average lease bonus in Stephens county, which they have as $404/acre. Could anyone tell if this is current?

The acres in section 23 are leased and producing, but production has dropped significantly since 2015. They’re taking the average monthly yield from the past 6 years are figuring approx 2.33 mineral acres are worth $29,000 if sold today. (Monthly return to the owner is currently only $250/mo on average). I apologize if that’s not much to go off of, but does that valuation sound accurate?

Thank you to anyone who can help! I’m very new to mineral rights, but I’ve appreciated what I’ve already learned from these forums over the past few days.

If you list the section, township and range of each properties, we may be give more current leasing amounts. Also,you may be able to get an engineer to value the properties based upon current pricing and decline curve analysis which is much more in line with today’s value instead of high production and high prices from six years ago. If that was a horizontal well, then its value has dropped quite a bit. I will take a quick look at this posted S-T-R for activity.

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Thank you for the quick reply, M_Barnes. I appreciate the advice. I’m unsure if they are horizontal or vertical, but I’ll see if I can find that out. They are valuing all of these combined at just under $30K. Section 23-2N-4W approx 2.33 acres (leased and producing)

Section 20-2N-5W 1 mineral acre

Section 9-2N-4W 1 mineral acre

I am not licensed to give exact values, but I can give activity and some comments as to how I would approach it. Do you know the royalty rate? The leasing rate will vary by the reservoir geology, so I would not use a generic rate for the whole county unless I had to. I would use a local rate from the public pooling orders in the contiguous eight sections around the center section within the last 12 months. There are quite a few horizontal wells in those sections, so they probably need an engineering evaluation on the producing sections.

Section 23-2N-4W** approx 2.33 acres (leased and producing) Horizontal wells. Lease rate no longer valid since wells have been online since 2013 and will probably last for decades at low rates. Does the owner have her Division Order paperwork? This section has quite a few multi-section wells-one set to the north with section 14 (Boles) and the other section to the south into 26& 35. The McClelland wells are not perforated in section 23 though.
Boles 1H-14X-37.0144%, 2/12/13 active date on the OTC site, so close to first sales.

Boles 2H-14X-64.9853%, 2/28/14

Boles 3H-14X-66.3366%, 8/25/14

Boles 4H-14X-64.8813%, 8/28/14, well essentially dead

Boles 5H-14X-66.6019%, 8/28/14

Boles 6H-1X-64.7473%, 8/28/14

Clarence 1H-23H-100%, 5/26/15

Section 20-2N-5W 1 mineral acre- no leasing in the section since 2014. Last poolings in contiguous sections were back in 2015. Sec 17 $2200 1/8th, $2000 3/16ths, $1500 1/5, $0 1/4th. (9/3/15 order oil prices at Cushing according to were $45.48 for Henry hub gas prices 2.66 prorate down to today prices.) Sec 21 $2252 1/8th, $2000 3/16ths, $1500 1/5th, $0 1/4 (8/4/15 order oil 42.87/bbl, gas 2.77/mcf prorate prices to today. Sec 16 -same (order date 7/27/15 oil $50.09/bbl gas $2.84 pro-rate down to today’s prices. Horizontals never drilled so value would be even lower since no proved production in the 9 block area. Cushing prices are lower than WTI. WTI today was $24.84 and gas was $1.88, so oil is roughly half of what it was back then and gas is about 2/3 of what it was back then.

Section 9-2N-4W 1 mineral acre (leased and producing)

Wright 1H-9-100%, 6/30/12

Wright 2H-4X-66.1654%, 4/7/14

Wright 3H-4X-65.7888%, 4/7/14

Wright 4H-4X-65.5993%, 4/10/14

Wright 5H-4X-65.8004%, 4/14/14

Wright 6H-4X -66.824%, 4/16/14

Virginia 1H-4X~56.9189% 5/21/15

Horizontal wells give up about 50-80% or more of their volumes in the first four years of production. These wells have been online for varying years since 2012, but they have given up quite a bit of their value, so I would protest using the last six years of production to predict the future. That might have worked with vertical wells, but not horizontal wells. The rule of thumb for vertical wells was about four years of oil and seven years of gas if prices were stable. The decline curves of horizontal wells are very different.

The equation for royalties is net acres/spacing acres x royalty x % perforations in your section. So each well listed above will have slightly different DO decimals.
For example. Boles 2H would be 2.33/640 x royalty x 64.9853%.

