2017 OIL & GAS CASE LAW UPDATE

Christopher Kulander, Director and Professor, Harry L. Reed Oil & Gas Law InstituteSouth Texas College of Law Houston1

TABLE OF CONTENTS

Denbury Green Pipeline-Texas, LLC v. Texas Rice Land Partners, Ltd., No. 15-0225 (Tex. Jan. 6, 2017)............................................................................................................................................1BP America Production Company v. Laddex, Ltd., No. 15-0248 (Tex. Mar. 3, 2017)...................6Davis v. Mueller, No 16-0155 (Tex. Mar. 23, 2017).....................................................................12Forest Oil Corporation v. El Rucio Land and Cattle Company, Inc., No. 14-0979 (Tex. Apr. 28, 2017)..............................................................................................................................................13Lightning Oil Co. v. Anadarko E&P Onshore LLC, No. 15-0910 (Tex. May 19, 2017)..............17Samson Exploration v. T.S. Reed Properties, No. 15-0886 (Tex. June 23, 2017)........................19Wenske v. Ealy, No. 16-0353 (Tex. June 23, 2017)......................................................................22High Mount Exploration & Prod. LLC v. Harrison Interests, Ltd., No. 14-15-00058-CV (Tex. App.—Houston [14th], Oct. 6, 2016).............................................................................................26Ring Energy, Inc. v. Trey Resources, Inc., No. 08-15-00080-CV (Tex. App.—El Paso, Jan. 18, 2017)..............................................................................................................................................28Aruba Petroleum, Inc. v. Parr, No. 05-14-01285-CV (Tex. App.—Dallas, Feb. 1, 2017)...........31Reed v. Maltsberger, No. 04-16-00231-CV (Tex. App—San Antonio, May 3, 2017).................33Chieftain Exploration Company Inc. v. Gastar Exploration Inc. and Cubic Assets, No. 10-15-00037-CV (Tex.App.—Waco, Aug. 30, 2017).............................................................................35XTO Energy v. Goodwin, No. 12-16-00068-CV (Tex.App.—Tyler, Oct. 18, 2017)....................36Boerschig v. Trans-Pecos Pipeline, No. 16-50931 (5th Cir., Oct. 3, 2017)..................................40

CASES

Denbury Green Pipeline-Texas, LLC v. Texas Rice Land Partners, Ltd., No. 15-0225 (Tex. Jan. 6, 2017)

On January 6, 2017, the Supreme Court of Texas reversed the judgment of the Beaumont Court of Appeals (Ninth District) and reinstated the judgment of the trial court. The Court held that because the summary judgment evidence produced by Denbury Green Pipeline-Texas, LLC (“Denbury Green”) established conclusively “a reasonable probability that, at some point after

1 B.S. (Geology) and M.S. (Geophysics), Wright State University; Ph.D., Texas A&M University (Petroleum Seismology); J.D., University of Oklahoma. The author wishes to thank Aaron Epstein, Pierre Grosdidier, Donald Jackson, Kyle Kemp, Cameron Sheppard, and Rachel Schiller for their assistance with this paper. © 2017 Christopher Kulander. All rights reserved.

1

construction, the carbon dioxide pipeline known as “the Green Line” would serve the public, as it does currently,” Denbury Green could be categorized as a common carrier for the Green Line.

Denbury Green built a pipeline that became part of a network of pipelines formed in part for the transportation of carbon dioxide (“CO2”) from Jackson, Mississippi to Texas. The route followed by the Green Line ran through eastern Texas and, prior to construction, Denbury Green had tried to get the permission of landowners across the proposed pipeline route, one of whom was Texas Rice Land Partners, Ltd. (“Texas Rice”), to perform surveys of their property. In 2007, Denbury Green was denied access to Texas Rice’s land after attempting to survey two of its Jefferson County, Texas tracts. The following year Denbury Green sought common-carrier status and, to that end, filed a T-4 permit application with the RRC.2 After receiving the permit, Denbury Green sued to obtain an injunction against Texas Rice to stop Texas Rice’s prevention of its entry onto the Texas Rice tracts in Jefferson County for the purpose of completing the pipeline survey. Then, while the suit remained unresolved, Denbury Green took possession of the property pursuant to the Texas Property Code3 and proceeded to survey for and build the Green Line.

Texas Rice I

The trial court found Denbury Green to be a common carrier with the power of private eminent domain in accordance with the Natural Resources Code, and this judgment was affirmed on appeal.4 In Texas Rice’s first appeal to the Supreme Court of Texas,5 however, the Court reversed and remanded the case to the trial court. (Hereafter, “Texas Rice I”.) According to the Court at the time, reversal and remand were intended to allow for proceedings in line with the common-carrier test established by the Court therein, which would provide an opportunity for Denbury Green “to produce ‘reasonable proof of a future customer, thus demonstrating that [the Green Line] will indeed transport to or for the public for hire and is not limited in [its] use to the wells, stations, plants, and refineries of the owner.’”6 The Court observed that on remand, Denbury Green produced evidence including transportation agreements with both Air Products & Chemicals, Inc. and Airgas Carbonic, Inc., both unaffiliated entities. The Court also noted the inclusion in the evidence of another transportation agreement, this one between Denbury Onshore and Denbury Green. The court of appeals’ review of the evidence produced on remand led it to the conclusion “that ‘reasonable minds could differ regarding whether, at the time Denbury Green intended to build the Green Line, a reasonable probability existed that the Green Line would serve the public,’” and it reversed the trial court’s grant of summary judgment for Denbury Green as the case wound through the court system for a second time.7

The Texas Supreme Court then turned to its first decision in Texas Rice I where, to conform with the Texas Constitution, it had held “that “[t]o qualify as a common carrier with the power of eminent domain, the pipeline must serve the public; it cannot be built only for the builder’s exclusive use.”8 The Court noted it had then specifically found:2 See TEX. NAT. RES. CODE § 111.019(a) (“Common carriers have the right and power of eminent

domain.”).3 Specifically, TEX. PROP. CODE § 21.021(a).4 Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 296 S.W.3d 877, 881 (Tex. App.—

Beaumont 2009), rev’d, 363 S.W.3d 192 (Tex. 2012).5 Texas Rice I, 363 S.W.3d 192.6 Id. at 204.7 457 S.W.3d 115, 121-22 (Tex. App.—Beaumont 2015, pet. granted).8 363 S.W.3d at 200.

2

“for a person intending to build a CO2 pipeline to qualify as a common carrier under Section 111.002(6) [of the Natural Resources Code], a reasonable probability must exist that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier.”9

According to the Court, a reasonable probability under the test “is one that is more likely than not.”10 The Court further observed that when a challenge to common-carrier status is brought by a landowner, “the burden falls upon the pipeline company to establish its common-carrier bona fides if it wishes to exercise the power of eminent domain.”11 The Court noted it held “Denbury Green was ‘not entitled to common-carrier status simply because it obtained a common-carrier permit, filed a tariff, and agreed to make the pipeline available to any third party wishing to transport its gas in the pipeline and willing to pay the tariff.’”12 The Court observed that, while the Texas Rice I affidavit testimony supported the existence of negotiations between Denbury Green and parties seeking to use the Green Line to transport CO2, it failed to show whether the gas would be used for other parties’ benefit or entirely by Denbury Green. 13 Per the Court, evidence in the record did not identify any possible customers; rather, the evidence merely attested to a likelihood of future customers making use of the Green Line.14 The Court also noted there had been evidence of an intention by Denbury Green to operate the Green Line wholly for purposes of its own,15 and Denbury Green’s website included statements suggesting the pipeline would be used for its tertiary recovery operations.16 The Court observed the evidence in Texas Rice I failed to show there was a reasonable probability the pipeline would serve the public “at some point after construction,”17 and led it to then hold that Denbury Green’s contentions were not enough to find it was a common carrier.18 The Court noted it had ultimately remanded the case for further proceedings in the trial court, having concluded that when the common-carrier status of a pipeline “has been challenged, “the company must present reasonable proof of a future customer, thus demonstrating that the pipeline will indeed transport ‘to or for the public for hire’ and is not ‘limited in [its] use to the wells, stations, plants, and refineries of the owner.’”19

Texas Rice II

The Court then turned to the dispute among the parties in current appeal (Texas Rice II): whether the new evidence, provided by Denbury Green on remand after Texas Rice I, entitled it to summary judgment as to whether it was a common carrier. Here, the Court found its task was to apply the Texas Rice I test to the facts of the new case. Therefore, observed the Court, it would consider whether, as a matter of law, Denbury Green established a reasonable probability 9 Id. at 202 (footnotes omitted).10 Id. at 202 n. 29.11 Id. at 202.12 Id.13 Id. at 203.14 Id.15 Id.16 Id. at 203-04.17 Cf. State v. K.E.W., 315 S.W.3d 16, 23 (Tex. 2010) (recognizing that “probability” is synonymous with

“likelihood”).18 Texas Rice I, 363 S.W.3d at 202 (quoting Houston Auth. of City of Dallas v. Higginbotham, 143 S.W.2d

79, 84 (Tex. 1940)).19 Id. at 204 (quoting TEX. NAT. RES. CODE §§ 111.002(a), .003(a) (alteration in original)).

3

the Green Line, after construction, “would serve the public by transporting gas for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier.”

The Court reflected on its own review of the evidence in Texas Rice I, noting it had then been limited to assertions by Denbury Green regarding its intention to have the public use the Green Line. The Court noted it was the lack of evidence demonstrating “a reasonable probability of the Green Line’s future public use” that led it to determine Denbury Green was not entitled to summary judgment.20 The Court observed that, by itself, such evidence of intent failed to meet the reasonable probability standard from Texas Rice I.21 There was also affidavit testimony in support of Denbury Green’s contention that there were other parties with which it was negotiating for the transportation of CO2 over the Green Line, but the Court found this testimony suggested Denbury Green would only transport gas for tertiary recovery operations of its own and, therefore, without evidence to the contrary, this did not establish public use.22 According to the Court, “[t]he testimony ‘did not identify any possible customers and [Denbury Green] was unaware of any other entity unaffiliated with Denbury Green that owned CO2 near the pipeline route in Louisiana and Mississippi.’”23 As to the claims of Denbury Green on its website, the Court had concluded:

“Denbury Green’s representations suggesting that it (1) owns most or all of the naturally occurring CO2 in the region, (2) intends to purchase all the man-made CO2 that might be produced under current and future agreements, (3) see its access to CO2 as giving it a significant advantage over its competitors, and (4) intends to fully utilize the pipeline for its own purposes, are all inconsistent with public use of the pipeline.”24

The Court had thus held Denbury Green had not established “a reasonable probability that, ‘at some point after construction,’ the Green Line would serve the public.”25

The Court next considered the court of appeal’s decision against Denbury Green, noting that the court of appeals, in holding “central to our inquiry is Denbury Green’s intent at the time of its plan to construct the Green Line[,]” had wrongly interpreted the Texas Rice I test’s introductory phrase “for a person intending to build[.]” The Court observed it was improper to focus on intent, as “person intending to build” did not describe the “intent” required of a party when the pipeline was being considered. According to the Court, this phrase merely showed who had to prove common-carrier status—the pipeline company. The Court observed the court of appeals’ focus on intent led it to discount relevant evidence Denbury Green had submitted regarding a contract with Airgas Carbonic for transportation of its CO2 over the Green Line, which the court of appeals noted had been entered into following construction of the pipeline.26 The Court also noted “the court of appeals rejected relevant evidence that the Green Line’s future public use could be supported by its proximity to other CO2 shippers once construction was completed.”27 According to the Court, the court of appeals had shifted the analysis to focus on intent and, consequently, had disregarded relevant evidence supporting the common-carrier 20 Texas Rice I, 363 S.W.3d at 204.21 See id. at 203-04.22 Id. at 203.23 Id.24 Id. at 204 (emphasis added).25 Id.26 457 S.W.3d at 120.27 Id.

4

status of Denbury Green.

Next, the Court reflected on the nature of the Texas Rice I test, observing it balanced landowner property rights with the public policy interest of the state in development of pipelines, even as it preserved respect for constitutional limitations on the oil and gas industry.28 The Court noted that before Texas Rice I, obtaining common-carrier status required pipeline owners “to do little more than “check[] a certain box on a one-page government form[.]”29 According to the Court, the Texas Constitution demands considerably more,30 requiring some objective evidence that the public will probably be served by a pipeline in order for its owner to obtain the right to condemn private property under eminent domain authority.31 The Court observed that when contracts with unaffiliated entities demonstrate the transportation of gas, not owned by the pipeline, is benefitting an unaffiliated entity, such contracts “can be relevant to showing reasonable probability of future public use.”

The Court then noted Texas Rice wanted the Court to hold that the Airgas Carbonic contract, made after contemplation of the Green Line and the Texas Rice I holding, was irrelevant and, if anything, merely raised an issue of fact regarding Denbury Green’s intent to offer use of the pipeline to the public. The Court held this reading misunderstood the test from Texas Rice I.

The Court found that, in the absence of additional relevant evidence, post-construction contracts typically established only pre-construction possibilities regarding future public use. However, the Court determined these contracts could be relevant to demonstrating “a reasonable probability that, ‘at some point after construction,’” the public would be served by a pipeline. According to the Court, post-construction contracts, in combination with additional evidence, have the potential to lead to a determination by a reasonable observer that, due to a pipeline’s proximity to possible customers and given the regulatory environment, when a challenge was made to common-carrier status ‘it was “more likely than not’” that someday the public would be served by a pipeline. The Court ultimately found Denbury Green had established a reasonable probability existed “that, at some point after construction, the Green Line would serve the public.” The Court further found the evidence of Denbury Green’s 2013 CO2 transportation contract, in combination with the Green Line’s proximity to possible customers like Air Products and Airgas Carbonic, meant a reasonable fact-finder could no longer find genuine fact issues “as to whether the Green Line would, at some point after construction, do what it now most certainly does: transport CO2 owned by a customer who retains ownership of the gas.” According to the Court, the contract with Airgas Carbonic showed present public use of the Green Line. Of great significance to the Court was the support, provided by the transportation agreement with Air Products, for Denbury Green’s assertion that the design of the pipeline’s route was intended to enable third parties to transfer their own gas. The Court determined the evidence before it established conclusively “that it was ‘more likely than not’ that, ‘at some point after construction,’ the Green Line would serve the public.”

