Relationship between Lease Bonus and Mineral Rights Value

Relationship between Lease Bonus and Mineral Rights Value

By John B. Gustavson, Certified Minerals Appraiser #1992-1

Lease Bonus Method for Conventional Oil & Gas Rights

The Lease Bonus method for conventional[1] oil & gas mineral rights[2] has been observed in the market and in literature[3], [4], [5] since the 1990’s and possibly earlier. In its simplest form it provides an estimate of the Fair Market Value of a landowner’s oil & gas mineral estate under the assumption that the Highest & Best Use is for the leasing and exploration for oil & gas. The Lease Bonus method is therefore applicable during the early stages of an oil & gas play.

The method is reliable when lease terms such as front-end bonus, annual rentals or paid-up bonus, primary term and royalty rate are reasonably uniform in an area. When applied to conventional oil & gas plays with a distinct petroleum system (separate source rock, reservoir rock, etc.), the FMV of unleased oil & gas rights is reliably estimated by multiplying the current lease bonus amount in dollars per acre with a factor of from 2½ to 3.

If the subject property were already under lease, the Appraiser may account for this negative fact[6] by using the present worth of the future bonus.

The Lease Bonus method works similar to a discounted cash flow approach from the landowner’s standpoint. When the Highest & Best Use is for the leasing and exploration of the oil & gas rights, the landowner exercises his executive rights (a defined portion of the oil & gas estate) and receives income in form of bonuses and rentals[7]. Even if no drilling and production were achieved until way out in the future or never, the landowner nevertheless could renew the leases or lease to different oil companies after the primary term and extensions expire. This sequence can be repeated, even allowing a market-observed hiatus between lease cycles to reflect sluggishness in the leasing market.

The similarity with the DCF approach is apparent. A simple cash flow forecast with a reasonable discount rate from the market for calculating the net present value to the landowner will yield an FMV similar to the one seen from this Lease Bonus method. Typically, 3-4 lease cycles over about 20-25 years provide an excellent reality check on the rule of “2½ to 3 times the bonus”.

Lease Bonus Method for Unconventional Oil & Gas Rights

As noted above, the unconventional oil & gas mineral rights include those that are being produced from horizontally drilled wells in shale formations. A change in the relationship between the bonus (now a larger paid-up bonus) and the Fair Market Value of the oil & gas mineral rights has been noted in the market. The multiplier is now 2 times the bonus amount to estimate the Fair Market Value of the mineral estate of early-stage acreage.

The reason is the larger bonus amounts willingly paid by the oil companies. From an oil company’s perspective, the so-called “shale play” start out with the need for a very large land position, because an oil company does not yet know exactly where the “sweet spots” are located. The shale varies greatly in its capability to produce. The oil company must therefore secure plenty of land on which to explore and improve its focus. It must therefore also control the lease rights to move laterally as early results come in.

Such plays are also called “resource plays”. While the shale may be in existence under even county size areas, the shale may not be amenable to horizontal drilling and to frac’ing and other requirements for economic flow. Therefore, petroleum engineers will not name potential oil & gas from such shale as reserves, but only as resources.

In short, the oil companies need the acreage and will pay. Likewise, the landowners also want more money up front. A landowner already knows that just leasing his land to an oil company does not guarantee drilling and royalty income from production, not to mention the numerous development activities, which must precede royalty payments (see Table below). The landowner will therefore insist on more money up front instead of waiting for the uncertain royalty.

1. Land position under control, with possible Shale geological potential

2. Land position under control over Shale with proven potential

3. “Sweet Spots” for oil in lieu of gas anticipated from surveys or sampling

4. Oil shows identified from vertical drilling intersections

5. Delineated Shale prospect for horizontal drill test

6. Permitted prospect for horizontal drill test

7. Unitized land position for horizontal drill test

8. Spudded and surface-cased drill test

9. Drilled horizontal drill test

10. Frac’ed and completed horizontal drill test

11. Producing single leg of horizontal drill test

12. Producing multiple legs of horizontal drill test

The combination of these market factors leads to larger bonus payments for the unconventional oil & gas leases. And with larger bonus payments it follows that the multiplier with which to estimate the FMV of the actual oil & gas mineral estate at these early stages will be smaller. Examples have been observed from the market where the leasing oil company has offered a landowner to choose between one bonus amount for a lease and the double amount for outright sale of his mineral rights. Thus, the FMV for the latter would equal 2 times the offered bonus.

Additional support for the multiplier of 2 toward FMV estimate of unconventional oil & gas rights at early stages of exploration comes from recent literature[8].

