This article was originally published on RBN Energy by Rick Smead
Natural gas and oil development, especially in shale plays that require a lot of wells and a lot of activity, can be inconvenient and noisy. There are also, of course, various criticisms and protests around some of the processes used, such as hydraulic fracturing, and around the overall level of activity, such as truck traffic. The gas and oil producing industry values strong relationships with the communities where it needs to work, and can use all the friends it can get as it takes the lead in developing the nation’s vast energy resource. Bringing big economic benefits to those communities, which are often rural or industrial areas hard-hit by economic downturns, is clearly really important in the efforts to build those relationships and friendships. There are a lot of different kinds of economic benefits deriving from supply development, but by far the most important to the affected landowners are the royalties resulting from private mineral rights. Today we continue our examination of the inner workings of oil and mineral rights issues, this time considering some common oil and gas royalty disputes.
Private mineral rights, the ownership by a landowner of the natural gas and oil under that landowner’s property, represent one of the most important aspects (maybe the most important) of the U.S. oil and gas shale revolution. Because, unlike many other countries, the people directly affected by the inconvenience of development can have a direct economic stake in the outcome, there is frequently an atmosphere of common effort toward safe and responsible (and rapid!) development very difficult to achieve anywhere else (Note: Having indicated earlier that private mineral rights were unique to the U.S., we were reminded that there are a degree of residual private rights in countries such as Canada, Australia, and Trinidad/Tobago, and that the Supreme Court in India has recently changed the law to allow such rights).
In the first installment of this series, “You Never Give Me Your Money”—Royalties are Critical but Complicated, we explored the royalty--the payment by a producer to the owner of the mineral rights, for the right to drill and produce. This direct infusion of money (frequently big money) into the pockets of individuals in the local economy can make for a wonderful courtship.
Then, after the courtship and wedding, the royalty owner, working-interest owner, and operator settle in for a long marriage. And this is a marriage where some of the underlying assumptions have changed a great deal—particularly the value and attractiveness of some of the natural gas development, at least in the short term. Thus, there are a number of areas where disputes have come up between royalty owners and producers, often leading to litigation and always requiring a lot of administrative vigilance on the part of the producer (as in, be sure you follow all the requirements of all the leases to keep from losing them). To be sure, the operators, who are the primary face of the producing industry seen by the community, work very hard to be valued members of that community, and between such efforts and the economic benefits they represent, it’s reasonable to expect that especially in revitalized rural and industrial areas, the operators remain very popular. As we’ll point out a bit later, the actual volume of serious disputes is not huge, but an understanding of the types and the issues is important on both sides of the table. We’ll explore four of these issues below in more detail. They have all been exacerbated by the economic pressure placed on producers as gas prices went way down right after competitive leasing frenzies had pushed the up-front cost of leases way up:
Post-Production Costs: Post-production costs can include gathering, conditioning, processing, transportation to a distant point of sale, or marketing expense to sell the gas. Many leases do not allow the producer to deduct post-production costs before figuring out what to multiply 12.5 or 25 percent by in writing a check to the royalty owner. In those cases the royalty owner simply gets the contractual percentage times whatever the producer sold the gas for. However, many leases do allow for the deduction of post-production costs, but it’s not always clear which post-production costs. For example, the royalty owner might think it’s reasonable to deduct the cost of getting the gas all shipshape for tender into a pipeline, but not reasonable to deduct costs of transporting it somewhere from the wellhead, or of marketing it. However, if the point of sale is actually at the end of that transportation/marketing effort, and if there’s no way the gas could have commanded the same price back at the wellhead, it would seem reasonable that the value at the wellhead is what it got at the other end, less the cost of getting it there. So, for example, if the producer were selling the gas at the Henry Hub, LA, at Henry Hub index prices, the cost of getting the gas to that point of sale should logically be deducted to determine a netback price at the wellhead. Or say the producer successfully captures premium prices for the gas, above the going market index, through special marketing efforts. If the royalty calculation is based on the premium prices, then the cost—the marketing—of getting those prices ought to be taken into account. But then we have the give and take of the original lease negotiation—what if the reflection of those costs is something the producer specifically gave up in order to get the royalty owner to sign up with him instead of with his competitor? So ultimately, each post-production cost case pretty much has to stand on its own facts, a good thing for all the attorneys involved in royalty cases.
