Oil, Gas and Mineral Contracts and Transactions - Module 4 of 5
Oil, Gas and Mineral Contracts and Transactions
This module explains the form and function of contractual terms common across oil, gas and mineral transactions. This includes terms for the grant of express and implied rights, damages, delays, and royalties encountered in oil, gas and mineral leases. The discussion closes with an analysis of best practices in mineral lease negotiations, including an explanation of how addendums are used to add customized terms to common mineral lease forms.
Granting Clauses - Express and Implied Rights
The first paragraph of a mineral rights lease is typically a granting clause, which describes the purpose of the lease, the minerals that can be explored for and produced and any restrictions on damages or activities allowed on the surface lands. Granting clauses are declarations of what, how and by whom minerals can be extracted on the subject parcel, and laws in oil and gas producing states affect the rights created by these terms. In Texas, for example, granting clauses convey a lessee the right to explore for and extract oil, gas, salt, sulfur or uranium, as well as coal, lignite or iron that can be extracted without destroying the surface estate.  Lessors wishing to limit the type, scope, or methods of exploration or extraction of the minerals on the estate must do so in express terms.
Granting clauses establish the legal rights of possession and use that a mineral, gas or oil lease holder has over a subsurface estate. Errors or oversights in the conveyance of rights can raise substantial issues in the future, so mineral rights leases often include so-called “Mother Hubbard” or catch-all clauses. Mother Hubbard clauses protect the lessee against inaccuracies in the legal description of the lands contemplated by the granting clause by including all adjacent land owned by lessor in the mineral lease, even if some land is omitted from legal description. Likewise, catch-all clauses include all of a grantors’ interests within a specified geographic area within the property eligible for mineral, oil or gas exploration or extraction. This is similar to the rights over physically contiguous properties in Mother Hubbard clauses, but catch-all terms can be even more expansive. As a result, many courts have limited the extent of the rights conveyed to a lessee under vague and far-reaching catch-all clauses.
A granting clause gives a lessee an express right to certain minerals and an implied right to reasonable use of the surface land to locate, develop and produce valuable commodities. While rules vary by jurisdiction, a mineral lessees’ interest is typically dominant to the lessor’s estate, meaning the subsurface mineral rights can be used as a basis for implied terms and covenants. In fact, a lessor who interferes with the lessee operations allowed by the granting clause use may be liable for damages under the commonly-recognized obstruction doctrine.
Once a mineral lease is executed, the law provides mineral lessees with the implied right to use as much of the physical surface of the estate as is necessary for the extraction. The lessee may use surface lands as necessary to explore for and produce minerals so long as these activities do not require additional rights of physical access or result in damages when operations cease. In general, a mineral lessee’s rights to use and access the surface property is limited to what is reasonable and in accordance with the accommodation doctrine. The focus of the analysis is on making the most beneficial use of the subsurface estate. In order to ensure that these goals are being met, courts will sometimes interpret implied rights and limitations into mineral leases to fill-in terms that parties may have missed. Courts apply these implied covenants based on the relationships between the parties, the lands and the minerals contemplated by the lease.
Courts have the power to find implied rights in mineral leases that don’t have all the express terms necessary to cover the bargain between parties. Lessees are generally entitled to impose easements on the surface property that are reasonably necessary to achieve the allowed exploration or extraction activities even if those easements are not in the agreement or granting clause. So, for example, a mineral lease holder typically has the right to access mineral deposits it discovers on the leased parcel regardless of whether the landowner has expressly conveyed an easement allowing for passage. Mineral lease holders are also generally entitled to impose easements on the subservient surface estate so long as the easement is necessary and reasonable in view of commercially-available alternatives.
Delay-Rental and Related Terms
The primary and secondary terms of a mineral lease period allow time for specific exploration, drilling, or mining activities. The primary term establishes a set period of time, typically about ten years, in which the lessee is allowed to set up everything it needs to start extraction operations. Most modern mineral rights leases include delay-rental clauses, which allow lessees to make regular payments to keep the primary term open between the time that the period expires and the time operations actually commence. The State of Louisiana is a notable exception to this approach, as Article 114 of the Louisiana Mineral Code classifies a mineral lease as solely a contract under which the lessee is granted the right to explore for and produce minerals. The code provides that a mineral lease may not be continued for more than ten years without drilling, mining operations or production.
Delay rental clauses allow mineral lease holders to make rental payments to the lessor as compensation for a delay in drilling during the lease primary term. The purpose of these contractual terms is to ensure that the lessee has the flexibility to test the premises within a reasonable time after the lease grant without pressure to drill a well or mine before operations are ready to commence. If a delay rental clause is included in a mineral rights lease, delay rentals must be paid to the proper parties in the amount identified in the time and manner described by the agreement. Courts have required strict adherence to the requirements of delay-rental clauses in order for these terms to effectively extend the duration of the primary term. For example, a court in Oklahoma terminated a valuable mineral lease after the oil company leasing the subsurface estate failed to make a delay-rental payment on time due to a clerical error. Likewise, a court in Texas terminated a mineral lease where a lessee’s payment due under a delay-rental clause was just under $3 short.