Limitations of Lease Bonus Method

With either conventional or unconventional oil & gas rights the lease bonus method loses reliability as the maturity of the activities (the Highest & Best Use on the Effective Date) increases from early exploration to development drilling and production. One reason is that the availability of unleased acreage will have drastically dwindled. Once production has been established in an area the acreage is rapidly leased up, and it is rare to find unleased acreage.

If ever found, a landowner holding any unleased mineral rights would look to the potential income from near-term royalties as his primary guide to value rather than to a signing bonus[9]. The DCF method may be reliably used by the landowner to estimate the FMV of his future royalty income, because the income is “reasonably likely in the near future”[10].

It is noted that the FMV of the mineral rights thus estimated is likely arrived at by a much higher multiple of the offered lease bonus than observed for early exploration leases. An offer for Niobrara shale acreage in Colorado gave a choice to the landowner between $500 per net acre as a lease bonus for a 3/16th royalty lease versus $1,900 for outright purchase of the mineral estate[11]. That is a multiplier of 3.8. In this case the local area had already seen Niobrara testing and development and the operator had commenced construction of a horizontal drilling and multiple-well production pad.

It is concluded that the lease bonus approach is reliable for both conventional and for unconventional oil & gas mineral rights as long as the acreage use is in the early exploration stages. At later stages and among producing properties any unleased acreage may be worth 3 to 4 (or more?) times the bonus offered. A more reliable method may be to run a discounted cash flow model, calculate a Net Present Value for the royalty stream and risk it by a probability factor for coming about at the predicted quantity and commodity price in the near future.

John B. Gustavson

Certified Minerals Appraiser #1992-1

[1] The term “conventional” is used here to denote oil & gas being produced from vertically drilled wells with classical completion technology in contrast to “unconventional” oil & gas including that being produced from horizontally drilled wells in shale formations.

[2] The term “mineral rights” is herein used interchangeably with the term “mineral estate”.

[3] Widlund, Douglas S., 1996, Evaluating Minerals In Condemnation Cases, in Land And Permitting II, Chapter 2, Rocky Mountain Mineral Law Foundation, Westminster, Colorado, January 1996.

[4] Moritz, Edwin C., 1997, Techniques for Valuing Acreage with Unproved Oil and Gas Potential, Society of Petroleum

Engineers, Hydrocarbon and Economics Symposium, Dallas, Texas, March 1997, SPE Preprint 37950.

[5] Castleton, John, 1990, Determining Fair Market Value of Oil Interests Is an Art, Trusts & Estates, 129, 2. January 1990.

[6] It is negative from an appraisal standpoint, because the lease bonus has already been paid to the landowner. A bonus cannot be expected again until the lease and any renewal terms have expired, usually a 5 to 10 year waiting period. An Appraiser may discount for that negative factor by using the present worth instead of the current lease bonus, calculated over the years of waiting for the next payment and with a discount rate commensurate with a landowner’s Weighted Average Cost of Capital (usually 3-4 percentage point lower than the extractive industry’s WACC).

[7] Historically, a large front-end bonus was paid to the landowner to be followed by annual rentals, the latter usually very small and less than five-ten percent the amount of the bonus. Recently, so-called paid-up bonuses have been noticed in the market, which include all future rentals in form of a lump sum added to the front-end bonus.

[8] Posgate, L., 2013, Methods of Royalty and Leasehold Appraisals, Issues and Comparisons in Several Cases; Soc. Mining Engineers, Annual Convention, Denver, CO, February, 2013 (abstract, slides and audio recording).

[9] It is noted that the mining in contrast to the petroleum industry frequently uses a compromise by paying the landowner “advance royalty” in lieu of a signing bonus, the former of which is deductible from ultimate production royalties.

[10] Reference is made to the U.S. Supreme Court decision in Olson vs. United States, 292 US 246, 255 (1934), which stated: “Either some existing use on the date of the transaction, or one which the evidence shows to be so reasonably likely in the near future [emphasis added] that that use would have affected its market price on the date of the transaction and would have been taken into account by a purchaser under fair market conditions.”

[11] Offer to Ms. Suzanne Nyhus for a 50% undivided mineral interest in 160 acres in Section 18, T8N R60W, Weld County, Colorado, dated February 2013, private communication.

2624-LeaseBonusMethodforConventionalOil4.doc (38.5 KB)

Very interesting explanation of what I have heard as a rule of thumb for some time.

Unfortunately I think it is far too variable and it's a judgement call even for what phase you think you are in. It also presumes, I think, that you would lease or not participate, thus selling a greater part of the value of 70% to 87.5% for a very low amount and that the value of your mineral acres is the residual of 12.5% to 30%. Admittedly, most people do lease, mainly because the laws are set up in most states so you could lose greatly if you don't lease but some states forced pooling laws will allow you a royalty while your production pays for the well, expenses and penalty so you need not lease at all and leasing could be greatly against your best interest. I would say that not being placed in the position of losing all if you do not lease would mean that you could require more for the purchase or lease of your acres.

