Shale Law

Thompson & Knight LLP partner Louis Davis recommends sellers negotiate a provision to restrict contact with employees and to prohibit solicitation by a potential acquirer.

T?he “deal drill” when buying or selling interest in a shale play is much the same as when buying or selling in a conventional play. The deal documents, the due diligence—these matters are standard. But new technology and the enormous amount of money at work in these competitive plays have given rise to disputes in contracts designed for conventional plays. Many E&Ps find themselves bogged down in contract litigation when time and money could be better spent developing acreage.

“A ton of disputes are going on in shale plays,” says Richard Bass, a partner with law firm Thompson & Knight LLP. “If you have Haynesville shale acreage right now you probably have one of these disputes. There are a lot of lawsuits attempting to bust leases in the Haynesville. When you spend a lot of time getting a lease, the last thing you want to do is lose it because of an oversight.”

Thompson & Knight’s upstream A&D lawyers recently presented a client tutorial on legal issues in emerging shale plays in Houston and Dallas.

For example, confidentiality agreements typically last for one to three years, but agreements in markets involving shale plays are terminating at two years at present. Of great importance: Negotiate a provision to restrict contact with employees and to prohibit solicitation by a potential acquirer.

“This is a very important provision for the seller,” says partner Louis Davis, particularly in the Haynesville where the selling entity often survives the deal, often retaining ownership of shallow rights. For these sellers, it’s particularly important to restrict the buyer’s contact with employees.

“The buyer gets to do all this due diligence and meet all the employees. If there’s not a restriction on that, they can go back and try to hire them. Then the seller finds it is losing employees to potential buyers. You want to avoid that.”

Similarly, a non-compete agreement is essential in a shale play before letting competitors view private data, but these often have to be customized to the type of buyer.

Buyers not presently active in the area should have no problem agreeing to not lease in a defined area with the advantage of the seller’s confidential information. But in shale plays, “the fact is most of these buyers are already extremely active in the area where the seller is trying to sell his leases. There’s no way realistically in that situation that a buyer is going to be able to agree to do a non-compete.”

What does a seller do? When the potential buyer is actively leasing in the area, it will usually agree to not buy any leases or mineral interests on lands covered by leases owned by the seller. Potential buyers should be diligent in keeping track of those agreements. “You can get in trouble if you don’t,” Davis says.

Busting the HBP
Legal problems result from primary term leases that are held by production (HBP) with existing shallow production. With neighbors finding themselves suddenly wealthier with high per-acre lease offers, mineral owners under HBP leases are often eager to find an escape clause so they too can share in the higher leasing payments. Production often becomes the target.

The production that’s holding some of these existing leases may be marginal, says partner Michael Byrd.

“You need to make sure that production is in ‘paying quantities’ sufficient that those leases are still valid.” Some custom leases expressly define the amount of production necessary to hold a lease. If no language exists, state law governs. Texas and Louisiana have slightly different legal standards for what constitutes “paying quantities.”

One producer with James Lime production in Sabine Parish, Louisiana, received a demand letter from the lessor to terminate the lease. This land-owner was being offered lease bonuses of $10,000 to $20,000 per acre. “So that lessor is trying to get out of that existing lease by claiming that the current production is not sufficient to maintain that lease.”

Even if the lease is producing in paying quantities, that may not be enough to assure that the operator can continue to hold deep rights as well. A traditional Pugh clause in a lease states that production does not hold the entire lease, but only certain lands around the producing well. A typical Pugh clause creates only a vertical severance.

“Now it’s becoming more common to see Pugh clauses with both vertical and horizontal severances,” says Byrd. Under this more modern lease clause, “your deeper rights may have terminated, so you won’t be able to drill in the shale formation.”

Continuous-development provisions can protect those rights, he adds. Problems may arise when the depth-release clause and continuous-development provision conflict.

In one case, the lessor may hold 4,100 net acres with an offer of $22,500 per acre for deep rights only. “Do the math. That’s more than $90 million. You can imagine that lessor has an incentive to try to get us to release the deep rights.”

Producing formations above the Haynesville include James lime, Cotton Valley, Hosston and Fredericksburg. Will the deep-rights seller retain the shallow production and rights?

“My experience in the Haynesville has been that the seller is going to keep the existing shallow production,” says Davis, unlike in the Barnett shale, which had relatively little existing production from other formations.
The shallow production is a foothold in the Haynesville play. “They understand the Haynesville shale is becoming valuable. They start to buy more leases, and there’s a combination of production and primary-term leases.”

Sellers need to be specific about what’s being sold. The definition should be marked by the stratigraphic equivalent of the base of a formation found at a certain depth in the electric log, and include the date of the log for a certain well and its API number, plus the exact location of the well.

“You want to use those words ‘stratigraphic equivalent’ and you want to tie it to a specific well log and adequately describe the location of the well. If you do that, you shouldn’t have any problem with what’s being reserved and what’s being sold.”

Most sellers want an option to enjoy the deeper potential. “They want to participate in the romance,” says Davis. Also, the buyer has experience with drilling these deep wells, and sellers can benefit from this.

These relationships, commonly a joint operating agreement (JOA), can be rife with landmines. A JOA in a shale play doesn’t work like one in a vertical play, says partner Greg Curry, a trial lawyer. “The term ‘deepen’ doesn’t work for a horizontal well, so you need to change it.” The definition of depth also needs to be clarified in a shale-play JOA, he says. “You can’t just do it by depth. Is it the depth to the bottom or the depth to the end? Make sure your JOA addresses it adequately.”

Also, many JOAs contain a preferential right to purchase. “Strike it!” says Curry. “Take it out, unless you want to hire me. There is more litigation with ‘pref’ rights than with any matter that comes out of a joint operating dispute.”

A preferential right removes the ability to negotiate, he says. “You have to perfectly accept what tender has been made. If you really wanted to acquire (the property), you’re not going to have the option to do so if you have not tendered it perfectly. You can’t negotiate.”

Tax pitfalls
Operators looking to sell interests in shale plays and keep an override may face unexpected and undesirable tax consequences, according to partner Roger Aksamit. “Unfortunately, whenever you retain a nonoperated interest, such as an override, in the sale of operating interest, that’s treated as a lease. Despite the intentions of the parties, what you’ve got is a lease.”

And although this tax law is decades old, “this has been a surprise to a lot of folks. We ran into this in the Barnett shale when it was hot, and now we’re seeing it in the Haynes­ville shale.”

The situation has led to a lot of quick deal restructuring once clients bring in term sheets. “Where you’ve got a lease instead of a sale, obviously there’s a number of differences.”

The primary difference involves capital-gains tax. For individuals, the tax on selling a property held longer than a year is 15%. If the sale is treated as a lease for tax purposes, whether corporate or individual, the capital gains will be taxed at 35%. “That’s the most significant consequence of it.”

Another issue is offset of basis. On a lease, some depletion may be taken, but on a sale, the entire basis can be used to offset the proceeds. Sellers may also want to move the sale proceeds into an IRS 1031 tax-deferred, like-kind-exchange property and avoid paying taxes altogether, but that is not possible if the transaction is deemed a lease.

“The easiest way around this is to simply take the override out and compensate the seller with more cash,” says Aksamit. Other solutions may include creating a partnership or contracting around it by structuring cash payments that mimic an override but are not secured by the property.

“Also, you can carve out an override before the sale—and the longer before the sale the better case you will have.”