Oil and Gas Update

In re Sanchez Energy Corporation: Presence of Real Property Covenants No Shield to Rejection in Bankruptcy

In In re Sanchez Energy Corporation, a recent Memorandum Opinion by the United States Bankruptcy Court for the Southern District of Texas (the “Court”), the Court held for arguably the first time that the presence of a real property covenant in an executory contract does not preclude the debtor from rejecting the contract in bankruptcy.

Over the last several years, whether midstream agreements create real property covenants has been a hot issue, particularly in the bankruptcy context.  Under many such agreements, the producer of oil, gas, or water purports to dedicate certain real property interests to the midstream provider and commits to deliver to the midstream provider all of the oil, gas, or water produced from such interests.  The midstream provider, in turn, may rely upon this dedication and the anticipated continued revenue stream from such production in agreeing to expend capital to build out midstream systems to provide services to the producer, which the midstream provider may plan to recover over the course of several months or years.  It obviously creates a big problem for the midstream provider if the agreement may be rejected by the producer in a subsequent bankruptcy proceeding.

Many have assumed that the presence of real property covenants or “covenants running with the land” in such agreements would mitigate this risk by preventing rejection.  Accordingly, much time and energy has been spent by both drafters and courts in ascertaining whether certain dedications meet the elements necessary to form real property covenants.  In many cases addressing the issue, bankruptcy courts have found that such agreements failed to form real property covenants in the first instance.[1]  This characterization has allowed courts to largely avoid the more overarching issue of whether a contract that forms a real property covenant can still be rejected by the debtor in bankruptcy.

In In re Sanchez Energy Corporation, the Court squarely addressed this question for arguably the first time and held that the presence of a real property covenant in an executory contract does not preclude the debtor from rejecting the contract in bankruptcy.[2]  As discussed below, this statement of law is contrary to those in other cases.  However, the Court further held that the real property covenant formed by the executory contract survived the rejection.

Background

In 2017, SN Maverick (“Maverick”), a subsidiary of Sanchez Energy Corporation (“Sanchez”), purchased from Anadarko assets (the “Comanche Assets”) in the Comanche Field area of the Eagle Ford shale (the “Comanche Transaction”).  In conjunction with the Comanche Transaction, Maverick entered into an Oil Gathering Agreement and a Gas Gathering Agreement (the “Gathering Agreements”) whereby it dedicated hydrocarbon production from the Comanche Assets to a pipeline network owned by Springfield Pipeline, LLC (a wholly owned subsidiary of Anadarko).  The Gathering Agreements explicitly expressed the intent of the parties to form covenants running with the land of their respective primary obligations.  On August 11, 2019, Sanchez and its affiliates filed voluntary petitions under chapter 11 of the Bankruptcy Code.[3]  The debtor proposed rejection of the Gathering Agreements, and Occidental, Anadarko’s successor-in-interest, objected.

The Court’s Holdings

With respect to the executory contract rejection issues, the Court first addressed whether executory contracts containing real property covenants could be rejected at all.  The Court held that the existence of a real property covenant in an executory contract does not preclude a debtor from rejecting the contract.[4]  The Court noted that section 365 of the Bankruptcy Code allows a debtor-in-possession to reject “any executory contract.”  Therefore, the Court stated, since executory contracts containing real property covenants still fall within the purview of “any executory contract,” they can be still be rejected.

The Court reasoned that “rejection mirrors a breach of contract outside of bankruptcy” and that a “counterparty retains those contract rights that would survive a breach under applicable non-bankruptcy law.”[5]  Because a breach of a contract granting a real property covenant does not terminate such covenant outside of bankruptcy, rejection of that same contract does not terminate the covenant in bankruptcy.  Instead, the Court reasoned, rejection of the Gathering Agreements would alleviate the debtor’s burdens under those contracts, but would not affect Occidental’s rights that would survive a breach outside of bankruptcy.  That is, despite rejection of the Gathering Agreements, Occidental still held any rights it would have had outside of bankruptcy, including the real property covenants.

The Court next determined that rejection of the Gathering Agreements satisfied the business judgment rule, holding that the debtor’s “decision to reject the [Gathering] Agreements, presumably with the goal of negotiating more favorable gathering terms with Springfield, is a reasonable exercise of its business judgment.”[6]  The Court went through each of the elements required to form a real property covenant running with the land and concluded that the Gathering Agreements formed real property covenants that run with the land.  Since, as the Court held earlier, rejection of an executory contract in bankruptcy does not eliminate real property covenants contained in the contract, the property rights that Occidental owned under the Gathering Agreements persisted.

Analysis

While the Court’s holding in Sanchez that a contract which forms a real property covenant can be executory and therefore rejected under section 365 is well reasoned, it is at odds with statements of law made in other cases addressing similar agreements.  In Alta Mesa, for example, the Court stated expressly what had been the assumption of many that “[c]ontracts forming real property covenants are not executory.”[7]  Similarly, the court in In re Sabine Oil & Gas Corp, a New York bankruptcy case applying Texas law, framed the question in that case as “whether the Agreements run with the land and therefore cannot be rejected pursuant to § 365(a).”[8]  The Court in Sanchez spent some time attempting to reconcile the differences between the statements of law in Alta Mesa and Sanchez noting that “[t]hat point of the Alta Mesa decision could lead one to believe that a debtor cannot reject an executory contract which creates a real property covenant.  Although real property covenants are not terminated by rejection, the existence of a real property covenant does not prevent a debtor from rejecting its executory obligations in a contract.”[9]  

Prior to Sanchez, no court had clearly made a distinction between rejecting an executory contract containing a real property covenant and rejecting the actual real property covenant.  Sanchez provides clarity as to what kinds of contracts debtors can reject in bankruptcy.  The Court makes clear that while executory contracts that form real property covenants can be rejected in bankruptcy, the real property covenants will continue to exist outside of bankruptcy, although, one may wonder, to what practical effect for the midstream provider.

Download In re Sanchez Energy Corporation

 

Cameron Haltom

Thompson & Knight, LLP

 

[1] See, i.e. In re Sabine Oil & Gas Co., 550 B.R. 59 (Bankr. S.D.N.Y. 2016); In re Chesapeake Energy Corp., No. 20-33233, 2020 WL 6325535 (Bankr. S.D. Tex. Oct. 28, 2020).

[2] In re Sanchez Energy Corp., No. 19-34508, 2021 WL 1822708 (Bankr. S.D. Tex. May 6, 2021).

[3] Id. at *4.

[4] Id. at *8.