The Court next addressed the court of appeals erroneous requirement “that the reasonably probable future use of the pipeline serve a ‘substantial public interest.’”32 According to the

28 See id. at 197, 204.29 Id. at 199.30 Id. 31 Id. at 202.32 457 S.W.3d at 121.

5

Court, the court of appeals disregarded a claim by Denbury Green that owners of small interests in the Jackson Dome and West Hastings fields were benefitted by the transfer of CO 2 from those units via the Green Line despite Denbury Onshore’s ownership of controlling interests in those units, which led the court of appeals to conclude a fact issue as to the substantiality of this non-Denbury Green use had been raised.33 The Court also noted the court of appeals found the agreement with Air Products was not substantial enough to withstand summary judgment.34 The Court found, by levying this added requirement, the court of appeals had wrongly relied on the Court’s Coastal States Gas Producing Co. v. Pate decision.35 In Pate, which involved “eminent domain authority to drill a directional well,” the Court observed it had held the benefit to the state, the dedication to the Permanent School Fund of a fraction of gross production revenue, “was a ‘direct, tangible and substantial interest’ in the taking.”36 According to the Court, it had not held an interest had to “be direct, tangible, or substantial,” but instead that the Pate facts provided support “that the public’s interest would be served.”37 The Court observed that “[t]o the extent that the degree of service to the public was woven into our test in Texas Rice I, we held that for the pipeline to serve the public it must ‘transport[] gas for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier.’”38 The Court held evidence that establishes “a reasonable probability that the pipeline will, at some point after construction, serve even one customer unaffiliated with the pipeline owner is substantial enough to satisfy public use under the Texas Rice I test.”

In conclusion, the Court then held the evidence Denbury Green produced on remand established a reasonable probability as a matter of law “that, at some point after construction, the Green Line would serve the public by transporting CO2 for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier.” The Court reversed the judgment of the court of appeals and reinstated the judgment of the trial court.

BP America Production Company v. Laddex, Ltd., No. 15-0248 (Tex. Mar. 3, 2017)

On March 3, 2017, the Supreme Court of Texas affirmed the holding of the Amarillo Court of Appeals (Seventh District) and held that (1) a top lease entered into by Laddex, Ltd. (the “Laddex lease”) did not violate the rule against perpetuities (the “Rule”) and, therefore, Laddex had standing to file its lawsuit, and (2) the court of appeals had correctly remanded the case for a new trial because the trial court erroneously charged the jury on the question of cessation of production in paying quantities.

In 1971, BP acquired an oil and gas lease (the “BP lease”) by assignment. The lease, covering property in Roberts County, Texas, had a 5-year primary term and was to continue “as long thereafter as oil or gas is produced from said land hereunder.” The BP lease had a single producing well (the “Mahler D-2”) during the relevant period and, in August 2005, it began experiencing significantly slowed production. In November 2006, the Mahler D-2 returned to producing quantities similar to those prior to the slowdown. In April 2006, during the slowed

33 Id.34 Id.35 Id. (citing 309 S.W.2d 828, 833 (Tex. 1958)).36 Id. at 833.37 Id.38 363 S.W.3d at 202 (emphasis added) (footnote omitted).

6

production period, the lessors’ attorney, believing the well had completely stopped producing, sent BP a letter stating the BP lease appeared to have terminated due to “failure to produce in paying quantities and cessation of production.” The letter included a request for BP to contact the lessors’ attorney to speak about the issue, but there was no response from BP.

In March 2007, around five months after the well returned to pre-slowdown levels of production, the lessors of the BP lease made a top lease with Laddex. The Laddex lease covered the same property as the BP lease, and provided in part:

“It is agreed that this is a top lease and, subject to the other provisions herein contained, the primary term of this lease shall commence [(a)] upon the date that written releases are filed in the official public records of the county in which the land is located by all owners of record of the prior terminated lease, releasing the last recorded prior now-terminated lease (the “base lease”); or (b) upon the date upon which a judgment of a court of competent jurisdiction terminating the base lease and all interests under the base lease becomes final and nonappealable. This lease is intended to and does include and vest in Lessee any and all remainder and reversionary interest and after-acquired title of Lessor in the Leased Premises upon expiration of any prior oil, gas or mineral lease…”

Laddex filed a suit against BP one month after execution of the Laddex lease, claiming the failure to produce in paying quantities terminated the BP lease. BP sought dismissal of the suit based on lack of subject-matter jurisdiction, contending Laddex did not have standing to submit its claims. According to BP, the source of Laddex’s standing, the Laddex lease, was void because it was in violation of the Rule. Following the denial of BP’s motion, the case was tried to a jury. The charge to the jury posed the following questions:

“whether the Mahler D-2 failed to produce in paying quantities ‘[f]rom August 1, 2005 to October 31, 2006’ and whether, under all the relevant circumstances, a reasonably prudent operator would not continue, for the purpose of making a profit and not merely for speculation, to operate the Mahler D-2 Well in the manner in which it was operated between August 1, 2005 to [sic] October 31, 2006.”

The jury gave yes answers to both questions, and further found the April 2006 letter from the lessor’s attorney “did not repudiate BP’s title to the [BP] lease.” In delivering judgment on the verdict, the trial court decreed the BP lease had “lapsed and terminated for failing to produce in paying quantities” and granted possession of the relevant leasehold estate to Laddex.

BP then appealed. As to the issue of standing, the court of appeals held that because the Laddex lease “conveyed to Laddex a vested interest in the lessors’ possibility of reverter,” it was not subject to the Rule.39 Concerning the jury charge, the court of appeals held “the trial court erred in limiting the jury’s paying-production inquiry to the specific fifteen-month period in which production slowed,”40 and concluded the charge had “limited the jury’s consideration to a period of time that was not reasonable.”41 The court of appeals also rejected the challenge by BP to the legal sufficiency of evidence supporting the verdict, and held the record showed “sufficient evidence to have allowed a reasonable jury to differ as to whether the lease produced

39 458 S.W.3d 686-87 (Tex. App.—Amarillo 2015).40 Id. at 688.41 Id.

7

in paying quantities when a reasonable period of time is considered.”42 Both parties filed petitions to review.

The Court began by addressing the perpetuities issue. Here, BP challenged “Laddex’s standing to seek termination of the BP lease” and argued the top lease which this standing depended upon was void as a perpetuity. The Court noted the Texas Constitutional prohibition on perpetuities43 is manifested in the Rule which states, “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.”44 The Court observed application of the Rule required them to “look at the conveyance instrument as of the date it is executed, and it is void if by any possible contingency the grant or devise could violate the Rule.”45 The Court acknowledged “that where an instrument is equally open to two constructions, the one will be accepted which renders it valid rather than void, it being assumed that a grantor would intend to create a legal instrument rather than one which is illegal.”46 The Court noted the Rule has no application to present or future interests vesting at their creation.47 Therefore, observed the Court, to determine whether the Rule applied, it had to analyze the nature of the interest the Laddex lease conveyed. The Court noted, “In Texas, a typical oil and gas lease actually conveys the mineral estate (less those portions expressly reserved, such as royalty) as a determinable fee.”48 It further noted, “[a] possibility of reverter is the interest left in a grantor after the grant of a fee simple determinable.”49 Finally, the Court observed a possibility of reverter is presently vested at execution of the lease, although it is not presently possessory.50

The Court turned to the BP lease, and observed it conveyed the mineral estate of the lessors, as a determinable fee, to BP’s predecessor “subject to a vested possibility of reverter in the lessors.” Noting they had acknowledged a lessor’s ability to sell or assign, in whole or in part, a possibility of reverter, the Court turned to Laddex’s contention that, through the Laddex top lease, the Lessor’s vested reversionary interest in the mineral estate had been conveyed to Laddex.51 In responding to Laddex, BP argued that, to the degree Laddex’s lease conveyed the possibility of reverter of the lessors, the vesting of this interest was delayed by the language of the lease until an uncertain future event occurred, this event being the expiration of the lease held by BP. According to the Court, this argument amounted to a claim the Rule was violated by the top lease and therefore was void. The Court observed that, generally, the conveyance of a top-lease that is contingent on a determinable-fee bottom lease expiring, without more, would violate

42 Id. at 689.43 TEX. CONST. art. I, § 26.44 Peveto v. Starkey, 645 S.W.2d 770, 772 (Tex. 1982).45 Id.46 Kelly v. Womack, 268 S.W.2d 903, 906 (Tex. 1954).47 See Id. at 905-06 (“The requirement of the rule in this respect is complied with when a future estate or

interest becomes vested in interest regardless of when it becomes vested in possession.”)48 Luckel v. White, 819 S.W.2d 459, 464 (Tex. 1991).49 Jupiter Oil Co. v. Snow, 819 S.W.2d 466, 468 (Tex. 1991); Luckel, 819 S.W.2d at 464 (explaining that the

possibility of reverter is “the grantor’s right to fee ownership in the real property reverting to him if the condition terminating the determinable fee occurs”).

50 See Snow, 819 S.W.2d at 468.51 See Michael L. Brown, Effect of Top Leases: Obstruction of Title and Related Considerations, 30 BAYLOR

L. Rev. 213, 239 (1978) (noting that a top lease “may be classified as a partial alienation of a possibility of reverter,” in that “a lessee under a top lease acquires the lessor’s possibility of reverter to the extent that what he has acquired is capable of ripening into a fee simple determinable interest upon expiration of the bottom lease” (emphasis omitted)).

8

the Rule. Noting this did not necessarily mean the Laddex lease violated the Rule, the Court turned its attention to the Laddex lease provisions. The Court noted the Laddex lease’s primary term began the date that either the BP lease (1) was released, or (2) was terminated by a final and nonappealable judgment. Therefore, observed the Court, until the BP lease was adjudged terminated or released, Laddex had no right to possess the mineral estate. The Court then turned to the Laddex lease provision forming the root of the dispute between the parties:

“This lease is intended to and does include and vest in Lessee any and all remainder and reversionary interest and after-acquired title of Lessor in the Leased Premises upon expiration of any prior oil, gas or mineral lease….”

While Laddex claimed the lease presently conveyed the possibility of reverter of the lessors, BP argued the language expressly delayed the reversionary interest from vesting until the BP lease expired, to the extent vesting of the interest could occur outside the period of the Rule. The Court concluded, “a plausible interpretation of this language is that the Laddex lease is a present ‘partial alienation’ of the lessors’ possibility of reverter under the BP lease,” insofar as Laddex’s acquisition “is capable of ripening into a fee simple determinable interest upon expiration of the [BP] lease.”52 The other plausible interpretation, which BP subscribed to, was “that the vesting of Laddex’s interest is contingent on the BP lease’s expiration.” The Court then again noted, “where an instrument is equally open to two constructions, the one will be accepted which renders it valid rather than void, it being assumed that a grantor would intend to create a legal instrument rather than one which is illegal.”53 If viewed in accordance with BP’s interpretation, the provision in dispute would serve only to guarantee violation of the Rule by the lease, so the Court instead held the Laddex lease was “a present conveyance of a vested interest” that did not contravene the Rule.

The Court then turned to the remaining disputes of the parties, which involved the finding by the jury “that the Mahler D-2 well failed to produce in paying quantities,” as well as the court of appeal’s remand of the case for a new trial. The Court began with a reiteration of the framework under which it evaluated claims for termination of production in paying quantities. The Court observed that the BP lease, having entered its secondary term, would continue so long as oil or gas was “produced,” which meant “produced in paying quantities.”54 The Court further observed that whether a well is generating production in paying quantities is a fact question for the jury, and the lessor has the burden of proving an absence of such production for the purpose of terminating a lease.55 The Court then turned to Clifton v. Koontz, where it had set forth an analysis for answering this question,

“holding that whether a well is producing paying quantities depends on (1) whether the well ‘pays a profit, even small, over operating expenses,’56 and (2) if not, whether, ‘under all the relevant circumstances a reasonably prudent operator would, for the purpose of making a profit and not merely for speculation,’ continue to operate the well as it had been operated.”57

The Court also noted Clifton had emphasized “there can be no limit as to time, whether it be 52 Brown, 30 BAYLOR L. REV. at 239.53 Kelly, 268 S.W.2d at 906.54 Garcia v. King, 164 S.W.2d 509, 511 (Tex. 1942).55 See Skelly Oil Co. v. Archer, 356 S.W.2d 774, 782-83 (Tex. 1961).56 Id. at 691 (citation omitted)57 Id.; see also Skelly Oil, 356 S.W.2d at 783.

9

days, weeks, or months, to be taken into consideration in determining the question of whether paying production from the lease has ceased.”58

The Court then reviewed the questions and instructions in the jury charge. Question 1 asked in part, “From August 1, 2005 to October 31, 2006, did the Mahler D-2 Well fail to produce in paying quantities?” Noting the jury answered this question “Yes,” the Court reviewed Question 2, which was based on a “yes” answer to Question 1, and asked in part if, “under all the relevant circumstances, a reasonably prudent operator would not continue, for the purpose of making a profit and not merely for speculation, to operate the Mahler D-2 Well in the manner in which it was operated between August 1, 2005 to [sic] October 31, 2006?” The jury answered this question “Yes” as well.

The Court noted the court of appeals held Question 1 to be erroneous because it restricted the jury’s deliberation to the fifteen months during which production had slowed, thus preventing the jury from taking into consideration the restoration of the Mahler D-2’s profitability following that time period.59 The Court observed the court of appeals had remanded the case for a new trial when it concluded evidence on the record “would ‘have allowed a reasonable jury to differ as to whether the lease produced in paying quantities when a reasonable period of time is considered,’” but noted the court of appeals specifically declined to make a determination as to “what would be an appropriate period of time in this case.”60

Turning to the parties’ arguments, the Court first took note of BP’s contention that the evidence conclusively established the profitability of the lease over a reasonable time and, therefore, a finding in its favor instead of remand was justified. BP took the position that a reasonable period here would, at the least, be the 27 months before Laddex filed its April 2007 suit. Laddex responded by arguing the jury’s finding—that throughout the fifteen-month slowdown the well was operated at a loss—was supported by the evidence, and further contended “that the trial court ‘acted properly in stating the period over which Laddex alleged there was a lack of paying production and instructing the jury that the measuring period must be reasonable.’” According to the Court, Laddex essentially argued the proper period for analysis was “that in which there is evidence of nonpaying production,” and it was for the jury to determine whether, under the circumstances, this period was reasonable.

According to the Court, both parties’ positions conflicted with Clifton. In Clifton, the primary term of a lease terminated in 1950 and, on September 12, 1956, the operator began reworking operations.61 The trial court in Clifton determined the well on the lease “had at all material times produced gas in paying quantities,” and the issue considered was whether there existed any record evidence that would sustain this finding.62 The lease had a clause barring termination due to cessation of production as long as reworking operations began “within sixty days of such cessation,” leading the Clifton Court to consider “whether there was evidence of paying production through July 12, 1956.”63 The Court “considered record evidence of monthly and aggregate profits and losses throughout 1954, 1955, and the first six months of 1956[,]” and

58 325 S.W.2d at 690.59 458 S.W.3d at 689.60 Id. at 688 n.3 & 689.61 Clifton, 325 S.W.2d at 688.62 Id.63 Id. at 689.

