STCL Houston Energy Newsletter - Spring 2021

ENERGY NEWSLETTER South Texas College of Law Houston

Harry L. Reed Institute of Oil & Gas

Letter from the Editor On behalf of the Editorial Board and the Members of the ENERGY NEWSLETTER, we are pleased to present you Edition 1, Volume 4. The ENERGY NEWSLETTER is a student-run scholarly newsletter committed to bringing to the global energy community timely and unique perspectives in the industry. South Texas College of Law Houston has an extensive student, Energy Alumni association, and general footprint across the world in oil, gas, and all things energy. The ENERGY NEWSLETTER seeks to bring all their perspectives in one place at the center of the global energy community in Houston.

This is the fourth volume of our ENERGY NEWSLETTER publication through South Texas College of Law Houston. Having such a center stage in downtown Houston, the newsletter team looks forward to bringing exciting articles co-authored by students and alumni. We look forward to growing the intellectual prowess of the ENERGY NEWSLETTER and South Texas College of Law Houston.

This publication begins with a look at the Rule Against Perpetuities and its impact in oil and gas law. Next, is an evaluation of the unprecedented oil price crash as a result of the rapid spread of COVID-19. We then turn to a discussion of force majeure clauses as applied to the executive orders issued to slow the progression of COVID-19. Thereafter, is an assessment of two recent cases examining deduction of postproduction costs. Next, we analyze the applicability of the reasonably prudent operator standard regarding joint operating agreements. Finally, the newsletter ends with a discussion of In re First River Energy, LLC. On behalf of the Editorial Board and the Institute of Oil & Gas, we thank the authors who have added their support to this enterprise through their submissions. We would also like to thank South Texas College of Law Houston and all organizations in and surrounding the College for making the ENERGY NEWSLETTER possible.

Sincerely,

Grant Armentor Editor-In-Chief Disclaimer: The opinions expressed in this publication are those of the authors. They do not purport to reflect the opinions or views of South Texas College of Law Houston or the Harry L. Reed Oil & Gas Law Institute, their students, staff, faculty, or associates.

Spring 2021 Edition

Contents •••

The Rule Against Perpetuities in Oil & Gas Law .................................. 2 Unprecedented Price Crash: What Happened? ...................................... 13 Force Majeure in the Time of COVID-19 ........................................ 21 Royalty Disputes Continue to Thrive: Two Recent PostProduction Cost Deduction Cases .......................................................... 27 Joint Operating Agreements and the Reasonably Prudent Operator Standard .......................................... 31 In re First River Energy, LLC: First Purchaser Statutes .......................... 34

Editorial Board •••

Editor-in-Chief GRANT ARMENTOR Managing Editors CRISTINA GOULET VIKESH PATEL Articles/Note Editors ASHLEY EAVES EMILY LITTLE EMMA BECKWITH JETT BLACK KIERRA VOGEL LAUREN DANIELSON

Authors ••• CHRISTOPHER KULANDER KEN RICE MICHAEL MILLER AUSTIN BRISTER JONATHAN BAUGHMAN GRANT ARMENTOR

the distribution of land long—long—after death and even to tie changes in ownership to activities conducted (or not) on the land and/or the activities of descendants. In the United Kingdom, this strife was particularly acute given the concerns of the nobility about their ancestral realms and what their noble descendants might get up to long centuries later. Courts were soon asked to make law. In 1682, The Duke of Norfolk’s Case launched the Rule into the common law tradition.1

The Rule Against Perpetuities in Oil & Gas Law By: Christopher Kulander Professor of Law South Texas College of Law Houston “It was a dark and stormy night and no executory interest was good unless it had to become possessory, if at all, within 21 years following a life or lives in being at the creation of the interest.”

An executory interest is a future interest, held by a third person, that either cuts off another’s interest or begins after the natural termination of a preceding estate. Further, a springing executory interest is one that operates to end an interest left in the transferor. The Duke of Norfolk’s Case established that executory interests are only valid and enforceable if they were sure to become possessory within a certain span of years.2 Instead of just ruling that the executory interests must be reduced to possession within a set time—say, forty years—the court in Norfolk (and courts after it) made the mandated time to take possession variable. 3 Specifically, the point in the future at which possession must have been achieved was set according to the lives of the people involved in the grant—the so-called “lives in being”—that law students and property lawyers have wished death upon over the years. The modern version of the Rule was not laid exactly down in Norfolk; later cases took the idea and refined it.

Subsequent evolution of the Rule converged on a measure of years ascertained such that no interest passed muster under the Rule save those that must vest, if at all, within twenty-one years following a life or lives in being at the creation of the interest.

Did you just convulse a familiar fright? As long as possession of land has existed in any form, owners have worried about what will happen to their property—and on it—after they go to the grave. The question of what will immediately happen to the property of the recently deceased has been answered with elaborate schemes of disposition carved into the headstone of whatever legal scheme governs the law where the land in question lies. In this article, taken from my paper at TexasBarCLE’s “Oil & Gas Disputes” symposium back on January 10, 2020 here in Houston, let’s talk about the Rule Against Perpetuities—hereafter, “the Rule.”

An Introduction The Duke of Earl Countries following the English system of estates accept that the owner of real property can decide what happens to his property at death, who might inherit it, and in what amount and division.

While this idea was leavened over the centuries with laws requiring dispositions meant to protect spouses and children from being left poor by such decisions, acceptance that the plans of immediate disposition of real property according to the wishes of deceased owners were generally recognized by society.

Difficulties and conflict arose, however, where the deceased tried to influence changes in 2

The Rule in the Parlance of Our Times

Rule removes the executory interest of the second party and the first party receives the interest in fee simple in the first example and the grantor merely retains the interest in the second example.

The Rule eliminates future interests that do not transfer as described (“vest”) in the time necessary. The word “vest” in regard to the Rule refers to an immediate, fixed right of present or future enjoyment of the interest. The Rule does not apply to present or future interests that vest at their creation. In practice, in states like Texas where the Rule is applied immediately, clauses that violate the Rule are simply crossed out, leaving the instrument to be read without the struck clause(s) but with all other clauses intact.

Estates that satisfy the Rule are considered “vested” from creation. Future estates in the grantor—possibilities of reverter, reversions, and rights of entry—are always vested. A possibility of reverter is, in turn, the grantor’s right to fee ownership in the real property reverting to him if the condition terminating the determinable fee occurs.

Strict application of the Rule is both harsh and relentless. The Rule’s proper application pops up in some bizarre circumstances, such as the possibility of children born to very old or young people, future unborn widows to existing groomsto-be’s, scenarios with a ridiculous amount of sudden synchronized death, or events that may not occur for decades—even though one expects them to be easily completed within the Rule’s boundaries. For example, a grant wherein “T, a testator, wills $100,000 to A and his heirs upon the probate of his will” founders upon the Rule as the will isn’t guaranteed to be probated within the Rule’s time limit. Students mastering the Rule via problem sets in study aids learn to consider all manner of unlikely schemes that theoretically could happen.

The Rule’s purpose is to reign in the application of executory interests so that tracts of land are not encumbered by perpetual interests that could potentially switch a tract’s ownership at the occurrence of some event many years later.

A commonly encountered executory interest that violates the Rule is one where the grantor conveys an interest to a first party and his heirs, but if something happens (or stops happening) on the captioned tract in the future, the interest goes to a second party and his heirs. The executory interest of the second party violates the Rule because the event described may not be triggered for a period longer than the lives in being plus twenty-one years. A simpler variation is that the grantor keeps the interest presently, but if something happens (or stops happening) in the future on the captioned tract, the interest goes to another party and his heirs. In either case, the Rule requires the event to happen but, as described, the event may happen 1, 10, 100 or 1000 years later. Therefore, application of the

Article I, section 26 of the Texas Constitution expressly provides: “Perpetuities… are contrary to the genius of a free government and shall never be allowed….”4 In Texas, the Rule states that no interest is valid unless it must vest, if at all, within twenty-one years after the death of some life or lives in being at the time of the conveyance. The Rule requires that a challenged conveyance be viewed as of the date the instrument is executed, and it is void if by any possible contingency the grant or devise could violate the Rule.

In Texas, the Rule is harsh as it unravels instruments upon execution and can be a trapdoor to malpractice for unwary attorneys. Hence, various mechanisms have been introduced into property law to soften application of the Rule. For example, Missouri, Oklahoma, and Texas have adopted a reform known as “immediate reformation.” These statutes allow (or direct) 3

courts to interpret an interest found to be under the shadow of the Rule in such a way so that it avoids the violation so long as that interpretation matches the conveyor’s intent. For example, Tex. Prop. Code Ann. §5.043(a) (2003) requires that:

domains for centuries with legalese. State constitutional prohibitions against “perpetuities,” like the comparable constitutional prohibitions against the fee tail, were cued by opposition to legal tricks that permitted surface owners to keep land within their families for generations by making the land practically unsellable by descendants. Modern commercial arrangements between sophisticated parties with access to counsel, such as those that give rise to oil and gas conveyances, rarely have this undesirable effect.

Finally, there is the fundamental nature of the real property at issue. Minerals are not habitable like the surface and yet are often much more valuable, at once less familiar and more fungible, and courts have seemingly sensed this difference.

Within the limits of [the Rule], a court shall reform or construe an interest in real or personal property that violates [the Rule] to effect the ascertainable general intent of the creator of the interest. A court shall liberally construe and apply this provision to validate an interest to the fullest extent consistent with the creator’s intent. 5 Another alternative application of the Rule is the “wait-and-see” approach. Under this approach, the interest threatened by application of the Rule is nevertheless valid even if it violates the Rule at execution if, in fact, the interest either vests or terminates during the vesting period provided for in the instrument. Only if it has not vested or terminated during the permissible vesting period is the interest deemed invalid under the Rule. Several states have adopted variations of the wait-and-see approach, such as Ohio, West Virginia, and Vermont, or had it in the past, like Pennsylvania.

Still, avoiding pitfalls is the work of sound drafters in the oil and gas realm. When mindful of the realities of the business, opportunities avail themselves for practitioners to avoid the Rule.

For example, does an oil company really care about still acquiring a top lease if it hasn’t vested in its possession after twenty years? Even ten years? Why not limit application of a top lease to a shorter term that reflects the horizon of realistic development plans and shelters the instrument from the Rule? The best quiet title action for a possible defendant is the one exorcised at spawning.

What If No One Cares?

The “200-year Test”

Many conveyances that could be subject to the Rule are not challenged. Case law regarding application of the Rule is made more capricious by the fact that parties claiming the Rule should apply in particular situations may look grasping by trying to unravel a settled deal and subsequent conveyance. This posture possibly explains reluctance by some courts to apply the Rule. In addition, times and attitudes have changed— dukes and earls have yielded to modern oil and gas practice. The Rule had its origin in England as a judicial reaction to labyrinthine estate schemes that were intended to tie up family

One simple trick (sounds like a clickbait internet ad) to develop a sort of “spidey sense” about when the Rule might apply is to consider the following question when evaluating any interest you think is imperiled by the Rule: Because of this clause within this interest, 200 years from now, could something happen that would make the interest in question change ownership over to a third party? I picked 200 years because no one lives that long, minus twenty-one years, and it is a nice round number of students remember. Do not fall for the head4

fake—we are talking about interests going off to another party, not (typically) back to the grantor!

In the oil and gas context, the “something” that “happens” is often the cessation of production in paying quantities, but it could be a preferential right or pooling agreement in a cross-conveyance state. Could that cause a defeasible interest to end and another to start, say, 200 years from now?

Your “spidey sense” should be tingling when looking at various “top leases” and “top royalties” and such interests that purport to pop up whenever another ends, maybe 200 years from now!

in 1990, a Georgia opinion that allowed a mining lease with a fifty-year term.6 With that validation, it appears that the modern oil and gas lease is safe from application of the Rule.

Renewal of Leases Options allowing for the renewal of property rights that are of indeterminate length can potentially run counter to the Rule. While the case law is unsettled in some instances, with some courts preferring to not apply the Rule because of other considerations, most courts have generally found the Rule applicable to options to purchase and repurchase real property. Although leases are considered real property in some states, a case considering the application of the Rule to a lease with a perpetual option to renew declined to apply it. 7 Approximately thirty years later, another California court of appeals discussed in dicta why a perpetual option to renew an oil and gas lease did not violate the Rule as it was real property and could be distinguished from “ordinary” commercial leases. 8 A court in Canada did not see the distinction, however, and applied the Rule to a similar perpetual renewal option, excising it from the contested lease. 9

Oil & Gas Leases Since the possessory working interest of minerals, or at least the exclusive license to develop them, reverts to the mineral owner at the end of an oil and gas lease, the leases themselves would seem to be largely removed from concerns of violating the Rule. While this is largely true outside of lease renewals and top leases (covered later), it has not always been so. The modern lease, with its fixed terms followed by a term dependent on production, is the result of various development schemes that have been tried and forgotten over the last 150 years. Fixed term leases, wherein the primary term was fixed and followed by no secondary term via a habendum clause, were popular at the dawn of the industry.

Soon “no-term” leases became ascendant, being defined as “a lease that allows a lessee to extend the primary term indefinitely by paying delay rentals or nominal fixed royalties.” Both are effectively extinct today.

