This article was originally published on RBN Energy by Rick Smead

There has been a great deal of publicity around royalties involved with the shale gas—stories of instant millionaires (or “shaleionaires,” as 60 Minutes called them in 2010), stories of producers reducing or even eliminating some royalty payments as the vast oversupply of natural gas took hold in the last couple of years, stories of long, excruciating negotiations to reach a royalty/lease agreement, only to find out that the seller’s side of the table didn’t actually contain the owner of the rights, and stories of neighbors turning on each other when they got radically different deals based on timing or whom they were dealing with, and so on.   Unless you have been directly involved in leasing and royalty work, a lot of it can be confusing.  So today we begin a blog series to illuminate the world of mineral rights, oil & gas leases and royalties.

In this world it seems like there are lots of arguments in both directions from both sides of every issue.  What we’d like to do here is simply get to the factual fundamentals and explain the basics:  How do mineral leases work, what are royalties, why are they important, who pays whom for what, and what are some of the issues that are coming up these days? To that end, what follows is a description of the players and commercial processes involved in natural gas development and production, especially in the era of shale gas.   Many of the same players and processes are involved in the development and production of shale oil, but most of our emphasis is on gas to keep things reasonably simple.

Everyone knows that to get gas or oil out of the ground, a producer drills a well—and as has been publicized a lot recently, if the target is shale, that well goes down and then sideways, often passing under the property of multiple owners (seeTales of the Tight Sand Laterals).  The “producer” usually has joint investors in the well, and the property owners can also have a piece of the action.  So let’s look at who they are and how the commercial transaction works.

In the United States in any natural gas or oil well, there are three primary parties with economic interests: 

  • The operator, who does most of the negotiation, operates the well, and usually manages the money;
  • The working-interest owners, who hold the actual equity ownership of the well, and are responsible for the costs incurred in developing and operating the well (usually, the operator is also one of the working-interest owners—they’re all “producers”); and
  • The royalty owners, who own the mineral rights for the gas or oil being developed, and have leased those rights to the working-interest owners (usually through the operator), in return for a percent of the proceeds and sometimes other payments.

There are, of course, other entities with some interest—taxing authorities, owner of the surface rights where all the surface stuff has to go, safety and environmental regulatory authorities.  But here, we want to concentrate on what may be the most important driving factor in the U.S. success in developing unconventional gas:  Private mineral rights and the way the owners of those rights interact with development.

Before getting into the ownership of the mineral rights and the use of royalties to involve the owner in the economics of production, it is worthwhile to clarify the roles of the operator and working-interest owner, primarily because these two roles can often confuse the reporting of production data, depending on the use to which the data is being put.  As noted, the working-interest owners are the actual equity owners of each well, so all the basic economics of the well show up in the working-interest owners’ financial statements.  Thus, when a producer reports a certain level of production or production revenue, those are the results of the producer’s specific working interest in each well, whether or not the producer has any role as an operator.  So, for example, say Producer A operates a well producing 10 MMcf/day, but only has a 25 percent working interest, the other 75 percent being owned by other producers.  Producer A would only report 2.5 MMcf/day on its income statement or on any investor reports of production.  Meanwhile, say Producer A also owns 25 percent working interests in other wells producing a total of 100 MMcf/day, but does not operate any of those wells.  Producer A’s financial reports would include 25 percent of the 100 MMcf/day, or 25 MMcf/day, for a total reported “owned” production of 27.5 MMcf/day.  When producers are ranked as to their relative size, it is these working-interest production numbers that are generally used.

The operator’s role and metrics are different.  First, anyone reporting production by operator (like the government) will include the whole 100 percent, so when supply is grouped by operator, you can get a completely different picture of who’s big and who’s little than would be gained from ownership. Second, in terms of role, the operator often does everything in the day-to-day operation and management of the well, including physical operation, sale of the production, payment of taxes, and payment of royalties.  Then the net operating profits of the well are parceled out to the working-interest owners.  There are variations—every well’s situation depends on the specific operating agreement that has been executed among the operator and the working-interest owners—in some cases, the working-interest owners will pay royalties themselves, or pay their own severance taxes, but the operator doing everything would seem to be the dominant model.  This role has several implications:  The operator is very much the “face” of the producing community to both royalty owners and the local residents; the operator is the entity holding all the key facts as to operational parameters and costs, leaving the working-interest owners very dependent on the operator’s performance; and the operator exercises a great deal of control over production rates, usually over pricing, over the point of sale, and over ancillary operations such as gathering, conditioning, processing, and the sale of non-methane natural gas liquids (NGLs).  The reason for elaborating on the difference between working-interest and operator roles is that quite often, royalty owners may be very confused as to whom they’re dealing with—their lease is with the working-interest owners, but the operator is the entity that they hear from every month, and it is the operator who controls how the well is produced.  So from here on out, we will refer more generally to the “producer,” which might be either the working-interest owner contractually bound with the royalty owner, or the operator managing the whole thing.  Usually it will mean the operator, but unless it matters, we’ll leave it ambiguous—reflecting the royalty owner’s desire simply to have someone to call when there’s a complaint.