10

held there was such evidence.64 In rejecting one of the lessors’ contentions regarding the relevance of the clause, the Court observed:

“There can be no arbitrary period for determining the question of whether or not a lease has terminated for the additional reason that there are various causes for slowing up of production, or a temporary cessation of production, which the courts have held to be justifiable. We again emphasize that there can be no limit as to time, whether it be days, weeks, or months, to be taken into consideration in determining the question of whether paying production from the lease has ceased.”65

After reviewing BP’s arguments about how paying production should have been evaluated by the jury, the Court found it agreed with BP that an evaluation of the question regarding any specific period violated Clifton. According to the Court, narrowing the paying production question to any specific period was “necessarily ‘arbitrary.’”66 The Court further noted the jury’s verdict, which benefited from considerable deference on appeal, could be influenced significantly by the chosen period. The Court took note of Laddex’s insistence that the jury’s verdict be upheld because the jury determined the fifteen-month time frame was a reasonable period over which to evaluate paying production. After noting this argument was based on the accompanying instruction to Question 1, the Court found it disagreed with Laddex, observing “the submission served to ‘focus the jury’ on the period of slowed production and then ‘imply that that is a reasonable time period.’” According to the Court, even if the jury had been given a more direct instruction that the selected period of time was required to be reasonable, “the question would still improperly direct the jury toward a specific period instead of allowing it to evaluate cessation of paying production with ‘no limit as to time….to be taken into consideration.’”67 The Court observed that while it was permissible for the parties to use evidence and argument to focus the jury, “the charge may not ask or instruct the jury about a specific period without unduly influencing the jury and violating Clifton.” The Court concluded the charge failed to allow the jury it fulfill its duties and, since “a reasonable jury could have differed as to whether the well ceased to produce in paying quantities under the Clifton standard,” it was appropriate to remand the case for a new trial.

64 Id.65 Id. at 690. (emphasis added) (internal citations omitted).66 Id.; see 1 ERNEST E. SMITH & JACQUELINE LANG WEAVER, TEXAS LAW OF OIL & GAS § 4.4[A][2][b], at

4-40 (Nov. 2009) (“Unless the lease defines the period for which production in paying quantities is measured, a well’s profitability is not determined by looking at any specific accounting period.”).

67 Clifton, 325 S.W.2d at 690.

11

Davis v. Mueller, No 16-0155 (Tex. Mar. 23, 2017)

On March 23, 2017, the Texas Supreme Court reversed the Texarkana Court of Appeals and held that blanket grants in multiple deeds were valid and unambiguous, conveying title to mineral interests. In 1991, two separate parties from outside Texas, Virginia Cope and James Mills, conveyed several tracts of vaguely-described land in Harrison County, Texas to James Davis (“Davis”). Both conveyances were on a printed form with small text. The list of tracts was followed by this sentence:

“Grantor agrees to execute any supplemental instrument requested by Grantee for a more complete or accurate description of said land.”

Later in the grants was found a two-sentence Mother Hubbard clause and a general granting clause:

The “Lands” subject to this deed also include all strips, gores, roadways, water bottoms and other lands adjacent to or contiguous with the lands specifically described above and owned or claimed by Grantors. If the description above proves incorrect in any respect or does not include these adjacent or contiguous lands, Grantor shall, without additional consideration, execute, acknowledge, and deliver to Grant[ee], its successors and assigns, such instruments as are useful or necessary to correct the description and evidence such correction in the appropriate public records. Grantor hereby conveys to Grantee all of the mineral, royalty, and overriding royalty interest owned by Grantor in Harrison County, whether or not same is herein above correctly described.

In 2011, however, the same individuals deeded the same interests to Mark Mueller (“Mueller”). In a subsequent quiet title action, Mueller asserted that the property descriptions in the original conveyances to Davis were vague and did not satisfy the requirement of the Statute of Frauds that the property conveyed be identified with reasonable certainty. Mueller also sued for conversion of the royalties from the mineral interests. The trial court held for Davis.

On appeal, Mueller argued that the general granting clause in the first deed was ambiguous as it purported to convey all the grantor’s interests in Harrison County while also following, in the same paragraph, the Mother Hubbard clause, a catch-all device useful only for conveying small, contiguous, and undescribed interests. The court of appeals reversed,68 agreeing with Mueller that the conveyances were vague and that the placement of the general granting clause after the Mother Hubbard clause in the same paragraph negated the former’s effectiveness.

The Supreme Court reversed, acknowledging that although the 1991 conveyances did not satisfy the Statute of Frauds,69 Texas law regards general granting clauses as valid and effective. Mueller argued that the general granting clause was only for small tracts such as those conveyed via the preceding Mother Hubbard clause. However, as the Court pointed out, if this had been the case there would not have been a need for the Mother Hubbard clause, which covers small pieces

68 485 S.W.3d 622, 631 (Tex. App.-Texarkana 2016).69 The Court noted that the test to satisfy the Statute of Frauds was provided by Morrow v. Shotwell wherein

the Court had opined “the writing must furnish within itself, or by reference to some other existing writing, the means or data by which the land to be conveyed may be identified with reasonable certainty.” 477 S.W.2d 538, 539 (Tex. 1972).

12

of land contiguous to the described tract. The court held that the granting clause, standing separately in its own sentence, indeed conveyed all the interests owned by Cope and Mills in Harrison County, not just the kind of small, contiguous tracts that the Mother Hubbard Clause would have passed.

The Court differentiated the present case with J. Hiram Moore, Ltd. v. Greer,70 a well-known Texas case wherein four sisters partitioned an 80-acre tract in the “Railroad Survey” in Wharton County into four 20-acre tracts. Each received the entire surface estate and minerals in one tract and a non-participating royalty interest (“NPRI”) in each of the other three tracts. Two of the tracts—neither owned by sister (and litigant) Greer—were pooled with an adjacent tract in the “Barnard Survey” to form the “SixS Frels” unit. Greer then deeded the mineral royalties produced from “[a]ll of that tract of land out of the [Barnard Survey]” known as the SixS Frels unit. Thus, the specific description conveyed nothing as Greer owned no royalty interest in any tract in the Barnard Survey. Greer’s deed continued, however, by adding “it is the intent of this instrument to convey . . . all of [Greer’s] royalty and overriding royalty interest in [Wharton County].” The Railroad Survey being in Wharton County, this general grant would have included the interests she did own in that survey. Because the deed “in effect states that Greer conveys nothing, and that she conveys everything,” the J. Hiram Moore court had concluded that it was ambiguous and could not be construed as a matter of law. The Court here noted that in J. Hiram Moore, the general granting clause in the deed at issue created an ambiguity, whereas in the present case, the general granting clause did not and so the cases could be differentiated.

Finally, Mueller argued that the 1991 grant shouldn’t be enforced because Davis was a bad actor. The Court held that Mueller’s evidence of Davis’ character has no effect on the interpretation of the 1991 grants. Ultimately, since Mueller’s other claims, including a Fraudulent Claim Against Real Property action, failed, the Supreme Court concluded that the 1991 deeds that conveyed title of Cope’s and Mills’ mineral interests to Davis were valid and unambiguous. Since those recorded grants pre-dated Mueller’s grants, Davis’ deed superseded Mueller’s and the Court therefore reversed judgment and rendered that Mueller take nothing.

Forest Oil Corporation v. El Rucio Land and Cattle Company, Inc., No. 14-0979 (Tex. Apr. 28, 2017)

On Apr. 28, 2017, the Texas Supreme Court considered the question of whether the RRC has exclusive or primary jurisdiction over actions for environmental contamination, which would possibly abrogate suits for monetary damages or another relief in civil court. In affirming the Houston [1st] Court of Appeals, the Court decided that the RRC did not have exclusive or primary jurisdiction over such claims. In addition, the Court considered whether the award given to the respondent in arbitration before litigation occurred should have been nullified due to alleged impartiality of the part of one the arbitrators or if the arbitrators had surpassed their powers, or both.

James A. McAllen (“McAllen”), respondent, owned a ranch in South Texas. Forest Oil Corporation (“Forest”) had leased 1,500 acres of the 27,000-acre ranch and produced oil from the ranch for more than 30 years, processing the production at facilities also located on the ranch. After litigation in the 1990s involving claims for the underpayment of royalties and alleged 70 172 S.W.3d 609, 614 (Tex. 2005).

13

violations of the implied covenant to develop the lease and express lease terms, the parties executed a “Surface Agreement” and a “Settlement Agreement.” Among other things, the Surface Agreement provided that Forest: (i) would not bring any hazardous material onto the leases; (ii) would perform necessary remediation work on the leases for harm caused by operations; (iii) would comply with all germane laws and regulations; and (iv) would not dispose of any hazardous materials on the surface of the leases.

An apparently disgruntled former employee of Forest informed McAllen in 2004 that Forest had both contaminated the leased premises and had donated used oilfield tubing to McAllen for a project involving construction of a rhinoceros pen. After handling the used oilfield tubing, McAllen had to get a portion of one of his legs amputated due to sarcoma, a form of tissue cancer. McAllen then sued, claiming Forest had maliciously gave him tubing imbibed with radioactive material as well as alleging environmental contamination and improper disposal of hazardous items on the leased premises. After McAllen objected to Forest’s motion to compel arbitration, the trial court denied arbitration. The Supreme Court eventually reversed.71

While the arbitration imbroglio bubbled up towards the Supreme Court, McAllen invited the RRC to investigate the ranch for contamination caused by Forest. The RRC, in turn, invited Forest to propose and begin remediation plans under its voluntary Operator Cleanup Program.72

Meanwhile, arbitration began with the attempted selection of three (it was hoped) neutral arbitrators. Forest and McAllen each selected one arbitrator, but the two selected arbitrators could not agree upon the third. Forest invited District Judge Ramos in Houston to appoint the third arbitrator. Judge Ramos chose one of the candidates McAllen had proposed.73 After appointment, the panel split. The two McAllen-favored arbitrators awarded McAllen $15,000,000, $500,000 in exemplary damages, and $6,700,000 in attorney fees as well as a $500,000 award to McAllen personally for physical injury. Furthermore, the majority of the troika decided that:

a. [Forest] has a continuing obligation and duty under the Surface Agreement to locate, remediate, and dispose of all hazardous and non-hazardous materials from the [Ranch] related to [Forest’s] operations;

b. [Forest] is required to perform remedial work where the need therefore arises, which shall include the removal of any and all hazardous and non-hazardous materials when those materials are no longer necessary in the conduct of [Forest’s] operations on the lease;

c. [Forest] is solely responsible for reimbursing [McAllen] for any future costs and expenses incurred by [McAllen] in conducting investigations which result in the identification of additional locations requiring remediation of hazardous and non-hazardous materials on the [Ranch] resulting from [Forest’s] operations; and

d. [Forest] is solely responsible for all future remediation costs and activities related to pollutants, contaminants, and hazardous and non-hazardous materials that are known to be present and/or discovered under those lands covered by the

71 Forest Oil Corp. v. McAllen, 268 S.W.3d 51, 62 (Tex. 2008).72 The Court noted that, as of Apr. 28, 2017, the RRC had approved portions of Forest’s remediation

proposals but had not yet approved its final remediation plans. 73 Interestingly, the Court points out that McAllen, two of his lawyers, and their paralegal (none of them

Houston residents) had donated money to Judge Ramos’ election campaign, their first such donations.

14

Surface Agreement.

To help insure that Forest would perform these commands, the split panel demanded that Forest post a $10 million-dollar bond. The arbitrator appointed by Forest wrote a 40-page dissent.

Not surprisingly, Forest sought to have the arbitrators’ decision set aside in district court. Forest first argued that the RRC had exclusive or primary jurisdiction over the dispute. A finding that exclusive jurisdiction lay with the RRC would eliminate the arbitrator award because the troika would have lacked subject-matter jurisdiction to make its ruling and the trial court would have lacked jurisdiction to order its enforcement. Forest also presented evidence that it had not been informed of a possible conflict of interest regarding one of the arbitrators that required vacating the award. Finally, Forest argued more generally that the damages were “in manifest disregard of Texas law, and that the parties had agreed to expanded judicial review of the arbitration award.” The trial court held for McAllen with the exception of the bond requirement, and the Houston [1st] Court of Appeals affirmed.74

The Court first turned to the matter of whether the RRC has primary or exclusive jurisdiction over issues of environmental contamination. If the agency has exclusive jurisdiction, a party must exhaust all agency remedies in order to advance to district court. After noting that “an agency has exclusive jurisdiction when the Legislature gives the agency alone the authority to make the initial determination in the dispute,”75 the Court stated that to abrogate the common-law right to seek a judicial remedy and to replace it with (an initial) agency primacy, the legislature must make its intent clear to do so. The Court also noted that tribunals are not to interpret a law creating an agency-driven remedy to deprive a party of common-law remedies unless the statute clearly reflects the legislature’s intent to preempt the common-law remedy with the statutory or regulatory one.

In seeking to prove such intent, Forest cited the Texas Water Code,76 which provides that the RRC is “solely responsible for the control and disposition of waste and the abatement and prevention of pollution of surface and subsurface water” by activities arising from exploration and production activities. The Court countered, however, that the legislative record showed that the “solely responsible” language was added to settle an inter-agency dispute between the RRC and the predecessor to the Texas Commission on Environmental Quality (the “TCEQ”).

Forest also cited the Texas Health and Safety Code,77 which provides the RRC with the “sole authority to regulate…the disposal of oil and gas [radioactive] waste.” Again, the Court noted in response that this citation was part of a subchapter requiring the RRC, the TCEQ, and other agencies to define their roles among themselves under the Texas Radiation Control Act,78 not to abrogate the right of common-law actions.

Continuing in its attempts to find clear legislative intent to show exclusive jurisdiction, Forest argued that § 85.321 of the Texas Natural Resource Code, which provides that a property owner’s remedy for harm arising from a violation of Chapter 85 or “another law of this state prohibiting waste or a valid rule or order of the [RRC] may sue for and recover damages and

74 446 S.W.3d 58, 87 (Tex. App.—Houston [1st Dist.] 2014).75 Forest Oil Corporation at *5, citing Cash Am. Int’l Inc. v. Bennett, 35 S.W.3d 12, 15 (Tex. 2000).76 TEX. WATER CODE § 26.131(a)(1).77 TEX. HEALTH & SAFETY CODE § 401.415(a).78 Id. § 401.0005.

15

have any other relief to which he may be entitled at law or in equity,”79 necessarily precluded any common-law action stemming from the same violations. The Court, however, saw no language that clearly abrogated a common-law action in the regulatory language cited by Forest.

Unrelated to actual statute language, Forest more broadly argued that the ability to seek statutory remedies through an agency and common-law remedies through a court could lead to the unfair result of a defendant paying twice for the same injury. Such a result may arise, it noted for example, if monetary damages from a suit are not be used to remedy actual environmental harm and the appropriate agency, perhaps the RRC in the event of harm arising from oil and gas exploration, might still have a responsibility to order site remediation. In response, the Court noted that the operator could seek an RRC cleanup order and fulfill its requirements, thus providing evidence in the concurrent lawsuit of lessened or remedied environmental harm and reduced or no monetary damages.

Ultimately, the Court held that Forest was unable to cite any statutes that indicated the legislature’s clear intent to replace a landowner’s right to obtain common-law relief in court for environmental contamination or other liabilities that may emit from the common law, such as contract disputes or for damage to property.