[5] Id.

[6] Id.. at *11.

[7] In re Alta Mesa Res., Inc., 613 B.R. 90, 99 (Bankr. S.D. Tex. 2019); (Alta Mesa drew some criticism for its reasoning from the court in In re Extraction Oil & Gas, 622 B.R. 608, 620-23, n.34 (Bankr. D. Del. 2020)).

[8] In re Sabine Oil at 76 (emphasis added).

[9]In re Sanchez Energy Corp. at *8.

Lyle v. Midway Solar, LLC: The Accommodation Doctrine and Surface-Use Disputes between Mineral Owners and Solar Developers

Texas has always been a leader in the U.S. energy industry.  Historically, that meant oil and gas exploration and production.  But as the energy transition continues, Texas has seen increased development in both the wind and solar energy sectors.  As this trend evolves, the potential for disputes between oil and gas operators and wind and solar companies will increase, especially in places where the windier or sunnier parts of our state exist above valuable mineral deposits. 

Lyle v. Midway Solar, LLC, 618 S.W.3d 857 (Tex. App.—El Paso 2020, pet. filed) illustrates one such dispute, where mineral owners are pitted against a solar array operator who constructed a large-scale solar facility above the mineral owners’ acreage.  In that case, the mineral owners claim the solar facility impairs their ability to develop their mineral acreage and unsuccessfully sought damages and injunctive relief from the solar operator.  With review now pending in the Texas Supreme Court,[1] the Court is presented with an opportunity to delineate the rights and obligations between Texas mineral owners and renewables companies, and to apply the “Accommodation Doctrine” in a new context.

The plaintiff mineral owners (the “Lyles”) own part of the minerals under a section of land in Pecos County, Texas (“Section 17”).  In October 2015, the surface owner of Section 17 signed a solar lease with defendant Midway Solar, LLC (“Midway”).  Under the solar lease, Midway constructed a large solar array atop 70% of Section 17.  Midway left two tracts untouched, designating them as future pad sites for horizontal access and development should oil and gas development ever occur, although it was undisputed the Lyles had never leased or otherwise planned to develop their minerals.  Even so, the Lyles sued Midway and the surface owner, alleging that the solar facility constituted a trespass.  By denying them reasonable access to 70% of the surface, they also claimed the solar facility violated the terms of a 1948 deed (the “1948 Deed”) that split Section 17’s surface and mineral estate and reserved to the mineral owners “such use of the surface estate…as may be usual, necessary, or convenient in the use and enjoyment of the oil, gas, and general mineral estate hereinabove reserved.”  Midway responded that it could not be liable for any surface obstruction until the Lyles sought to actually develop the minerals.

In Texas, ownership of fee minerals carries with it an implied easement to use as much of the surface as is reasonably necessary for the reasonable development of the mineral estate.  The rationale is that, without this implied easement, mineral ownership could unilaterally be rendered worthless by a surface owner who refuses to allow mineral development.  The Accommodation Doctrine is a limited exception to this general rule and was developed to promote cooperation between surface and mineral owners by balancing their differing interests.  Under the Accommodation Doctrine, “the surface owner carries the burden to show that (1) the mineral owner’s use of the surface completely precludes or substantially impairs the surface owner’s existing use, and (2) there is no reasonable alternative method available to the surface owner by which the existing use can be continued.”  Id. at 869 (quoting Merriman v. XTO Energy, Inc., 407 S.W.3d 244, 249 (Tex. 2013)).  In addition, the surface owner must demonstrate that the mineral owner has alternative, reasonable methods of development.  Id.

However, parties may preempt application of the Accommodation Doctrine by contract. Id. (citing Coyote Lake Ranch, LLC v. City of Lubbock, 498 S.W.3d 53, 56 (Tex. 2016)).  If the parties’ deed describes the disputed rights, the Accommodation Doctrine is unnecessary as a gap-filler.  Id.  But when a deed is silent or ambiguous about the rights and obligations of the surface and mineral owners as to surface-use issues, the Accommodation Doctrine may be applied.

In Lyle, the court of appeals held that the 1948 Deed did not preempt the Accommodation Doctrine, and that the doctrine could not require Midway to accommodate the Lyles’ future mineral development until they actually sought to develop the minerals under Section 17.  The court explained that, “if the Lyles are not exercising their right, there is nothing to be accommodated.  Stated otherwise, until the Lyles seek to develop their minerals, Midway owes no duty to the Lyles respecting the surface usage.”  618 S.W.3d at 874.  Responding to the Lyles’ argument that they had no plans to develop because the existence of the solar array prevented any realistic prospect of development, the court recognized that “evidence that the Lyles have unsuccessfully sought to market a lease, or otherwise develop the minerals” may eventually give rise to a valid claim by the Lyles.  But there was no such evidence in the record.

This case puts the Lyles in the difficult position of having to demonstrate concrete—yet unsuccessful—steps towards mineral development, while recognizing that the solar array facility rendered realistic development plans potentially untenable.  The court’s statement that the Lyles might have had a viable claim if they had introduced evidence that they actually tried—and failed—to sell a mineral lease perhaps ignores the commercial reality that the lessee interested in the prospect is often the first to initiate lease negotiations.  But with the solar array in place, one can understand why lessees might pass over the Lyles’ tract in favor of other, less restricted tracts.  In their petition for review before the Texas Supreme Court, the Lyles highlight this dilemma and also argue that the appellate court’s decision harms Texas mineral owners and their lessees.  The case will be an interesting one to watch if the Texas Supreme Court grants review.

Download Lyle v. Midway Solar - Court of Appeals Opinion

Download Lyle v. Midway Solar - Petition for Review

 

Aaron Powell

Thompson & Knight, LLP

 

[1] Case no. 21-0094.

Fixed or Floating? Another Texas Case Tackles Interpreting NPRIs

    A Texas court of appeals recently issued a decision construing the reservation of a nonparticipating royalty interest (NPRI) in a deed and resolving a dispute concerning the nature and calculation of such NPRI.  The case, Hoffman v. Thomson[1], is another example of the “fixed” vs. “floating” royalty line of Texas cases, which has become an area of frequent litigation in the oil and gas arena, and is one in a recent line of such cases in which the court had to assess the impact of the parties’ inclusion of a double fraction in the deed.

    A fixed royalty is a fixed fraction of the total production.  A floating royalty refers to a fraction of the entire royalty interest, meaning the total amount the NPRI owner receives depends on the royalty rate negotiated in the lease.  Confusion arises with double fractions.  For example, does “1/2 of the 1/8 royalty” result in a fixed 1/16 royalty or a floating 1/2 royalty?