Top Leases Top leases are prevalent and contentious in the oil patch, raising concerns related to the Rule as they are interests that may not vest for as long as the existing “bottom” lease is in effect, preventing the leasehold interest from reverting to the mineral owner.

The Texas Supreme Court considered the application of the Rule to a “top deed” in Peveto v. Starkey. 10 Far less common than a top lease, the top deed involved a conveyed terminable royalty lasting “for a period of fifteen years” and “as long thereafter oil, gas or other minerals, or either of them is produced….in paying commercial quantities.”11 Thirteen years later, the

Depending on the local case law’s interpretation of when possession of the minerals takes place, title to the minerals under no-term leases may not become possessory until minerals are actually produced, raising the specter of the application of the Rule. Fortunately, the first half of the 1900s saw a series of cases that buried that notion, culminating later with Parker v. Reynolds 5

grantors executed a second royalty deed, which according to its express terms, would “become effective only upon the expiration” of the initial, terminable royalty. 12 The validity of the second deed was soon challenged as void per the Rule. 13 The Court held that the second royalty was invalidated by application of the Rule, stating “[t]he words ‘effective only upon’ created a springing executory interest in [the grantee] which may not vest within the period of [the Rule]; therefore, the deed is void.”14

vesting is postponed for an indefinite time that may outlast the period of the Rule.

The Hamman court also held that a top lease that runs afoul of the Rule cannot be ratified whatever the status of the bottom lease. 23 This would seem contradictory to other Texas cases where a grantee in a conveyance could later ratify an invalid instrument once the reason for its invalidity was removed. Although the decisions may seem contradictory, it is possible that the Hamman court was concerned that landowners may inadvertently ratify previously void leases by executing division orders or other instruments that contain specific language of ratification. This concern can hardly rise to the level of constitutional policy, however, for the problem can be dealt with on a case-by-case basis by requiring the beneficiary of lease ratification to show that the other party understood the full effect of his or her actions. It is difficult to articulate any state policy that would disallow a knowing and informed ratification of a top lease after the bottom lease terminates.

The cases in Texas continued with Hamman v. Bright & Co..15 In the early 1950’s, John and George Hamman leased approximately 19,000 acres to Shell Oil Co. and 1,800 acres to Superior Oil Co. (the “bottom leases”). 16 Shortly thereafter, they executed two top leases to John Hamman, Jr. that covered the land leased to Shell and Superior. 17 These top leases provided for a ten year, primary term that would commence “after and subsequent to the forfeiture, or to the expiration” of the bottom leases.18 The top leases also stipulated that during the existence of the bottom leases “the rights, interests, estate, privileges and royalties, as fixed thereby, of said Lessors shall remain vested in . . . said Lessors . . . .” 19 Subsequently, a dispute arose between the lessors and an assignee under the top leases over payment of royalty and wrongful pooling. 20 A remote purchaser of part of the lessor’s mineral estate was joined as a party and asserted that the top leases were void under the Rule.21

Top leases and the Rule present drafting challenges. The result in Hamman may have been different if the top lease had contained a clause stipulating that the lease “is granted on lessor’s reversionary interest and is hereby vested in interest, but is subject to an existing oil and gas lease and will become possessory only upon the expiration of that lease.” This language avoids the perpetuities problem by granting the top lease in the lessor’s possibility of reverter. Although a possibility of reverter is a future interest, it is presently vested, and the Rule voids only interests that may vest too remotely. If an interest is vested at the moment of creation, it is not affected by the Rule, even though the interest may not become possessory for an indefinitely long period. A device similar to the one suggested by the language in the question was used in Bowers v.

Following the lead of Peveto, the court held that the top leases were void because they would not vest until the termination of the bottom leases.22 Since the Rule invalidates any interest if there is any possibility, however unlikely, that it may vest beyond lives in being plus twenty-one years, any interest that will not vest until oil or gas production terminates is invalid because 6

Taylor, 24 and successfully survived a challenge that the grantee’s interest violated the Rule.

later had a dispute with El Paso, which was the purchaser of the lessee’s gas as well as its lessor, however, and as part of the dispute settlement the lessee surrendered its lease to El Paso in return for receiving a transfer of the mineral fee. 28 Although there was no break in production as a result of the dispute of the settlement transactions, Medallion’s overriding royalties were held to have terminated. 29 The court pointed out that the assignment stated that the overriding royalties would extend to and include renewals and extensions of the oil and gas, but that here the lessee did not acquire a new or extended lease, but received a fee interest in the mineral estate. 30

Another method of avoiding the Rule is to use a clause that recites that the lease is subject to an existing lease, states it shall become effective upon the expiration of such lease, but further provides that if the existing lease has not expired within one year (or whatever period under twenty-one years with which the lessee is comfortable) after its primary term, the top lease automatically terminates. This method of avoiding the Rule should work in most situations.

It would not work in the highly unlikely situation where the bottom lease has more than twenty years remaining in its primary term—a fact that should be evident when choosing a clause to avoid the Rule.

Defeasible Term Interests A deed conveying or (more commonly) reserving an interest in minerals for a fixed term of years and so long thereafter as minerals are produced creates and typically immediately vests a defeasible property interest. A common example would be the conveyance of a fee simple absolute in the surface and minerals subject to a reservation of a portion of the mineral estate lasting as long as production of minerals is maintained, commonly after a set term of years.

Such reservations read much like the habendum clause in an oil and gas lease.

Overriding royalty, being carved out of the working interest in a lease, is susceptible to being “washed out” when the lease expires and then the tract is re-leased. In some instances, lessees and lessors have conspired to allow a lease encumbered by an overriding royalty to expire so that another lease can be issues that is not subject to the override. It can be difficult to draft a clause which will protect the owner of the overriding royalty from a top lease washout at the creation of the override without running afoul of either the Rule or the statute of frauds. The former problem can be avoided by providing at severance that the overriding royalty applies only to new leases executed within twenty-one years.

Of all the oil and gas-related interests that could run afoul of the Rule, defeasible term interests are probably the most like “traditional” real property interests in that the instruments at peril may not be seen as specialty instruments like oil and gas leases, joint operating agreements, pooling agreements, or subdivided interests of the mineral estate like royalty or executive interests, each of which are more commonly owned and exchanged between parties familiar with the business. In contrast, defeasible term mineral interests are simply defeasible term interests covering the “dirt” instead of the surface and which are more commonly reserved by individuals. As such, these interests generally

Drafting to cover all contingencies is still difficult. GHR Energy Corp. v. TransAmerican Natural Gas Corp.,25 provides a good illustration.

El Paso Natural Gas Co., which owned the land in question, leased it to TransAmerican, which assigned an overriding royalty to Medallion Oil Company. 26 The assignment specified that the overriding royalty would apply to any extensions and renewals of the underlying lease. 27 The lessee 7

might seem less likely to receive the “you’re in the oil business, you get a pass” treatment regarding application of the Rule.

solve, the Court held that application of the Rule in this instance would not serve its purpose.

Most recently, Kansas has wrestled with the nature of defeasible term interests in the case of Jason Oil Co. LLC v. Littler.36 On December 30, 1967, Frank Littler, as Grantor, executed two deeds conveying tracts of land situated in a single section located in Rush County, Kansas, to two couples: (i) Franklin G. Littler and Elaine Littler and (ii) Ruby I. Myers and George E. Myers, as the Grantees therein.37 The east half of the section was conveyed to the first grantee couple, and the northwest quarter of the section was conveyed to the second grantee couple. 38 Both deeds stated, “[e]xcept and Subject to: Grantor saves and excepts all oil, gas and other minerals in and under or that may be produced from said land for a period of twenty years or as long thereafter as oil and/or gas and/or other minerals may be produced therefrom and thereunder.”39 Upon the Grantor’s death in 1973, the Rush County probate court distributed the grantor’s estate, including the reserved mineral interest, to the grantor’s heirs.40

Still, courts continue to pass over opportunities to cull such suspect instruments with the Rule. In ConocoPhillips Co. v.

Koopmann, the Supreme Court of Texas held that the Rule did not impact an NPRI reservation that lasted for fifteen years and as long thereafter as production continued in paying quantities.31 The Court started by opining that the fee simple interest in the NPRI was certain to end, either because production in paying quantities stopped or because all the producible minerals were extracted. 32 For these reasons, the grantor’s reserved interest was ruled similar enough to a vested remainder merely because the grantee could take possession upon the expiration of the former estate.33 Accordingly, the Court changed this niche application of the Rule in Texas: it will not void a mineral deed if, regardless of the grant or reservation, the holder of the future remainder interest is at all times ascertainable and the prior estate is “certain” to terminate. The Court appeared to take an expansive view of “certain to terminate” in that the words “production in commercial quantities” in the disputed reservation and the fact that reservoirs of oil and gas are indeed finite was enough to convince the Court the reservation would certainly end. 34

On December 30, 1987, the twenty year term ended, along with any drilling activity or further production, and the term interest expired. 41 At this point, the reserved mineral interests vested in the Grantees’ successors. 42 Almost thirty years later, in 2016, a producer named Jason Oil Co. leased from the Grantees’ successors.43 Jason Oil Co. sued to quiet title in itself after the Grantor’s heirs claimed the leases were not valid because the underlying mineral interests sprang from springing executory interests subject to the Rule and thus, void.44

Ultimately, the Court held that in an oil and gas context, where a defeasible term interest is created by reservation, leaving an executory interest that is certain to vest in an ascertainable grantee, the Rule does not invalidate the grantee’s future interest. 35 From a public policy perspective, recognizing the modern aspect of oil and gas transactions over the late medieval roots of the problems the Rule was originally crafted to

At trial, the district court held that the contested interest reserved by the decedent was a defeasible term interest, but added some falderal about how the future estate reserved to the Grantees was a reversion not possibly subject to 8

the Rule as it did no harm to the public policy of using the Rule to ease restrictions on alienation.45 An appeal to the Kansas Supreme Court followed, where the Court was asked to determine whether the prevalent practice of reserving a term interest in minerals that continues so long as there is production creates a springing executory interest in violation of the Rule.46 To starters, the Court stated that because no binding precedent existed in Kansas, it was “free to decide if the Rule should apply” in this situation. 47 Thus fortified, the Court then held that the future interest could become possessory in the Grantees more than twenty-one years after the death of the last of the relevant parties, and therefore, it technically violated the Rule. 48 The Court went on to explain, however, that the interest originally created in the Grantees was not a reversion, but rather a present, vested interest to which the “Rule is simply inapplicable.” 49 From a broader policy context, the Court, citing Koopmann, declined to apply the Rule, noting the “chaos” that would result in the realm of oil and gas title.50

generally thought to consist of five components: (1) the right to develop (the right of ingress and egress); (2) the right to lease (the executive right); (3) the right to receive bonus payments; (4) the right to receive delay rentals; and (5) the right to receive royalty payments. These attributes, when taken together, are often referred to as a “bundle of sticks,” and it has been recognized that individual “sticks” can be sold while others are retained. While no case law directly relating the Rule to the right to collect bonus and rentals was found, the right to receive royalty and the executive right have had brushes with the Rule in case law.

Non-Participating Royalty Interests A freestanding royalty or non-participatory royalty interest (NPRI) is an expense-free real property mineral interest that does not participate (hence the name) in collecting bonus or delay rentals, or participating in leasing, exploration, and development. This interest is “nonpossessory in that it does not entitle its owner to produce the minerals himself,” as the Texas Supreme Court has described it, going on to say the NPRI “merely entitles its owner to a share of the production proceeds, free of the expenses of exploration and production.” 51 The size of an NPRI can be expressed in two general ways: the NPRI can be reserved or conveyed as a fixed fraction of gross production, commonly 1/16, or it can “float”—being dependent upon the lessor’s royalty in the existing lease and every lease covering the captioned land thereafter. In the second instance, the NPRI fraction is typically multiplied by whatever lessor’s royalty is found in whatever oil and gas lease covers the captioned land at any particular time.

Oil and gas practitioners ought to breathe easier after these rulings as it has long been commonplace for grantors to reserve defeasible freestanding royalties when conveyancing minerals. Applying the Rule as promoted by the losing party would have made all such royalty reservations perpetual, invalidating hundreds—if not thousands—of similar interests not yet litigated.

Royalty and Executive Interests A fee simple absolute ownership interest in minerals, such as hydrocarbons, can be further split into more elemental components that relate to development and recovery of profits for development. In Texas, the mineral estate in a specific mineral, such as uranium, or particular group of minerals, such as oil and gas, is

Floating NPRIs have run afoul of the Rule because some jurisdictions, namely Kansas, have assumed that such conveyances only vest when production occurs. To start, the court in Miller v.

9

Sooy52 opined in dicta that NPRIs to be paid by as-yet non-existent leases would violate the Rule. A quarter of a century later, the Kansas Supreme Court again endorsed the view of Miller in its opinion of Lathrop v. Eyestone.53 In the case, the captioned tract was covered by an oil and gas lease. 54 The lessor/mineral owner then acted as grantor and, using two distinct instruments, attempted to convey a fractional interest in the existing lease and interests in the bonus and royalty from any future leases. 55 Thereafter, the grantor conveyed his own reserved interests to another party. 56 This wily newcomer soon challenged the first doublebarreled conveyance with a quiet title action brought on grounds that the conveyance of future royalty interests from leases not yet taken violated the Rule, and the Kansas Supreme Court agreed.57

only if and when future leases were executed. 59 The court held that the grantor’s retained NPRI was a presently vested interest because there was no language that expressly delayed vesting until some future event. 60 The language relied on by the grantee’s successor merely made clear that the grantor’s enjoyment of the interest depended upon the execution of future leases and future production.61 That no suspect language was found in the instrument in Luecke to invoke the Rule leaves open the possibility that future instruments with different language might not be so lucky.

