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Permalink Reply by jffree1 on July 9, 2010 at 2:11

"If the O&G fails to continue with their in-fill production of your unit, then the lease terminates at the end of it's primary term".

Wouldn't the lease terminate when the failure to develop occurs... sometime after the end of the primary term? I mean, the lease gives them three years to realize production on your land or any land pooled with yours, assuming your primary term is three years with no option to extend.
That sounds nit-picky but how would you get an operator to agree to a clause that could, in effect, cause the termination of the lease if they produced a well in the first year of the term and failed to further develop within the three year term?

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Permalink Reply by DJG on July 9, 2010 at 4:25

Jffree1,

Not "nit-picky" at all. You are, of course, correct.

The lease would terminate at the time when the O&G fails to comply with the terms of the continuous production agreement.

For instance, if the terms of your Continuous Production clause dictate that in-fill wells continue at a rate no later than 3 years after completion of each prior well then the clock would begin ticking based upon the reported completion date of that previous well.

The O&G would then have a three year period to begin operations for the next well. If they do not get that well started prior to that date then the lease would become void.

If they do continue with well #2, then the three year clock gets reset again based upon the completion date of well #2.

Hope that makes better sense then what was stated in the previous post.

For our own lease, we tried to get the O&G to agree to a 2 year period for this clause. They initially said no-way, and that they would not include this clause whatsoever.

We stated that it was a deal-breaker clause for us and they then came back and said they could agree to a in-fill production commitment of a least one well every 5 years.

We, in turn, said no way to their proposed 5 year period, but said we could agree to 3 years. We eventually agreed to a compromise scenario and met in the middle and resolved the time-period of at least one well for every 4 years.

I would imagine that your negotiating power to keep the time period shorter would greatly improve based upon the size of your tract.

Ideally, I would have liked a shorter period, but am pleased nonetheless to at least have the clause in place.

My own sense is that if the O&G agreed to be bound to every 4 years in writing then it is likely that back in their war room then that they do actually intend to develop at a faster pace than what they have committed themselves to on paper - otherwise, I don't think they would agree at all.

In any event, even though we ended up compromising to a longer period then what we were asking for, the clause as written does protect us from a situation where the acreage would get HBP for decades on end with little or no in-fill production.

Permalink Reply by Marc Stepman on July 9, 2010 at 3:04

Very good advice here. I think any landowner would be wise to include this in his or her lease.

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Permalink Reply by Henry on July 9, 2010 at 4:29

D. Garr,
Can you help me understand? If the company doesn't drill the second well, and the lease terminates, what is the status of the first well? It is still producing -- is it's production still governed by the now-terminated lease?

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Permalink Reply by DJG on July 9, 2010 at 4:40

Correct, any wells that have been drilled while your lease was valid, would be bound by the terms of your initial lease.

Permalink Reply by Dion Warr, CPL on July 9, 2010 at 6:21

Led:

I'll agree at least in part with Henry's post above, as it addresses the issue of duration of production versus the time value of money (which by inflation always means that the further you project out into the future, the present-day dollar's worth of production is worth less than the the dollar that one realizes tomorrow, next month, or next year, much less 30-40 years) but would also point out that the purchase of royalty still contains some speculative value. Actuarily, most assumptions made by royalty calculators fail to project the risks and implications of subpar well performance, wells taken offline as necessary for extended periods, etc.

There are many valid reasons that mineral owners sell royalty that have nothing to do with being ill informed or under some sort of financial strain. Many sophisiticated landowners hedge against possible future returns as a means to raise short and moderate term capital. Should the individual seller be wary of unsolicited offers? Sure. Should the individual seller be aware that their options to seek redress from royalty purchasers out of the consequences of a subpar sale are extremely limited? Absolutely. But unless or until individual owners can 'borrow' against their 'minerals in place' as a tangible asset in a reasonable way, one of the best ways for one to convert one's minerals in place into cash is to sell them within the marketplace.

There is another uncertainty that still lingers within the royalty sector, which is the lack of extended production data in the Haynesville Shale area. Yes, there is a great deal of information that be gleaned from the first six to twelve months of production, but the 'tails' of cumulative production which follow the steep declines of the first production runs (say, out to years 3, 5, and 10) have not been established. Can the industry look to the Barnett history as a guide? One would think so, but there's no proof in the pudding quite yet in the Haynesville, and a slight steepening or flattening of that portion of the curve can significantly impact the projected EUR's for these wells, and this uncertainty represents a real risk in every productive well, regardless of its IP or optimal or suboptimal operation.

Does that mean that I would advocate someone cashing a $250 check they receive in the mail as a "down payment" against the purchase of their minerals or royalties, and execute a "and we'll do the rest" trade on some portion of their minerals? Absolutely not. Such a transaction is worthy of more consideration (notwithstanding monetary consideration) than an exchange by mail.