Different Vintage Leases: There can be a great deal of dissatisfaction among royalty owners when the market shifts and one owner gets a radically different deal from his next-door neighbor. Of course, if the older lease is really expensive because the producer was in a competitive frenzy when it was signed, the producer isn’t that happy with the differences either. In any event, a lot of argument and sometimes litigation can result from claims that the producer was being discriminatory in paying a lot more to one landowner than to another.
Leases Held by Production: Most drilling leases have a finite time limit in them, that causes them to expire if the producer hasn’t drilled and started producing by the lease’s deadline – for example in dry-gas plays that looked great a few years ago at $6.00/MMBtu but that are kind of on hold at at recent price levels of $4.00/MMBtu or so. As you might expect, producers want to hold on to the rights they paid for levels that make economic sense given their drilling and other cost structures. This puts a lot of pressure on producers to drill and produce wells that aren’t necessarily all that attractive right now, simply to hold the leases they paid so much money for. Leases that are thus extended by at least one well having been drilled and completed, all the way to commercial levels of production, are referred to as “Held by Production,” or HBP. Such HBP wells have been one of the reasons production stayed up in dry gas plays like the Haynesville even in the face of sharp declines in gas prices. However, there’s another wrinkle to HBP wells in plays such as Haynesville, where the shale formation is very deep (11,000 feet), and thus very expensive to drill and produce. That’s the “shallow HBP well.” If small amounts of commercially producible gas can be found at much shallower levels, reached with vertical wells that are a lot cheaper than horizontal wells, the question becomes whether that satisfies the HBP requirements. Again, that is an issue where the specific language of the lease is the determining factor.
Rights to NGL Production: And then there are the Natural Gas Liquids (NGLs) that recently have been worth a lot more than the gas (see our Tailgate Blues series on gas processing economics). In some old leases, NGLs extracted from the stream are treated as waste product, not as valuable hydrocarbons originally owned by the royalty owner. Sometimes this is a function of the royalty owner’s deed itself, sometimes it is the result of nuances in the lease. In any event, when hydrocarbon molecules could stay in the gas stream and be sold as gas, or could be separated out as NGLs and sold in a separate market, it’s hard to see how different treatment for royalty purposes wouldn’t get some lawyers stirred up. This is especially true in plays such parts of the Marcellus where it’s the NGLs that are causing the drilling in the first place.
Every one of these areas of dispute has arguments on both sides, every one also might have a lot of underlying tension that existed before the specific issue was raised. The result has been a lot of litigation. In the twelve months ended June 30, 2013, according to Navigant Consulting Inc.’s Disputes and Investigation Practice, 416 new lawsuits were filed in Federal and state court involving unconventional oil or gas. As shown here, 230 of them (the first two orange bars), or over half, involved land and lease rights or royalty disputes. It is also interesting to see the extent to which the orange bars (12 months ended June 30, 2013) exceeded the blue bars (the prior 12 months). There was a 55 percent increase between the two periods in the number of cases filed.
However, while this level of litigation is a significant increase over what it was, it is not a huge volume at all compared with the level of drilling activity. The U.S. gas and oil industry is currently drilling something like 45,000 to 50,000 wells per year, supported by at least that many new mineral leases. So even if a single suit covers a number of parties, it’s pretty easy to see that 230 (the land, lease, and royalty lawsuits) is a lot less than 50,000 (the number of new wells). The litigation is significant, but not enough to indicate the industry isn’t doing a good job of keeping most landowners happy.
Of course, some are unhappy for reasons that will probably never lead to a suit. In Gregory Kallenberg’s documentary “Haynesville,” the potential lessors all band together, spend the whole movie working through their negotiation with the producer, then (spoiler alert) find out that another producer already had the properties under lease, and the producer with whom they were negotiating could now just deal with that guy. No pot of gold, but plenty of drill pads, rigs, and trucks.
We would note that most of the dispute issues appear to have arisen in areas where the enthusiasm for drilling has dropped off for now. In the wetter areas, such as Marcellus and Eagle Ford, as long as the issue of who owns the NGLs is worked out, folks ought to be pretty happy. We certainly know that the level of activity in Eagle Ford has made South Texas motel owners very happy, so the same ought to be true of royalty owners.
But throughout those areas of the country where there is a constant tension between the industry and anti-development concerns, the power of the royalty to put everyone in the same boat and let everyone win must continue to be effectively harnessed. So it would be very good to get as much of the royalty litigation behind us as possible. A lot of that process can just be education and communication—this is a classic case where it’s more important to listen than just to wait to talk.