Recent Cases

    Before discussing Hoffman, a brief recap of recent decisions is useful in framing the case.

 Hysaw v. Dawkins[2]

             In this 2016 case from the Supreme Court of Texas, a woman’s 1946 will left each of her three children a NPRI of “an undivided one-third (1/3) of an undivided one eighth (1/8) of all oil, gas or other minerals in or under that may be produced from any of said lands.”[3]  This language created an issue of whether the double fraction reserved a fixed 1/24 royalty or a floating 1/3 royalty.  The Court found this was a floating 1/3 royalty for a variety of reasons.  It made sense that three children would be given equal 1/3 shares, the standard royalty at the time the will was drafted was 1/8, and a fixed interest would create disharmony among deed language.

U.S. Shale Energy II, LLC v. Laborde Properties, L.P.[4]

            The Supreme Court of Texas dealt with a case very similar to Hysaw in 2018.  Here, a 1951 deed reserved “an undivided one-half (1/2) interest in and to the Oil Royalty, Gas Royalty and Royalty in other Minerals in and under that  may be produced or mined from the above described premises, the same being equal to one-sixteenth (1/16) of the production…”[5]  Again, this was found to be a floating royalty based on the standard 1/8 royalty of the time, “…the same being equal to one-sixteenth…” serving as clarifying language to the calculation, and the 1/2 interest being tied to the royalty rate.

Five Star Royalty Partners Ltd. v. Mauldin[6]

             The Fifth Circuit answered another question about a deed containing floating royalties in this 2020 decision.  The confusion stemmed from a 1927 deed conveying a “royalty interest of three-eighths (3/8) of all … minerals…” which also included the clauses, “the royalty interest hereby conveyed is a three-eighths (3/8) part of the royalty provided by said lease to be paid…” and “three-eighths of one-eighth interest… is a royalty interest only…”  In determining whether this was a fixed 3/64 royalty or a floating 3/8 royalty, the court looked to factors such as the usual 1/8 royalty during that era, the deed did not relieve the grantee of the requirement to pay production costs, and the previous lease with a 1/8 royalty terminated.  The court held this was a floating 3/8 royalty, resulting in a victory for the royalty interest owners, who were represented by Thompson & Knight attorneys.

Van Dyke v. Navigator Group[7]

            This late 2020 decision comes from another Texas court of appeals.  The court found a fixed 1/16 NPRI existed.  The deed reserved a “one-half of one-eighth of all minerals and mineral rights,” and this figure was the only mention of the size of an interest.  The court determined the language in the deed to be unambiguous, since there was no other language used to describe the reservation, thus creating a fixed 1/16 reservation.

            All of the above cases (particularly Hysaw and U.S. Shale Energy II) show a trend of a holistic approach in deed interpretation, rather than a mechanical approach.  Hoffman continues to follow this trend.

Hoffman v. Thomson

             In 1956, the Hoffmans conveyed a tract of land to Peeler and reserved “an undivided three thirty-second’s (3/32’s) interest (same being three-fourths (3/4’s) of the usual one-eighth (1/8th) royalty) in and to all of the oil, gas and other minerals, in to and under or that may be produced from the land herein conveyed…”[8] Both parties argued the deed was unambiguous, with the Hoffmans asserting the deed reserved an undivided floating 3/4 royalty and the Peelers claiming the deed only reserved a fixed 3/32 NPRI.  The parties did not dispute any facts; this was purely a deed construction case.  The trial court sided with the Peelers and construed the deed to reserve a fixed 3/32 NPRI.

            Before beginning its interpretation, the court laid out a few basic deed construction principles that it stated guided its analysis.  Continuing in the line of cases discussed above, the court placed particular emphasis on the fact that at the time when the deed was written in 1956, a 1/8 royalty was considered “standard and customary.”[9]

            Ultimately, the court honed in on three clauses contained in the deed, which read as follows:

Clause 1          “There is hereby expressly reserved… an undivided three thirty-second’s (3/32’s) interest (same being three-fourths (3/4’s) of the usual one-eighth (1/8th) royalty) in and to all of the oil, gas and other minerals…”

Clause 2          “Hoffman … shall receive a full three thirty-second’s (3/32’s) portion thereof as his own property…”

Clause 3          “Hoffman, shall own and be entitled to receive three thirty-second’s (3/32’s) of the gross production of all oil, gas and other minerals produced and saved…”

The court noted that, read in isolation, the latter two clauses would likely establish a fixed royalty interest.  Clause 3, for example, appears to expressly require that the owner be entitled to three thirty-seconds (3/32’s) of the “gross production.”  However, the court stated it “must give effect to, and harmonize, all the language, even if the second and third clauses might initially appear inconsistent or contradictory to the entire first clause.”[10]

When harmonizing the language, the court noted again that the “same being three-fourths (3/4’s) of the usual one-eighth (1/8) royalty” was consistent with the usual 1/8 royalty of that time, meaning the Hoffmans kept a 3/32 interest, or 3/4 of the royalty, whatever that royalty may actually be under the relevant lease at issue.  Thus, the court concluded, when 3/32 is used in the later clauses, it was used as “a placeholder or shorthand” for the full 3/4 of the royalty.[11]  According to the court when 3/32 is replaced with “three-fourths of the royalty” in later clauses, the “substitution also gives full effect to the language in all three clauses and does not create any conflicts or render any provision meaningless.”[12]  If the deed reserved only a 3/32 interest, the “same being three-fourths … of the usual one-eighth royalty” language would be both meaningless and create a conflict if the royalty was anything besides 1/8.  In continuing to follow the trend of holistic interpretation, the court determined the deed established a floating 3/4 royalty interest, reversing the trial court’s decision.

Current Status

            On March 24, 2021, a motion for extension of time to file motion for rehearing was granted.

Download Hoffman v. Thomson

 

Anna Boyer

Thompson & Knight, LLP

 

[1] No. 04-19-00771-CV, 2021 WL 881286 (Tex. App.—San Antonio Mar. 10, 2021, no pet. h.). 

[2] 483 S.W.3d 1 (Tex. 2016).

[3] Id. at 2.

[4] 551 S.W.3d 148 (Tex. 2018).

[5] Id. at 150.

[6] 973 F.3d 367 (5th Cir. 2020).

[7] No. 11-18-00050-CV, 2020 WL 7863330 (Tex. App.—Eastland Dec. 31, 2020, no pet. h.).  On March 12, 2021 a Second Motion for Extension of Time to File Petition for Review was granted.