Delay-rental payments can delay the secondary term for months, years, or indefinitely. In some cases, mineral rights holders may want to sell or transfer their rights under the mineral lease to a third party. Most modern mineral leases contain a notice of assignment clause to avoid disputes regarding how the assignment affects delay-rental payments, providing some flexibility to mineral lease assignees when they are required to make delay rental payments.
Regardless of whether the original lessee or a subsequent assignee is the one responsible for making delay rentals, they stop when the secondary term commences. The secondary term starts when drilling or mining extractions actually begin, which is most often a cut-and-dried factual determination. However, sometimes mineral lease holders will drill a hole or mine on a leased premise during the primary term with the intention of commencing extraction operations, only to find that there are no minerals to be found. To address these circumstances, most modern leases contain dry hole clauses, which address the question of whether delay rentals are due after a lessee has drilled for minerals but failed to find them. In these circumstances, lease holders may prefer to maintain the primary term by making delay rental payments rather than have the act of drilling trigger the secondary term. A dry hole clause allows a lessee to maintain its rights under the lease for the remainder of the primary term by making delay rental payments despite the fact that it had already drilled a well. Once a lessee has drilled a well or mine to the depth sought and the lessee has determined in good-faith that the drilling was unsuccessful, a dry hole clause comes into effect.
The policy behind allowing for this flexibility is to deter the abandonment of unproductive wells and mines, which can be major public safety hazards. By building much-needed flexibility into mineral lease terms, delay rental and related clauses help encourage the productive use and responsible decommissioning of oil, gas, and mineral extraction operations.
Royalty clauses spell out the amount that a mineral rights lessor is due based on the productivity of the oil, gas or minerals extracted from his or her land. Typically, the lease royalty is a fixed percentage of the revenues generated by the extraction operation. Historically, the standard lease royalty was 12.5 percent, or one-eighth of the mine or well’s production. Today, lease royalty clauses are fiercely negotiated. As a result, modern lease royalties typically range between 20 and 25 percent.
Royalty clauses typically allocate a percentage of a well or mine’s production to the mineral rights owner. In rare circumstances, these percentages may be paid out “in kind,” meaning that the lessor is entitled to a percentage of the physical commodity extracted from his land. However, the person leasing out the mineral rights typically isn’t interested in accepting payment in barrels of crude oil or tons of mineral ore. Rather, the parties include a manner of converting the lessor’s retained percentage of production into monetary terms. As a result, royalty clauses must include clear explanations of how these payments are to be calculated.
Whether the percentage of production is to be paid out based on fair market value, market price at time of sale or based on a pre-negotiated fixed price can have substantial impact on the value of the lease over time. Take for example the case of Exxon Corp v. Middleton, which involved a dispute over royalties from a natural gas lease. The parties agreed on a fixed price for royalties that amounted to only about one-fourth of the current market price for natural gas. The lessors argued that they should be entitled to royalties based on the market price rather than the agreed-upon rate, which was far lower. To the natural gas developer’s dismay, the court agreed with the mineral lessors and held that they were entitled to compensation based on fair market value when the gas is sold.
Jurisdictions vary on their approach to the question of how percentage-of-production royalty terms should be monetized. Some courts have required royalties based on the price of the mineral, oil or gas when it is extracted, rather than when it is sold. Others have required royalty payments to be calculated as a percentage of market value at the point of sale, minus costs associated with getting the commodities to the downstream market. Often, oil, gas or mining companies bear the costs of exploration and production for the extraction of subsurface minerals, as well as the costs associated with getting the product to market, but whether these expenses are shifted to the lessor in the royalty clause is a question of negotiation between the parties. Still, while royalty clauses are negotiated in lease agreements, parties are often subject to the legal standards applied to percentage-of-production compensation in their jurisdictions.
Parties paying royalties to the federal government pursuant to mineral leases held for public lands are subject to the requirements of the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, which amended the Federal Oil and Gas Royalty Management Act of 1982. This law was passed to simplify the process of paying royalties on federal mineral leases by establishing a seven-year statute of limitations for royalty collections and requiring interest and refunds for overpayments private lessees made to the government when paying royalties.
