Here’s a hypothetical situation. Suppose there is a 90-acre undivided tract which is 2/3 leased ... with 1/3 holding out (30 net mineral acres).
One operator has all the surrounding property leased ... and pools the 90 acres into a 360-acre pool ... then begins drilling wells ... NOT on the 90-acre tract with the holdout. If I understand the Texas law correctly, the 90-acre leased mineral owners will receive their proportionate share of royalties from all the pool wells ... while the 1/3 holdout will receive nothing.
But suppose this turns out to be a very good play ... and eventually the operator decides that the 90 acres is too valuable not to put a well on ... so they go ahead and drill a well on it ... and the 1/3 holdout becomes a carried working interest.
What percentage of that well would the 1/3-holdout carried working interest own?
(a) .3333 (30 net mineral acres divided by the 90 undivided acres), or
(b) .0833 (30 net mineral acres divided by the 360-acre pool), or
(c) none of the above ... I don’t have a clue what I’m talking about.
And how likely is the operator to pool, or drill on, the 90-acre undivided interest with the burden of 1/3 of it being unleased?
Thanks for your insight!
The holdout is entitled to 1/3rd of all production from the well without dilution from the unit under pre-2008 law. After the Texas Supreme Court's opinion in Wagner & Brown v. Sheppard, however, there is an argument the lessee can make that the holdout's 1/3rd is diluted by the unit. In other words, the holdout would receive 30/360ths of production. This is based on language in the opinion that a lessee's unit designation that describes the pooling of "lands" and not just "leases" would include the holdout's share in the unit. This of course ignores the law that a holdout would have to ratify the unit in order to be bound by it, but the court did not address that issue. I believe the holdout has the better argument that he gets 1/3rd of production without unit dilution.
As to your last question, that depends on a lot of factors, such as cost to drill the well, expected recoverable reserves, the lessee's net working interest, among other things. A lessee is taking a risk drilling on the tract with the unleased interest in this respect, because it would have to create new law that is an extension of the Wagner & Brown decision.
This discussion appears to assume vertical wells. I understand that in the case of horizontal wells, all points along the well are considered drill sites so if the operator drilled a horizontal well under the holdout's tract, the holdout would come in for their carried working interest. Is that correct? If so, how is the holdout's interest computed? If the operator has all the surrounding acreage leased, couldn't he just drill horizontally around the holdout's tract and drain it without paying?
For horizontal wells, you are correct that all points along the wellbore are technically drillsite tracts. What we are seeing however, is that companies are allowed to designate no-perf zones along portions of the wellbore that are underneath an unleased interest, and arguing they are not a drillsite tract. The other option is to drill around the holdout as you suggest. As long as the company meets spacing requirements, this can be done and the holdout arguably gets drained if he doesn't drill his own well. This is a risk of holding out nowadays.
If the company designates no-perf zones along portions of the wellbore as you stated, does that lower their recovery since not all the wellbore is perfed? If so, that strategy would seem to have some (adverse) economic consequences to the operator. Is that correct? Seems to me that the reasons for holding out would be related to amounts of bonus and royalty, lease contract terms and length of the lease. Any recommendations for mineral owners to assess the current (market) value of their minerals in terms of bonus and royalty? With gas prices down, operators seem to me to be trying to acquire unleased interests at low rates to complete tracts so they can drill and HBP. At these prices, I'm not sure it makes sense to produce the minerals hence don't lease but your comments suggest that the risk is your minerals are drained and you end up with nothing.
That is true that a no-perf zone would result in the well producing less, but it is being done. Admittedly, I do not see it being done in dry gas plays as much as oily and wet gas plays, such as the Eagle Ford. Mineral owners need to shop their interest around to try to get the best price. Research on the RRC website to determine who is operating in your area, and then cotnact the company's land department and let them know your acreage is available for lease. They often will at least take a quick look at your acreage if you have a legal description, and if you have a plat of your acreage that is even better. But if you are in a dry gas play, such as the Haynesville, you are not going to see high prices for bonus and royalty as long as natural gas prices are as low as they are. It is a personal decision to the mineral owner as to how much they are willing to lease for or if they are willing to risk holding out.