The Executive Right The executive right has been defined by Smith and Weaver in their oil and gas law treatise as “the right to take or authorize all actions which affect the exploration and development of the mineral estate … [including] the right to engage in or authorize geophysical exploration, drilling or mining, and producing oil, gas, and other minerals.”62 However, courts rarely use the term in this broad sense. More commonly, they equate the executive right with the right to execute oil and gas leases.

The Rule has played a significant role in determining the validity of perpetual NPRIs in Kansas. Kansas appears unique in taking this position, however, and the validity and scope of the application of the Rule to NPRIs has been repeatedly questioned by the Kansas lower courts.

Meanwhile, the highest courts in Arkansas, Alabama and Florida have declined to apply the Rule, finding it archaic.

The executive right can, in most jurisdictions it appears, be held independently of any other right in the minerals as in Texas. Some authority exists for the proposition that an exclusive executive right divorced from any ownership interest in the mineral estate is subject to the Rule.

In Dallapi v. Campbell, the California Supreme Court treated such a right as a special power of appointment and held that it was void because it could be exercised beyond the period permitted by the Rule.63 The result would likely be different in a jurisdiction like Texas that follows the Day & Co. view that the executive right is a severable interest in property because of the conceptually different nature of the executive right. If the executive right is a severable interest in property, like a royalty or an easement, it vests immediately

Occasionally litigants in other jurisdictions argue that the language of a specific instrument compels the application of the Kansas rule. For example, the grantor in Luecke v. Wallace, reserved “an undivided one-half (1/2) nonparticipating interest in any and all oil, gas and mineral royalties reserved by Grantee, his heirs and assigns at any time in the future and which may be payable to Grantee, his heirs and assigns under any future lease of the property.” 58 The grantee’s successor argued that the grantor’s retained interest violated the Rule both because it was contingent upon a future reservation by the grantee or his successors and because it vested 10

in its holder. The Rule is inapplicable to presently vested interests, regardless of their nature.

sell—it did not compel a sale itself like the option nor potentially hinder alienation but instead just redirected the sale.68 Further, the Court noted that the pref right in the present case only lasted as long as the JOA and the leases that comprised it, and thus, holding that a pref right that was so limited does not violate the Rule. 69

Joint Operating Agreements (JOAs) and Pref Rights The Rule can menace JOAs in a number of circumstances, some more obvious than others.

One of the conspicuous clauses that could incur the Rule is the “preferential right to purchase” clause. This optional clause, currently somewhat unpopular, gives signatories the right to purchase another signatory’s interest if it attempts to sell a property subject to the JOA. An early Texas case suggested the “pref right” clause would fall outside coverage of the Rule, and more contemporary commentators agreed. Then, in 1967, the Oklahoma Supreme Court considered a case wherein a party was granted the option to receive an assignment of any possible future lease over certain captioned minerals if those minerals were ever leased by the grantor. 64 The Court invalidated the pref right interest, considering it a contract that created an interest in real property instead of a personal contractual right.

After this, when courts were asked to choose between Melcher or Producers Oil Co., most went with the latter. For example, the New Mexico Supreme Court, when asked to consider application of the Rule to an option to repurchase a working interest in a lease that would arise after a certain production threshold was met, decided against it. 70 The litigation had erupted when the party retaining the repurchase right attempted to assign it to a third party.71 After determining that the right was assignable, the Court, drawing from Producers Oil Co., held that since the option was likely to vest (or not) within a reasonable amount of time—an interval largely dependent on the geology of the field and reservoir dynamics—immediate application of the Rule to the option was forestalled even though the option had no express expiration date. 72 In such an instance, the Court held, the language of the option would instead be construed to imply a reasonable time limit for vesting, a result similar to the wait-and-see approach to applying the Rule as described above.73

Later, this led to a federal district court, applying Oklahoma law, to invalidate a pref right provision in a JOA.65 The court, after opining that it seemed the Rule’s purpose would not be advanced by application in the present case, still felt compelled to apply the Rule due to the similarity of the facts and judicial analysis found in Melcher.66 After the case was appealed to the Tenth Circuit Court of Appeals, a certified question was sent by that federal court to the Oklahoma Supreme Court regarding the Rule’s application to the pref right clause in the JOA. 67 The Oklahoma high court answered that the pref right was distinguishable from an option as found in Melcher as it was limited to activation when the owner of the right so encumbered sought to

In Texas, pref rights also appear safe from the Rule, with one court recently boldly stating, “[i]n Texas, a preferential right to purchase or a right of first refusal does not violate the [Rule].” 74 This safety lies in Texas courts considering that the Rule was devised to prevent “unreasonable” restraints on alienation.75 Since the pref right does not itself prevent alienation, but rather merely determines who will have the first right to obtain a certain property when and if the owner decides to sell it. This is in contrast to the option-to11

purchase described above in Oklahoma and in the Texas case of Maupin v. Dunn, in which a court held an “option agreement was illegal and void from its inception and violated the [Rule].”76

36

See Jason Oil Co. v. Littler, 446 P.3d 1058 (Kan. 2019).

Id. at 1060.

38 Id. 39 Id. 40 Id. 41 Id. 42 Id. 43 Id. 44 Id. 45 Id. 46 Id. 47 Id. 48 Id. 49 Id. 50 Id. 51 Plainsman Trading Co. v. Crews, 898 S.W.2d 786, 789 (Tex. 1995).

52 Miller v. Sooy, 242 P. 140 (Kan. 1926).

53 See, e.g., Lathrop v. Eyestone, 227 P.2d 136, 143–44 (Kan. 1951).

54 Id. at 138–40.

55 Id. 56 Id. 57 Id. at 144.

58 Luecke v. Wallace, 951 S.W.2d 267, 272 (Tex. App.— Austin, n.w.h. (1997).

59 Id. at 273.

60 Id. at 274.

61 Id. 62 Ernest Smith & Jaqueline Weaver, Texas Law of Oil and Gas § 2.6 (2d ed. 2000).

63 Dallapi v. Campbell, 45 Cal. App. 2d 541, 545 (114 P.2d 646 (1941)).

64 Melcher v. Camp, 435 P.2d 107, 112 (Okla. 1967).

65 Producers Oil Co. v. Gore, 437 F.Supp. 737 (E.D. Okla.

1977), vacated, 634 F.2d 487 (10th Cir. 1980).

66 Id. at 742.

67 Producers Oil Co. v. Gore, 610 P.2d 772 (Okla. 1980).

68 Id. at 774.

69 Id. at 776.

70 El Paso Prod. Co. v. PWG P’ship, 866 P.2d 311 (N.M. 1993).

71 Id. at 315.

72 Id. at 316.

73 Id. 74 Jarvis v. Peltier, 400 S.W.3d 644, 652 (Tex. App.—Tyler 2013, pet. denied).

75 Forderhause v. Cherokee Water Co., 623 S.W.2d 435, 438-39 (Tex. Civ. App.—Texarkana 1981); rev’d on other grounds, 641 S.W.2d 522 (Tex. 1982).

76 Maupin v. Dunn, 678 S.W.2d 180, 182 (Tex. App.— Waco 1984, no writ).

37

Duke of Norfolk’s Case, 3 Ch. Cas. 1, 22 Eng. Rep. 931 (1682).

2 Id. 3 Id. 4 Tex. Const. art. I, § 26.

5 Tex. Prop. Code Ann. § 5.043(a) (2019).

6 Parker v. Reynolds Metals Co., 747 F. Supp. 711, 713 (M.D.Ga. 1990).

7 See Becker v. Submarine Oil Co., 204 P. 245, 247 (Cal.App. 1921).

8 See Epstein v. Zahloute, 222 P.2d 318, 319 (Cal.App.2d 1950).

9 See Canadian Export Gas & Oil Ltd. v. Flegal, 80 D.L.R.3d 679 (1978) 1 W.W.R. 185 (Alta.S.Ct., Trial Div. 1977).

10 Peveto v. Starkey, 645 S.W.2d 770, 771 (Tex. 1982).

11 Id. 12 Id. 13 Id. at 772.

14 Id. 15 Hamman v. Bright & Co.,924 S.W.2d 168 (Tex.App.— Amarillo 1996).

16 Id. at 170.

17 Id. 18 Id. at 172.

19 Id. 20 Id. at 170–71.

21 Id. at 171.

22 Id. at 172–173.

23 Id. at 174.

24 Bowers v. Taylor, 263 S.W.3d 260 (Tex. App.—Houston [1st Dist.] 2007, no pet.).

25 GHR Energy Corp. v. TransAmerican Natural Gas Corp.,972 F.2d 96 (5th Cir. 1992).

26 Id. at 97.

27 Id. at 99.

28 Id. at 100.

29 Id. 30 Id. 31 ConocoPhillips Co. v. Koopmann, 547 S.W.3d 858, 865 (Tex. 2018).

32 Id. 33 Id. at 873.

34 From a geologic perspective, such production is not absolutely certain to terminate within a non-geologic period of time as a reservoir could conceivably be replenished as fast as production occurs. In addition, as history has shown, humans have proven very technically adept at finding new ways to wring more and still more hydrocarbons from a discrete formation (hydraulic fracturing, etc.), continually pushing back the date of reservoir exhaustion.

35 Koopmann, 547 S.W.3d at 873.

1

12

Unprecedented Price Crash – What Happened?

crude. This drop in demand put unprecedented downward pressure on the price of oil.

By: Ken Rice Adjunct Professor South Texas College of Law Houston

The second factor greatly contributing to the price crash was the brief price war that emerged between two members of the Organization of the Petroleum Exporting Countries organization (OPEC+): Saudi Arabia and Russia. In March of 2020, Russia refused to agree to additional production cuts requested by OPEC. Saudi Arabia responded by reducing their price to Asian buyers and announcing that crude production would be increased from just under ten million barrels per day to over twelve million barrels per day, putting additional downward pressure on the price of crude.2 Eventually, the members of OPEC+ were able to reach agreement on production cuts and stabilize supply levels, but this initial disagreement greatly contributed to the price crash.

Although the oil and gas industry has seen significant price volatility since the seventies, never before have we seen the level of volatility as experienced earlier this year. Not only did the crude price crash, but for the first time in history, crude futures for West Texas Intermediate (WTI) went negative, meaning that sellers of crude were actually willing to pay buyers to take future deliveries of the product. What caused this unprecedented event? What were the series of events culminating in the widest crude price swings and most severe price crash in the history of the industry? This article addresses those questions.

Evolution of Covid-19

Overview

The first cases of COVID-19 were reported in December of 2019, in Wuhan, China. 3 Within the next few weeks, the disease spread to other parts of China, due mainly to the size and transient nature of the Wuhan population. The Chinese government attempted to prevent the spread of COVID-19 by imposing a mandatory quarantine in Wuhan on January 23, 2020, but by that time, millions of residents had already left the city.

Within a month from the first reported case, the virus had spread to several other countries, including Italy, the United States, and Germany. 4 On January 22, 2020, the World Health Organization (WHO) Director General convened the WHO Emergency Committee to discuss whether to declare the outbreak in China as a public health emergency of international concern.

The committee members could not reach a consensus at that meeting and requested to reconvene ten days later after further information gathering and additional consideration of the

At the macro level, the price crash of early 2020 was caused by two primary factors. The first was the spread of the COVID-19 virus, which had huge negative impacts on the global economy and demand for hydrocarbons.

Governmental responses around the world resulted in significant oil and gas demand destruction as governments took measures to slow the spread of the disease.

These measures included shelter-in-place requirements for many countries, the closing of businesses and other non-essential sectors of the economy, and the halting of international travel. 1 Although the effectiveness of these measures in preventing the spread of the disease varies from country to country and is the subject of some debate, there is general acceptance that these preventive measures taken by governments, while successfully stemming the spread of the disease, drastically reduced the level of global demand for 13

matter. After a WHO delegation traveled to China on January 28, 2020, the WHO Emergency Committee reconvened on January 30, 2020, and the Director-General, on the recommendation of the EC, declared the novel COVID-19 outbreak (2019-nCoV) a Public Health Emergency of International Concern (PHEIC). 5 Approximately five weeks later, the WHO declared the virus a global pandemic.

governmental mitigative measures have had on global hydrocarbon demand.