The Court then turned to the question of whether the RRC had primary jurisdiction over claims for environmental damage arising from oil and gas operations. The Court first noted that primary jurisdiction, a judicially-created doctrine that allocates power between courts and agencies when both have authority to settle a dispute, typically results in an agency being given the first opportunity to decide an issue, with a court deferring to the agency for an initial determination. This doctrine relies on the notions that agencies are typically staffed with trained specialists in the field at issue, unlike courts and juries, and that such agencies would provide more consistent interpretations of specialized regulations and statutes than courts or juries.

Applying the doctrine to the facts before it, the Court determined that several of McAllen’s claims were inherently judicial in nature, like trespass, fraud, negligence, and even assault. It noted that the RRC’s jurisdiction was not so broad as to oust a court’s jurisdiction. Turning to the requirements placed on Forest by the Surface Agreement, the Court answered Forest’s claim that only the RRC could determine what hazardous materials had to be removed by law when it opined that, while the RRC could inform the extent of legally required remediation, the RRC could not supplant Forest’s common-law duties. In addition, the Court noted that the Surface Agreement expressly disallowed placing hazardous materials on the leases and that violation of those terms did not entail primary RRC jurisdiction as such violations were purely contractual and beyond the standards of regulatory compliance.

Turning finally to Forest’s claim of alleged arbitrator partiality, the Court first established that arbitration awards must be set aside when “the rights or a party were prejudiced by…evident partiality by an arbitrator appointed as a neutral arbitrator.”80 Quoting itself further, “evident partiality” is arises by the nondisclosure of “facts which might, to an objective observer, create a reasonable impression of the arbitrator’s partiality,”81 but not does require the disclosure of “trivial” facts.82 Agreeing with the trial court, the Supreme Court held that Arbitrator Ramos

79 TEX. NAT. RES. CODE § 85.321.80 TEX. CIV. PRAC. & REM. CODE § 171.088(a)(2)(A).81 Tenaska Energy, Inc. v. Ponderosa Pine Energy, LLC, 437 S.W.3d 518, 524 (Tex. 2014).82 Burlington N. R.R. Co. TUCO Inc., 960 S.W.2d 629, 636-637 (Tex. 1997).

16

should not have been disqualified for failing to disclose what the trial court referred to as a “trivial, non-prejudicial, not consummated invitation to act as mediator” in another matter.

Regarding the scope of the arbitration troika’s awards, Forest argued that the panel had exceeded its authority both under the terms of the Settlement Agreement and by requiring damages that were not allowed under Texas law. Here, the Court turned to the terms of the Settlement and Surface agreements themselves, noting that the Settlement Agreement allowed arbitrators “to award punitive damages where allowed by Texas substantive law” and that all “disputes relating to his [sic] Agreement or disputes over the scope of this arbitration clause will be resolved by arbitration.” The Court held that, under these provisions, the panel had very broad authority, including determining what damages Texas law allows, as well as the amounts to be awarded as damages. The Court observed that the panel had defined the remediation requirements and costs—both within the boundaries of the agreements.

Forest finally argued that, since the parties had authorized the troika to “award punitive damages where allowed by Texas substantive law,” the parties had allowed for judicial review of any exemplary damages. The Court noted that, while the Texas Arbitration Act limits judicial review of awards made by arbitration, parties can—by “clear agreement”—allow for judicial review. In the present case, however, the Court contrasted the Settlement Agreement’s terms concerning discovery protocols—which “apply the Texas Rules of Civil Procedure” and allow for parties to apply for relief in district court—with exemplary damages, where no provision is made for judicial review. Finding no clear agreement by the parties in the Settlement and Surface agreements to allow judicial review of exemplary damages, the Court declined to exercise judicial review of the punitive damages.

Lightning Oil Co. v. Anadarko E&P Onshore LLC, No. 15-0910 (Tex. May 19, 2017)

On May 19, 2017, the Texas Supreme Court affirmed the San Antonio Court of Appeals and held that an oil and gas operator could drill through the mineral estate underlying an adjacent tract of land without the adjacent mineral lessee’s permission. After balancing the interests of the oil and gas industry against evidence showing only a small loss of minerals caused by off-site drilling, the Texas Supreme Court rejected the adjacent lessee’s claims for trespass and injunctive relief. Consequently, this holding permits an operator to locate its drill sites on the surface above an adjacent lease so long as the surface owner grants permission and the interference with the adjacent mineral estate is no more burdensome than was shown in this opinion.

Anadarko leased the minerals under the Chaparral Wildlife Management Area (“WMA”), a tract controlled by the Texas Parks and Wildlife Department. The state lease required Anadarko to locate its drill sites on other tracts whenever possible. Anadarko contracted with adjacent surface owner Briscoe Ranch, Inc. (the “Ranch”) for the right to place wells on the Ranch’s surface. Under that agreement, Anadarko could also drill through the mineral estate beneath the Ranch so that Anadarko’s horizontal wells could then reach the minerals underlying the adjacent Chaparral WMA. Lightning Oil Co. (“Lightning”), lessee of the minerals underlying the Ranch, was not a party to the Anadarko-Briscoe Ranch agreement and objected to Anadarko’s plans to drill through Lightning’s mineral estate.

Lightning sued Anadarko for underground trespass and tortious inference with its mineral

17

lease, seeking a temporary restraining order and an injunction against drilling on the Ranch’s surface. The trial court granted partial summary judgment in favor of Anadarko, and the San Antonio Court of Appeals affirmed. Noting that “the mineral estate owner does not control the subsurface mass,” the court of appeals reasoned that the surface owner could grant a third-party permission to locate a well on its tract to produce from the adjacent mineral estate.83 Lightning appealed this decision to the Supreme Court of Texas.

Although the Supreme Court generally agreed with the court of appeals’ reasoning, it found significant that Anadarko’s wellbore would displace a small quantity of Lightning’s recoverable minerals, namely the volume of minerals contained in the wellbore cuttings. To assess the implications of this fact—which was not addressed in the cases cited by the court of appeals—the Court reviewed the attributes of mineral ownership (the “bundle of rights”), focusing on a mineral lessee’s right to develop. The Court then divided Lightning’s trespass claim into two inquiries: (1) whether Anadarko’s drilling would impermissibly interfere with Lightning’s use of the surface and subsurface terrain under its lease; and (2) whether Anadarko’s drilling would impermissibly interfere with the minerals themselves.

To guide the first inquiry, the Court set out the following rule: “an unauthorized interference with the place where the minerals are located constitutes a trespass . . . only if the interference infringes on the mineral lessee’s ability to exercise its rights” (emphasis by Court). Within this context, Lightning argued that Anadarko’s drill sites would interfere with its right to develop by limiting Lightning’s access to the surface and subsurface of its leased tract. Noting that Lightning’s speculation that this would occur was not enough, the Court found that Lightning had not demonstrated an unauthorized interference for two reasons. First, Lightning had presented no evidence that the RRC’s drilling regulations were insufficient to protect its rights to use the surface. Second, because Anadarko’s rights under the contract were not any greater than those of the surface owner, the accommodation doctrine still afforded Lightning’s dominant mineral estate the same protections.

In conducting the second inquiry, the Court weighed the interests of society and the oil and gas industry against Lightning’s individual interest in its leased minerals. Even though it acknowledged that Anadarko’s drilling would inevitably destroy some small fraction of Lightning’s leased minerals, the Court recognized that the loss would be relatively small. In fact, the drilling process would only extract “fifteen cubic yards of dirt and rock for each thousand linear feet drilled with an eight-inch wellbore,” and Lightning only had a right to the even smaller quantity of minerals contained within that volume of drilled-out subsurface.

Additionally, the off-lease drilling strategy would likely avoid some of the waste associated with horizontal drilling and reduce the number of wells required to extract the minerals underlying the Chaparral WMA. Drilling from an adjacent tract, instead of the leased tract, would help eliminate the unproduced volumes of reservoir left behind below the kick off point and before the wellbore complete its turn to the horizontal plane. Starting drilling operations on an adjacent tract would instead allow the wellbore to enter the formation completely horizontally. Thus, given the “longstanding policy of this state to encourage maximum recovery of minerals and to minimize waste,” the industry and societal interests in recovering oil and gas outweighed Lightning’s individual right to extract all its leased minerals. In conclusion, the Court rejected Lightning’s underground trespass claim and related request for

83 See Lightning Oil Co. v. Anadarko E&P Onshore LCC, 480 S.W.3d 628 (Tex. App.—San Antonio 2015).

18

injunctive relief.

The Court then dispatched Lightning’s remaining arguments. First, Lightning had argued that finding in favor of Anadarko would legitimize other types of underground trespass that the Court had impliedly recognized, such as trespass resulting from the migration of wastewater injected into a well. In response, the Court clarified that it had not impliedly recognized such a cause of action, as it had never addressed the issue on the merits. The Court then rejected Lightning’s argument that its decision would impair the dominance of Lightning’s mineral estate. The Court refused to expand the accommodation doctrine to grant Lightning “the right to prevent any surface or subsurface use that might later interfere with its plans.” Addressing Lightning’s related contention that this decision would make the accommodation doctrine applicable to adjacent mineral owners, the Court reiterated that any rights Anadarko had under the contract were as a surface owner’s assignee, not an adjacent mineral lessee.

Turning finally to the tortious inference claim, the Court agreed with the lower court that Anadarko could raise a valid justification defense because it had received a contractual right to drill on the surface of the Briscoe Ranch. Thus, Anadarko was entitled to summary judgment on Lightning’s claims for underground trespass and tortious inference with contract. Accordingly, the Court affirmed the decision of the San Antonio court that summary judgment was appropriate.

Prior to this decision, Texas case law was uneven on the issue of who exactly comprises the necessary parties to drill-through agreements. For example, Humble Oil and Refining Company v. L & G Oil Company seemed to established that a leasehold owner only needed permission from the surface owner to drill from a tract in which it had no leasehold interest to penetrate laterally a tract in which it held a lease, although that case focused on the ability of state authorities to grant permits for such wells.84 Conversely, Chevron Oil Company v. Howell granted an injunction against Chevron from drilling a directional well from a surface tract on which it did not own the lease.85 The Chevron court quoted favorably a witness in the case that stated “anytime you drill into something there is bound to be some damage.”86

Samson Exploration v. T.S. Reed Properties, No. 15-0886 (Tex. June 23, 2017)

On June 23, 2017, the Supreme Court of Texas affirmed in part, and reversed in part the Beaumont Court of Appeals, holding that one group of royalty owners was entitled to royalties from a well located in two units while another group of royalty owners that was dropped from a unit were not so entitled. The lessors and other stakeholders (as below defined, the “Overlapping Stakeholders” and “Unpooling Stakeholders”) alleged that the lessee, Samson Exploration (“Samson”), underpaid royalties on their mineral leases and pooling agreements. All parties involved petitioned the Court for review of the court of appeal’s judgment.

The case involved multiple gas units. The first unit at issue was created in 2001 when Samson formed the “Black Stone Minerals A No. 1 Gas Unit” by filing a unit declaration with the RRC. This unit had vertical boundaries of 6,000 to 13,800 feet of depth. Two wells were 84 259 S.W.2d 933 (Tex. Civ. App. – Austin 1953, writ ref’d n.r.e.). A similar decision was reached in

Atlantic Refining Company v. Bright & Schiff (321 S.W.2d 167 (1959)) two years later.85 407 S.W.2d 525 (Tex. Civ. App. 1966, writ ref’d n.r.e.).86 Id. at 528.

19

completed within this unit. The first—producing from a depth interval of 12,304 feet to 12,332 feet—was located on property leased by Black Stone Minerals Co. Late in 2002, Samson successfully completed a second gas well within the Black Stone Minerals A No. 1 Gas Unit’s existing boundaries on the “Joyce DuJay” lease. The gas from this well was produced from 13,150 to 13,176 feet subsurface.

Black Stone later declined to give its consent when Samson tried to pool its lease into the Black Stone Minerals A No. 1 Gas Unit, although a co-tenant lessor approved, and Samson changed the Black Stone Minerals A No. 1 Unit’s pool boundaries via a unilateral declaration. This amendment changed the unit’s name from “Black Stone Minerals A No. 1 Gas Unit” to the “Joyce DuJay No. 1 Gas Unit” (the “Joyce DuJay Unit”) After this amendment and change of boundaries, Samson no longer attributed gas produced by the first well on the Black Stone lease to the renamed and amended Joyce DuJay Unit.

Samson later completed another gas well, the producing interval of which was shallower than the pool associated with the Joyce DuJay Unit. This third well was on the Joyce DuJay lease, and this lease was one of a number the Joyce DuJay Unit included. Less than a year later, Samson formed the “Joyce DuJay A No. 1 Gas Unit” (the “DuJay-A Unit”), which retroactively defined a pool between a depth interval of 12,197 to 12,342 feet and including most of the leases and a significant portion of the zones that Samson previously defined as being in the Joyce DuJay Unit. Both units shared a zone being produced by the Joyce DuJay lease well (the second well described above) as the Joyce DuJay lease had been pooled into these units—the well and lease were in two units. Samson, however, only paid royalties derived from production from the second well to stakeholders in the Joyce DuJay Unit and not to the stakeholders in the DuJay-A Unit.

All these maneuvers eventually gave rise to two groups of claimants against Samson. The first group—the Unpooling Stakeholders in the Joyce DuJay Unit—originally composed of six Joyce DuJay Unit stakeholders—sued Samson in 2004, contending that in refusing to allocate production from the first well (on the Black Stone Mineral Co. lease) that had been excised from the Joyce DuJay Unit to their accounts, Samson had breached its obligations under the leases. They also argued that Samson had improperly amended the unit. The second group—the Overlapping Stakeholders of the Joyce DuJay Unit, none of whom were being paid royalties for production from the second well—sued, seeking to be paid royalties.

Samson argued that establishing overlapping pools was never its intent but rather represented a mistake it made internally over ten years before the current litigation. Samson contended that the DuJay-A Unit was invalid because of its overlap with the older Joyce DuJay Unit. Even if the overlapping did not invalidate the pool, Samson argued, the fact that the Overlapping Stakeholders had accepted payments attributed only to the third well should deny enforcement of the DuJay-A Unit. Samson also argued that the pooling designation should be reformed to allow for a bottom depth boundary of 12,400 feet subsea because of a scrivener’s error.

The trial court awarded contract damages to all the claimants under a breach of contract theory. Specifically, the Unpooling Stakeholders were awarded $450,000 while the Overlapping

20

Stakeholders received $2,500,000 in damages. The trial court also awarded pre-judgment interest of more than $1,500,000 as well as post-judgment interest at statutory and contractually specified rates.

All the parties cross-appealed. The Beaumont Court of Appeals reversed and remanded in part the decision of the trail court, holding: (1) the Unpooling Stakeholders were not entitled to recovery on their claims due to their ratification of a unit amendment; (2) the Overlapping Stakeholders could recover on their claims for an operator’s breach of their leases; and (3) the trial court’s awards to the Overlapping Stakeholders were excessive.