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Permalink Reply by ledlights on July 9, 2010 at 9:15

Dion,

I can't prove what is only a personal (and not fully researched) impression, but my sense is that the majority of royalty purchasers are more than adequately hedged against risk. Often they are buying existing, proven production from multiple geological zones. And there are many other ways that they can use diversity in their investments to hedge against risk. I would not be surprised if they do not have ultimate fall back tactics such as reselling mineral interests to mineral producers. One of the aspects of the shale play that must make it particularly attractive to royalty purchasers is its character as a resource play with a very high percentage of ultimately producing wells.

Do you buy an extended warranty for your new computer from BestBuy? Not me... I would only do it if I considered the expense trivial and was not capable or willing to reduce my risk from computer failure in other ways. The warranties that BestBuy sells are ridiculously overpriced in terms of the instances of failures that they are insuring against. BestBuy could simply replace every computer that they provide an extended warranty for and they would still be making a nice profit from their warranty business. I know - this example applies to a simple business where the risks are much more uniform and way more easy to accurately calculate than the risks in mineral recovery. But it is still an example where common practice has made it acceptable to charge way more for "insurance" than is justified by the risk involved.

My contention is that royalty purchasers take all of their known risks, add a factor for unknown risks and are still adding a nice (excessive?) safety buffer in their initial offers. Can anyone refer me to any posts that have described negotiations with royalty purchasers where a mineral owner has attempted to pare down some of the wiggle room purchasers may be building into their offers? We spend a lot of time around here trying to help each other with what the market will bear in terms of lease offers. And D. Gaar has provided an interesting suggestion for protection from indefinitely delayed infill. Can someone provide a little more information about reasonable bargaining tactics in royalty purchase negotiations or accounts of attempts at such negotiation?

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Permalink Reply by Dion Warr, CPL on July 9, 2010 at 10:17

Led:

All valid counterpoints. Just keep in mind that just because a royalty accumulator has hedged risk within its portfolio with 'known quantity' conventional production or prospective conventional revenue products does not translate into higher prices for this particular reservoir, anymore than it would change the risk assessment on a single coin flip if you had known that you had flipped tails the previous thirteen times in a row. If one were to start employing such methods, one runs the risks of the fallacy of 'playing on house money', in which the player casts successively riskier bets based upon an increased tolerance for risk in believing that "they are ahead", and by doing so decrease their short term and cumulative performance by repetitively overbuying into riskier odds.

By those conclusions, I share your belief that each sale (or bet, or purchase) must be evaluated separately for ROI, risk, and outside circumstances, I'm just getting there by a separate result, and to a separate end. To discuss your analogy as extended warranties, when I was first starting out in the land business, making less money and spending more time on the road, I purchased extended warranties on my work vehicles which provided for cost- and hassle-free (or at least minimal) repair, replacement, or loaner. Why? I was less risk tolerant to a major repair which might have occurred between 36K and 100K miles which might prevent me from being on the road, earning income. Now that I earn more, have more disposable income with which to both plan and save, I no longer subscribe to the practice. But for a time, this was assessed on per vehicle basis.

As a final note, although I feel confident that you are aware of this, I would submit that at the individual owner level, in dealing with most of the larger operators, the lease negotiation and the royalty purchase negotiation would be wholly separate events. Thus, it would be improbable that the negotiation of one would necessarily translate favorably into a higher negotiated price on the other, at least not in any significant premium would be paid on royalties derived from leases whch contain such an infill provision. IMO, it would be the equivalent of negotiating the price of apples, then during the negotiation of the price of oranges, throwing in that you also grow dates. Not that dates are worthless, but your buyer is there to buy oranges. I would submit that D. Gaar's provision would be good for you, and by extension good for them, but I don't believe that it would mean that they would be willing to pay more for it, because it is not be a factor that is usually tracked. To go back to the fruit analogy, the orange distributor does not usually move dates and does not track dates, thus, what is the fact that he has dates really do for him as an orange distributor?

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Permalink Reply by ledlights on July 9, 2010 at 12:22

My interpretation of D. Gaar's point was that he was trying to address a mineral owner's concern about the timeliness of a lease's royalty payback which might otherwise be one factor influencing some owners to consider selling their royalties for more immediate reward. Otherwise I did not infer any other connection between the 2 different transactions.

Permalink Reply by Dion Warr, CPL on July 9, 2010 at 12:44

Led:

Ah, good.

Permalink Reply by Marc Stepman on July 8, 2010 at 12:13

Thanks for the formula. It should help

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Permalink Reply by Jack Blake on July 9, 2010 at 0:58

Jack Blake says, "Has anyone received a decent royalty check"?

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