Global demand for hydrocarbons As the virus continued to spread throughout the world earlier this year, governments began to enforce various restrictions on the movement of people and social interactions. These measures include, among other things, complete or partial lockdowns, curfews, closings of schools and nonessential businesses, and bans on public gatherings with large groups of people. 10 These restrictions significantly reduced demand for energy as they were implemented. Demand for jet fuel collapsed due to international travel restrictions. Demand for gasoline and other petroleum-based fuels used for transportation declined severely, causing unprecedented market imbalances between crude demand and crude supply. The International Energy Agency’s Global Energy Review 2020 captures the impact of COVID-19 on energy demand in general and crude demand in particular. In the period of a single month, between mid-March and mid-April, the global share of energy use impacted by governmental restrictions increased from 5% to 50%. Further, the IEA’s analysis indicates that countries with complete lockdown measures in place faced an average 25% weekly decrease in energy demand, while countries with partial lockdowns averaged an 18% weekly decline in energy demand.11 Overall, during the first quarter of 2020, global energy demand declined by just under 4% due to governmental actions. By the end of April, just one month into the second quarter of 2020, more than four billion people, representing approximately 54% of the global population and just under 60% of global GDP, were impacted by governmental restrictions.12

The impact of COVID-19 on the global economy cannot be overstated. The virus spread rapidly and had an unprecedented impact on the major economies of the world, many of which are members of the OECD. The table below depicts currently the ten most affected countries with the highest number of cases to date and includes the date of the first known case in each country: 6

Country7

Confirmed Cases

Cumulative Deaths

Date first case reported 8

United States

9,868,389

236,042

1/21/2020

India

8,591,730

127,059

1/29/2020

Brazil

5,664,115

162,802

2/25/2020

France

1,857,309

41,062

1/23/2020

Russia

1,802,762

30,899

1/30/2020

Spain

1,381,218

39,345

1/31/2020

Argentina

1,262,476

34,183

3/2/2020

UK

1,237,198

49,861

1/30/2020

Colombia

1,155,356

33,128

3/5/2020

Italy

995,463

42,330

1/30/220

Mexico

967,825

95,027

2/28/2020 9

Although cases continue to rise and appear to have accelerated in certain countries recently, the mitigative measures governments implemented earlier this year were effective in slowing the spread of the disease, at least until recently. The following section describes the impact that these

The graph below depicts the percentage of the global population impacted by governmental containment measures over time. The graph 14

distinguishes between containment measures taken by governments based on the degree of severity of the measure, ranging from limited social restrictions to full lockdowns. In midJanuary 2020, roughly 20% of the world’s population was under some form of containment measure, consisting primarily of closings of schools and universities, as well as non-essential businesses. By mid-March, as the spread of the virus increased exponentially, some form of containment measures impacted practically the entire global population.

As can be expected, significant declines in oil demand were felt in most major economies of the world. The graph below compares the Y-O-Y decline in monthly oil demand from 2019 to 2020 among the world’s highest consuming regions.

The largest declines were seen in April and May, with a fairly steady recovery expected heading into the fourth quarter of 2020. Although we’ve seen an improvement in demand through midyear, if a second spike in COVID-19 cases emerges, which appears likely, recovering demand could begin to decline again.

13

15

The graph below shows the percentage of energy demand impacted by containment efforts.

January and February remained relatively flat at just under 5%. By mid-March, the percentage of global energy demand impacted by lockdowns (either full or partial) skyrocketed to over 50%, causing significant demand destruction and greatly contributing to the falling crude price.

The diagram below is prospective in nature in that it provides a projected breakdown of the anticipated change in energy demand by source, comparing 2020 to 2019. The most significant energy source impacted is expected to be oil, projected to fall by roughly 9% year-over-year.

This dramatic decrease in demand for crude oil is the primary contributor to the price crash.

14

16

15

crashing crude prices.19 This disagreement will be described below, but first a brief history of the creation and decisions of OPEC+ will be discussed.

In terms of actual impact on demand for oil and related products, crude demand was down approximately 5% during the first quarter of 2020, due mainly to restrictions on mobility and the sharp decline in aviation activity. Mobility and aviation account for nearly 60% of global oil demand. By the end of the first quarter, global road-based transport had fallen almost 50% below the 2019 average, while aviation was roughly 60% below the 2019 average. The data below illustrates the drop in road transport by region, as well as the drop-in global aviation activity.

In September 2016, Saudi Arabia and OPEC, along with Russia and several other non-OPEC countries, agreed to cooperate in reducing global crude supply, with the intent of stabilizing the global crude price. This informal alliance of OPEC and non-OPEC producers was dubbed "OPEC+,” and would be formalized at the “Joint OPEC-Non-OPEC Producing Countries’ Ministerial Meeting” in December of 2016, via an instrument called the Declaration of 20 Cooperation.

One month prior to the formal creation of OPEC+, OPEC member countries met on November 30, 2016, for the 171st OPEC Ministerial Conference and agreed to a production adjustment of 1.2 million barrels a day, effective January 1, 2017. Simultaneous with the OPEC agreement was the agreement of eleven non-OPEC members to reduce production by 558,000 barrels per day, effective as of January 1, 2017. 21 Non-OPEC member reductions would also be for six months, extendable for an additional six-month timeframe. This initial 1.8 million barrels per day reduction (1.2 million barrels by OPEC and 600,000 by OPEC+ members) was the first agreement reached by OPEC+, but was followed by numerous additional agreements to control production levels with a view to stabilizing prices. Below is a summary of subsequent OPEC+ meetings and the production level adjustments reached by the group since inception:

17

The IEA predicts that for 2020, oil demand could fall by 9%, or roughly 9 mb/d, which would reduce global oil demand to levels not seen since 2012. 18 The combination of drastically reduced demand for road transport and an even more severe decline in jet fuel was the most significant factor leading to the price crash.

OPEC Although the demand destruction caused by the COVID-19 virus was a major contributor to the fall in crude price, the other significant factor is the failure of OPEC+ to reach an agreement on production cuts. The failure of two key OPEC+ members (Saudi Arabia and Russia) to agree on volume reductions precipitated a price war between the two, with both producers announcing that they would be increasing production despite

● Second OPEC+ meeting held May 2017, where agreement was reached continue volume reductions for additional nine months, starting July 2017 to March of 2018.

16

of to an of

● Third OPEC+ meeting in November of 2017, with agreement that the volume adjustments agreed to in May would extend through the entire year of 2018. ● Fifth OPEC+ meeting in December of 2018, the group agreed to revise the initial 1.8 million barrels per day adjustment to 1.2 million barrels per day, starting January 2019, for a period of six months.

OPEC countries would reduce production by 800,000 barrels per day, while OPEC+ members would reduce production by 400,000 barrels per day. ● Sixth OPEC+ meeting was held in July of 2019, and the December 2018 volume reductions were extended from July 2019 to March 31, 2020. ● Seventh OPEC+ meeting held in December of 2019, where production cuts were increased to 1.7 million barrels per day by the group, while several additional countries, including Saudi Arabia, agreed to additional voluntary cuts in production, bringing the total reduction to 2.1 million barrels per day.

and resulted in prices falling even further than they had in the prior weeks due to declining demand. On March 6, 2020, the closing price for WTI was $41.14, and by the following Monday, WTI had fallen dramatically, closing at $31.05. 24 As a response to Russia’s refusal to implement production cuts, Saudi Arabia announced on March 9, 2020,,their decision to discount Saudi crude exports by between six and eight dollars to various regions of Asia, which caused a further decline in the crude price. 25 The following day, Saudi Arabia announced its intention to increase crude production from just under ten million barrels of oil per day to over twelve million barrels per day.26 Russia also announced its plan to increase production by approximately 300,000 barrels per day. 27 These actions collectively caused panic in the markets, exacerbating the price decline already caused by COVID-19.

Eventually, corrective action was taken by the group at the April 9OPEC+ meeting, where the group agreed to cut production by ten million barrels per day between May 1, 2020, and June 30, 2020, eight million barrels per day for the time period July 1to December 31, 2020 with a six million barrel per day reduction for the time period January 1, 2021, to April 30, 2022. 28 However, these corrective actions by OPEC+ were not sufficient to prevent the WTI futures price from continuing to slide steadily until reaching $36 on April 20, 2020. This was the first time in recorded history that prices had reached negative territory.

The price war emerged during the 178th (Extraordinary) Meeting of the Conference, which occurred on March 5, 2020. At the summit, in addition to extending the 1.7 million barrels per day cuts agreed to at the seventh OPEC+ meeting for the remainder of the year, OPEC members agreed on an additional production cut of 1.5 million barrels per day through the first half of 2020 (OPEC cuts of 1.0 million barrels per day; non-OPEC cuts of 500,000 barrels per day), subject to further consideration and discussion at the next OPEC+ meeting. 22 This additional increase brought the total proposed volume reduction to 3.6 million barrels per day, as compared to 2016. Russia refused to agree to these volume reductions on the basis that it was too soon to determine whether additional production cuts would serve as an adequate remedy to the falling commodity price. 23 Russia’s unwillingness to agree to the additional production cuts rattled the commodity markets

History of Pricing The past fifteen years have seen extreme crude price volatility. The crude price began to climb from around $30 per barrel in 2005 to a peak of just over $140 per barrel in 2008. In 2009, due to the global financial crisis, the price fell precipitously to just over $30 per barrel again, followed by fluctuations in price from between 17

concern that if drastic measures weren’t taken to reduce supply, crude storage capacity at Cushing, Oklahoma would become insufficient to store the crude being produced and shut-ins would be needed.31

$30 to $130 per barrel between 2009 and 2012.

Between 2012 and 2015, the price hovered between $70 and $110 per barrel range, then fell to levels ranging between $30 and $90 between 2015 and 2020. The graph below depicts the history of crude prices (Brent and WTI) dating back to 1987.

Impact of price crash on E&P Companies As a result of the price crash, exploration and production companies have been forced to take extreme measures by drastically reducing capital spend in light of decreasing revenues due to lower prices. Citing GlobalData analysis, Offshore Magazine reported that total CAPEX cuts by oil and gas companies had reached $85 billion as early as April 2020.32 The reduction in investment levels within the industry has been made even worse due to numerous bankruptcies that have taken place. The graph below shows the breakdown of CAPEX cuts by segment within the oil and gas industry, in both dollar terms and as a percentage of CAPEX for each oil and gas industry segment.

29

When focusing more closely on the six months or so leading up to the price crash of April 2020, prices were actually relative stable.

Prices hovered in the mid $50 per barrel range between October of 2019 and early March of 2020. However, in early March, the price began to fall steadily until by mid-April, after the full impact of COVID-19 was felt and OPEC+ failed to reach agreement on production cuts, WTI crashed to historic levels.

Prices reached negative territory for the first time in recorded history, falling to $36.78 on April 20, 2020.

30 33

Fortunately, WTI recovered quickly, reaching positive territory the following day and climbing to the $40 level by early June, where the price has generally remained. Governmental easing of social restrictions resulting in increasing demand for crude combined with OPEC+ agreement on production cuts have helped stabilize the price.

Outlook Covid cases appear to be increasing recently in various places throughout the world, although the distribution and deployment of vaccines should greatly stem the increasing number of cases going forward. The IEA projects in their Stated Policies scenario that global energy demand will grow beyond 2019 levels before

Crude storage capacity also contributed to the negative WTI price, as there was widespread 18

2025 as COVID-19 impacts reduce and long-term drivers prevail. 34 For oil and natural gas producers, reduced cash flows of current lower pricing require near term cost cutting and reduced investment measures.

Currently reduced investment levels are expected to increase again enabling the ability to meet recovering demand, as existing oil and natural gas supply reduces by natural depletion.

3, (Apr. 2020), https://www.iea.org/reports/global-energyreview-2020.

12 Id. at 5.

13 Id. at 6.

14 Id. at 6.

15 Id. at 20.

16 Id. at 15.

17 Id. at 18.

18 Oil Market Report 2020, IEA, (Apr. 2020), https://www.iea.org/reports/oil-market-report-april-2020 (detailing statistics on oil supply, demand, inventories, prices and refining activity, and oil trade for IEA and selected non-IEA countries).

19 Sam Meredith, OPEC+ fails to agree on massive supply cut, sending crude prices to 2017 lows, CNBC (Mar. 6, 2020, 12:12 p.m.), https://www.cnbc.com/2020/03/06/opecmeeting-coronavirus-weighs-on-oil-demand-as-oil-pricesfall.html.

20 Declaration of Cooperation, Organization of the Petroleum Exporting Countries (OPEC), (Dec. 10, 2016), https://www.opec.org/opec_web/en/publications/4580.htm.

(OPEC includes the following countries: Azerbaijan, the Kingdom of Bahrain, Brunei Darussalam, Equatorial Guinea, Kazakhstan, Malaysia, Mexico, the Sultanate of Oman, the Russian Federation, the Republic of Sudan, and the Republic of South Sudan).

1

Considerations for implementing and adjusting public health and social measures in the context of COVID-19, WHO, Interim Guidance (Nov. 4, 2020), https://www.who.int/publications/i/item/considerations-inadjusting-public-health-and-social-measures-in-the-contextof-covid-19-interim-guidance.

2 Jillian Ambrose, Saudi Arabia steps up oil price war with big production increase, THE GUARDIAN (Mar. 11, 2020), https://www.theguardian.com/world/2020/mar/11/saudiarabia-oil-price-war-production-increase-aramco.

3 Listings of WHO’s Response to COVID-19, WHO, https://www.who.int/news/item/29-06-2020-covidtimeline (last updated Dec. 28, 2020).

4 Fan, Jingchun et al., Epidemiology of Coronavirus Disease in Gansu Province, China, 2020, 26, 6, Emerging Infectious Diseases 1257, 1257 (Mar. 13, 2020), https://wwwnc.cdc.gov/eid/article/26/6/20-0251_article.