The first cluster of issues the Supreme Court reviewed was Samson’s challenges to the judgment in favor of the Overlapping Stakeholders. Samson argued that its pooling agreement constituted an impracticable and invalid contract as actually written and raised the affirmative defenses of quasi-estoppel and reformation based on scrivener’s error that were triggered when it had created the overlapping pooling unit. Samson also contended that it was not obligated to pay royalties on the third well because its unit overlapped with the second well’s unit, and that the unit was therefore invalid. Samson sought reimbursement from stakeholders in the Joyce DuJay Unit to the extent it might be liable to the Overlapping Stakeholders.

On the judgment favoring the Overlapping Stakeholders, the Supreme Court first agreed that the breach of contract theory was proper and affirmed the court of appeals. Samson had claimed that, since pooling in general effectuated a cross-conveyance of real property, it was impossible for it “to cross-convey the same pooled lands, substances, and depths twice at the same time” and hence the pooling of the minerals owned by the Overlapping Stakeholders was invalid and payment of royalty to them was unnecessary despite what the requirements of contract law may be. The Court countered that “pooling implicates both contract and property law—authority to pool emanates from contract but pooling agreements give rise to interests in reality.” The Court saw no reason not to enforce Samson’s obligations under a theory of contract despite the possibility that the pooling designation failed to convey title.

Second, Samson also claimed that because the Overlapping Stakeholders accepted the lower royalty payments they waived any contractual entitlement to a higher rate under the equitable defense of quasi-estoppel. The Supreme Court held, however, that accepting the underpayment was not inconsistent with claiming entitlement to more. Regarding Samson’s argument that since a scrivener’s error existed due to a mutual mistake in the contract, and thus providing the grounds for reformation, the Court held that the evidence showed the Overlapping Stakeholders had taken no part in outlining the pooled unit’s boundaries, writing the description of the unit, or filing the designation. Crucially, the Court also noticed that Samson alone was responsible for all aspects of pooled-unit designation. Without any participation by the Overlapping Stakeholders, the Court opined, the defense of mutual mistake could not be invoked.

Samson also further claimed the right to seek reimbursement from the stakeholders in the DuJay 1/Amended Unit in order to pay the Overlapping Stakeholders. The Court noticed that Samson was on record notice that it had paid the now-disputed royalty fees despite knowing that the units overlapped. Moreover, Samson did not try to correct the alleged error in the pooling

21

designation. The Court therefore held that Samson must fulfill its contractual obligation and pay the due royalties out of its working interest and denied reimbursement from the DuJay 1/Amended Unit stakeholders.

After a lengthy determination that Samson had reserved the argument for appeal, the issue of whether the Unpooling Stakeholders had ratified the change in the Joyce DuJay Unit was considered. The Court affirmed that the Unpooling Stakeholders had been aware that Samson had changed the parameters of the unit designation, although the Court recognized the change was not entirely clear. Because the Unpooling Stakeholders had continued to accept payments according to the terms of the amended unit designation without complaint, the Court affirmed that the record established that the Unpooling Stakeholders had ratified the amendment. In making this determination, the Court relied on its holding in Hooks v. Samson Lone Star, Ltd. P’ship,87 wherein a claim by similarly-situated stakeholders arising from a similar unpooling situation had invoked a ratification defense like Samson’s in the present case. In Hooks, the Court had found ratification occurred based “solely on the facts that [the lessors] received notice of an amendment to the unit designation, accepted royalties from the amended unit, and [did] not challenge the amended unit.”88 Here, the Court had found the Unpooling Stakeholders had actual notice of a change in the unit designation that, when followed by acceptance of royalties without protest, amounted to ratification.

The final issue addressed by the Court was the Overlapping Stakeholders’ assertion that the damages awarded for breach of contract had been improperly reduced by Samson due to its reliance on a proportionate-reduction clause in the lease. The lower court had found—and the Supreme Court took notice—that the lease terms required a 50% reduction in the royalty payments to the Overlapping Stakeholders. Samson asserted that the lease covered an undivided 50% interest in the oil, gas, and other minerals across the total acreage described in the lease, which was necessarily less than the entire undivided fee simple estate of the total acreage of all that certain land. The Unpooling Stakeholders asserted that the lease covered a 100% interest in the oil, gas, and other minerals, equivalent to the entire undivided fee simple mineral estate of the acreage covered by the lease. After analysis of the lease’s language, the Court agreed with Samson’s understanding of the lease and affirmed the court of appeals ruling of the applicability of the proportionate reduction clause.

Wenske v. Ealy, No. 16-0353 (Tex. June 23, 2017)

On June 23, 2017, a sharply divided Supreme Court of Texas considered how to interpret reservation and exception language within a mineral conveyance, deciding whether the language of the instrument passed the entire burden of a prior outstanding non-participating royalty interest (“NPRI”) to the grantee of the minerals or whether the NPRI proportionately burdened the grantor’s reserved mineral interest as well. The majority affirmed the decision of the court of appeals, but for different reasons, that the NPRI burden should be proportionately spread. The four-justice dissent maintained that the language of the mineral deed clearly required only the grantee to bear the NPRI burden.

87 457 S.W. 3d 52 (Tex. 2015).88 Id. at 66.

22

In 1988, the Wenskes purchased land burdened by a 1/4th of royalty NPRI via a deed subject to a reservation (the “1988 Deed”). Specifically, each of the two grantors in the 1988 Deed reserved a 1/8th NPRI, resulting in a total reservation of 1/4th of the royalty estate.89 The Wenskes sold the property in 2003, reserving an undivided 3/8th fee mineral estate interest (the “2003 Deed”). The purchasers from the Wenskes, the Ealys, received an undivided 5/8th mineral estate interest. Specifically, the reservation in the 2003 Deed provided the following “Reservations from Conveyance”:

For [appellants and appellants’] heirs, successors, and assigns forever, a reservation of an undivided 3/8ths of all oil, gas, and other minerals in and under and that may be produced from the Property. If the mineral estate is subject to existing production or an existing lease, the production, the lease, and the benefits from it are allocated in proportion to ownership in the mineral estate.

Following that reservation, the 2003 Deed thereafter contained the following “Exceptions to Conveyance and Warranty”:

Undivided one-fourth (1/4) interest in all of the oil, gas, and other minerals in and under the herein described property, reserved by [Vyvjala], et al for a term of twenty-five (25) years in an instrument recorded in Volume 400, Page 590 of the Deed Records of Lavaca County, Texas, together with all rights, express or implied, in and to the property described herein arising out of or connected with said reserved interest and reservation reference to which instrument is here and now made for all purposes

.…

Grantor, for the Consideration and subject to the Reservations from Conveyance and the Exceptions to Conveyance and Warranty, grants, sells, and conveys to Grantee the Property, together with all and singular the rights and appurtenances thereto in any way belonging, to have and to hold it to Grantee and Grantee’s heirs, successors, and assigns forever. Grantor binds Grantor and Grantor’s heirs and successors to warrant and forever defend all and singular the Property to Grantee . . . except as to the Reservations from Conveyance and the Exceptions to Conveyance and Warranty.

In 2011, the Wenskes and Ealys leased their respective mineral estates. The Wenskes filed a declaratory judgment petition in 2013, arguing their 3/8th interest had been taken free and clear of the NPRI. According to the Wenskes, the NPRI should have been deducted exclusively from the 5/8th interest owned by the Ealys. The Ealys’ counter summary judgment motion was granted by the trial court, which concluded both parties’ mineral estates would share the 1/4 NPRI burden proportionately.

On appeal, the Wenskes argued the 2003 Deed conveyed the NPRI burden to the Ealys alone. Thus, the Wenskes’ reserved mineral interest was unburdened by the NPRI. The Wenskes pointed to the following provision in the 2003 Deed for support:

89 The 1988 Deed provided “…there is expressly excepted and reserved to the grantors herein, [Vyvjala] and [Novak], their heirs and assigns . . . an undivided one-fourth (1/4) interest in and to all of the oil royalty, gas royalty, and royalty in casinghead gas, gasoline and royalty in other minerals in and under and that may be produced from the above described tract or parcel of land for a period of twenty-five years. . ..”

23

“Grantor, for the Consideration and subject to the Reservations from Conveyance and the Exceptions to Conveyance and Warranty, grants, sells, and conveys to Grantee the Property, together with all and singular the rights and appurtenances thereto in any way belonging to have and to hold it to Grantee and Grantee’s heirs, successors, and assigns forever. (Emphasis added)”

The Ealys countered the NPRI burdened the entire mineral estate and that the resultant mineral estates were proportionally burdened. The Corpus Christi Court of Appeals (Thirteenth District), following a de novo review, overruled the Wenskes’ sole issue and affirmed the trial court’s decision that the Ealys were entitled to summary judgment. The court concluded that a reservation of a 1/4 of royalty NPRI burdened subsequent owners of both mineral estate interests. The Wenskes had argued the use of the phrase “subject to” in the 2003 Deed was an unqualified limitation on the conveyance, making the Ealys entirely responsible for the NPRI.90 The court of appeals distinguished Bass, however, noting it “sa[id] nothing about how to apportion a separate royalty estate that corresponds with the minerals.”91 The court of appeals found the 2003 Deed did not supply guidance as to this apportionment and, therefore, “the default rule should apply: ‘Ordinarily the royalty interest…would be carved proportionately from the two mineral ownerships….’”92

The court of appeals noted the exception in the 2003 Deed provided the NPRI owners “own an undivided one-fourth (1/4) interest in all of the oil, gas, and other minerals in and under the land for a term of twenty-five (25) years.” (emphasis added) It then also noticed the 1988 Deed stated the NPRI owners owned a 1/4th interest in the royalties produced from the land, while the 2003 Deed made no mention of royalties. The court stated it disagreed with the Wenskes “that they could be unburdened by the NPRI simply by stating in the 2003 Deed that they conveyed the property to the Ealys ‘subject to’ the exception without even mentioning anything about royalties or that the portions of the royalty estate owned by [the NPRI owners] would be paid entirely by the Ealys.”

The Wenskes appealed to the Texas Supreme Court. The five justices composing the majority affirmed the lower courts. In doing so, the Court provided perhaps its strongest message yet reaffirming what it called “the paramount importance of ascertaining and effectuating the parties’ intent.” The Court held that, in such interpretive cases, it must “determine that intent by conducting a careful and detailed examination of a deed in its entirety, rather than applying some default rule that appears nowhere in the deed’s text.”

Like the lower courts, the Supreme Court agreed with both parties that the instrument was unambiguous, allowing the Court to interpret its meaning as a matter of law. As they had before the Corpus Christi court, the Wenskes again relied on the Court’s treatment of a similar “subject-to” clause in Bass v. Harper,93 wherein the Court had considered the effect of a prior reservation of 6/14 of the 1/8th lessor’s royalty under an existing lease on a subsequent conveyance of a 1/2 interest in the minerals to a later grantee. As in the present case, a dispute on the payment of royalty later arose with the grantor in that case claiming that the grantee should bear all of the outstanding 6/14 royalty interest (1/2 of 1/8 less 6/14 of 1/8 or 1/14) while the grantee believed the 6/14 of 1/8 royalty burden should be proportionately apportioned between

90 Bass v. Harper, 441 S.W.2d 825 (Tex. 1969).91 See id.92 Pich v. Lankford, 302 S.W.2d 645, 650 (1957).93 Bass v. Harper, 441 S.W.2d 825 (Tex. 1969).

24

the grantor and grantee. In Bass, the Court agreed with the grantor, reasoning that the exception of the 6/14ths lessor’s royalty was “tied specifically to the grant”94 and so operated to limit the mineral grant in addition to protecting the grantor against warranty claims.

In response here, the Court noted that Bass was decided “under the specific wording of the instrument”95 and its effects should be limited to similarly-worded instruments. Specifically, the Court noted that the Bass instrument’s “subject-to” clause was in the granting clause and not the warranty clause. More broadly, the Court also noted that, since Bass, interpretive jurisprudence in Texas has moved towards focusing on the intent of the parties and harmonizing all parts of a disputed instrument when interpreting its parts.

After discounting Bass, the Court admonished the court of appeals for turning to a “default rule” to interpret the deed instead of seeking the parties’ intent. The Court claimed it could ascertain the drafters’ intent from “careful examination of the entire deed” before it focused almost exclusively on the “subject-to” clause and its location within the deed. The Court noted that “subject-to” clauses can have two uses: protecting the grantor from breaching a warranty and making the grantee’s interest bear the burden of an outstanding royalty. The first use is commonplace and relatively straightforward, but the Court, citing Professor Ernest Smith, observed that relying on a “subject-to” clause to perform some other function can be fraught with ambiguity requiring litigation to unravel.

Turning to the instrument itself, and “[g]iving the deed’s words their plain meaning, reading it in its entirety, and harmonizing all of its parts, [the Court could not] construe [the deed] to say the parties intended the Ealys’ interest to be the sole interest subject to the NPRI.” (emphasis by Court) The Court’s majority agreed with the dissent that the amount of royalty a mineral interest grantee receives is typically the same fraction as the amount of the fractional mineral interest received in the deed96 and that, under the same reasoning, a freestanding royalty that encumbered the entire mineral interest before a partial conveyance of that mineral interest would generally burden a proportion share of each of the split mineral interests after the partial conveyance. The Court observed, however, that parties could contract for whatever division of burden by a freestanding royalty they desire and that their intent, as expressed in a deed, controls. Here, the Court’s majority found no intent in the deed indicating that the drafters wanted to deviate from the general rule.

Further, the Court’s majority noted that in the disputed deed, the exceptions to the conveyance and the exceptions to the warranty were combined into one clause. The fact that the clauses were combined, when read with the reservations from conveyance clause, indicated to the majority an intent to avoid breaching the warranty only, and not an intent to reserve to the Wenskes a full, unencumbered 3/8 interest. In addition, the majority noted that the mineral-reservation paragraph ended with, “[i]f the mineral estate is subject to existing production or an existing lease, the production, the lease and the benefits from it are allocated in proportion to ownership in the minerals.”

The dissent, composed of four justices, believed that, by the deed’s plain language, the interest of the Ealys was the only one burdened by the NPRI. The minority noticed that the 2003 Deed described one “Reservation from Conveyance”—a reservation by the grantors of “an

94 Id. at 827. 95 Id. at 828.96 Woods v. Sims. 273 S.W.2d 617, 621 (Tex. 1954); Benge v. Scharbauer, 259 S.W.2d 166, 169 (Tex. 1953).

25

undivided 3/8th of all oil, gas, and other minerals in and under and that may be produced” from the captioned land—and multiple “Exceptions to Conveyance and Warranty,” including the NPRI. Further, in the minority’s eyes, the granting clause unambiguously identified what the “subject-to” clause modified. Noting that the deed identified the reservation as a “Reservation from Conveyance” and the exception as an “Exception to Conveyance and Warranty” (minority’s emphasis), the minority thought it clear that the conveyance to the Ealys was subject exclusively to the reservation and exceptions—including the NPRI. The minority believed that the “subject-to” clause did not just act to prevent a warranty breach and that the deed described precisely one interest that was subject to the NPRI—the mineral interest of the Ealys.