Best Practices in Mineral Lease Negotiations
Mineral rights owners and lessees have worked together to make productive use of America’s natural resources for generations. However, this process has also been fraught with conflict, because parties have sometimes failed to consider everything relevant when negotiating the terms of the document. It is often difficult to renegotiate the terms of a mineral lease once executed. Thus, before commencing any operations, the owner of a mineral estate and the potential lessee must consider key terms and conditions associated with the extraction of subsurface commodities. There is a lot at stake during mineral lease negotiations, so there are several known practices that expert mineral lease negotiators follow when hammering out contractual terms.
Mineral rights owners should consider whether they want to limit the amount, type or method of the oil, gas or minerals being extracted from their lands. They should also consider any limitations that may be necessary over the surface lands, such as easements or access to utility service. Nearly everything in a mineral lease is negotiable, and best practices for mineral owners are encouraged to take time to settle with a prospective lessee on mutually favorable terms. This is particularly true if the mineral rights owner owns mineral acreage close to production that many potential lessees are competing over. Rather than accepting the first offer, shrewd mineral rights owners consider what they want from the bargain, often requiring a long addendum with additional terms. An addendum to a mineral lease typically begins with the wording “Notwithstanding anything to the contrary in the foregoing Oil, Gas and Mineral Lease, the following terms and provisions control...” then lists each additional term in addition to the original lease.
Just like the lessor, mineral rights lessees take on substantial risk when executing these agreements. Mineral leases provide lessees with the opportunity to discover and extract new oil, gas, and mineral deposits, but they require the mobilization of significant resources for the discovery of valuable subsurface minerals. Even if oil, gas, or minerals are discovered on leased land, the capital-intensive long-term operations necessary to remove them also place lessees at economic risk. Effective negotiation is key to mitigating this risk, and, as a result, a set of best practices have arisen across the extraction industry regarding how to approach mineral lease agreements.
First, lessees often request the right to maintain the lease for as long as production is economically profitable without strict limitations on what qualifies as production. This is an important way to mitigate risk during the primary and secondary terms and maximize profits. The right to maintain the lease is essential because the length of time during which the well will maintain oil flow is unpredictable. Secondly, in addition to minimizing risk and maximizing profitability, parties to a mineral lease have a mutual interest of avoiding legal disputes. Courts have developed default rules over time designed to clarify key lease terms, but jurisdictions vary in how they respond to these circumstances. As a result, anyone involved in oil, gas or mineral lease negotiations will clarify all relevant terms and put them in writing before a single shovel meets the ground.
This module rounds out our discussion of oil, gas and mineral contracts negotiated between private parties. The next and final module explains how the federal government manages private exploration and extraction of publicly-managed natural resources.
 Judon Fambrough, Hints on Negotiating an Oil and Gas Lease, Texas A&M University Real Estate Center (July 2015) (available at: https://assets.recenter.tamu.edu/documents/articles/229.pdf).
 Mark Burghardt, The Mother Hubbard Clause, Holland & Hart, LLP (Oct. 20 2015) (available at https://www.theoilandgasreport.com/2015/10/20/the-mother-hubbard-clause/).
 See. e.g. Bergeron v. Amoco ProductionCo., 602 F. Supp. 551 (M.D. La. 1984) (relying on a Mother Hubbard clause to bind lessors’ interest in a 40 acre tract of land contiguous to 330 acres identified in a mineral lease).
 See J. Hiram Moore, Ltd. v. Greer, 172 S.W.3d 609 (Tex. 2005).
 See e.g. Hunt Oil Co. v. Kerbaugh, 283 N.W.2d 131 (N.D. 1979).
 Sauder v. Mid-Continent Petroleum Corp., 292 U.S. 272 (1934).
 John Lowe, Oil and Gas Law in a Nutshell, 191-92 (West Academic 2002).
 , 904 F. Supp. 2d 199, 211-12 (N.D.N.Y. 2012).
 Phillips Petroleum Co. v. Curtis 182 F.2d 122 (10th Cir. 1950).
 Young v. Jones, 222 S.W. 691 (Tex. Civ. App. 1920).
 See e.g. Gulf Refining Co. v. Shatford,159 F.2d 231 (5th Cir. 1947).
 John Lowe, Oil and Gas Law in a Nutshell, 196 (West Academic 2002).
 U.S. Forest Service, “Abandoned Mines” https://www.fs.fed.us/lei/abandon-mines.php (last visited Jan. 23, 2019).
 Fambrough, supra note 1, at 14-15.
 Exxon Corp v. Middleton, 613 S.W.2d 240 (Tex. 1981).
 See e.g. Piney Woods Country Life Sch. v. Shell Oil Co., 170 F. Supp. 2d 675 (S.D. Miss. 1999) (discussing Memorandum Opinion Order dated June 6, 1995).
 Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, 142 Cong. Rec. H. 7597 (amending 30 U.S.C. 1701 §3).
 Fambrough, supra note 1, at 3.
 John Lowe, Oil and Gas Law in a Nutshell, 195 (West Academic 2002).