[8] Id. at *1.

[9] Id. at *3 (citing Hysaw, 483 S.W.3d at 9).

[10] Id. at *4.

[11] Id. at *6.

[12] Id.

Supreme Court sides with lessors on post-production costs, but lessee not out of fuel just yet

    In the recent Texas Supreme Court (“Court”) decision in BlueStone Natural Resources II, LLC v. Randle,[1] the Court once again addressed the practice of deducting postproduction costs in oil and gas royalty calculations.  The Court also, for the first time, directly addressed the effect of a lease’s “free use” clause, applying such a clause more narrowly than some would have anticipated.  Ultimately, based primarily on what the Court concluded the plain meaning of the words of the lease required, the Court affirmed the lower court’s rulings in favor of the lessors on all issues. 

    The dispute in this case arose due to a change in the calculation of royalty payments to a number of lessors.  BlueStone Natural Resources II, LLC’s (“BlueStone”) predecessor in title had been paying the lessors (“Lessors”) gas royalties calculated on its gross sales proceeds  without subtracting any costs for gathering, processing, or otherwise handling the gas after its production (commonly known, as postproduction costs).  After BlueStone acquired the leases (“BlueStone Leases”) in 2016, BlueStone took a different interpretation of the leases and began deducting postproduction costs to calculate the gas royalties.  Subsequently, the royalty payments declined, and the lessors sued.  During the ongoing litigation, the Lessors also argued that BlueStone had failed to pay them for certain volumes of gas used in operations that occurred off of the leased premises and the issue was made part of the suit.

Postproduction Costs

    Texas courts frequently state that gas royalties are usually free of production costs, or the expenses incurred in extracting the product from the ground, but are not free of the additional expenses incurred to prepare and transport the gas for downstream sales.[2][3]  However, while the general rule is that lessors are responsible for their share of postproduction costs, many lessors attempt to modify this general rule to avoid the deduction of postproduction costs.  The attempts to allocate postproduction costs have become a frequently litigated issue and the Court has tackled the issue of the permissibility of the deduction postproduction costs from gas royalties a number of times.[4]  

    In the instant case, there were two provisions that addressed royalty payments.  The first was in the printed lease form (Paragraph 3) and the pertinent part stated as follows:

(b) on gas, including casinghead gas, or other gaseous substance produced from said land and sold or used off the premises or for the extraction of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold by Lessee the market value shall not exceed the amount received by Lessee for such gas computed at the mouth of the well, and on gas sold at the well the royalty shall be one-eighth of the amount realized by Lessee from such sale .... (emphasis added)

Neither party disputed that if this provision were the only clause regarding royalty computation, the Lessors’ royalty would be based on the value of the gas at “the well” and would be calculated inclusive of any postproduction costs incurred downstream from the wellhead.  However, the BlueStone Leases contained a second provision regarding the payment of royalties, which the lessors argued modified this general rule and required a different result.

The second relevant provision is located in the addendum attached to the printed form. The addendum included an introductory paragraph providing that “[i]t is understood and agreed by all the parties that the language on this [Exhibit] supersedes any provisions to the contrary in the printed lease hereof[.]”  Paragraph 26 of the addendum, states in whole as follows:

LESSEE AGREES THAT all royalties accruing under this Lease (including those paid in kind) shall be without deduction, directly or indirectly, for the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and otherwise making the oil, gas[,] and other products hereunder ready for sale or use. Lessee agrees to compute and pay royalties on the gross value received, including any reimbursements for severance taxes and production related costs. (emphasis added)

Contrary to the paragraph in the printed lease, if this provision were the only clause regarding royalty computation, the Lessors’ royalty would not have to pay their share of the postproduction costs incurred. 

    Accordingly, the heart of the dispute between the parties was whether the provisions in the printed lease and the addendum conflicted or whether the two provisions could be harmonized.  If there was a conflict, pursuant to the introductory paragraph of the addendum, the language in the addendum would control and the result would be a prohibition on the deduction of postproduction costs.  If there was no conflict, then according to BlueStone, the provisions would be reconciled and the Lessors would have to pay their share of the postproduction costs, as paragraph 3 of the printed lease form provided the royalties should be paid “at the mouth of the well.” 

    In order to best illustrate the arguments put forth by BlueStone and the Lessors, the Court described a typical royalty clause as a three part constructions: (1) the royalty fraction, (2) the yardstick, and (3) the valuation point or location for measuring the yardstick.[5]  A royalty provision must have all three parts for a royalty to be calculated.

    BlueStone argued that the relevant provisions in the printed lease form and addendum could be harmonized because “at the mouth of the well” was the only language providing a valuation point.  BlueStone contended that the “gross value received” in the addendum could be understood with the “at the well” valuation point in the printed lease form to produce a “net proceeds calculation.”[6] In addition, BlueStone argued that pursuant to the Court’s prior holding in Burlington Resources, the mere presence of the “at the mouth of the well” language gave it a controlling effect. 

    The Lessors argued that the royalty provisions could not and should not be harmonized because “gross value received” in the addendum contained both a yardstick and a valuation point.  Since the royalty provision in the addendum contained all necessary information to compute the royalty, the Lessors argued the addendum provision superseded the printed lease form and prohibited the deduction of postproduction costs. 

    The Court rejected BlueStone’s argument in favor of harmonizing the two provisions, finding that the requirement to value royalties on the “gross” value inherently conflicted with the requirement to value royalties at the well.  To address the question of where the royalty clause’s valuation point was, the Court pointed to the use of the “gross” as setting the valuation point. The Court clarified that “[w]hen proceeds are valued in ‘gross,’…the valuation point is necessarily the point of sale because that is where the gross is realized or received.” 

    BlueStone cited Burlington Resources as support for its argument that the “at the well” is controlling and requires the holding that royalties are to be subject to postproduction costs.  The Court explicitly rejected this interpretation of the Burlington Resources holding and stated that BlueStone had failed to acknowledge that the provision in Burlington Resources did not state whether the amount realized was “gross” or “net”, thus the Court had to give effect to other language.[7] The Court stated that its holding in Burlington Resources was made using general contract construction principles to construe the meaning of the agreement and did not make “at the well” language a magic bullet to allow for the deduction of postproduction costs in all cases.

    Ultimately, the Court affirmed that the use of “gross” in the addendum creates a valuation point at the point of sale and the “at the well” language was not the only valuation point.  Due to this conflict, the language of the addendum controlled and prohibited the deduction of postproduction costs. 