5 Listings of WHO’s response to COVID-19, WHO, https://www.who.int/news/item/29-06-2020-covidtimeline (last updated Dec. 28, 2020).

6 WHO Coronavirus (COVID-19) Dashboard, WHO (Mar. 1, 2021 5:03pm), https://covid19.who.int (providing real time data of the number of confirmed COVID-19 cases and deaths in countries across the world).

7 WHO Coronavirus (COVID-19) Dashboard, WHO, https://covid19.who.int/ (last visited Feb. 28, 2021, 5:31 PM).

8 Johns Hopkins Coronavirus Resource Center, New Cases of Covid-19 In World Countries., JOHNS HOPKINS UNIV. & MED., https://coronavirus.jhu.edu/data/new-cases (last visited Nov. 9, 2020).

9 Mexico Confirms First 2 Cases of Coronavirus, ASSOCIATED PRESS NEWS (Feb. 28, 2020), https://apnews.com/article/a7d2aaac19fc3022ba686ba91e7 d4395.

10 Considerations for implementing and adjusting public health and social measures in the context of COVID-19, WHO, Interim Guidance (Nov. 4, 2020), https://www.who.int/publications/i/item/considerations-inadjusting-public-health-and-social-measures-in-the-contextof-covid-19-interim-guidance.

11 Global Energy Review 2020: The Impacts of the Covid19 crisis on global energy demand and CO2 emissions, IEA,

22

Press Release, Org. of the Petroleum Exporting Countries, OPEC 178th (Extraordinary) Meeting of the Conference concludes (Mar. 5, 2020), https://www.opec.org/opec_web/en/press_room/5865.htm.

23 Irina Slav, The Reason Why Russia Refused To Cut Oil Production, (Mar. 12, 2020, 11:00 AM), https://oilprice.com/Energy/Energy-General/The-ReasonWhy-Russia-Refused-To-Cut-Oil-Production.html.

24 U.S. Energy Information Administration, http://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm (last visited Mar. 1, 2021.) (Providing Spot Prices for Crude Oil and Petroleum Products. In order to obtain data, view the history under daily values and then download XLS file).

25 Tak, Natasha. Oil Nose-dives as Saudi Arabia and Russia set off ‘Scorched Earth’ Price War, CNBC (Mar. 9, 2020, 5:33 PM), https://www.cnbc.com/2020/03/08/opec-dealcollapse-sparks-price-war-20-oil-in-2020-is-coming.html.

26 Jillian Ambrose, Saudi Arabia steps up oil price war with big production increase, THE GUARDIAN (Mar. 11, 2020, 8:09 PM), https://www.theguardian.com/world/2020/mar/11/saudiarabia-oil-price-war-production-increase-aramco.

27 Id. 28 Press Release, Organization of the Petroleum Exporting Countries (OPEC), The 9th (Extraordinary) OPEC and nonOPEC Ministerial Meeting concludes, (Apr. 9, 2020), https://www.opec.org/opec_web/en/press_room/5882.htm.

29 U.S. Energy Information Administration, Spot Prices for Crude Oil and Petroleum Products, EIA, http://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm (last visited Nov. 29, 2020).

30 Id.

19

31

Crude Oil Tanks: A Look Into Oil Prices and Storage., Brown Brothers Harriman (May 1, 2020), https://www.bbh.com/us/en/insights/private-bankinginsights/crude-oil-tanks-a-look-into-oil-prices-andstorage.html; Krien Van Beek, Crude Storage Broker: Remaining Global Oil Storage Capacity is “Maybe Less Than One Percent” (Apr. 24, 2020, 6:10 AM), https://www.cnbc.com/video/2020/04/24/crude-storagebroker-remaining-global-oil-storage-capacity-is-maybeless-than-one-percent.html.

32 Capex Cuts Reach More the $85 Billion, Offshore Mag. (May 4, 2020), https://www.offshoremag.com/home/article/14175262/capex-cuts-reach-morethe-85billion#:~:text=Integrated%20oil%20and%20gas%20comp anies,exploration%20budgets%2C%20and%20unsanctione d%20developments.

33 Id. 34 World Energy Model: Part of World Energy Outlook, IEA, 5, (Oct. 2020), https://www.iea.org/reports/worldenergy-model/stated-policies-scenario.

20

Force Majeure in the Time of COVID-19 By: Michael Miller Michael P. Miller, PLLC; affiliated with Sadler Law Group, PLLC “The man who smiles when things go wrong has thought of someone else he can blame it on.”

- Robert Albert Bloch While it is assumed that the reader is well acquainted with the concept of force majeure, the purpose of this article is to discuss the employment of a force majeure clause to excuse nonperformance due to executive orders issued by the federal and various state governments that prevented or encumbered workforce activity in an attempt to slow the progression of COVID-19.

This article identifies operative components of a typical force majeure clause and the normal analysis of the same usually undertaken by courts.

Although COVID-19 is the first worldwide pandemic in over 100 years1 and its global impact on all aspects of society has been monstrous, an analysis of its impact as to whether its effects could trigger an exercise of a force majeure clause is no different than that for any other event.

It may be interesting to note that the concept of Force Majeure dates back to Roman law under the names of “via major” or “vis divina,” used as an excuse for nonperformance due to unforeseeable and “irresistible” events.

Subsequently, the French included this concept as a “force majeure” in the French Civil Code dating back to 1804.2 In common law, the concept began an adoption of an existing excuse for nonperformance due to impossibility, and the English embraced the concept to forgive nonperformance when there was an “Act of God or the existing King’s Enemies” that prevented total performance. 3 Unlike its common law cousins of impossibility, impracticability and

frustration of purpose, force majeure is a purely contractual concept which otherwise does not exist in current common law. It should be noted that while there are remnants of Texas law that treat impossibility and impracticability differently, over time Texas courts have gradually blended these concepts and now recognize no functional distinction between impossibility, impracticability and frustration of purpose. 4 The purpose of a force majeure clause is to allocate risks for nonperformance caused by events which are superior and cannot be overcome by a contracting obligor, by providing a defense for the nonperformer. Generally, the nonperformer bears the burden of proof to establish such defense. 5 Typically, there are two operational components found in a force majeure clause: (1) catch-all language, and (2) identification of express events. Catch-all language exists in an attempt to excuse nonperformance of contract terms due to the occurrence of an unforeseeable event that has made performance impossible or impracticable.

To be an effective agent of excused performance under the catch-all term of a force majeure clause, it is important that such event was unforeseeable at the time the parties entered into the contract. 6 Catch-all events are usually caused by acts of God (flood, hurricane, fire, earthquake, etc.) or uncontrollable events caused by people (unanticipated legislation and changes in agency rules, riots, strikes, wars, terrorist acts, severe civil unrest). A typical catch-all force majeure term frequently found in an oil and gas lease effectively states that should the Lessee be prevented from complying with any express or implied condition or covenant of the lease, from conducting drilling or reworking operations thereon or from producing oil or gas therefrom by reason of a force majeure, then while so prevented, the Lessee’s obligation to comply with such covenant or condition shall be suspended, and Lessee shall not be liable in damages for

failure to comply therewith, and the lease shall be extended while and so long as the Lessee is so prevented by any such cause from conducting drilling or reworking operations or from producing oil or gas from the lease premises.

Terms found in typical force majeure clauses tend to evolve with the times, as events once not foreseeable become foreseeable. For example, impossibility of performance due to terrorism is a more common express term post 9/11. Limited egg production caused by disease is frequently an express excuse for nonperformance in contracts with egg producers after the outbreak of avian influenza in 2014-15. Impossibility due to shutdowns and impossibility due to government regulations, pandemics, epidemics, and contagion outbreaks are foreseeable today. Therefore, force majeure catch-all language in a post-COVID-19 contract should not be relied upon to excuse performance due to the results caused by a future (or current) pandemic or resulting government restrictions. Accordingly, such events should be included as an express event that will excuse performance.

Although many events may halt compliance with a contractual condition or covenant by an obligor, a claim of force majeure under catch-all language to excuse a nonperforming party will be met with resistance if such an event was foreseeable. For this reason, a second component of most force majeure clauses describes express events, which if such was to occur and prevent performance, the parties agree in advance as to how, and to what extent, the risk and cost of such nonperformance shall be allocated. Not all oil and gas contracts, particularly older agreements, describe specific events in their force majeure clause.

Generally, courts view force majeure clauses as limited in scope, and their application is interpreted narrowly. Texas courts favor provisions that describe express events excusing nonperformance over broad, general provisions that often are vague. 9 Language is very important, as further illustrated below in Rembrandt Enters. v. Dahmes Stainless, Inc. 10 Force majeure clauses are a contractual term; accordingly, their definition and use depend upon how such is defined in the contract. 11 Parties to a contract themselves draw the silhouette of a force majeure clause, and those terms dictate its application.

Lease terms are controlling regarding an assertion of a force majeure event, and common law rules merely fill in the gaps.12

When parties include the occurrence of express events to excuse performance, there is no need for such event to be unforeseeable. “[W]hen the promisor has anticipated a particular event by providing for it in a contract, he should be relieved of liability for the occurrence of such event regardless of whether it was foreseeable.” 7 Foreseeable special events often found in a force majeure clause include weather-related incidents, Federal or state law rules and regulations, riots, insurrection, terrorist attacks, inability to procure materials or utilities, scarcity of materials or labor, union strikes, transportation shortages, and inadequate market price. Without a catch-all, the canon of construction expressio unius est exclusio would exclude any event not named. If the catchall merely says “or any other events or circumstances beyond the reasonable control of the parties affected,” the canon of construction ejusdem generis would limit the meaning of the catch-all to the same type of events as those listed.8

When analyzing a force majeure event, always ask (1) what is the triggering event, and (2) what is the impact of that event? It is crucial that one show with particularity how an event frustrated performance or made it impossible. 13 A party who seeks to excuse a contractual obligation due to a force majeure event must 22

methodically connect the dots between the event (cause) and the effect (frustration of its contractual obligation to perform).

As stated previously, facts and terms matter!

For example, it may be considerably more difficult to convince a court that the occurrence of nonperformance caused by a hurricane should be excused under the catch-all language in a force majeure clause, if destroyed production facilities are located in Lake Charles, as opposed to Boise.

As Big Tech has well proven recently, many employees do not need to be physically present at one central location to do their job and effectively communicate with the rest of the world. A catchall provision in a force majeure clause would likely be an anemic claim as an excuse for nonperformance by an operator if the facts indicated the reason for such claim was because governmental rules preventing travel meant the division order department could not go to the office. However, a defense offered to excuse nonperformance would be more enthusiastically received by a court if the reason was that unforeseen governmental regulations prevented the ability of trucks to load and transport oil production. Regardless, government regulations which restrict travel due to a pandemic is now a foreseeable event. Nonperformance due to such an event would probably not now be excused under a catch-all provision in a force majeure clause contained in a lease made after recent events caused by COVID-19. Therefore, one would need to consider the excused performance provisions for express events, if any, in the contract.

Although the COVID-19 pandemic is a new phenomenon, its effects on the economy are not unique. Exercising a force majeure clause to excuse nonperformance due to an economic downturn has been the source of considerable litigation.14 An economic downturn in oil and gas prices is generally not an event that a court will allow to trigger catch-all terms in a force majeure clause. Economic downturns in the oil patch, as well as in most other businesses, is foreseeable regardless of the cause. 15 Texas courts seem to be in agreement that contractual obligations cannot be avoided because one’s economic burden becomes significantly larger than anticipated. 16 While COVID-19 and resulting governmental regulations may be the event, if the significant effect to an oil and gas producer is a decline in production revenue due to dropping oil prices (planes are not flying, cruise ships are not sailing, people are not driving to work, restaurants and entertainment venues are closed or limited), then such would be an attempt to invoke the force majeure clause due to economic hardship. Of course, if economic hardship was defined and enumerated as an express event in a force majeure clause, then declining revenue due to market conditions may have merit. Additionally, if government regulations due to COVID-19 had the effect of preventing equipment from being delivered, production in tanks from being transported to market, and vital oil and gas well operations labor from going to work, thus making production impossible, such effect may be more meritorious. However, it should be noted that Texas courts have specifically allowed parties to escape contractual obligations where performance has been prevented by government regulations, even when a government regulation is subsequently ruled as being invalid. 17

Look at performance prior to the triggering event. It will be difficult to convince a court that terms of a force majeure clause excuse nonperformance if nonperformance began prior to such an event. A party asserting a force majeure event, regardless of whether it falls under catchall language or a listed express event, will need to be able to demonstrate that they took reasonable efforts to overcome a barrier to performance and mitigate damages or lack of performance. 18 As illustrated in Hitz below, courts generally look to 23

equity and usually inquire about remedial steps taken to minimize the impact of the triggering event. Courts must not and “will not enforce an illegal contract, ‘particularly where the contract involves the doing of an act prohibited by statutes intended for the protection of the public health and welfare’.”19 However, if a contract is entered into for a specific purpose and that purpose subsequently becomes illegal, a court will likely not void the contract if the possibility of a subsequent illegality should have been foreseen.

