Five Things New Oil and Gas Attorneys Should Know
By Rebecca L. Phillips – January 30, 2013
The United States is on track to become the world’s top oil producer by 2017. The United States is already the world’s second largest producer of natural gas, outpaced only by Russia. International Energy Agency. This is news.
Technology has spurred the increased production. Most notably, the technique of fracturing, or fracking, has given old wells new life. It also has enabled producers to tap into previously unreachable resources. This means new wells and new locations. States such as Ohio, not traditionally associated with oil and gas production, will begin to contribute substantially to national production.
This expansion of oil and gas production will require new legal regimes to be developed—as well as a new kind of attorney. To hit the ground drilling, oil and gas attorneys need to know something about the field. This article is based on my experience as a first-year energy-litigation associate in a Texas law firm, but some of the article’s lessons are applicable to corporate attorneys and solo practitioners. Law is drawn from the great state of Texas, which is largely followed by other producing states. Even where state laws differ, this article will provide background perspective.
Oil Is Not Gas and Vice Versa
Oil is not gas and vice versa. That simple point can get lost when you read contracts and case law that use the words “oil” and “gas” seemingly interchangeably. And American colloquial usage of those words adds to the confusion. “Gas,” as used in the legal context, is not the stuff that you pump into your car. Rather, in the legal context, “gas” generally refers to what you probably call “natural gas.” Oil, black gold, Texas tea—that is the stuff that eventually ends up in your fuel tank.
The distinction between oil and gas is not just important at the pump. It matters to your clients, and your understanding of the distinction will be most crucial for your role as a counselor. Most obviously, oil and gas are sold in different markets, each with its own set of pricing variables. Generally speaking, oil is sold in an international market, while gas is sold more locally because gas is harder to transport. Indeed, during the twentieth century, oil producers flared billions of cubic feet of gas as waste, because they had no viable way to market the gas. Martin S. Raymond and William L. Leffler, Oil and Gas Production in Nontechnical Language 12 (2006). Pipeline development and control was and continues to be critical to the success of the gas industry. In sum: The distinction between oil and gas bears on practical considerations, and to effectively solve problems for your client, you need to get familiar with the distinction. I recommend reading Oil and Gas Production in Nontechnical Language, mentioned above, and The Global Oil and Gas Industry: Management, Strategy and Finance by Andrew Inkpen and Michael H. Moffett.
Texas-Tea Parties Draw a Crowd
The ownership interests at stake in oil and gas law are unique. And there are more of them than you might expect. Three interests are important: mineral interest, working interest, and royalty interest.
Roman property law espoused a simple mineral-interest rule: “whosoever owns the soil, owns up to the sky and down to the depths.” Richard Kinder, Casebook on Torts 343 (2012). It was a rule of absolute ownership. Our modern oil and gas law functions differently.
As minerals, oil and gas are severable from the land. Accordingly, the law recognizes two separate estates: a mineral estate and a surface estate. A mineral-estate owner has the right to develop the minerals below the land or to lease the estate and collect royalties. A surface-estate owner retains all other rights to the surface of the land, subject to an implied easement to the mineral-estate owner.
Generally, the mineral estate is governed by the rule of capture. You have likely heard this rule in its more colorful form: “I drink your milkshake!” There Will Be Blood (Paramount 2007). To put it concisely, producers who capture oil and gas from a well on their own property own that oil and gas, regardless of whether it once flowed under their neighbors’ land.
Moving on from mineral interests, there are working interests. Working-interest owners control production at the well. The working-interest owner generally bears the royalty obligation, unless otherwise assigned. And that brings us to our final interest.
Royalty interests come in three varieties: ownership royalty interest, nonparticipating royalty interest, and overriding royalty interest. The first interest, an ownership royalty interest, is the most simple; it is the owners’ royalty interest, given by producers in return for leasing the estate. The second, a nonparticipating royalty interest, is a third-party interest, created when mineral owners convey away a portion of their royalty interest. The interest is so named because its third-party owner has no authority to participate in governance of the mineral estate; for example, a nonparticipating royalty interest owner cannot lease the mineral estate. Finally, overriding royalty interests are owned by producers. They are created when working-interest-owner producers assign their working interest to another producer, reserving for themselves a royalty interest in the new producer’s production. Reread this paragraph slowly.
Agreements Come in Like Gushers
Given the interests just discussed, you should not be surprised to learn that oil and gas agreements abound. Most of these agreements are creatures of state law, but do be aware that federal agreements exist; they govern operations offshore and on federal lands. The three types of agreements that you are most likely to encounter are oil and gas leases, pooling agreements, and joint-operating agreements.
Oil and Gas Leases
An oil and gas lease is the basic agreement between a mineral owner and a producer. In it, the mineral owner conveys to the producer the right to develop the mineral estate in return for a royalty interest.