Free Use of Fuel

    The second issue the Court reviewed was whether BlueStone was entitled to a royalty-free right to use gas in off-lease operations if those operations benefited the lease, specifically plant fuel and compressor fuel.  The base royalty clause in the BlueStone Leases stated that it applied to all gas “sold or used off the premises or for the extraction of gasoline or other product therefrom.” However, the leases also contained a “free use” clause, providing that

Lessee shall have free from royalty or other payment the use of . . . gas . . . produced from said land in all operations which Lessee may conduct hereunder, including water injections and secondary recovery operations, and the royalty on . . . gas . . . shall be computed after deducting any so used. (emphasis added)

When included in a lease, courts generally hold that a “free use” clause controls a lessee’s right to use production from the lease premises in the operation of that lease.  If the lessee has the free right to use certain volumes of gas, such gas will be excluded from the volumes used to determine the lessor’s royalty.

    Accordingly, the crux of the dispute centered on whether the free use clause in the BlueStone Leases, which permitted use in all “operations… hereunder,” permitted BlueStone to use gas for operations that benefited the leases, regardless of where that use physically occurred, or whether such right to use gas without paying royalties was limited to only that use that physically occurred on the premises of the BlueStone Leases.  The court of appeals held that the BlueStone Leases limited the free use of gas to solely operations actually conducted on the leased premises. 

    The Court had not previously resolved a dispute regarding a free use clause and so turned to case law from other jurisdictions. Ultimately rejecting the jurisprudence from other oil and gas producing states, such as North Dakota, which have traditionally been more aligned with Texas in issues royalty clause interpretation, the Court relied heavily on the reasoning of the federal Tenth Circuit, which reached different conclusions after applying New Mexico and Colorado law to two sets of free use clauses similar to the ones currently before the Court. 

    The Tenth Circuit in Anderson Living Trust examined two groups of leases (one set for properties in New Mexico and one set for properties in Colorado), and ultimately concluded that the New Mexico leases permitted a broader royalty-free use of gas than the Colorado leases.[8] 

    The free use provision in the New Mexico leases provided “the right to use free of cost, gas, oil and water found on said land for its operations thereon, except water from the wells of the lessor.”  (emphasis added)  The Tenth Circuit found that New Mexico precedent provided that “the phrase ‘operations thereon’ in the . . . ‘free use’ clause [in the New Mexico leases] is not a limitation on where the use of the gas may occur but rather a limitation on the purposes for which the gas may be used—furtherance of the lease operations.”[9]  The Tenth Circuit held that the New Mexico lease provision included providing gas to third-party processors as under the umbrella of free use, as that action ensured a market for the product.  It is noted that the court included a footnote stating that its holding was in part due to the favorable citing of Bice v. Petro Hunt, L.L.C., 768 N.W.2d 496 (N.D. 2009) by the New Mexico Supreme Court.[10] 

    Conversely, the Colorado leases contained a clause providing the lessee “free use of oil, gas and water from said land . . . for all operations hereunder.”  Using general contract construction principles, and unrestrained by prior Colorado precedent, the Tenth Circuit held that the ordinary meaning of the language limited operations to those that occurred on the leased lands.  The court further pointed to the royalty clause that required the royalty to be paid on gas “…used off the leased premises” as additional support for its holding. 

    The Court here followed the Tenth Circuit’s holdings as related to the Colorado leases due to the fact that language in the BlueStone Leases was similar and the Court saw no reasonable way to extend the language to off-lease uses.  As support for its limitation of the free use clause to uses on the leased premises, the Court noted the lack of any limitation to the application of the free use clause would create a “fact-finding mission to determine whether progressively more attenuated uses ‘benefit’ or ‘further’ the lease operations.”[11] Without further parameters provided in the clause, the Court refused to broaden any interpretation of the free use clause in the BlueStone Leases to include uses of gas that did not occur “hereunder” (or under) the lease premises.  The Court affirmed the court of appeals holding that the free use of gas was limited to operations conducted on the leased premises and royalties were owed on all gas used off of the lease premises.

    The Court then reviewed the two uses of the gas that BlueStone claimed were free of royalty under the free use clause.  First, the “plant fuel” was gas that BlueStone’s processor used to fuel the plant operations that processed the gas delivered by BlueStone.  The parties stipulated that the plant fuel had been used off the leased premises, so the Court held that royalties were due on all of the plant fuel.

    The second and more difficult use at issue, according to the Court, was the “compressor fuel” or gas that returned by the processor to BlueStone to power compressors on the leased premises.  As part of its agreement with its processor, BlueStone contracted for redelivery of processed gas back to BlueStone, which BlueStone used for various purposes, including compressor fuel for compressors located on both the plaintiffs’ and BlueStone’s other leases.  Notably, it was undisputed that at least some of the compressor fuel was used on the leases at issue for operations on those leases and would therefore be covered by the free use clause.  However, the Court determined that since the gas used as compressor fuel was commingled and aggregated with gas from other properties prior to its use by BlueStone, BlueStone could not use gas from one lease for operations on a different lease and was required to produce evidence linking each leases’ fractional share of the commingled, processed gas to consumption by compressors on each of the leased premises.  Accordingly, the Court remanded to the trial court to determine the damages “if any” owed for the off-lease use of compressor fuel.    

    Ultimately, the Court reemphasized that the plain meaning of the words chosen would continue to control the result in cases concerning postproduction costs.  And in the Court’s first review of a “free use” clause case, the Court signaled that it may be unlikely to read a broad meaning into the free use clause without further indication of the parties intent.  Drafting of the royalty clause and free use clauses should be carefully reviewed to ensure that the intention of the clause is clearly being described. 

Download BlueStone Natural Res. II LLC v. Walker Murray Randle Decision

 

[1] No. 19-0459, 2021 WL 936175 (Tex. Mar. 12, 2021).

[2] Id. at *3 (citing French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex. 2014)).

[3] It is noted that any discussion regarding postproduction costs is normally only discussing gas royalties.  This is because the postproduction costs for oil are minimal as oil is typically sold to a refinery from the storage tanks at the well and just need to be transported/trucked to the refinery for processing.

[4] See also Burlington Res. Oil & Gas Co. LP v. Tex. Crude Energy, LLC, 573 S.W.3d 198 (Tex. 2019); French v. Occidental Permian Ltd., 440 S.W.3d 1 (Tex. 2014); Chesapeake Expl., L.L.C. v. Hyder, 483 S.W.3d 870 (Tex. 2016); and Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996).