“When a party voluntarily undertakes and by contract binds himself to do an act or thing, without qualification, and performance thereof becomes impossible by some contingency which should have been anticipated and provided against in the contract, the nonperformance will not be excused.” “…the party’s failure to exempt himself from the responsibility in the event of the happening of the contingency will be attributable to his own folly… .”20

Instructive cases Claim of economic downturn as a force majeure, and the importance of contractual terms: 1. TEC Olmos, LLC v. Conoco Philips Co.21 Under a Farmout Agreement with Conoco, TEC agreed to test drill in search of oil and gas.

The Agreement contained the following force majeure clause: Should either Party be prevented or hindered from complying with any obligation created under this Agreement, other than the obligation to pay money, by reason of fire, flood, storm, act of God, governmental authority, labor disputes, war or any other cause not enumerated herein but which is beyond the reasonable control of the Party whose performance is affected, then the performance of any such obligation is suspended during the period of, and only to the extent of, such prevention or hindrance, provided the affected Party exercises all reasonable diligence to remove the cause of force majeure.

Listed below are eight summary questions to examine when considering a claim of a force majeure defense:

TEC invoked the force majeure clause after a change in the global oil market eliminated the financing expected by TEC, causing TEC to not perform. TEC argued that the economic downturn qualified as an excused nonperformance under the general catch-all contained in the force majeure clause. However, the court held that economic downturns in oil and gas markets were foreseeable conditions, not covered by the general force majeure clause. Because such condition was not specifically listed as a force majeure event, such changes could not be considered as a force majeure.

1. What is the link between the triggering event and the impact of that event?

2. Was the triggering event foreseeable or unforeseeable?

3. Does the force majeure clause enumerate specific trigger events, or does it only contain general language of foreseeability?

4. What analysis is produced when examining language contained in the force majeure clause?

5. Is the assertion of a force majeure event more than just the result of economic hardship?

6. Were there mitigating steps taken to minimize the impact of a force majeure event? By both sides?

7. What was the contractual performance prior to the triggering event?

8. Was anything about the underlying contract for the performance of an illegal activity?

2. Rembrandt Enter. v. Dahmes Stainless, Inc.22 Rembrandt, a commercial producer of eggs, entered into a contract with Dahmes for the installation of an egg dryer. Subsequently, but prior to the installation of the dryer, an outbreak 24

of the Avian Flu necessitated Rembrandt to reduce his bird production by over 50% and to cancel construction of the facility in which the dryer was to be installed. Claiming a force majeure, frustration of purpose, and impracticability due to the drastic reduction in egg production, Rembrandt cancelled the installation of the egg dryer and Dahmes claimed breach of contract. The pertinent part of the force majeure clause stated the following:

majeure clause in the lease stated in pertinent part the following: Whenever a period of time is prescribed in this Lease for action to be taken by either party, such party will not be liable or responsible for, and there will be excluded from the computation of any such period of time, any delays due to strikes, riots, acts of God, shortages of labor or materials, war, governmental laws, regulations or restrictions or any other causes of any kind whatsoever which are beyond the reasonable control of such party.

Force Majeure. Neither party shall be liable to the other for failure or delay in performance of the Work caused by war, riots, insurrections, proclamations, floods, fires, explosions, acts of any governmental body, terrorism, or other similar events beyond the reasonable control and without the fault of such party…

Kirkland’s filed a motion to dismiss, asserting that its rent obligation was relieved by the force majeure provision in the lease triggered by government edicts for restrictions on business operations and nonessential activities. The court found several failures of Kirkland’s argument. (1) Kirkland’s did not explain how the government action it describes as a force majeure event resulted in its inability to pay rent, and even if it had demonstrated this, (2) an analysis of the same would be a factual determination and therefore improper on a motion to dismiss.

The court held that the force majeure clause defined “work” to mean efforts by Dahmes to build and install the dryer and therefore only applied to a failure or delay in performance by Dahmes. Because Dahmes did not cancel the contract, rather it was Rembrandt who unilaterally initiated the cancellation, no force majeure event occurred per the express terms of the contract.

4. In re Hitz Restaurant Group24 This COVID-19 case illustrates that a force majeure clause does not excuse a claimant from mitigating damages. The force majeure clause at issue provided that any obligations that are prevented or delayed due to governmental action or order would be excused. Tenant Hitz, a Northern Illinois area pizzeria focused on dine-in service, ceased paying rent and declared bankruptcy. Hitz argued that Illinois Governor J. B. Pritzker’s executive order prohibiting on-site consumption of food and beverages at Illinois restaurants should excuse its failure to pay rent from March through June 2020. However, the court noted that said order permitted carry-out, curbside pick-up, and delivery from restaurant premises, and therefore only partially excused the

Claims of the effects of COVID-19 as a force majeure: 3. Palm Springs Mile Associates v. Kirkland’s Stores, Inc.23 This recent decision illustrates how litigants often try to fit the facts of their case into a force majeure event without giving thoughtful attention to the specific language of the operative force majeure clause or carefully connecting the force majeure event with a purported inability to perform. (Always connect the dots!) Kirkland’s, a home décor retailer, ceased paying rent beginning in April 2020. Consequently, Palm Springs sued for breach of a commercial lease. The force 25

failure of Hitz to pay rent. Finding that the kitchen could have continued operations and that it (the kitchen) occupied approximately 25% of the rented space square footage, the court held that Hitz remained responsible for 25% of the rental payments and other contractual obligations such as real estate taxes and common area maintenance charges. Additionally, Hitz was adjudged responsible for the March rental obligation because it was due March 1, 2020, prior to the Governor’s order.

10

Rembrandt Enter. v. Dahmes Stainless, Inc., No. C154248-LTS, 2017 U.S. Dist. LEXIS 144636 (N.D. Iowa Sept.

7, 2017).

11 See Zurich Am. Ins. Co. v. Hunt Petrol, 157 S.W.3d 462 (Tex. App.—Houston [14th Dist.] 2004, no pet.).

12 See, e.g., Tex. City Ref., Inc. v. Conoco, Inc., 767 S.W.2d 183, 186 (Tex. App.—Houston [14th Dist.] 1989, writ denied).

13

Jamie Gottlieb Furia & Justin Corbalis, Mounting A Successful COVID-19 Force Majeure Argument, Law 360 (Sept. 25, 2020), https://www.lowenstein.com/newsinsights/publications/articles/mounting-a-successful-covid19-force-majeure-argument-gottlieb-furia-corbalis.

14 See TEC Olmos, LLC v. Conoco Philips Co., 555 S.W.3d 176, 182 (Tex. App. — Houston [1st Dist.] 2018, pet. denied).

15 Id. 16 See Grayson v. Grayson Armature Large Motor Div., Inc., No. 14-09-00748-CV, 2010 WL 2361432, at *5 (Tex. App. — Houston [14th Dist.] June 15, 2010, pet. denied (mem. op); Huffines v. Swor Sand & Gravel Co., Inc., 750 S.W.2d 38, 40 (Tex. App.—Fort Worth 1988, no writ).

17 See Tractebel Energy Mktg. v. E.I du Pont de Nemours & Co., 118 S. W.3d 60, 65 (Tex. App. — Houston [14th Dist.]

2003, pet. denied).

18 See id. (citing Restatement (Second) of Contracts §261, cmt. d (1981).

19 Peniche v. Aeroméxico, 580 S.W.2d 152, 155 (Tex. App.—Houston [1st Dist.] 1979, no writ). See Merry Homes, Inc. v. Chi Hung Luu, 312 S.W.3d 938, (Tex. App.—Houston [1st Dist.] 2010) (appellate court affirmed district court holding that a commercial lease for a nightclub, and for “‘no other’ purpose” was void for illegality because the tenant was unable to obtain a liquor license due to the premises’ proximity to a public school); See also McCreary v. Bay Area Bank & Trust, 68 S.W.3d 727, 733 (Tex. App.—Houston [14th Dist.] 2001, pet. dism’d) (“Where a contract is made in violation of a statute, it is illegal and void.”); Lewis v. Davis, 199 S.W.2d 146, 148-9 (1947) (if an illegality does not appear on the contract’s face, a court will not find it void unless facts showing the illegality are before the court).

20 Houston Ice Brewing Co. v. Keenan, 88 S.W. 197, 198 (Tex. 1905).

21 TEC Olmos, LLC v. Conoco Philips Co., 555 S.W.3d 176 (Tex. App.—Houston [1st Dist.] 2018, pet. denied).

22 Rembrandt Enter. v. Dahmes Stainless, Inc., No. C154248-LTS, 2017 U.S. Dist. LEXIS 144636, at *34,*32,*35-36 (N.D. Iowa Sept. 7, 2017).

23 Palm Springs Mile Associates v. Kirkland’s Stores, Inc., No.20-21724, 2020 WL 5411353, at *2 (S.D. Fla. Sept. 9, 2020).

24 In re Hitz Restaurant Group, No. 616 B.R. 374, 2020 WL 2924523, at *379-380 (Bankr. N.D. III. 2020).

1

History of 1918 Flu Pandemic, Centers for Disease Control and Prevention, National Center for Immunization and Respiratory Diseases (NCIRD), https://www.cdc.gov/flu/pandemic-Resources/1918commemoration/1918-pandemic-history.htm (last updated Mar. 21, 2018) 2 Marel Katsivela, Contracts: Force Majeure Concept or Force Majeure Clauses?, 12 UNIF. L. REV. (UK) 101 (2007); Jennifer Sniffen, Symposium Note and Comment: In The Wake of the Storm: Nonperformance of Contract Obligations Resulting From Natural Disaster, 31 NOVA L. REV. 551 (2007).

3 See Peter Declercq, Modern Analysis of the Legal Effect of Force Majeure Clauses in Situations of Commercial Impracticability, 15 JOURNAL OF LAW & COMMERCE 213, 214 (1995).

4 See Tractebel Energy Mktg. v. E.I. du Pont de Nemours & Co., 118 S.W.3d 60, 69 (Tex. App.—Houston [14th Dist.]

2003, pet. denied).

5 See Kodiak 1981 Drilling P’ship v. Delhi Gas Pipeline, Corp, 736 S.W.2d 715 (Tex. App.—San Antonio 1987, writ ref’d n.r.e.).

6 See TEC Olmos, LLC v. ConocoPhilips Co., 555 S.W.3d 176 (Tex. App.—Houston [1st Dist.] 2018), citing Zurich Am. Ins. Co. v. Hunt Petrol., 157 S.W.3d 462, 466 (Tex. App.—Houston [14th Dist.] 2004, no pet.).

7 See Kodiak, 736 S.W.2d at 721 (quoting E. Air Lines v.

McDonnell Douglas Corp., 532 F.2d 957, 992 (5th Cir. 1976)).

8 Natalie L. Arbaugh, Amy Sanders & Elyse Lyons, Best Practice for Key Contract Provisions, State Bar of Tex. Prof. Dev. Program, 19th Annual Advanced In-House Counsel Course, ch. 6, (2020).

9 See Va. Power Energy Mktg., Inc. v. Apache Corp., 297 S.W.3d 397, 402 (Tex. App.—Houston [14th Dist.] 2009, pet. denied); Sun Operating P'ship v. Holt, 984 S.W.2d 277, 283 (Tex. App.—Amarillo 1998, pet. denied).

26

production costs: the Burlington Resources Oil & Gas Co. LP v. Texas Crude Energy, LLC case from 2019, and the Chesapeake Exploration, L.L.C. v. Hyder case from 2016. 2 In BlueStone, the owner of a nonparticipating royalty interest (NPRI) contended that a 1986 deed creating the NPRI interest contained language that prohibited the deduction of postproduction costs. The 1986 deed contained the following language:

Royalty Disputes Continue to Thrive: Two Recent Postproduction Cost Deduction Cases By: Austin W. Brister Partner, McGinnis Lochridge

Royalty disputes continue to thrive across Texas, including disputes regarding whether a royalty interest must bear a proportionate share of postproduction costs such as transportation, compression, processing, and marketing. These disputes often turn on determining the proper “valuation point” for the royalties. For instance, if a royalty provision establishes a valuation point “at the well,” then that factor generally suggests the royalty is subject to postproduction costs. On the other hand, if the royalty provision establishes a valuation point “at the point of sale,” then that factor generally suggests the royalty is free of postproduction costs.

“This Grantor … shall be entitled to receive … a free one-eighth (1/8) of gross production of any such oil, gas or other mineral said amount to be delivered to Grantor’s credit, free of cost in the pipe line, if any, otherwise free of cost at the mouth of the well or mine...”3 In 2004, BlueStone’s predecessors leased the tract and drilled numerous producing wells.

BlueStone’s predecessors incurred a number of postproduction costs but did not pass those costs onto the NPRI owner. In 2016, BlueStone acquired these leasehold interests and began to deduct from the NPRI a share of BlueStone’s postproduction costs for transportation, gathering, and compression. The NPRI owner filed suit. The trial court granted the NPRI owner’s motion for summary judgment and then this appeal followed.

Other cases have focused on the meaning of phrases such as “gross production,” “cost-free,” and enforceability of no-deducts provisions. As one recent case shows, sometimes parties utilize unique language that requires the lessee to actually add amounts to its proceeds before calculating royalties.

This article discusses two recent Texas appellate court cases regarding deduction of postproduction costs. In both cases a petition for review has been filed with the Texas Supreme Court.