The minority then examined whether principles that govern the inherent nature of interests being conveyed and reserved in an instrument altered the deed’s express language and determined it did not. The minority included in its dissent a very lengthy description and analysis of precedent it claimed supported its position and that, it claimed, was ignored by the majority, including Duhig v. Peavy-Moore Lumber,97 Benge v. Scharbauer,98 Pich v. Lankford,99 Bristow v. Selman,100 and Bass v. Harper.101

High Mount Exploration & Prod. LLC v. Harrison Interests, Ltd., No. 14-15-00058-CV (Tex. App.—Houston [14th], Oct. 6, 2016)

On Oct. 6, 2016, the 14th Court of Appeals (Houston) decided a question about whether the producer was underpaying and improperly deducting marketing costs from the royalty owners. The court affirmed the trial court ruling, that the producer did miscalculate the royalties and improperly deduct marketing costs.

In 1990 Harrison Interests, Ltd. (“Harrison” or the “Harrison Parties102”) reserved 5% of 8/8th perpetual NPRIs in a conveyance (the “1990 Conveyance”) to Meridian Oil Production (“Meridian”). Harrison and Meridian also executed a royalty agreement (the “Agreement”) that provided terms governing the administration and payment of royalty. One of the appellant/defendants, Dominion Oklahoma Texas Exploration & Production (“Dominion”), successor-in-interest to Meridian, sold its interest to appellant/defendant High Mount Exploration & Production (“High Mount”) in 2007. That same year, Harrison requested an audit after Harrison concluded that the defendants, Dominion and High Mount (collectively the “High Mount Parties”), were not paying the full amount of the royalties owed to Harrison.

In 2009, the Harrison Parties filed suit against the High Mount Parties raising two issues. First, Harrison claimed that the High Mount Parties did not pay the correct royalties owed based on terms of the 1990 conveyance and the Agreement. They claimed that the High Mount Parties did not pay royalties on the gas produced from the captioned property; on the oil and gas leases; and on the oil, gas, and mineral leases that were subject to the terms of the Agreement; and on the gas used as fuel to power the equipment on the captioned land. Second, Harrison claimed that the High Mount Parties were improperly deducting marketing costs. 97 144 S.W.2d 878 (Tex. 1940).98 Benge v. Scharbauer, 259 S.W.2d 166, 169 (Tex. 1953).99 302 S.W.2d 645 (Tex. 1957)100 402 S.W.2d 520 (Tex.Civ.App.—Tyler 1966, writ ref’d n.r.e.)101 441 S.W.2d 825 (Tex. 1969).102 The Harrison Parties include: Harrison Interests, Dan J. Harrison III, and BFH Mining.

26

The High Mount Parties moved for partial summary judgment. They claimed that the Harrison Parties were not entitled to compensation for gas used as fuel on the captioned land and that they were entitled to deduct marketing costs. The Harrison Parties countered by filing two petitions for summary judgment based on the accounting and deduction issues. The trial court granted both summary judgment motions to the Harrison Parties, and denied the High Mount Parties. The trial court also rendered a final judgment and awarded actual damages, prejudgment interest, and attorney’s fees to the Harrison Parties. The High Mount Parties appealed the judgment.

Reviewing the summary judgment de novo, the court found that the evidence raised a genuine fact issue. The court concluded that the Harrison Parties were in fact entitled to receive the royalty share of the gross proceeds of the gas that was used for fuel on the captioned land. Specifically, the court noted that Section 4(e) of the Agreement provided, “Owners shall receive their royalty share on the gross proceeds for gas used or utilized on or off the Subject Interests, such as gas used for fuel.” The Agreement defined “gross proceeds” as “…the entire economic benefit and all consideration in whatever form received by or accruing to Producer…” Thus, the court concluded that, under the plain language of the Agreement, the High Mount Parties did owe royalties to the Harrison Parties for the gas used for fuel.

The High Mount Parties had further asserted that the gas used for fuel on the leases covering the captioned land was part of post-production activities, and that the Agreement allowed for some cost sharing. They also asserted that because the gas used for fuel also benefitted the Harrison Parties such cost sharing should be permitted. However, the court maintained its decision that the plain language of the Agreement entitled the Harrison Parties to royalties on gas used for fuel.

Finally, the High Mount Parties also claimed that it was impossible to calculate the amount of royalties owed on the gas used for fuel. However, the court accepted the auditor’s royalty calculations showing that the High Mount Parties shorted the Harrison Parties and that were used as the basis for the suit in the trial court. The court also pointed out that the High Mount Parties never objected to the calculation of the damages in the trial court. Thus, the court determined that the trial court did not err in granting the Harrison Parties the summary judgment motion regarding the royalties owed for the gas used as fuel on the captioned land.

Turning to the deduction issue, the court noted the language of the Agreement provided that any deductions for compressors first required that the compressors be located downstream from a “central facility,” as defined therein, and that the Harrison Parties’ evidence had established that the compressors in question were not located downstream from such a “central facility.”

The High Mount Parties submitted a memorandum in response to the Harrison Parties summary judgment motion and their corresponding evidence. However, the High Mount Parties failed to submit any authentication of the memorandum and diagram. The court determined that the High Mount Parties’ failure to authenticate their evidence was a substantive defect that could not be waived, and therefore there was no issue of fact to appeal the second summary judgment.

27

Due to the Harrison Parties’ failure to authenticate their evidence, or to produce any other substantial evidence, the court found that the Harrison Parties did not raise a genuine issue of fact. Thus, the trial court did not err in granting the Harrison Parties’ second summary judgment.

Ultimately, the court concluded that the trial court did not err in granting either summary judgments—that the High Mount Parties miscalculated the royalties owed to the Harrison Parties or that the High Mount Parties improperly deducted marketing costs.

Ring Energy, Inc. v. Trey Resources, Inc., No. 08-15-00080-CV (Tex. App.—El Paso, Jan. 18, 2017)

On Jan. 18, 2017, the El Paso Court of Appeals decided a question of first impression concerning whether a district court not located in Travis County, Texas had jurisdiction to enjoin the holder of a permit issued by the RRC allowing for the use of injection wells used for disposal wastes associated with oil and gas operations. After considering questions of statutory interpretation, legislative intent, and the nature of the common-law claim (waste), the court of appeals reversed and held that a local court retained subject matter jurisdiction to deliver injunctive relief to the producer/appellant for a probable, imminent, and irreparable injury. In addition, the court held that the RRC did not retain exclusive or primary jurisdiction over actions for common-law claims and that such actions did not constitute a collateral attack on the permit.

On Sep. 6, 2012, Trey Resources, Inc. (“Trey”) applied for nine permits from the RRC to conduct injections operations into certain wells in Andrews County, Texas. At the time, Stanford Energy operated five producing wells proximal to the proposed operations. These five wells were later assigned to Ring Energy, Inc. (“Ring”). Ring did not file a protest of the proposals for a permit, as allowed by RRC regulations, and the RRC granted the permits on Jan. 17, 2013. 103 On Sep. 23, 2013, before any injection operations had occurred, Ring sued Trey in state district court in Andrews County, seeking a declaration that the RRC permits were void and that injunction operations would limit recovery by Ring of its mineral interest and thus constituted waste. In its suit, Ring sought both damages and equitable relief in the forms of temporary and permanent injunctions.

After several temporary injunctions had lapsed, Trey filed in Andrews County a motion to dismiss for lack of subject matter jurisdiction, arguing that Ring had both failed to exhaust its administrative remedies before the RRC and had failed to file suit in the proper venue—Travis County, Texas. Ring responded, conceding its claim that the permits should be invalidated out of hand, but that its claims for damages and injunctive relief under § 85.321 of the Texas Natural Resources Code were rightly placed before the trial court located where the captioned land and alleged harm might take place. The trial court granted Trey’s motion to dismiss and Ring appealed.

Ring contended in its appeal that the trial court had mistakenly dismissed the suit for lack of subject matter jurisdiction. In its response, Trey argued that Ring could seek injunctive relief

103 Although the court did not consider the question in the present case, a dispute existed about whether Trey had provided the required notice of the proposed operations—delivering a copy of the injection proposal to any owners and/or operators of wells located within a half mile of the proposed operations and publication in the local newspaper of record.

28

before possibly damaging activities occurred only in Travis County where, by statute, orders by the RRC authorizing injection of oil and gas waste are exclusively considered. Any other such action outside Travis County, Trey contended, would be a collateral attack on a valid RRC permit. Ring answered that § 85.321 allows for equitable relief to prevent waste.

The court first considered whether equitable relief was available at the trial court proximal to the affected properties. Trey asserted that § 85.241 of the Texas Natural Resources Code104 required that such actions must be brought in Austin (Travis County) where the headquarters of the RRC are located. After noting Trey’s argument, the court noticed that, after an RRC permit has been put to actual use, all courts in Texas with subject matter jurisdiction can hear cases addressing the consequences of use of the permit and highlighted case law that compared the permit to a driver’s license which permits driving but not immunity to damages resulting from same.105

The court then considered § 85.321, which Ring argued expressly authorized it to seek local equitable (injunctive) relief for a common law action like waste before the permit was utilized. Ring focused on the opening phrase of the section, which states that a party owning property “that may be damaged by another” may sue, and argued that this implied injunctive relief could be sought before the possibility of damaging activities even began. The court was unconvinced, answering that the meaning of the word “may” depended on the surrounding language in the law and could have instead been used to express the probability of damages happening, not that injunctive relief could be sought before the possibly damaging activities occurred.

Trey countered Ring with the argument that § 85.321 only allowed for local judicial review of actions brought after injection operations had commenced and any alleged damages had arisen. If Ring wanted injunctive relief before injection operations had begun, Trey also argued, it would have to bring such action in Travis County. The court was again unconvinced with the presented definition, however, answering that the case law cited by Trey covering this section—wherein no party had sought injunctive relief—did not mean that injunctive relief was not available. The words of the statute, the court stressed, primarily drove any interpretive decision.

With the interpretive schemes proffered by both sides thus discounted, the court then dove into an analysis of the entire act. Ultimately, the court focused on § 85.322 of the Natural Resource Code, which provides that:

None of the provisions of this chapter that were formerly a part of Chapter 26, Acts of the 42nd Legislature, 1st Called Session, 1931, an amended, no suit by or against the [RRC], and no penalties imposed on or claimed against any party violating a law, rule, or order of the [RRC] shall impair or abridge or delay a cause of action for damages or other relief that an owner of land or producer of oil or gas…may have or asset against any party violating any rule or order of the commission or any judgment under this chapter.106

104 Specifically, § 85.241 provides that “[a]ny interested person who is affected by the conservation laws of this state or orders of the commission relating to oil or gas and the waste of oil or gas, and who is dissatisfied with any of these laws or orders, may file suit against the [RRC]…in Travis County to test the validity of the law or order.”

105 Berkley v. R.R. Commn. of Texas, 282 S.W.3d 240, 243 (Tex.App.—Amarillo 2009, no pet.). 106 § 85.322 TEX. NAT. RES. CODE (emphasis by court).

29

While the court admitted it seemed odd that the legislature would draft laws that detailed how suits would have to be brought in Travis County in one section (§ 85.241) and then would allow such suits to be tried locally in another section of the act (§ 85.322), the court believed that it could interpret § 85.322 no other way but to allow the injunctive relief sought by Ring to be brought in the local court.

The court also held that the RRC did not have exclusive or primary jurisdiction over Ring’s claims. Citing In re Discovery Operating, Inc.107 for the proposition that the RRC does not have exclusive jurisdiction over injection wells used for secondary recovery operations, the court also agreed with the Eastland Court of Appeals that the language of §§ 85.321-2 clearly allowed district courts to hear claims for common law actions like waste and negligence.

As for the allocation of primary jurisdiction between courts and agencies, the court first noted that a trial court should abate its own actions to allow initial agency primacy if the agency is properly staffed with experts and “great benefit is derived from an agency’s uniformly interpreting its laws, rules, and regulations, whereas courts and juries may reach different results under similar fact situations.”108 Then, the court noticed that Trey had not sought abatement, but rather outright dismissal of Ring’s claims. It also noticed that the Legislature had not clearly and expressly granted the RRC exclusive or primary jurisdiction over the type of claims Ring brought. And, again, the court agreed with the determination of the Eastland Court of Appeals in In re Discovery that claims such as negligence and waste were “inherently judicial” and thus did not warrant giving the RRC primary jurisdiction. In ruling against Trey, the court acknowledged that injunctive relief of the kind Ring sought could negate use of an RRC permit, but pointed out that injunctions required the complaining party name a cause of action and probable right to relief, along with a “probable, imminent, and irreparable injury”109 as well as the posting of a substantial bond.

Turning at last to Trey’s argument that the injunction sought by Ring amounted to a collateral attack on the RRC’s permit, the courted noted that Trey had cited a handful of cases in support of the general proposition that an order of the RRC cannot be collaterally attacked, particularly outside of Travis County. The court dismissed consideration of any of the cases, noting that they either did not concern a claim brought under § 85.321 or simply did not support Trey’s claims. In addition, the court held that none of the cases undermined the possibility of bringing an equitable claim as expressly allowed by §§ 85.321-2.

Aruba Petroleum, Inc. v. Parr, No. 05-14-01285-CV (Tex. App.—Dallas, Feb. 1, 2017)

On Feb. 1, 2017, the Dallas Court of Appeals considered whether an operator had created an intentional nuisance that affected neighboring surface owners when it conducted exploration and production activities in the Barnett Shale. Three members of the Parr family—Robert, Lisa, and Lisa’s daughter, E.D. (collectively, the “Parrs”)—sued several oil and gas companies including Aruba Petroleum, Inc. (“Aruba”), alleging that “environmental contamination and

107 216 S.W.3d 898 (Tex.App.—Eastland 2007, orig. proceedings).108 Subaru of Am. v. David McDavid Nissan, 84 S.W.3d 212, 221, citing Gregg v. Delhi-Taylor Oil Corp.,

344 S.W.2d 411, 413 (Tex. 1961). 109 The court noted that the injunctive relief sought by Ring was brought under §§ 65.011-2, TEX. CIV. PRAC.

& REM. CODE. Interestingly, § 65.012 allows for relief that prohibits “subsurface drilling or mining operations” when an injury is threatened that cannot be remedied with damages for the resultant injuries.

30

polluting events” had occurred on the captioned land. The court of appeals concluded that no legally sufficient evidence of intent to cause a nuisance had been presented by the Parrs and reversed the district court.