[5] BlueStone Nat. Res. II, LLC, 2021 WL 936175 at *4 (citing BlueStone Nat. Res. II, LLC v. Randle, 601 S.W.3d 848, 856 (Tex. App.—Forth Worth 2019) (quoting Byron C. Keeling, In the New Era of Oil & Gas Royalty Accounting: Drafting a Royalty Clause That Actually Says What the Parties Intend It to Mean, 69 Baylor L. Rev. 516, 520 (2017))). 

[6] Id. at *3.

[7] Id. at *7.

[8] See Anderson Living Trust v. Energen Res. Corp., 886 F.3d 826 (10th Cir. 2018).

[9] BlueStone Nat. Res. II, LLC, 2021 WL 936175 at *12 (citing Anderson Living Trust, 886 F.3d at 845).

[10] See ConocoPhillips Co., 299 P.3d 844.

[11] BlueStone Nat. Res. II, LLC, 2021 WL 936175 at *13.

 

 

Brooke Sizer, Josh Downer and Anna Boyer

Thompson & Knight, LLP

A Wrinkle in Time: Texas Supreme Court Takes on the Rule Against Perpetuities

The Texas Supreme Court recently issued an opinion that may have caused some attorneys to relive a law school nightmare. In Yowell v. Granite Operating Company, the Court determined that an anti-washout provision in a reservation of an overriding royalty interest violated the infamous rule against perpetuities (the “Rule) by attempting to attach the overriding royalty interest to a new oil and gas lease.[i]

The Rule provides that “no property 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.”[ii] Originally the rationale of the Rule was to prevent real property owners from controlling interests in the real property for long periods of time. For an example of a scenario violating the Rule, suppose a ranch owner grants the ranch to Ben for as long as the property is used for a school, then to the owner’s grandchildren. Because the ranch could ceased to be used as a ranch more than 21 years after the death of Ben, the second transfer fails. However, the simplicity of the Rule in application can quickly become complex.

The recent decision in Yowell was the first time that the Court analyzed the application of the Rule to an anti-washout provision in new leases. Previous cases determined that the anti-washout provision did not violate the Rule for leases that were renewed or extended.[iii]

In Yowell, the original lease was acquired in 1986. The original lessee later assigned its interest while reserving a 2.25% ORRI. The reservation (now owned by the Yowells) was made subject to an anti-washout provision that was to cover any extension, renewal or new lease executed by the lessee. In 2007, a top lease was taken and shortly thereafter, the top lessee sued alleging that the 1986 lease had terminated. The parties ultimately settled their dispute and agreed that the 1986 Lease had terminated and the new 2007 lease was in effect. The lessee decided that the new 2007 lease negated the obligation to pay the Yowells the ORRI. The Yowells sued and sought a judicial declaration of ownership and recovery of the payments. The trial court granted the motion for summary judgment filed by the defendants, holding that the ORRI violated the Rule. The Court of Appeals of Amarillo affirmed the ruling.

In the Court’s analysis, the Court first determined whether the Yowells’ ORRI was a property interest that could be subject to the Rule. The Court affirmed that the ORRI was a real property interest and that any contingency regarding whether or not the ORRI would be extended to a future lease did not affect the real property characterization of the interest.

The Court then analyzed whether the ORRI as extended to new leases violated the Rule. The ORRI did not vest in new leases at the time of its creation due to the existence of contingencies, including that the original lease had to terminate. Because the ORRI had not vested, the Court turned to whether or not it would vest within the 21 years after the death of some life in being at the time of reservation. Applying the anti-washout clause to new leases violated the Rule because the enjoyment of the ORRI under future leases relied on additional events that may not occur within the prescribed timeframe such as the original lease terminating and a new lease being granted.

Because the clause at issue in its application violated the Rule, the Court held that the interest should be reformed under Texas Property Code § 5.043, which provides that if an instrument is found to violate the Rule, the instrument shall be reformed or construed “to effect the ascertainable general intent of the creator of the interest.” The Court left the trial court to grapple with the practicalities of how an unconstitutional deed can be reformed, particularly when there is no measuring life.

Additional questions left unanswered in the opinion may become the subject of future litigation. For instance, the court did not address defendants’ arguments regarding the distinction between the four year statute for reformation and actions for the recovery of real property, which have no time limitations other than the adverse possession statutes. The Court also declined to guide operators faced with attributing payment to such an interest. Numerous overriding royalty interests that exist of record that may now be deemed invalid due to their violation of the Rule; however, the Court provided no indication as to whether an operator has a continuing duty to pay the owner of that interest because the instrument may be reformed.

Until those questions are fully addressed, any attempt to include an anti-washout provision that would apply to new leases should be drafted to ensure the interest vests within the Rule’s timeframe. And until there is further guidance from the courts on how these interests will be reformed, operators face vexing questions of how to handle potentially invalid but reformable interests.

 

[i] 2020 WL 2502141 (Tex. May 15, 2020).

[ii] Id. at *3.

[iii] See, e.g., Sunac Petroleum Corp. v. Parkes, 416 S.W.2d 798, 802-03 (Tex. 1967).

 

Brooke Sizer

Thompson & Knight LLP

Arbitration: Keep It Efficient and Cost Effective

In OJSC Ukrnafta v. Carpatsky Petroleum Corp., 957 F.3d 487 (5th Cir. 2020), the Fifth Circuit recited a familiar notion: “Arbitration is supposed to keep disputes out of court and ‘increase[] the speed of dispute resolution.’” The Fifth Circuit made this statement in the context of a contract dispute governed by an arbitration agreement that spawned related litigation and a decade-long confirmation process. This case highlights that not all arbitrations are speedy, efficient, and cost-effective. To achieve the intended purposes of arbitration, such provisions should be carefully prepared and the process vigilantly managed.

In 1994, Carpatsky Petroleum Corporation, a Texas company at the time, entered into a Joint Activity Agreement (JAA) with the Ukrainian company OJSC Ukrnafta to develop a gas condensate field in Ukraine. Disputes were to be resolved by arbitration. In 2007, Carpatsky commenced arbitration against Ukrnafta, alleging breach of the JAA. The arbitration was not speedy and did not stay out of court. The arbitral award was issued some three years later in 2010, during which three separate related lawsuits were filed. It took another decade for the arbitral award to be confirmed into a U.S. judgment while execution continues.