On appeal, BlueStone argued that the 1986 deed’s use of the phrase “in the pipe line” indicated that the royalty was to be valued at the pipeline and therefore was subject to postproduction costs. The Fort Worth Court of Appeals agreed with BlueStone and reversed the trial court’s decision, rendering judgment in favor of Bluestone.

BlueStone v. Engler Energy One recent case is BlueStone Natural Resources II, LLC v. Nettye Engler Energy, LP.1 This case is of interest to trial lawyers and inhouse lawyers for its interpretation of two notable Texas Supreme Court cases on deduction of post-

The BlueStone case is of interest due to its analysis of two Texas Supreme Court decisions

27

regarding postproduction Resources,4 and Hyder.5

costs:

wellhead. 10 The BlueStone court rejected that interpretation as well. 11 Instead, the court construed the word “otherwise” as simply meaning that the valuation point is at the pipeline if there is a pipeline, otherwise the valuation point is at the mouth of the well. 12

Burlington

In Burlington Resources, the Texas Supreme Court held that the phrase “into the pipelines…with which the wells may be connected” was tantamount to the phrase “at the well,” thereby establishing a valuation point that requires a royalty interest owner to bear postproduction costs.

The NPRI owner also attempted to draw several analogies between the 1986 deed and the Hyder case. The NPRI owner cited Hyder in arguing that the phrase “cost free” in the 1986 deed means free of postproduction costs. 13 The appellate court rejected that comparison. The appellate court noted that the Hyder decision was not based solely on the phrase “cost free,” but was instead “focused specifically” on the parenthetical that followed, which read “cost-free (except only its portion of production taxes).” 14 Even though the phrase “cost free” in a royalty provision typically means only that the royalty free of production costs, this parenthetical in Hyder reflected a different intention given that it made an exception for “production taxes” which is a type of postproduction cost. Therefore, based on that parenthetical, the Hyder Court held that the parties intended for the phrase “cost-free” to mean free of postproduction costs.15

The NPRI owner made several arguments in an attempt to distinguish Burlington Resources.

The NPRI owner argued that Burlington Resources was based on the full phrase in that case and did not broadly hold that “into the pipeline” sets a valuation point at the wellhead.

Instead, the NPRI owner argued that the holding in Burlington Resources was limited to instruments referencing pipelines “connected” to the well. The BlueStone court disagreed, stating Burlington Resources “did in fact focus heavily on the singular phrase ‘into the pipeline.’”6 The NPRI owner also argued that, because the 1986 deed did not include a “connected to the well” phrase like in Burlington Resources, that reflects that the parties to the 1986 deed were referring to a major pipeline downstream, and not merely a gathering system connected to the well. 7 The BlueStone court rejected that argument as well, pointing to multiple resources indicating that a gathering system is a type of pipeline. 8

The BlueStone court also rejected the argument that the 1986 deed’s use of the phrase “a free one-eighth (1/8) of gross production” brought the 1986 deed in line with Hyder.16 The court explained that Hyder recognized the phrase “free” in a royalty provision typically refers only to production costs and not postproduction costs. 17 The BlueStone court explained that the 1986 deed did not express a contrary intent, as the word “free” appeared in multiple other locations in the context of production costs.18 Moreover, in the phrase “free of cost at the mouth of the well,” the reference to the mouth of the well suggests the word “free” is used in its standard nature, in reference to production costs. 19

The NPRI owner also argued that, because the two phrases “free of cost in the pipeline” and “free of cost at the mouth of the well” are separated by the word “otherwise,” that means they are mutually exclusive. 9 The NPRI owner argued that the second phrase refers to gas with a valuation point at the mouth of the well, and therefore the first phrase must refer to oil and a valuation point somewhere other than the 28

should have been added to the lessee’s gross proceeds prior to calculating the lessors’ royalties.

Devon Energy v. Sheppard The lessees argued that the controlling language in the leases was the royalty provision indicating that royalties were to be paid on the basis of “gross proceeds . . . at the point of sale.”23 The lessees argued that this established a valuation point at the point of sale, whereas the lessees argued that the reductions or charges at issue in this case were incurred downstream of the point of sale.24

Another recent postproduction costs royalty case is Devon Energy Production Co., L.P. v.

Sheppard. 20 This case involves “highly unique royalty provisions” in lease forms prevalent during the shale boom in the Eagle Ford area. The leases at issue included the following “add to proceeds” provision: “If any disposition, contract or sale of oil or gas shall include any reduction or charge for the expenses or costs of production treatment, transportation, manufacturing, process or marketing of the oil or gas, then such deduction, expense or cost shall be added to the market value or gross proceeds so that Lessor's royalty shall never be chargeable directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes.”21

The lessors and lessees submitted a joint stipulation to the court, identifying twenty-three different scenarios for the court’s consideration. 25 The trial court granted summary judgment in favor of the lessors, and this appeal followed. 26 The appellate court emphasized that Texas courts construe oil and gas leases by seeking to enforce the intention of the parties, and that they seek to give effect to all parts and do not give any single provision controlling effect. 27 The appellate court reviewed the “highly unique royalty provisions” in the underlying leases and concluded that it is “exceptionally broad, and there is nothing in the leases suggesting that [it] is limited to pre-point-of-sale expenses.”28 The court further explained that the initial royalty clause indicates that “royalty is to be initially based on the [lessees’] gross proceeds (before [this unique additional provision] is applied).”29 The court explained that, if it were to hold that royalties were due only on gross proceeds, then the court would be rendering this additional “add to . . . proceeds” provision meaningless.30

Another provision in the addendum indicated that royalties “shall never bear or be charged with, either directly or indirectly, any part of the costs or expenses of” several enumerated categories of postproduction costs.22 The royalty owners argued that these lease provisions required the lessee to add any ‘reduction or charge’ included in any ‘disposition, contract or sale of oil or gas’ to the lessee’s gross proceeds before calculating royalties. The lessors argued that a wide variety of the lessee’s purchase agreements, purchase statements, processing arrangements, and other instruments reflected reductions or charges, and therefore they

The court also explained that this unique provision differs “significantly” from a mere “no deducts” clause, as it does not concern deductions 29

made to the royalty; rather, it focuses on the dispositions and sales contracts, and applies if they contain a “reduction or charge” for such expenses. Moreover, the phrase indicating that the royalty shall never be “directly or indirectly” charged with such costs reflected an intent that the royalty should not be reduced where “a downstream sales price is reduced to account for costs incurred or anticipated by the purchaser.” 31

18

Id. Id. at 18.

20 Devon Energy Prod. Co., L.P. v. Sheppard, No. 13-1900036- CV, 2020 Tex. App. LEXIS 8378 (Tex. App.— Corpus Christi Oct. 22, 2020).

21 Devon Energy Prod. Co., L.P. v. Sheppard, No. 13-1900036-CV, 2020 Tex. App. LEXIS 8378, at *4-5 (Tex. App.—Corpus Christi Oct. 22, 2020).

22 Id. at 5.

23 Id. at 30.

24 Id. at 32.

25 Id. at 2.

26 Id. 27 Id. at 14.

28 Id. at 2.

29 Id. at 35.

30 Id. at 30.

31 Id. at 35.

32 Id. at 43.

33 Id. at 4-5.

34 Id. at 21-22.

19

Ultimately, the court concluded that this unique language reflected the parties’ intent to base the royalty on more than mere gross proceeds. The court coined this a “proceeds plus” royalty. 32 The court held that this language requires the lessee to add to its gross proceeds any reduction or charge that is included in a disposition, contract, or sale of oil and gas, so long as the charge is for one of categories enumerated within the lease addendum. 33 The Devon case serves as a reminder that determining whether a royalty interest bears postproduction costs is not merely a matter of determining the valuation location. 34 1

BlueStone Nat. Res. II, LLC v. Nettye Engler Energy, LP, No. 02-19-00236-CV, 2020 Tex. App. LEXIS 5095 (Tex. App.—Fort Worth July 9, 2020).

2 Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 872 (Tex. 2016).

3 BlueStone Nat. Res. II, LLC v. Nettye Engler Energy, LP, No. 02-19-00236-CV, 2020 Tex. App. LEXIS 5095, at *2-3 (Tex. App.—Fort Worth July 9, 2020).

4 See Burlington Resources Oil & Gas Co. LP v. Texas Crude Energy, LLC, 573 S.W.3d 198 (Tex. 2019).

5 See Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870, 872 (Tex. 2016).

6 BlueStone, 2020 LEXIS 5095, at *13.

7 Id. 8 Id. 9 Id. at 12.

10 Id. 11 Id. at 13.

12 Id. 13 Id. at 16.

14 Id. 15 Id. 16 Id. at 17.

17 Id.

30

Joint Operating Agreements and the Reasonably Prudent Operator Standard By: Jonathan Baughman

Partner, McGinnis Lochridge

Background on Joint Operating Agreement Forms The reasonably prudent operator standard is not only applicable to the lessor-lessee relationship. It also applies, for instance, to the operator-non-operator relationship. In this context, Joint Operating Agreement (JOA) forms typically provide an express provision indicating the standard by which the operator is expected to perform. Modern operating agreements will expressly include within that standard reference to the “reasonably prudent operator.” The most commonly used JOA form for on-shore US assets in Texas is the “Model Form 610,” published by the American Association of Professional Landmen (“AAPL”). Over the last several decades there have been multiple revisions of the Form 610, including material differences in the provisions defining the operator’s standard of performance and the exculpatory provision.

While the first version of the Form dates back to 1956, this article will briefly touch on the standards set forth in the 1982, 1989, and 2015 AAPL Forms.

Evolution of JOA Standards from "Good and Workmanlike Manner" to "Reasonably Prudent Operator" The 1982 version of the AAPL JOA form stated that the Operator “shall conduct all such operations in a good and workmanlike manner.”

Courts have generally construed that standard to be similar to the “reasonably prudent operator” standard. The 1989 version of AAPL’s JOA form

was amended to actually incorporate the phrase “reasonably prudent operator” within its provision. When the AAPL most recently updated the Model Form 610 JOA in 2015, they maintained the “reasonably prudent operator” standard within the form.

Exculpatory Provisions in Joint Operating Agreements One of the most hotly contested aspects of the operating agreement has been the scope of the exculpatory provision. Generally, an exculpatory clause relieves the operator of liability in the event damages are caused by the operator during its performance unless the operator was “grossly negligent” or engaged in “willful misconduct.” In other words, while the JOA form provides that an operator must act as a “reasonably prudent operator,” the exculpatory provision relieves the operator of liability for certain types of operations or activities. Again, however, that limitation on liability will not apply if the liability results from the operator’s “gross negligence” of “willful misconduct.”

A number of courts have addressed the scope of model form exculpatory clauses. These decisions vary and, in some cases, demonstrate two different scopes that have been applied to exculpatory clauses. Stine v. Marathon Oil Co. was an earlier case discussing this standard where the Fifth Circuit extended the exculpatory clause to all of the operator’s actions including breaches of contract for administrative and accounting duties.1 A number of other courts in and outside of Texas have directly or indirectly rejected the Fifth Circuit’s interpretation of the exculpatory clause in Stine. For instance, in Hornberg, the court limited the reach of the exculpatory clause to the operator’s operations on the contract area. 2

One explanation might be that the courts are implicitly concerned about granting an operator such wide latitude on matters where the operator and the non-operators interests are not aligned.

The Tenth Circuit in Ultra Resources stated:

paper, and would be outside the scope of this short article.

Many industry participants believed that the interpretation set forth in Reeder was inconsistent with the industries’ intentions. As such, when the AAPL formed a task force to update the Model Form 610, one of the changes implemented was a clarification of the exculpatory provision, with the intention of making clear that it applies only to operations, and not to a breach of the operating agreement itself. As suggested above, even if an exculpatory provision applies to a given category of conduct, the Operator may still be held liable if the damages result from “gross negligence” or “willful misconduct.” These are difficult standards to prove. To prove gross negligence, the plaintiff must show the defendant had “actual subjective knowledge of an extreme risk of serious harm.” 7 The magnitude of the risk is judged from the viewpoint of the defendant at the time the events occurred. 8 The harm anticipated must be extraordinary harm, not the type of harm ordinarily associated with breaches of contract or even with bad faith denials of contract rights; harm such as death, grievous physical injury, or financial ruin.9 As for willful misconduct, Texas courts have applied a standard akin to gross negligence. A finding of willful misconduct requires evidence of “a specific intent by [the operator] to cause substantial injury to [the nonoperators].”10

While a higher standard for breach might apply to drilling . . . and other risky operations because most operators have the same incentive as non-operators to do well in operations, it is nonsensical to apply such a standard to administrative and accounting duties where the operator can profit by cheating, or simply overcharging, its working interest owners.3 AAPL’s various versions of the JOA differ in the scope of the exculpatory clause. Several lawsuits have been fought over the meaning of those differences. The 1982 JOA form contains an exculpatory provision that applies to “operations on the contract area,” while the 1989 JOA form applies to all “activities under this Agreement.”