This formula, X times lease bonus may work in many places but I would not use it in North Dakota, Montana or Colorado to name but a few states.

You are correct in all your points. Unfortunately, even in North Dakota, Montana and Colorado (and other states) we, minerals appraisers rarely find sales of outright mineral estates on a stand-alone basis. Therefore, we are forced to look at the observable market, namely lease bonus payments and then do our best to work from there. To be safe, I recommend using this method only, if the local area is a uniform, settled leasing market with little actual drilling, not to mention any nearby production.

John Gustavson

Let me provided you with an actual example and see what you might conclude.

lease offered after completion of, and after first production. ($2,000nma 20% royalty.)

lease offered again after 100,000 barrels produced in one year, but prior to 2nd well being spudded within 60 days.

Could you, using your formula or any other method of appraisal, guess how much that new lease offer would be? or should be?

Hi Andy: I am slightly confused over your example, but I assume that you are talking about an unleased area NEXT TO a producing well. If not, the following may not fit, but read it as a general note:

The example, which I assume, is most likely to be acreage for a so-called Proved, Undeveloped Offset well (subject to a detailed look at the immediate geology). The $2,000 bonus per Net Mineral Acre would now likely be at least $5,000, maybe higher.

But wait, more importantly, for such a Proved, Undeveloped well the over-weighing value lies in the near-term ability of the new well to produce Non-Participating Royalty Interest (in contrast to income from the permanent Executive Right to lease out the acreage). That NPRI (if assuming a 20% lease and the 100,000 barrels per year) would amount to (0.20 * 100,000 * $80/barrel), namely $1.6 million for the whole horizontal drilling spacing unit.

These spacing units vary, but let us assume 200 acres and that you own the whole 200 acres. Then your first year's income from the NPRI would be ($1,600,000 / 200), namely $8,000 per acre. The next few years would add to that, maybe $5,000, $3,000, $2,000 per acre and so on, now slowly going down. An impressive cash flow, even when discounted back to Net Present Value.

We can now compare the results of the two methods.

The Fair Market Value of the Mineral Estate would be, say, 3 times the bonus (of $5,000), namely $15,000 per acre, if we use the Bonus method. You would want that amount, if you sold your mineral rights.

The FMV may be, say $20,000 per acre, if we use the Discounted Cash Flow method and sum up the discounted annual income shown above. But we must discount a little more for the risk that the well actually would be spudded, drilled, completed, find a pipeline and would be producing as expected. Let us say a 0.80 probability that all goes as predicted. That gives us a Fair Market Value of $16,000. You would want that, if you sold your mineral rights.

I would personally rely most on the DCF approach in this case, because the use of the acreage was so close to production in time and space. But I would also look at the leasing market and at the bonus variations. In your case the market is probably not settled down, so the bonus method is less reliable.

A landowner must also consider whether he should lease or sell at all. Maybe in this case he should consider going "non-consent" and let the State force-pool his acreage. In some states this is not good, because the state may allow the operator to recover a whopping 3 times his costs of drilling. In other states this factor is TWO times the experienced costs.

Finally, in your example the landowner might consider "participating" in the well as a Working Interest Owner and pay for his share of the well. A well might cost $7-8 million, but at 100,000 barrels the investment would be recovered in the first year. And the rest of the years would be pure profit on 20% of the income and income less operating expenses on the remaining 80%.

Final Answer to your question: If leasing under those Proved, Undeveloped Offset conditions: go for $10,000 per acre.


John Gustavson

Certified Minerals Appraiser

I'm not sure if this will change any of your math...but I did mean a lease offer for a producing well...I also mean a lease offer from that operator after the 100,000 barrels, after going non-consent. They most likely need to offer a lease every time they plan on spudding a new well in that spacing unit, which is 1280 acres.

What I am hoping is that your method is, or could be accepted, as a "standard" model for determining whether or not a lease is offered in "good faith." I will provide the lease offer after you have a chance to re-evaluate if in fact you came up with the numbers based on "Next to" acreage. I assure you this is acreage being produced, non-consent on first well, 100,000 barrels and will be one year this May. Not sure if this will change the math, but if it does, I sure would like to hear it.

Let me think about this situation overnight.