If I were going to get a more rigorous answer, I would get a certified reservoir engineer who work up each well and based upon the decline curve of each well, the estimated economic limit for the well and the current prices would be able to give a close estimate of what each well is worth and roll it up to the section level and then to the acreage level and project out the future I did a quick look and the Boles and Wright wells look like they have given up about 75% of their predicted values. So I would not use the last six years to predict the future since only about 25% of the value is left. (Quick look by a geologist, not an engineer, but gives you a ballpark idea) Hope this helps a bit. Maybe one of the reservoir engineers on the forum can give an opinion.

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M_Barnes you are an angel for giving all this info!

They have an interest in each of the Boles wells, Clarence also. These are the wells that are really putting them above the resource limit for DHS. Here are the royalty rates I could find. I did see that Boles 4H-14X has not produced since 2018.

BOLES 1H-14X 0.016869%

BOLES 2H-14X 0.029621%

BOLES 3H-14X 0.030236%

BOLES 4H-14X 0.029573%

BOLES 5H-14X 0.030356%

BOLES 6H-14X 0.029513%

CLARENCE 1H-23 0.045574%

Based on the royalty equation you provided, am I calculating the royalty correctly for Boles 2H-14X? 2.33/640 x .029621% x 64.9853% = .00007

Since we’re trying to determine the current value (as if they were being sold today), I’m also trying to understand how to calculate the mcf/bbl for a well. I’ve looked at some of your other replies in similar forums, which has helped greatly! Is this something that is predicted when the well is being drilled? Or is this something an reservoir engineer would need to look at? I see that you said the Boles wells had given up 75% of their predicted values, so I’m wondering what resources you’re utilizing to get that figure.

Again, thanks much!

no, not quite right. I think those are division order decimals. Where did you find those numbers? What document? They do not look right for 2.33 acres. Do you know the royalty amount? 1/8th (.125), 3/16ths (.1875), 1/5th (.20) Is there a lease or a pooling document? Was there a sibling or more? it looks like there may be about half that acreage. Is there just a bit over 2.33 acres in your original thinking. I need the rest of the decimals if you have them.

If I use the Clarence well since the math is easier, this is what I get that almost matches what you found.

2.33/640 x .25 x 1.0= 0.00091016 If I divide by 2, then I get 0.00045508 which is pretty close to the 0.00045574 which is what you have. That means either the acreage was split in half with a 25% royalty. Does that make sense?

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There was a sibling, yes. The mineral rights were inherited with each sibling getting half of the interest. It was originally a 7/60ths interest in the NE/4 NE/4 (40 acres total) of Section 23-2N-4W. Approx. 4.666667 was inherited, and then split in half. That’s where I’m getting the 2.33333 amount.

The royalty amounts I listed were pulled from the production breakdown attached with a recent check. They were listed under “Payment Decimal” which I must have misinterpreted as the royalty amounts. I’m unaware of another document which lists the royalty amount specifically. Mostly just going off a probate document and the production breakdown provided with the check.

Your calculations with the Clarence well makes sense though, so perhaps it is a 1/8th royalty since it’s divided in half?

The extra bit of acres makes it work at 1/8th.
2.3333333/640 x .125 =0.00045573 which is pretty close to what you have. The check statements decimal is the Division order decimal. So the royalty is 1/8th. That should work for the rest of them on the Boles and Clarence.

They would be 2.3333333/640 x .125 x each of their splits.

Back to your question about mcb/bbl. That is calculated from the stream of products that comes off of each well. They do a prediction before they drill in order to justify drilling. You can actually look at the stub and find the ratio using a bit of math. Look at the Clarence for February oil and find the same Feb gas (probably on the next statement) and do the math. mcf/bbl. A quick rule of thumb is 6000 cubic feet of gas per bbl. (6 mcf/bbl) The actual calcuation is done by BTU value. A reservoir engineer would give the exact measurement.

To get my ballpark estimates, I have a subscription service that can do quick decline curves and show predicted Estimated ultimate recovery and recovery to date. Each well was a bit different, but they came up to about 75% already produced. These are mostly gas wells with condensate (which shows up as oil on the statement). So for the Boles, the ratio is bbls condensate/mcf.

Just as a rough guide, if each the Boles wells were supposed to produce 12 BCF of gas and they had already produced 9 BCF, that would leave about 3 BCF left. If I guessed a gas price of 1.50/mcf, then that would be $4.5MM left gross. I would then use the decimal amount for each well for your acreage.
For example:
Boles 1 $4.5MM x .00016869=$759

Boles 2 $4.5MM x .00029621=1333

Boles 3 $4.5MM x .00030236=1360

Boles 4 dead, but some reserves remain. engineer would decide how to handle. Given today’s prices, they would probably not drill it again.