In the late 1980’s and early 1990’s, some commentators suggested that this difference in language significantly broadened the scope of the protection afforded by the 1989 JOA Form exculpatory clause. That interpretation was ultimately confirmed by the Texas Supreme Court in Reeder v. Wood County.4 The court held that the phrase “activities under this Agreement” served to relieve the operator from liability for all activities, not merely operations, including activities performed. 5 For practical purposes, several commentators have interpreted that as meaning that the exculpatory provision under the 1989 JOA Form could theoretically relieve an operator from liability for certain accounting obligations and for certain breach of contract actions. 6 A thorough review of these cases and potential analyses could very easily span an entire

Conclusion The “reasonably prudent operator standard” has become integral to Texas oil and gas law, applying in many scenarios and relationships. As discussed in the last edition of Producer’s Edge, it forms a foundational component of the implied covenants in oil and gas leases and is often directly or indirectly incorporated into a variety of express provisions.11 In addition, the standard 32

is also incorporated in many joint operating agreement forms, including the Model Form 610 JOA, published by the AAPL. 1

Stine v. Marathon Oil Co., 976 F.2d 254, 257 (5th Cir. 1992).

2 Abraxas Petroleum Corp. v. Hornberg, 20 S.W.3d 741, 759 (Tex. App. – El Paso 2000, no pet.) (holding that the exculpatory clause is limited to claims based upon an allegation that the operator failed to act reasonably prudent and does not apply to a claim that breached the JOA).

3 Shell Rocky Mountain Prod. v. Ultra Res., Inc., 415 F.3d 1158 (10th Cir. 2005).

4 Reeder v. Wood Cnty., 395 S.W.3d 789 (Tex. 2012).

5 See id. at 794.

6 See Wood Cnty. 395 S.W.3d at 794; see also Robert C. Bledsoe, The Operating Agreement: Matters Not Covered or Inadequately Covered, 47 ROCKY MTN. MIN. L. INST. §15.03[1] (2001).

7 See IP Petroleum Co. v. Wevanco Energy, LLC, 116 S.W.3d 888, 897 (Tex. App.—Houston [1st Dist.] 2003, pet. denied).

8 Id. 9 Id. 10 Id. 11 See Jonathan Bauhgman, Recent Global Events and the Increased Importance of the Reasonably Prudent Operator Standard, 2 Producer’s Edge 11, 12-13 (2021) (discussing the reasonably prudent operator standard).

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In re First River Energy, LLC: First Purchaser Statutes

choice-of-law and the governing law of perfection, which were both underscored in the SemCrude decision.3

By: Grant Armentor Student South Texas College of Law Houston

SemCrude

Introduction Oil and gas development is an intricate and precarious venture requiring extensive expertise and capital. In light of the complexity and risk of production, most mineral interest owners will “lease” their interest, transferring their mineral rights to oil and gas producers in exchange for a bonus payment and a royalty interest in the production.

Subsequent to development, producers will then sell the oil to “first purchasers,” generally midstream services providers. Should the first purchaser fall into financial distress and file for bankruptcy protection, however, the producer and mineral interest owners may find themselves at risk of never receiving the payments due to them. To protect royalty interest owners and producers during difficult times, some oil-producing states have enacted statutes to assist producers in securing payments from first purchasers for production sold. In light of a recent bankruptcy and Fifth Circuit decision, however, Texas producers may not enjoy the full protections that its legislature has provided for them.

First Purchaser Protection In response to pressures from mineral interest owners to secure their interest in delivered production, Oklahoma legislature passed the Oil and Gas Owner’s Lien Act of 1988 (“1988 Act”).1 Additionally, Texas passed Section 9.343 of the Texas Business and Commerce Code (“Texas First Purchaser Statute”), a non-standard UCC provision. 2 Each of these statutes, however, had significant deficiencies regarding the applicable

In SemCrude, producers from Oklahoma and Texas sold and delivered oil and gas production to SemCrude L.P., a limited partnership incorporated in Delaware. 4 Trouble arose when SemCrude fell into bankruptcy with hundreds of millions of dollars still owed to producers—and through the producers’ leases—with mineral owners owed royalties through leases. 5 Consequently, the Oklahoma and Texas producers asserted lien priority under the 1988 Act and the Texas First Purchaser Statute, respectively.6 Oklahoma’s 1988 Act was enacted to provide Oklahoma oil and gas producers an automatically perfected and prioritized statutory lien in the resultant proceeds of oil and gas sold and delivered to first purchasers. 7 As the SemCrude decision highlighted, however, two flaws of the 1988 Act included: (1) that the governing law was determined by the debtor’s “location”—here, Delaware as the debtor’s state of incorporation— as opposed to Oklahoma law where the producing wellheads were located; and (2) expressly subdued Oklahoma producer’s rights to the rights of those under the UCC.8 Thus, because Delaware law requires the filing of a financing statement to duly perfect, any opposing security interests that were properly perfected had primed the interests asserted by the Oklahoma producers under the 1988 Act. Similarly, the Texas First Purchaser Statute granted Texas producers a prioritized purchase money security interest in production sold and delivered to first purchasers, as well as in proceeds thereof.9 The purpose of the statute was to assist Texas producers in securing outstanding payment obligations of first purchasers by

granting the producers an automatically perfected security interest without the filing of a financing statement. In similar fashion to the Oklahoma 1988 Act, the court held that the laws in which a first purchaser is “located,” rather than where the oil and gas was produced and sold, was the appropriate governing law – here, Delaware. 10 Thus, the Texas producer’s security interests under the Texas First Purchaser Statute were also deemed unsecured and subordinate to the capital lending bank’s Article 9 UCC security interests that were filed and perfected in Delaware.

Oklahoma and Texas producers, the first purchaser filed for bankruptcy with outstanding payments still due. 15 The Texas producers claimed they held an automatically-perfected security interest under the Texas First Purchaser Statute, while the Oklahoma producers asserted that they held a prioritized lien under Oklahoma’s newly enacted 2010 Act.16 Unsurprisingly, the bankruptcy court applied the same reasoning as the SemCrude court in determining that the Texas debtor’s “location” determined the governing law to be applied. 17 Thus, Delaware law governed, and the Texas First Purchaser Statute was not applicable.

Accordingly, Texas producers were left unsecured on their right to outstanding payments.

Oklahoma’s Oil and Gas Owner’s Lien Act of 2010 In response to the SemCrude decision, Oklahoma legislature passed the Oil and Gas Owner’s Lien Act of 2010 (“2010 Act”). 11 The 2010 Act was fashioned to circumvent the deficiencies identified by the bankruptcy court and to ensure intended protection to Oklahoma mineral interest owners and producers.

Specifically, the 2010 Act: (1) granted an oil and gas lien to producers, as opposed to a security interest, in attempt to avert an application of an opposing state’s UCC as in the SemCrude decision; and (2) stipulated that the 2010 Act granted an automatic super-priority lien, subordinating any conflicting liens or security interests created under the UCC. 12

The Oklahoma producer’s claims, however, encountered a pleasant deviation. In a first impression decision determining the efficacy of the 2010 Act, the bankruptcy court concluded that the 2010 Act had corrected the deficiencies of the 1988 Act in successfully creating a super-priority oil and gas lien, securing the payment obligation of first purchasers. 18 The bankruptcy court noted that to the extent the Oklahoma producers could demonstrate their interest in “oil and gas rights,” Oklahoma law would apply to the perfection and priority of the Oklahoma producer’s lien over conflicting duly perfected security interests. 19 Thus, the 2010 Act successfully provided Oklahoma producers liens in production that primed the capital lending banks’ Article 9 UCC security interests.

First River Ten years later, the 2019 bankruptcy court decision of First River was rendered by Bankruptcy Judge Craig Gargotta, examining the integrity of the Texas First Purchaser Statute and Oklahoma’s newly enacted 2010 Act. 13 Similar to the SemCrude decision, this case involved a Delaware limited liability company, First River, LLC, acting as first purchaser for the acquisition of oil and gas produced from wells located in Oklahoma and Texas. 14 Following the first purchaser’s acceptance of oil purchased from

The Texas producers appealed the bankruptcy court’s decision to the Fifth Circuit Court of Appeals. On February 2, 2021, Judge Edith Jones of the Fifth Circuit entered judgment affirming the bankruptcy court’s decision. 20 Judge Jones emphasized Delaware’s denial of “certain nonstandard UCC security interests.” 21 This was significant because Delaware has no provision 35

comparable to the Texas First Purchaser statute.

Thus, application of Delaware law thwarted the Texas producer’s ability to acquire an automatically perfected security interest without the filing of a financing statement in Delaware.

The Fifth Circuit additionally recognized Oklahoma’s success in curing the defects of the 1988 Act determined in the SemCrude decision.

Oklahoma was able to strengthen the rights of Oklahoma producers with the enactment of the 2010 Act, while Texas producers must continue to rely on the vulnerable protections afforded under the Texas First Purchaser Statute. In order to ensure the intended protection that the Texas First Purchaser Statute was enacted to provide for the state’s producers, the Fifth Circuit notes that “Texas legislature should take note” of the Texas First Purchaser Statute’s shortcomings.

The Fifth Circuit ultimately concluded that the Delaware UCC governed the issues of perfection and priority with respect to the Texas producer’s asserted security interests in production delivered to first purchaser and proceeds thereof. 22 Further, the court confirmed that the Texas producer’s security interests created by the Texas First Purchaser Statute were subordinate to the perfected security interests of the capital lending banks. 23

1

Okla. Stat. Ann. tit. 52, §§ 548–548.6, repealed by Okla.

Stat. Ann. tit. 52, §§ 549.1–549.12 (West 2021).

2 Tex. Bus. & Com. Code § 9.343 (West 2021).

3 Samson Res. Co. v. SemCrude, L.P. 407 B.R. 140 (Bankr.

D. Del. 2009).

4 Id. at 150.

5 Id. at 144.

6 Id. at 147.

7 Okla. Stat. Ann. tit. 52, §§ 549.4, repealed by Okla. Stat.

Ann. tit. 52, §§ 549.1–549.12 (West 2021).

8 Sahar Jooshani, There’s a New Act in Town: How the Oklahoma Oil and Gas Owners’ Lien Act of 2010 Strengthens the Position of Oklahoma Interest Owners, 65 OKLA. L. REV. 133, 136 (2012).

9 Tex. Bus. & Com. Code § 9.343(b) (West 2021).

10 Arrow Oil & Gas, Inc. v. SemCrude, L.P., 407 B.R. 112, 137 (Bankr. D. Del. 2009).

11 Okla. Stat. Ann. tit. 52, §§ 549.1–549.12 (West 2021).

12 Okla. Stat. Ann. tit. 52, § 549.3 (West 2021).

13 In re First River Energy, LLC, No. 18-50085-CAG, 2019 WL 1103294 (Bankr. W.D. Tex. Mar. 7, 2019).

14 In re First River Energy, LLC, 2019 WL 1103294, at *3.

15 In re First River Energy, LLC, 2019 WL 1103294, at *4.

16 In re First River Energy, LLC, 2019 WL 1103294, at *11.

17 In re First River Energy, LLC, 2019 WL 1103294, at *20.

18 In re First River Energy, LLC, 2019 WL 1103294, at *16.

19 In re First River Energy, LLC, 2019 WL 1103294, at *16.

20 In re First River Energy, L.L.C., 986 F.3d 914 (5th Cir. 2021).

21 Id. at 921.

22 Id. at 931.

23 Id. at 928.

24 Id. at 917.

Looming Effect The Fifth Circuit decision highlights the deficiencies in Texas legislature’s attempt to protect Texas oil and gas producers—and through them, parties owed royalty—with the Texas First Purchaser Statute. The court notes that producers must “beware the amazing disappearing security interest and continue to file financing statements.”24 This language by the court should be sincerely received by Texas producers as the current protection provided under the Texas First Purchaser Statute will undoubtedly fall short in situations similar to those in the SemCrude and First River decisions where Texas producers solely rely on the Texas First Purchaser Statute without the filing of a financing statement. In order to ensure that a security interest in production sold and delivered to first purchasers is duly perfected, Texas producers should file a financing statement in the debtor’s state of incorporation or organization after every delivery of production.

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The ENERGY NEWSLETTER is sponsored by the Harry Reed Institute for Oil & Gas at South Texas College of Law Houston

How to Help Support the Oil & Gas Law Institute at South Texas College of Law Houston

South Texas College of Law Houston’s ability to make strategic investments in initiatives such as the Oil & Gas Law Institute hinges on the amount of annual support at its disposal, and the size and strength of our endowment. Last year, the College directed a portion of its annual operating budget to fund the formation of the Institute. This budget has been supplemented by early philanthropic investments in the Institute made by generous friends of the College.

To sustain the Oil & Gas Law Institute for the future and expand its reach through partnerships with industry and other academic thought leaders, new CLE courses, public lectures, and symposia, the ENERGY NEWSLETTER, and additional faculty and staff, the College is seeking to enlist the help of the oil and gas community, its alumni, other corporate and foundation partners and the community at large.

The evolution of oil and gas law — and of the legal education and scholarship behind it — challenges all of us to be nimbler and more purposeful. It requires us to innovate, reimagine, and adapt. So too do we understand the growing role philanthropy must play in the life of any educational institution that wishes to lead.

South Texas College of Law Houston would greatly appreciate a philanthropic investment in the Oil & Gas Law Institute. Together, we can ensure the Institute’s place as Houston’s premiere legal teaching and learning resource serving the oil and gas industry.

To make a tax-deductible donation, go to the link below. https://www.stcl.edu/academics/oil-gas-institute/support-us/

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