Importantly, these leases contain habendum clauses, which state the period for which the leases will run. The leases’ habendum clauses contain a “primary term” and a “secondary term.” The primary term covers a specific period of time, four years for example. Once the primary term runs, the lease may continue under the secondary term for as long as the producer continues to produce oil or gas in paying quantities. Production in paying quantities (PPQ) generally exists if the producer is able to pay a royalty. If the producer cannot continue PPQ, the mineral owner may discontinue the lease. The lease may also contain a delay-rental clause, which allows the producer to delay drilling and production by making periodic payments.
A pooling agreement brings together two or more oil and gas leases covering separately owned land. Leases usually contain a pooling clause, allowing a producer to pool leases without the mineral owners’ permission and stating that the pooled unit will be governed by the same rules outlined in the lease. Pooling can increase production of oil and gas, because it prevents the depressurization that occurs when too many wells are drilled on a unit. Pooling may also be necessary to comply with state regulations regarding well spacing.
A joint-operating agreement (JOA) is an agreement between producers. JOAs enable producers to share the risk and expense of oil and gas exploration. Under these agreements, one party is responsible for day-to-day production operations; the other parties contribute financially and are entitled to benefit from exploration profits.
The Process Matters, from Shale to Sale
Lawsuits happen when there is a problem. In many areas of law, attorneys have enough practical experience to understand the problem. For example, when a client says she threw a vase at her mother-in-law, her attorney has at least a superficial understanding of the problem. However, when a client says that it deducted drilling expenses from the gross profit, the attorney may not know where to begin. To understand oil and gas clients’ problems, you will need a basic understanding of oil and gas production and royalty calculation.
Oil and gas production can be divided into three stages: upstream, midstream, and downstream. The upstream stage involves exploring and drilling for oil and gas. The midstream stage involves transporting oil and gas, generally through pipelines. The downstream stage involves refining, processing, and marketing oil and gas. For a full picture of the process and the lingo, I recommend reading Oil and Gas Production in Nontechnical Language. But nothing is more invaluable than a good mentor.
Knowing the process comes in especially handy when working with royalty calculations. A royalty is generally calculated based on the sale price that a producer receives for oil and gas. The specifics are determined by the lease agreement, which may allow the producer to deduct certain expenses from the gross sale price before calculating a royalty. A producer cannot, however, deduct production expenses, those expenses incurred to get the oil and gas out of the ground. Depending on the lease language and the jurisdiction, non-production expenses may be deducted.
It is not obvious, but three small words—“at the well”—can make a big difference in royalty payments. Oil and gas can be sold at the well or downstream, after they have been processed. Processing adds value to the oil and gas. The higher the sale price, the higher the royalty. Therefore, when leases provide that a royalty be paid on value of oil and gas “at the well,” producers and royalty owners fight about who should profit from the downstream processing. States resolve the dispute differently.
The so-called majority states allow producers to subtract transportation costs from a downstream sale price to arrive at an “at the well” value of the oil and gas. This is called the “net-back” or “work back” rule. Majority states include California, Kentucky, Louisiana, Mississippi, Montana, New Mexico, North Dakota, and Texas. See Byron C. Keeling and Karolyn King Gillespie, “The First Marketable Product Doctrine: Just What Is the ‘Product’?”, 37 St. Mary’s L. J. 1, 52 n. 193 (2005) (citing cases from each state).
The so-called minority states instead charge producers with a duty to market the oil and gas, including a duty to place the oil and gas in marketable condition. Because of their duty to market, producers cannot deduct transportation expenses to arrive at an “at the well” value. This can all get very complicated when companies do then sell oil and gas “at the well,” raising a question as to whether the oil and gas was in marketable condition at the well. Minority states include Kansas, Colorado, Oklahoma, West Virginia, and Wyoming. See id. at 51; see also 3 Williams and Meyers, Oil & Gas Law § 645.2 (discussing Wyoming interpretation of post-production costs); Stirman v. Exxon Corp., 280 F.3d 554, 564–65 (5th Cir. 2002).
You Are Not the Wildcatter
It is fun to practice law. It is fun to do business. And it is really fun to use the law to help clients do business. You should be enthusiastic about what you do.
But you are not the wildcatter. I recommend this: Before you give a client advice, take a few deep breaths and channel your worrisome mother. You have a duty to be your clients’ counselor. While it is tempting to get enthusiastically carried away in helping clients plan their dreams, being a counselor requires that you think of everything that might not work with their plan. Ask for all the facts, be practical, and discuss the full range of possibilities. This will help your client make fully informed decisions. Even the wildest wildcatter has to appreciate that.
Keywords: energy litigation, oil, gas, mineral interest, working interest, royalty interest, PPQ, JOA
Rebecca L. Phillips is an associate with Vinson & Elkins in Houston, Texas.