Which brings us back to leases and royalties.  Although a lot of drilling takes place on state and Federal lands (including offshore), where state or Federal government owns the mineral rights, the vast bulk of shale oil and gas development has taken place on private land.  This is where a very important distinction between the United States and all other countries (as far as we know) comes into play:  The United States allows private ownership of underground mineral rights, whereas other countries do not.  So the landowner or community most directly affected by development can have a very lucrative partner’s role in the ultimate production here, but not elsewhere.  This distinction is very apparent in Europe, in the many countries with large shale resources—the government owns all the mineral rights, so the people affected by development pretty much all hate that development—they’re not getting anything out of it.  Not a good formula for rapid exploitation of the shale resource.  So bottom line—the potential for a shaleionaire living in a double-wide shopping for a Bentley can create an awful lot of friends for the producer when a shale play starts to be developed.  Jed Clampett would have been right at home in the shale leasing boom. The U.S. royalty owner is one of the U.S. market’s key competitive advantage in keeping this vast engine of development motoring along.

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The first step for a producer moving into a potential area of development is to determine who owns the mineral rights.  Those rights can be sold separately from the ownership of the land, so the producer has to be very careful to be sure it’s the right party across the table (or parties—some mineral rights are spread over many people of many generations, for one piece of property).  Not only is the ownership of the mineral rights very important to confirm, but the producer has to find out whether there are already other leases tying up that particular property.  In some regions, there are some very old, and very long-term leases still hanging around that mean the producer has to be talking to the holder of those leases, not the owner of the mineral rights.  Then, in a challenge particularly unique to shale, the producer’s land agents have to do all of this a lot, over very many landowners and property records.  First, this is because the nature of shale development requires very many wells.  But second, the key to shale development is horizontal drilling, meaning that one well will frequently pass under several landowners’ properties, and the operator basically has to have deals with all of them.

Upon making sure the conversation is with the right party, the producer’s land agent then offers royalties for the right to drill.  These days, the royalty agreement usually includes both an up-front payment (“bonus royalty”) for the right to explore, and an ongoing share of any revenue gained from selling the natural gas or oil that is discovered.  If the surface rights owner is a different person from the mineral rights owner, there may be separate payments to make up for disturbing the land, road access into drilling sites, etc., but those payments are usually much less than the royalties for the mineral rights.

The level of royalty payments varies based on the area of the country and the eagerness of producers to execute leases.  In particular, the initial payments and fixed lease payments paid for access to drill can vary extremely widely, even based just on the date when leases were executed.  The longstanding version is “percent of proceeds,” whereby the royalty owner gets a share of the gross revenue from sales, without deduction of the producer’s cost of drilling or operating the well.  Here, where the royalty owner only makes money if gas or oil is actually produced, this ongoing “percent of proceeds” royalty ranges from one-eighth (12.5%) to one-quarter (25%) of the actual sales revenue taken in at the wellhead.  The lower 12.5% was the prevailing level for a very long time, but eagerness to drill and to be the first one there has caused many more producers to pay 25% these days.

There are a lot of issues arising out of every part of the leasing process and royalty structures that grew exponentially with the industry’s enthusiasm for shale gas.  Everyone was racing to be the first and biggest in each emerging play, particularly five years ago when natural gas prices were in the $8/MMBtu to $10/MMBtu range, and everyone simultaneously lost interest in drilling for ‘dry’ natural gas when prices plummeted (except for a few prolific areas like the Northeast part of the Marcellus).  Producers—and here we mean the working-interest owners responsible for costs—have been saddled (or self-inflicted?) with very high bonus royalty expense, the kind they have to pay whether or not there’s ever any production.  So with the whole economics of their gas operations under significant pressure, these producers have been quite interested in doing what they could to reduce costs until prices improve.  Royalty owners who made a deal, and most likely told their families to count on a lot of money coming in, have not been amused.  And prospective royalty owners who did not manage to sign a deal before the producers lost a lot of their enthusiasm are not at all happy with this turn of events.  The end result has been a great deal of dispute and litigation around royalties, masking the incredible importance of this relationship in bonding the interests of the producers and the landowners.  In the second installment of this series, we will explain some of the specific areas of issues or dispute, and basically tell both sides of the table what to watch out for.