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Permalink Reply by Skip Peel - Mineral Consultant on Wednesday

Niel, not that I am aware of.  There was some talk about estimated royalty based on bonus in the first year of the Haynesville Shale.  Over that year bonuses went from $250 an acre to $30,000 an acre and then down to $2500 an acre.  Some of the minerals leased turned out to be sub-economic and were discarded.  Chesapeake leased over 300,000 acres across LA and E TX in the north end of the fairway. They couldn't sell them to another company and had to write it off as a total loss.

Although it will always be a rough estimate, the better approach is to look at the production volumes of recently completed wells in close proximity, the number of future wells and make calculations based on the royalty fraction in the lease, any no cost language and the forward strip of Henry Hub natural gas prices.

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Permalink Reply by Hale Yayuh 11 hours ago

Something that people need to understand is that a very large percentage of the factors going into how much a company receives back (if anything) are uncertain. The oil biz is rife with uncertainty. You could have everything perfect (as it can be) going into drilling and they hit what mother nature put there and it's crappy rock. This is less so in these days of drilling shale as opposed to conventional (old days mostly) reservoirs but it still happens.

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Permalink Reply by Jesse Joyner 10 hours ago

True. You know your stuff, Hale.

But even with ubiquitous shale drilling, a fault can screw things up, as can a flub on a frack per the wireline going snafu. It's sorta rare, yet the unexpected can occur. A couple of years back, an operator drilled two wells (on our land) from one pad. One well completed and went into production. No problem. But its sister well had a wireline problem. Zero royalty. Stuff happens.

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Permalink Reply by Ryan Howrish 10 hours ago

The short answer is yes companies run full-field development economics, including land acquisition costs, before investing any capital (large or small).  Part of the economic evaluation includes an estimate of the royalties to be paid because they have to assume (or calcualte) their net revenue interest in every well included in the development model.  Depending on the size of the development area, the company may use a single type curve (to estimate future volumes) or have multiple type curves for smaller areas within the full development area. This is generally done by the reservoir engineers at the company.  Publicly traded companies are required to conduct reserve evaluations, including undeveloped locations, every year and submit the year-end report to the SEC.  As pointed out in a previous response, geologic features such as faults are incorporated into the economic models and impact either the productivity of wells near faults or the number of wells that can be developed in faulted areas.

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Permalink Reply by Skip Peel - Mineral Consultant 10 hours ago

Thanks, Ryan.  An explanation for non-industry members on net royalty interest/net revenue interest would be appreciated.

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Permalink Reply by Ryan Howrish 7 hours ago

Sure - that's a good idea.  I'll put something small together and share it in this thread.

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Permalink Reply by Skip Peel - Mineral Consultant 7 hours ago

Thanks.  A number of energy media articles mention NRI and acronyms stump a lot of the members.  It is a good definition for them to know.

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