John Gustavson

I happen to know a little about Andrew's situation. Andrew was understating the case, being unleased ( non consent), with his first well producing 119,028 bbls in ten months and at that I think the operator is not operating Andrew's well at it's maximum safe rate because it has no pump and his production increases by 50% for a month or two and declines to the average the month after on multiple occasions. Andrew is also waiting on the imminent drilling of his first Three Forks well probably to be followed by more of both Bakken and Three Forks. From what I understand, the operator was offering $2,000 per acre while state acres nearby were leased for over $10,000. I believe the operator is still offering the chance to lease and has increased their offer by $xxx, so evidently they feel that 80% NRI in the Three Forks is only worth $xxx per acre, which makes me wonder if the operator leased someone with significant acreage with a most favored nations clause, or if possibly it would just hurt their pride to let a mineral owner drive a hard bargain? Either way, I think they made a poor business decision.

Andrew, I hope you don't mind this post, I tried to keep it within what you have already posted, adding my suppositions, and no the production is not a missprint, production for Feb dropped back to 7,446.

My operator is a sweetheart too, they would still allow me to lease, with a bonus larger than Andrew is offered and I would get 4% more royalty right now in exchange for 80% NRI. Of course I have 6 wells with that operator, 4 Bakken and 2 Three forks, all appear profitable with the best well to date at 215,500 bbl oil in 17 months, and the latest well producing 24,000 bbl in the first month. My answer to the lease offer was no, they asked me to reconsider so I waited three seconds and said no again.

Interesting to hear of these "problems". The best solution may be to get other lease offers from as many small would-be oil companies as possible. Some are flush with money from investors, which they must spend now, and they can be expected to pay the highest combo of bonus and royalties.

John Gustavson

Thank's for the reply Mr. Gusravson. I don't really see this situation as a problem anymore, as we are poised to make as much off our oil as a mineral owner could without participating. I am baffled though by the operators inability to open their wallet when dealing with mere mineral owners, even when it would be greatly to their profit mid and long term.

If the owner has a good idea of what the property is worth, it should not matter whether the owner is an oil company, speculator or ordinary land/mineral owner.

I consider it a truism that an operator can't make the money he wants if he can't lease the acres, at least it's true in North Dakota.

I was thinking the best solution would be to develop a persuasive argument in order to convince the NDIC that they could not in good conscience, grant the operator the risk penalty that they have viewed as automatic and built into their business model.

If I did lease at this point, what happens to the nearly $100,000 the operator has kept of my oil revenue in order to recover their cost for carrying my share?

I have done a really crappy job at communicating, so my fault.

What I am looking for is your opinion on what the minerals would be valued at, for the purpose of leasing, with the set of facts presented. I intend to use this information to see if it will strengthen or weaken my position when I challenge the risk penalty(s) Ideally, you will use your method, with my information, come up with a range that you consider "fair market" and come up with a number that is "ridiculous" to even consider.....for example if I offered to buy your 2010 Benz for $10. That would not be considered, by anyone, to be a "good faith" offer.

The info again: I control the fate of 80nma in this spacing, I own 30 of it, 10 of it is participating. All the rest is being carried. (confusing maybe, but it might change your math when there are 80 acres as opposed to something like .25 acres.

As Mr. Kennedy pointed out, this well has produced 119,000 bbls in 10 months. Another well to be spudded any day now...........spacing is 1280........if nearby production is important then there are 2 good wells in the 1280 spacing to the East and one decent one on the 1280 to the west......all 6 sections are operated by the same operator.

Actually the total is 90nma 80 of them are carried, so I have been receiving the 16% royalty. The other 84% they keep.

If there is additional information you need to apply your formula let me know......also, if you don't feel like bothering that is ok too, I don't want to make you feel like I expect you to do something.....why don't I use your formula?........frankly, I don't think I understand it well enough.

Hi Andy:

At this point I recommend that you do not use any rules of thumb. There is enough factual information about and around your property to technically and financially model the various scenarios, and for you to select the best for your personal situation.

The market based on bonuses is too irregular for your situation. I reported originally on my observations regarding the multiple to use with a local lease bonus to estimate Fair Market Value of a mineral estate. That still works reasonably well in the very early exploration stages. However, you are in the other end of the spectrum, namely at or close to the production stage.

To show the lack of reliability of the market, I just talked with a landowner in Logan County, Oklahoma. There is a new horizontal play there. He reported that he had received offers to lease for $350/acre (3/16 royalty) or to sell for $2,000/acre! That is a multiple of SIX! I have not looked into the details, but that reflects a very unsettled market.

I am currently working for another client in Divide County. Similar problems. And I just finished another job (Niobrara fairway in Weld County) in Colorado, and it is too early to draw conclusions. I am doing Utica shale appraisals for landowners in Ohio.

So, don't use multiples of lease bonus, when production is close. Get a petroleum engineer (and possibly a geologist, too) and model the various potential outcomes.

Good Luck!

John B. Gustavson

Certified Minerals Appraiser