Boles 5 $4.5MM x .00030356=1366

Boles 6 $4.55 x 0.00029513=1328

Clarence 1-oil well with about 45% left ~135,000 bbls at $20 oil + about $2.7MM x 0.045574= $1230 You would have to calculate the condensate left for the Boles and the gas left on the Clarence, but just using the primary liquid, the numbers add up to about $7400 (over the next 50 years. You would need to do the same thing for the Wright wells. Who knows if someone will live 50 more years. Who knows what the price will be next week or next month? If you sold today, you would not get the full value of the production. Most buying companies buy on an internal multiple that they set. The values are all based upon the prices or oil and gas. I do not think it would be fair to evaluate on $50 oil and $3.00 gas in this environment. I do not know what the DHS uses as a guideline.

This is why it is good to get an engineer to take a close and more accurate look it the production. They have the correct software and access to the field costs. They can give a complete report with decline curves, discount factors, etc. using standard SEC guidelines.

I am just giving you a ballpark concept look. Do not take for gospel!

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Minerals can be non-countable (exempt) if they are valued at $6,000 or less. Valuations are tricky. Here is the synopsis of the rules from DHS:

A. The following are the formulas DHS uses to value mineral interests:

  1. Producing mineral interests: We use the gross amount of royalties reported on the most recent 1099 issued to the client. We are currently using the royalties reported on the 2016 1099s received by the clients in January 2017. If the amount of gross royalties owed is less than an amount required to be reported on a 1099, I ask the client or the caseworker to contact the oil company that owed the royalties to request the gross amount owed in the preceding year. I divide the gross amount of royalties owed by 12 to arrive at the average monthly payment and multiply that amount by 36 to determine the fair market value.

  2. Leased mineral interests that are not paying royalties: If a mineral interest is leased, but has never paid royalties, we multiply the gross amount of the lease bonus times 1.5.

  3. Mineral interests that are not leased: DHS subscribes to the U.S. Lease Price Report. It lists the low, high, and most common lease bonuses for most of the counties in Oklahoma and the United States. It is published six times a year. A one-year subscription is $270.00. The e-mail address is If the client has documentation that lists the number of net mineral acres he or she owns, or if we can obtain it from a landman or oil company that previously leased the mineral interest, I multiply the net mineral acres times the most common lease bonus reported for that county in the U.S. Lease Price Report. If the number of net mineral acres cannot be obtained, I multiply the number of surface acres times the most common lease bonus reported for that county in the U.S. Lease Price Report. I also use probate documents to determine the fractional interest inherited, if the client does not have documentation that shows the number of net mineral acres .

The client is advised that DHS will re-value a mineral interest if he or she can provide the following:

  1. Credible evidence that the surrounding mineral owners in that county recently leased their mineral interests for less than the most common lease bonus listed in the U.S. Lease Price Report for that county; or

  2. Information from a credible source, who is knowledgeable about the oil and gas industry in that county, that shows the lease bonus amount we used to determine the value of the mineral interest is incorrect; or

  3. The number of net mineral acres the client owns if that information was not provided when we valued the mineral interest.

B. A client can decide to make a good faith effort to sell his or her mineral interest for at least fair market value and the mineral interest will be exempt for an established period of time pursuant to OAC 317L35-41.1 (a) (1 ).strong text

A landman should be able to provide a valuation. Due to Covid and the Saudi-Russian price war it is likely that the typical methods listed above are no longer valid.

In the past I had a client who had minerals valued in excess of $6k. Those were reduced through gifting and using portions to pay attorney fees. However, this should only be done with an attorney who understands the Medicaid rules. It is also to structure an agreement to sell the minerals to a family member who takes back a promissory note. Again, the exchange and the promissory note must meet Medicaid rules.


Thank you Richard for the clarification!

I greatly appreciate both of your inputs! This was far more information than I expected to receive, especially so quickly. Regarding the DHS valuation rules, one issue we’ve had is that 6 years worth of royalties were inherited all at once last year after probate went through. So the 1099 for 2019 reflected production from 2013-2019. So they took the amount received in 2019 and divided it by the 76 months of production to come to the monthly average. Then then took that figure times 36 to come up with their valuation. Unfortunately this greatly inflated the current value as the production in 2014 & 2015 were significantly higher than what they have received in the past couple years.

I’m going to get with the owner about contacting a landman or reservoir engineer to get a clearer answer on the current value. But your ballpark estimations have definitely given us a great starting point!

Again thank you both so much. I’ve learned so much from this conversation!

If you can show DHS the last 12 months (as opposed to 6 years of production) you numbers should adjust. The DHS attorney who works with valuations is actually helpful.

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