The Parrs owned forty acres of land in Wise County, Texas. Since approximately 2000, the region has seen extensive activity related to development of the Barnett Shale. All three Parrs lived on the property after 2007, with one family member present on the captioned land since 2002. After litigation began, several other defendants either settled with the Parrs or were released from liability in the case by either summary judgment or claim severance through the trial court, eventually leaving Aruba as the sole defendant. The Parrs alleged a variety of environmental claims, including nuisance, stemming from Aruba’s activities. All claims except for private nuisance were eventually dismissed, nonsuited, or abandoned prior to trial. As for negligent private nuisance, the trial court granted a directed verdict to Aruba. The jury, however, found that Aruba had intentionally created a private nuisance and awarded the Parrs $2.65 million in damages for “past and future physical pain and suffering and mental anguish” and $275,000 for loss of market value of the captioned land.

Aruba appealed, marshalling six issues. Among them, the court of appeals focused on Aruba’s argument that no legally sufficient evidence existed allowing the jury to establish that Aruba had any intent to create a private nuisance targeting the Parrs or their land. The court acknowledged that it must sustain a no-evidence challenge if the evidence presented by the Parrs illustrated a complete absence of any proof of a vital fact, including evidence it could not consider due to the rules of law or evidence.110 In addition, the court noted it must sustain a no-evidence challenge if the evidence offered of a vital element is no more than a “mere scintilla” or the evidence shows the opposite of the vital fact.111

In establishing the applicable law, the court first turned to the definition of intentional nuisance in Texas, quoting recent case law that “[A] defendant may be held liable for intentionally causing a nuisance based on proof that he intentionally created or maintained a condition that substantially interferes with the claimant’s use and enjoyment of land by causing unreasonable discomfort or annoyance to persons of ordinary sensibilities attempting to use and enjoy it.”112 Aruba argued that no evidence existed that it knew it was harming the Parrs or their properties or that harm was substantially sure to occur due to its conduct. Furthermore, Aruba noted that the jury had found that its activities were not abnormal or unusual for the area and were no different than any of the other operators nearby. Therefore, Aruba could have had no notice that its activities were uniquely affecting the Parrs or their property, or both.

In response, the Parrs argued that evidence existed that Aruba did know that its activities were harmful to the Parrs and their property and was significantly interfering with their use and enjoyment of the property. In support of this assertion, they offered three categories of evidence showing Aruba’s knowledge of the harm it caused the appellees: (1) complaints made by a neighbor; (2) their own complaints to the Texas Commission on Environmental Quality (the “TCEQ”); and (3) their own complaints directly to Aruba and contractors hired by Aruba.

In support of the first category of evidence showing Aruba’s knowledge of the specific harm to the Parrs, the Parrs offered evidence from trial that Lisa Parr had testified that a neighbor

110 Serv. Corp. Int’l v. Guerra, 348 S.W.3d 221, 228 (Tex. 2011).111 Id. 112 Crosstex N. Tex. Pipeline, L.P. v. Gardiner, No. 15-0049, 505 S.W.3d 580 (Tex. June 24, 2016).

31

had complained to Aruba through various outlets multiple times. This meant, the Parrs believed, that Aruba had knowledge it was harming the neighboring landowners—including the Parrs—and that that sufficed to satisfy the knowledge requirement of harm and thus established intent. Aruba countered that none of this evidence showed that the complaints included specifics about the Parrs or their property. Aruba could not have known about alleged nuisance activities directed at the Parrs and, therefore, the evidence was not germane to a claim of intentional negligence.

In support of the second category of evidence, the Parrs argued that they had offered evidence at trial of complaints they made to the TCEQ about Aruba’s activities. In response, Aruba pointed out that no evidence existed that the Parrs had identified themselves or their property to the TCEQ or that Aruba knew about the complaints the Parrs had made to the TCEQ. The court noted that the Parrs had offered no evidence that Aruba knew the Parrs were making complaints to the TCEQ about their activities on the captioned land.

In support of the third category of evidence, the Parrs offered evidence that they had alerted Aruba directly of the harm caused by Aruba’s operations. Here, the case provides a lengthy recap of the testimony at trial of Lisa and Robert Parr regarding various haphazard encounters Lisa had with Aruba field personnel and contractors on or near the captioned property, and phone calls made by Lisa to various people at Aruba, with each person reached vaguely remembered by Lisa only on a first name basis. The court noted that Lisa Parr had testified under cross examination that the Parrs had not contacted Aruba via letter or email. In response, Aruba argued that the Parr’s evidence of anonymous complaints to people near the wellsite—some of them contractors—or on the telephone did not suffice to prove it had knowledge and intent on its part to create a nuisance.

The court noted that Aruba had no producing wells on the Parr’s property and that the jury had, when asked if Aruba’s operations were abnormal and out of place such as to constitute a private nuisance, answered “No.” The Parrs, while conceding that intentional nuisance “requires evidence of more than an ‘awareness of the mere possibility of damage,’”113 presented evidence they claimed showed Aruba was aware that its operations generally resulted in smells, noise, light, and vibrations. They cited testimony of an Aruba corporate officer that locals neighboring operations would “probably” find the activities a nuisance and that Aruba had “probably” had complaints about approximately twenty wells near the Parrs and their property.

Ultimately, however, the court stressed that the question before it was not whether Aruba had created a nuisance or acted negligently, but rather whether it had created an intentional nuisance as to the Parrs. Returning to Crosstex for the legal standard of intentional nuisance, the court noted that a party intentionally creates a nuisance if it “actually desired or intended to create the interference” or actually knew or believed “that the interference would result” from its activities.114 The court noted that evidence showing Aruba had “intentionally engaged in the conduct that caused the interference”115 was not enough to show an intentional nuisance. Instead, Aruba must have “intentionally caused the interference that constitutes the nuisance [.]”116 In other words, Aruba must have specifically known that the Parrs’ use and enjoyment of their land was being interfered with by its operations. Here, the court held that none of the evidence

113 City of San Antonio v. Pollock, 284 S.W.3d 809, 821 (Tex. 2009).114 Crosstex, 2016 WL 3483165, at *16.115 Id.116 Id.

32

presented by the Parrs showed that Aruba knew it was interfering with the Parrs or their property or that the Parrs had expressly made their complaints known to Aruba.

Reed v. Maltsberger, No. 04-16-00231-CV (Tex. App—San Antonio, May 3, 2017)

On May 3, 2017, the San Antonio Court of Appeals (Fourth District) reversed the judgment of the trial court regarding the interpretation of a mineral conveyance from 1942 (the “1942 Deed”). The court held that the 1942 Deed conveyed a 1/4 mineral interest to the grantees/appellants.

The appellants (collectively, the “Reed Plaintiffs”), successors of the original grantees, argued that a 1/4 mineral interest was conveyed in the 1942 Deed. The appellees argued that the 1942 Deed conveyed only a fixed NPRI. At the time of the 1942 conveyance, the captioned land was already subject to an oil and gas lease that provided for a 1/8 lessor’s royalty under that existing lease. The court affirmed that, although the 1942 Deed conveyed:

“…an undivided one-fourth (1/4) interest in and to all of the oil, gas, and other minerals in and under that may be produced from the following described lands.”

The language in the 1942 Deed also stripped the grantees (W.B. Dossett and E.M. Benz) of certain fee mineral rights:

“In the event the above lease…shall for any reason become cancelled or forfeited, it is agreed that the joinder or consent of grantee, his heirs or assigns, shall not be required to another or new lease upon said property…nor shall grantee, his heirs or assigns, be entitled to share in any bonus consideration therefor or delay rentals thereunder, it being the purpose and intent hereof to grant and convey an undivided one-fourth (1/4) of the one-eighth (1/8) royalty (including any annual gas rentals) under said existing lease and an equivalent royalty interest under any future mineral leases thereon by [lessor], his heirs, administrators or assigns.”

The dispute over whether the conveyance amounted to a fixed royalty or a mineral interest lay at the heart of the case. Under the terms of the lease covering the captioned land at the time of the dispute (the “Hanks Lease”), the lessee, Rosetta Resources Operating, was paying a fixed 1/32 royalty to the Reed Plaintiffs. However, because the Reed Plaintiffs believed that they owned a 1/4 mineral interest in fee, they argued that they were owed 1/4 of the 22.5% royalty (the agreed royalty in the Hanks Lease) instead of the fixed 1/32 royalty that Rosetta had been paying.

Both parties moved for summary judgment with the district court. The trial court determined that the Reed Plaintiffs owned only a fixed 1/32 NPRI. The Reed Plaintiffs appealed.

Reviewing the trial court’s grant of summary judgment de novo, the court of appeals considered the nature of the conveyance, noting that the primary objective in interpreting mineral grants is to determine intent from the four corners of the instrument and not the subjective intent that would benefit each party. The court used a “holistic” approach to discern the intent of the parties from the 1942 Deed as to whether a mineral interest or a royalty interest had been conveyed. The court first delineated the five components of a mineral interest in Texas: (1) the right to develop, (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. The

33

court clarified, however, that not all the elements of a mineral interest must be conveyed; a grantor may reserve specific interests in the conveyance.

In contrast, the court noted that a royalty interest comes from the grantor’s mineral interest, is non-possessory, and could be separated. A royalty interest has two distinct characteristics: (1) it is non-possessory, and (2) it is free of production and operating expenses.

The court further noted that, just as it is possible to strip certain rights from a mineral fee interest, it is also possible to strip or add certain rights to a royalty interest. Hybrid fee and royalty interests occur frequently despite the problems created. Distinct conveyance or reservation language may help indicate which type of interest is being conveyed or reserved. Traditional mineral fee language refers to the “oil, gas, and other minerals ‘in and under’ the described land.” On the other hand, simply using the word “royalty” typically creates a royalty.

The court then compared several cases117 to determine whether a conveyed mineral interest that strips the grantee of several mineral interest rights remains a mineral fee interest or converts it into a royalty interest. Ultimately, the court noted that each case varied in analysis and conclusion, and determined that no fixed rule existed, concluding that the court must analyze the language of the instrument to glean and interpret the intent of the drafters.

Getting down to business, the court then applied rules of construction to the 1942 Deed. First, the court noted that the traditional mineral fee conveyance language of “in and under” was used in the 1942 Deed. Second, the court noticed that at the time the 1942 Deed was conveyed, the land was already subject to an existing oil and gas lease. This implied the possibility of future leases (which was believed consistent with conveying a mineral interest). Third, the court noted that the 1942 Deed stripped the grantees of certain rights and opined, “if the grantor had intended to convey only a royalty interest, this language stripping the grantee of rights would be redundant because a royalty interest owner has no such rights.”

Finally, the court considered the provision in the 1942 Deed regarding future royalties. The lease stated that the grantees were entitled to an “equivalent royalty interest under any future mineral leases.” The court decided that this provision made it clear that under future leases, which could provide for an amount differing from a 1/8 royalty (the amount in the original lease), the grantees will be entitled to “an equivalent royalty interest” – that is, 1/4 of any future royalty negotiated.

Ultimately, the court held that the 1942 Deed conveyed a 1/4 mineral interest and not a royalty interest. Therefore, the court reversed the judgment of the trial court.

Chieftain Exploration Company Inc. v. Gastar Exploration Inc. and Cubic Assets, No. 10-15-00037-CV (Tex.App.—Waco, Aug. 30, 2017)

On Aug. 30, 2017, the Waco Court of Appeals issued an opinion that considered the question of whether a lease had been included in a unit with a producing non-tract well. The case

117 Watkins v. Slaughter, 189 S.W.2d 699 (Tex. 1945); Altman v. Blake, 712 S.W.2d 117 (Tex. 1986); French v. Chevron USA, 896 S.W.2d 795 (Tex. 1995); Temple-Inland Forest v. Henderson Family Partnership, 958 S.W.2d 183 (Tex. 1997); Garza v. Prolithic Energy Co., L.P., 195 S.W.3d 137 (Tex. App.—San Antonio 2006, pet. denied); and Hamilton v. Morris Resources, 225 S.W.3d 336 (Tex. App.—San Antonio 2007, pet. denied).

34

concerned the Streater Gas Unit (the “Unit”) that was formed in 2010 by Gastar Exploration Inc. (“Gastar”) and two other entities. The Unit was comprised of 56 oil and gas leases and covered 702.3 acres of land. The leases included in the Unit were listed in the Unit Designation that was recorded in the official public records. Tract 17, which was comprised of 56 surface acres, was included in the Unit. A producing well, the Streater Well, was drilled on the Unit but not on Tract 17. Two parties, the McBeth Family Limited Partnership and Lone Oak, each owned one-half of the minerals in Tract 17. An undivided 1/4 NPRI, currently owed by Chieftain, encumbered Lone Oak’s mineral estate. Before Chieftain acquired the NPRI, two oil and gas leases were executed, one each by the McBeth Family Limited Partnership and Lone Oak. The Lone Oak Lease covered 3,466 acres, including the 56-acre tract. The McBeth Lease covered 591.3 acres, including the 56-acre tract.

Claiming it was owned royalties from the Streater Well, Chieftain sued Gastar asserting violations of the Natural Resources Code, breach of contract, and violations of the Texas Theft Liability Act. As a successor-in-interest to Gastar’s rights in the Streater Unit, Cubic intervened in the suit. Each party filed competing motions for summary judgment. The trial court granted the motions of Gastar and Cubic and denied Chieftain’s motion.

The Waco court of appeals considered whether the Live Oak lease was included in the Streater Gas Unit in the first place, determining that if it was thusly pooled, Chieftain would be owed royalties. The court determined that the plain language of the Unit Designation indicated the Lone Oak Lease was not pooled into the Streater Unit. The court noticed that, while Tract 17 was listed, the Lone Oak Lease itself was not listed as being one of the 56 leases included within the Streater Unit. The court also noticed that the Lone Oak Lease had expressly provided that the lessee, “may pool all or any portion of the leased premises” into a unit of up to 640 acres only if the leased premises comprised at least 50 percent of the unit. Since the Streater Unit was composed of over 700 acres, and since Tract 17—the 56 acres in which half of the minerals were the subject of the Lone Oak Lease—did not make up at least 50 percent of the Unit, the court held the Lone Oak Lease, by its express terms, could not have been pooled as Chieftain claimed. Further, even if the Lone Oak Lease had it been pooled by the pooling agreement (the Streater Gas Unit Designation), the terms of the lease would have made the pooling invalid and unenforceable. Ultimately, the court held the Lone Oak lease had expired before creation of the Unit, was not revived by creation of the Unit, and that Chieftain was not entitled to payment under a pooling theory.

Despite the expiration of the lease, Chieftain argued that the rule of Wagner & Brown, Ltd. v. Shepperd118 and Ladd Petroleum Corp. v. Eagle Oil & Gas Co.119 applied, and that the Unit Designation pooled not only “leases” but also “lands” and that “lands” included freestanding royalties such as the NPRI burdening the minerals estate leased by Lone Oak. The court noted, however, that unlike the pooling agreements in Wagner and Sheppard, the Unit Designation in the current case instead provided that the “Leases, insofar and only insofar as the leases cover the lands described and delineated…are hereby combined, unitized and/or pooled into a single, consolidated pooled unit.” Therefore, with no “lands” mentioned, only the leases could be combined, not the lands and the associated NPRI.