Despite the experience of Carpatsky and OJSC Ukrnafta, arbitration can be a quicker, cheaper route than courthouse litigation. As a creature of contract, the process is controlled by the parties. When negotiating an arbitration clause, parties should consider how to maximize the efficiency and minimize the costs of the process. All too often, parties simply agree, usually at the end of the negotiation process, to boilerplate language that may fail the twin goals of efficiency and economy. But parties with bare-bones or boilerplate arbitration clauses need not lose hope. Pay careful consideration to selecting the applicable ruleset and, in the event the clause is exercised, work with the arbitral tribunal to design an efficient and cost-effective process.

Getting the most out of arbitration requires attention to both the drafting of an appropriately tailored ADR provision and the management of the arbitration process. To do otherwise is to risk repeating the process followed in OJSC Ukrnafta.

 

Andrew B. Derman, Andrew Melsheimer, TJ Auner

Thompson & Knight, LLP

Prorationing No Longer on the Table, Railroad Commission Enacts Other Temporary Relief

As a follow-up to this post, the Railroad Commission of Texas’s May 5, 2020 open meeting resolved the pending prorationing request. Public comments made by the Commissioners in advance of the meeting made clear that the Commission would not order prorationing, and as expected, the Commission voted 2-1 at the meeting to dismiss the verified complaint submitted by Parsley Energy and Pioneer Natural Resources, with only Commissioner Sitton in opposition.

In addition to dismissing the complaint, the meeting resulted in other important items that producers should be aware of. First, the Commission issued orders providing temporary relief and exceptions to several of its rules, including (1) waivers of fees and surcharges associated with multiple applications for the remainder of 2020 (namely, P-17, W-14, H-1, H-4, W-3C), (2) extensions to the deadline to plug certain wells and to backfill authorized pits under Statewide Rules 8 and 14, (3) extensions to the permitted duration of administrative approvals for alternative casing and tubing programs under Statewide Rule 13, and (4) granting greater discretion to the Commission’s legal enforcement division in assessing penalties for violations of the Commission’s rules occurring between March 1, 2020 and March 1, 2021.

Of particular note, the Commission broadened the options for underground liquid storage by granting a temporary exception to Statewide Rule 95. Under the current rule, only an impermeable salt formation may be used as a liquids storage facility. However, the order will allow applications for permits to store liquids in all other types of formations and suspends the requirement to hold a hearing for uncontested storage permit applications.

Some of the rule modifications approved yesterday were based on recommendations of the Blue Ribbon Task Force for Oil Economic Recovery, comprised of representatives from each facet of the industry, which the Commission tapped to provide advice for recovery following the COVID-19 pandemic. The Task Force submitted a report to the Commission with over four dozen recommended action items, indicating that more rule changes may be expected in the future.

Finally, the Commission expressed an increased desire to explore additional regulations on the flaring of natural gas, with both Chairman Christian and Commissioner Craddick stating their belief that the current circumstances presented an opportunity to address the issue in a meaningful way. Chairman Christian further requested that the Task Force explore possible ways to effectively address flaring and report back before the Commission’s open meeting scheduled for June 16^th.

For further information, see the full recording of the open meeting, with discussion of the above topics beginning approximately thirty minutes into the recording, The Task Force’s report, and the full text of two of the orders, including the exception to Statewide Rule 95.

Josh Downer 

Thompson & Knight, LLP

 

Railroad Commission of Texas Declines to Order Prorationing – For Now

In an open meeting virtually conducted yesterday morning, the Railroad Commission of Texas seemed to indicate that prorationing may be a real possibility in the near future. Commissioner Ryan Sitton, citing the need for prompt action, moved that the Commission immediately consider a prorationing order, designed to curtail 20% (approximately 1 million barrels per day) of oil production by Texas producers. Commissioner Sitton further outlined his vision of a proposed order, which would have an effective date of June 1^st and would be contingent on other oil producing states and nations also agreeing to reduce production by 4 million barrels per day. As proposed by Commissioner Sitton, the order would apply to all Texas producers producing over 1,000 barrels per day, with allowables set for individual producers based on the producer’s production in October, November, and December 2019.

The proposal comes on the heels of a verified complaint from producers Pioneer Natural Resources and Parsley Energy, requesting that the Commission institute prorationing, and an associated hearing conducted on April 14, 2020, in which the Commission heard an unprecedented 10 plus hours of testimony. At a high level, proponents of prorationing argue that, with current oil prices, unchecked production constitutes waste, which must be regulated by the Commission under Tex. Nat. Res. Code § 85.051, while opponents argue that the free market is the best regulator of over supply and that governmental interference may have unintended consequences that have not been fully assessed.

Despite Commissioner Sitton’s urging, the Commission ultimately decided to postpone considering the motion until the next open meeting, currently scheduled for May 5^th. Commissioners Christian and Craddick pointed to ongoing coordination efforts with other oil and gas producing states, such as North Dakota and Oklahoma, and a concern that proceeding with the motion without the benefit of a thorough review by staff and the Attorney General might lead to extended litigation as reasons to support the delay.

A recording of the full meeting is available on the Commission’s website at the following link. http://www.adminmonitor.com/tx/rrc/open_meeting/. For those wanting to cut to the heart of the matter, the proposal on prorationing is item 309 on the agenda, and the relevant discussion begins about 43 minutes into the recording.

 

Joshua Downer

Thompson & Knight LLP

Carnivorous Clauses: Piranha Partners Consumes Entire ORRI

The Texas Supreme Court recently addressed whether an assignment of overriding royalty interests conveyed the seller’s interest in the only then-existing wellbore, or in any subsequent well on the entire lease. In Piranha Partners v. Neuhoff the court held that the assignment at issue “unambiguously conveyed the assignor’s overriding royalty interest in all production under the lease” as opposed to just production from a single well.[1]

The facts are simple: Neuhoff Oil & Gas sold and assigned its mineral interest in Section 28 but reserved a 3.75% ORRI in all production under the Lease. Only one well—the “Puryear B #1-28”—was completed during the relevant timeframe, in Section 28’s northwest quarter. Later, Neuhoff Oil auctioned off its ORRI to Piranha Partners; to complete the sale, Neuhoff Oil and Piranha executed a written assignment.

The assignment is not as simple. The granting clause provided:

Neuhoff Oil does hereby assign, sell and convey unto Piranha ... without warranty or covenant of title, express or implied, subject to the limitations, conditions, reservations and exceptions hereinafter set forth ... all of Neuhoff Oil’s right, title and interest in and to the properties described in Exhibit “A” (the “Properties”).[2]

Exhibit A provided:

Time passed and the operator completed several other wells on Section 28. The operator paid the ORRI from the Puryear B #1-28 to Piranha and the ORRI from the new wells to the Neuhoffs.[3] Later title opinions, however, concluded that Piranha owned the ORRI on all production under the Lease—not just production from the Puryear B #1-28. As a result, the operator retroactively paid Piranha the ORRI on all Section 28 wells and demanded refunds from the Neuhoffs. And so the Neuhoffs sued, arguing that Neuhoff Oil assigned only its ORRI in the Puryear B #1-28 to Piranha. The trial court agreed with Piranha, the court of appeals disagreed with everyone,[4] and the Texas Supreme Court granted review to determine exactly what the parties intended.

The Texas Supreme Court sided with Piranha: “Neuhoff Oil conveyed its 3.75% overriding royalty interest in all production under the Puryear Lease.”[5] Although the court noted that Exhibit A was ambiguous and potentially unenforceable, it held that other provisions demonstrated the parties’ intent to convey Neuhoff Oil’s ORRI under the entire lease. The first provision followed the assignment’s granting clause and described:

All oil and gas leases, mineral fee properties or other interests, INSOFAR AND ONLY INSOFAR AS set out in Exhibit A . . . whether said interest consists of leasehold interest, overriding royalty interest, or both, which shall include any working interest, leasehold rights, overriding royalty interests and reversionary rights held by Assignor . . . .

The Court held that this paragraph “explain[ed] that the interest described in Exhibit A include[d] any overriding royalty interest Neuhoff Oil then owned.”[6] The court then proceeded to the next paragraph, which stated the conveyance included:

All presently existing contracts to the extent they are assignable and to the extent they affect the Leases, including agreements for the sale or purchase of oil, gas and associated hydrocarbons, division orders, unit agreements, operating agreements, and all other contracts and agreements arising from, connected with, or attributable to the production therefrom.

Because Neuhoff Oil conveyed contracts that affected “the Leases”—as opposed to just the well or the land—the Court explained that this paragraph provided further support for its holding that Neuhoff Oil intended to convey its entire interest under the Lease. Justice Bland dissented—she would have held that the assignment was ambiguous and submitted its interpretation to a jury.

Piranha demonstrates that parties must closely scrutinize the language used in their assignments, as well as any attached exhibits. Buyers and sellers are usually focused on the language of the purchase agreement and the assignment document itself, and rightfully so. But Piranha shows the importance of paying attention to exhibits, which generally describe the exact nature of the assets being bought and sold. For buyers, confirmation of exhibits should be a key aspect of any due diligence examination. And for sellers such as Neuhoff Oil, inattention to exhibits can result in serious, unintended consequences. A simple notation on the exhibit that the conveyance was limited to the wellbore only of the Puryear B #1-28 might have avoided this result for Neuhoff.

 

[1] ---S.W.3d---, No. 18-0581, 2020 WL 868120, at *1 (Tex. Feb. 21, 2020) (emphasis added).

[2] Id. at *3 (brackets omitted)

[3] By this point Neuhoff Oil had dissolved and assigned its remaining assets to individual members of the Neuhoff family.

[4] The Amarillo Court of Appeals “held that Neuhoff Oil sold the overriding royalty in production not from all of Section 28, and not just from the Puryear B #1-28, but from all of the northwest quarter of Section 28.” Id. at *2.

[5] Id. at *11.

[6] Id. at *10.

 

Brandon King and Aaron Powell

Thompson & Knight, LLP

LNG Update: U.S. Eases Restrictions on Small-Scale LNG Export Projects

The U.S. has an estimated 2,462 trillion cubic feet of recoverable natural gas, enough to last about 90 years at current consumption rates.[1]  With such reserves, the U.S. is well-positioned to meet anticipated four to five percent annual growth in global natural gas demand, primarily through U.S. LNG export projects.[2] 

While large-scale LNG projects are prevalent in the U.S., the current permitting process for such projects can be expensive, and smaller-scale projects are often not cost-effective under current conditions. In a move to reduce the time and investment required to develop small-scale projects, on July 25, 2018, the U.S. Department of Energy, Office of Fossil Energy (“DOE-FE”) promulgated a final rule streamlining the authorization process for small-scale export authorizations of natural gas and LNG (the “Final Rule”).[3] 

Under the Final Rule, applications seeking export authorization under the proscribed volume limit (less than 51.75 billion cubic feet per year) and qualifying for a categorical exclusion from environmental impact review, are presumed to be in the public interest. This presumption lowers the evidentiary threshold for approval of natural gas and/or LNG export authorizations to countries with which the U.S. lacks a free trade agreement governing natural gas and LNG.

Just this November, the U.S. DOE-FE issued the first set of orders applying the Final Rule.[4]  These orders authorized SpotX Energy, LLC to purchase LNG from suppliers and load it into shipping containers or onto ocean-going vessels for export.[5]  SpotX was also authorized to export LNG as an agent for parties holding title to the LNG upon export.[6]  Underscoring the unique development characteristics of these small-scale projects, the SpotX orders also marked a policy shift enabling a new business model in the U.S. LNG sector: a gas aggregator who is not an owner or operator of an LNG facility procuring LNG and exporting it under its own authorization.   

The Final Rule was well received by Republicans in Congress where Senators Marco Rubio (R-FL), Bill Cassidy (R-LA) and John Kennedy (R-LA) co-sponsored the Small Scale LNG Access Act which, if signed into law, would codify the Final Rule. The bill’s sponsors focused on the legislation’s positive impact on U.S. jobs and benefits to consumers in smaller export markets such as the Caribbean, Central America, and South America.  The bill remains pending in the Senate.  U.S. Representative Ted Yoho (R-FL) is leading pending companion legislation in the House.

According to proponents, these recent regulatory and legislative developments affecting small-scale LNG export projects pave the way for significant economic benefits for the U.S. including: increased tax revenue on gas production and processing activities, strengthened job creation in the natural gas sector and ancillary industries, and an improved balance of trade by increasing exports relative to imports.

[1] U.S. Energy Information Administration, Frequently Asked Questions: How Much Natural Gas Does the United States Have, and How Long Will It Last? (Last Update April 5, 2019), available here.

[2] Id.

[3] U.S. Dep’t of Energy, Small-Scale Natural Gas Exports; Final Rule, 83 Fed. Reg. 35,106 (July 25, 2018).

[4] See SpotX, DOE-FE Order Nos. 4461 and 4462 (Nov. 8, 2019).

[5] Id.

[6] Id. at 8-9.

*Photo licensed under Creative Commons

 

Nick McTyre

Thompson & Knight, LLP