Chieftain also argued that since its predecessor-in-interest had ratified the Streater Gas Unit Designation, it was entitled to royalty. The ratification had provided that: 118 282 S.W.3d 419, 422 (Tex. 2008).119 695 S.W.2d 99, 106 (Tex. App.—Fort Worth, 1985 writ ref’d n.r.e.)

35

“…pooling or unitization shall occur only by the Lessee’s exercise of the pooling provision of the above referenced lease and in such event the royalty interest of the undersigned shall be pooled or unitized to the extent, and only to the extent, that the tract or land in which the royalty interest is owned is included within such unit.”

Chieftain argued this language amounted to an “anti-pooling provision” and, per the rule established in London v. Merriman120 and Verble v. Coffman,121 was ineffective to prevent an NPRI owner from ratifying the unit designation. The court countered that, unlike the scenario encountered in London and Verble wherein “anti-pooling” language had attempted to prevent an NPRI owner from being able to ratify a lease, the present case presented no ratification of a lease by an NPRI owner and that the supposed “anti-indemnity” language never attempted to prevent the NPRI owner from receiving benefits under the Lone Oak lease. Therefore, since Gastar did not include the Lone Oak lease in the Unit, Gastar had never exercised the pooling provision of the Lease. Consequently, neither the Lone Oak lease lessor nor Chieftain the NPRI owner were entitled to royalties from the Unit.

Chieftain argued that the fact an NPRI owner is entitled to revive a dead lease permitted it to collect payment. The court countered that since the Lone Oak lease was never part of the Unit, whether the lease was revived was immaterial.

Finally, the court held that since Chieftain was never entitled to royalties generated under the terms of the Unit, its claim under the Texas Theft Liability Act122 axiomatically failed.

XTO Energy v. Goodwin, No. 12-16-00068-CV (Tex.App.—Tyler, Oct. 18, 2017)

On Oct. 18, 2017, the Twelfth Court of Civil Appeals in Tyler reversed a trial court’s decision to award a mineral owner over two million dollars in a dispute with an operator specializing in hydraulic fracturing, holding instead that no evidence existed of actionable trespass or a breach of the lease terms. The court also held, however, that the lease was correctly declared void by the trial court and that the operator was not owed the royalty back it mistakenly paid the lessor.

In 2007, Elton Goodwin executed an oil and gas lease with CS Platinum as lessee. The lease covered three tracts Goodwin owned in San Augustine County, Texas, consisting of approximately 27 acres, 55 acres, and 2 acres. Within the lease was incorporated a letter agreement that provided CS Platinum would pay Goodwin a lease bonus. The amount of the bonus was dependent on the lessee’s determination that Goodwin owned a 50% undivided mineral interest in the 55-acre tract and an undivided 100% mineral interest across each of the other tracts.

After Goodwin accepted the bonus, he discovered he might own more than half the minerals in the 55-acre tract. Meanwhile, XTO Energy (“XTO”) was assigned CS Platinum’s interest in the lease. Goodwin notified XTO that he thought the lease was void as he had not been paid the correct bonus as required under the letter agreement. XTO later agreed a mistake had been made in the acreage calculation, but disagreed the lease was void.120 756 S.W.2d 736 (Tex.App.—Corpus Christi 1988, writ denied)121 680 S.W.2d 69 (Tex.App.—Austin, 1984 no writ)122 TEX. CIV. PRAC. & REM. CODE ANN. § 134.003(a)(West 2011).

36

XTO included Goodwin’s tracts in a new unit called the Butler Rooney Unit (the “Rooney Unit”) in 2010. A year later, XTO completed a producer known as the Butler Rooney 1H well within the new unit. Goodwin began accepted royalty payments from the well in 2012. During this time, XTO created the Terrapins Unit adjacent to the Rooney Unit wherein it planned to drill two horizontal wells that were platted to be close to—but not cross—the vertical plane of Goodwin’s 27-acre tract.

While drilling and completing the Terrapins 1H well, the drill bit deviated horizontally from the planned route but away from the boundary plane with Goodwin’s tract. The drill bit for the second well—the Terrapins 1HB well—also deviated horizontally during drilling but towards Goodwin’s property. A gyroscopic survey later showed the wellbore of the second was within 60 feet of the boundary plane of Goodwin’s tract, but XTO continued drilling. A second survey later revealed the wellbore had penetrated 126 feet into Goodwin’s tract at approximately 10,000 feet subsurface. XTO continued drilling, but by changing the direction of the bit, managed to exit Goodwin’s tract at 13,200 feet subsurface. Ultimately, a 2,900 feet segment of the completed well was located inside the volume of Goodwin’s strata.

After the second well was completed, XTO requested a subsurface easement from Goodwin. Meanwhile, XTO had suspended Goodwin’s royalty payments from production in the Rooney Unit, claiming he had been overpaid because of an accounting error. After the parties were unable to resolve the disputes over the trespass and easement, the lease’s validity and the bonus payment, and the royalty payments, Goodwin sued.

At district court, Goodwin was granted a partial summary judgment that retroactively voided the lease due to nonpayment of the full amount of bonus. At trial, the jury found that XTO committed: (1) a trespass for which it awarded $815,392.00 in damages; (2) bad faith trespass for which it awarded $78,000.00 in damages; (3) bad faith pooling for which it awarded $1,272,331.80 in damages; and (4) conversion for which it awarded $636,668.90 in damages. The jury also found that XTO had not acted with malice or committed fraud. Goodwin chose to accept the damages awards for trespass and bad faith pooling, and the trial court awarded damages of $2,088,723.80 and interest.

On appeal, XTO presented seven issues. The court’s opinion considered five. First, XTO argued that Goodwin did not have a “legally protected ownership interest” in the portion of its subsurface estate that was impacted by the trespass, noting that no evidence existed that its trespass interfered with Goodwin’s ability to develop his minerals or that the trespass affected Goodwin’s surface. XTO cited dicta from Coastal Oil & Gas Corp v. Garza Energy Trust123 for the supposition that, for such a deep intrusion, Goodwin could not support a trespass claim, noting in particular the Court’s quote that the ad coelum doctrine “has no place in the modern world.”124

The court of appeals disagreed, looking instead to the more recent holding of Lightning Oil Co. v. Anadarko E & P Onshore, LLC, in which the Texas Supreme Court held that the ownership rights of the surface owner included the non-mineral matrix of strata that held up the surface and extended those ownership rights to the “geologic structures beneath the surface.” Noting that the Lightning opinion mentioned Coastal but attached no limitation to the ownership right of the surface owner, even at great depths, the court held that Goodwin did have legally

123 268 S.W.3d 1 (Tex. 2008)124 Id. at 12.

37

protected ownership rights in the strata at the depth of the second Terrapin well’s intrusion that could, in turn, give rise to a trespass action.

Then the court turned toward the question of calculating trespass damages. Goodwin relied on an expert to measure the damages he sought. The expert, in turn, used a two-step methodology. First, he measured the length of the wellbore trespass and compared that to the wellbore’s overall length. Second, he estimated the value of the well using XTO’s annual filings with the Securities and Exchange Commission. XTO argued that this methodology was impermissible because it did not measure the permanent injury to the land as XTO believed a traditional trespass action should require.

The court agreed for three reasons. First, the expert’s voluminous valuations were based on company-wide economic forecasts and not analysis of the actual productive formation found in the trespassed interval. The court found this to be an unreliable source. Second, no evidence of production from the well was presented. The court highlighted the speculative nature of the well’s ultimate value—if it produced and, if so, for how long. XTO was waiting to see how the lawsuit turned out before it decided on either completing or plugging the well. Third, the court noted that XTO could not have produced from the well in the first place without some kind of drill-through agreement or easement from Goodwin and that the expert’s estimation did not explain how his estimated trespass award would provide XTO any right to move gas through that portion of the well traversing Goodwin’s strata. The court therefore set aside the expert’s estimate.

As its second issue, XTO argues that no evidentiary basis existed for the jury’s finding of bad faith pooling and the award of over a million dollars. Specifically, XTO argued that when the lease taken by CS Platinum in the Rooney Unit was deemed void, the lessor of that lease lost the ability to rightfully claim royalty from wells not drilled on the leased land. Further, since the lease was void, it couldn’t be pooled in the first place, much less in bad faith. Goodwin countered, arguing that termination of the lease had no effect on his bad faith pooling complaint, citing Wagner & Brown v. Sheppard125 for the proposition that termination of a lease in a pool does not necessarily terminate the pool as to the previously-leased land. Further, Goodwin argued that bad faith pooling can arise merely from wrongful attempts to pool.

The court disagreed with Goodwin, noting that to pool, the lessee must have the contractual ability to do so. If it does not, pooling does not occur. Since XTO had no lease, it could not pool. Bad faith pooling, the court explained, arises when the lessee has the ability to pool but does so for reasons that violate the implied duty to only pool in a way fair and in good faith to the lessor. In the present case, unlike in Wagner, there was never a lease that authorized pooling—it had been retroactively found void. Pooling with no authority is not pooling at all and binds no one.

Moving on to XTO’s fourth issue, the court considered Goodwin’s allegation of bad faith trespass. Bad faith trespass—in this case, continuing to enter under an expired oil and gas lease without a good faith reason to believe the lease still existed—can give rise to additional damages. Goodwin argued that XTO’s actions—misrepresentations to the RRC, continuing to drill despite knowledge that the wellbore was approaching the unpermitted tract, and the filing of a modified pooled unit declaration in the public property records—showed that XTO was a bad faith trespasser. Further, these facts would have allowed the jury to find that XTO had acted “with a

125 282 S.W.3d 419 (Tex. 2008)

38

conscious indifference to and disregard of Goodwin’s rights” and therefore entitled him to additional damages. The jury did not find, however, that XTO had acted with malice or fraud. The court held that, with no finding of fraud or malice, and no evidence to support a recovery for actual damages, XTO’s appeal on this point was sustainable.

In the same issue, XTO also argued that no sufficient evidence supported the jury’s award of $636,668.90 for conversion because nothing showed that any of Goodwin’s minerals were extracted as a result of the intrusion by XTO’s wellbore or through pooling of Goodwin’s mineral tracts. The court agreed, noting that the expiration of the lease meant no bad faith pooling could have occurred and that the trespassing well had yet to produce.

In XTO’s fifth issue it argued that, because of the voidance of the CS Platinum Lease, Goodwin was not entitled to receive the royalty ($386,000) paid to him by XTO and should be made to pay it back. Goodwin answered XTO’s unjust enrichment claim with the defense that XTO had voluntarily paid the money without any input by Goodwin. The court noted that, while all the royalty payments Goodwin received through the Rooney Unit were derived from the Butler Rooney 1H well and no part of the Butler Rooney 1H was drilled on Goodwin’s property, Goodwin had no hand in creating the mistakes that led to XTO’s overpayment and even had informed XTO that the lease might be void due to bonus underpayment. Further, XTO had created the division orders associated with the Rooney Unit—division orders that reflected XTO’s mistaken belief it owed Goodwin royalty—and no other royalty owner was negatively affected by the overpayment to Goodwin. It had all the necessary data to evaluate whether the lease was still in effect after Goodwin claimed it was not and it still had paid the money. The court overruled XTO’s fifth issue, opining that, “[m]oney voluntarily paid on a claim of right, with full knowledge of all the facts, in the absence of fraud, deception, duress, or compulsion, cannot be recovered merely because the party [paying the money] at the time of the payment was ignorant of or mistook the law as to his liability.”126

Boerschig v. Trans-Pecos Pipeline, No. 16-50931 (5th Cir., Oct. 3, 2017)

On Oct. 3, 2017, the U.S. Court of Appeals, Fifth Circuit, held that the private condemnation process utilized by pipelines in the Texas Utility Code did not violate the private nondelegation doctrine as it applies to the Fourteenth Amendment of the U.S. Constitution.

Trans-Pecos Pipeline (“Trans-Pecos”) was constructing an intrastate pipeline and wanted to cross Boerschig’s land in Jefferson County, Texas. After negotiations failed, Trans-Pecos initiated the power of private eminent domain provided for under TEX. UTIL. CODE § 181.004, which allows a pipeline to exercise the power of private eminent domain “if it devotes its private property and resources to public service and allows itself to be publicly regulated.”127

The court noted that this process generally proceeded in two phases. First, if initial negotiations failed, a gas utility, upon determining that a taking was necessary to further a public purpose (i.e. transporting the gas of the public as a common carrier), could initiate an administrative procedure whereby a state district court appoints special commissioners who assess the value of the property being condemned. After the assessment, the condemner could

126 BMG Direct Mktg., Inc. v. Peake, 178 S.W.3d 763, 768 (Tex. 2005) (citing Pennell v. United Ins. Co., 243 S.W.2d 572, 576 (Tex. 1951))

127 Anderson v. Teco Pipeline Co., 985 S.W.2d 559, 565 (Tex.App.—San Antonio, 1998).

39

then assume control of the contested property. A second judicial phase could follow in state district court if the landowner contesting the award challenges the utility’s finding of public necessity.

In this case, before the commissioners assessed the property, Boerschig filed a federal case seeking an injunction to stop the state condemnation proceeding from going forward. Boerschig sought the injunction on the grounds that the Texas eminent domain process for pipelines violated the Due Process Clause of the U.S. Constitution both because of the delegation of condemnation power to a private party and because the process did not provide for judicial hearing before the commissioners’ assessment of the takings and award of the property. The federal district court did not issue the desired injunction, instead finding that the federal Anti-Injunction Act applied.128 Following the district court’s ruling, the state special commissioners determined the award value due Boerschig and Trans-Pecos assumed control of the property. While Boerschig appealed the district court’s opinion, Trans-Pecos completed the pipeline over Boerschig’s land.

On appeal, a preliminary matter was first considered: Trans-Pecos argued that, since the pipeline was complete, the issue was moot. In response, the federal court of appeals noted that, while injunctive relief typically becomes moot if the event sought to be stopped with an injunction occurs, an exception exists when the party that was going to be potentially enjoined goes ahead with the act with notice of the request for injunctive relief and the reviewing court can restore the original status quo. Here, the court noted the pipeline could be removed, restoring the land to its original condition, and thus the appeal of Boerschig before it was not moot.

Turning to Boerschig’s argument that the district court had wrongly applied the Anti-Injunction Act before a judicial process had started in state court, the court of appeals noted that the Texas condemnation process indeed had two stages—an administrative stage possibly followed (possibly) by a judicial stage and that a question may exist whether the entire Texas eminent domain scheme at issue could be considered one proceeding (administrative and judicial) or two separate proceedings (one administrative and then one judicial). The court side-stepped this conundrum, however, by determining that Boerschig had not satisfied the “demanding” standard for successfully seeking an injunction in the first place.

Noting that the district court’s failure to determine whether an injunction should be issued (because of its application of the Anti-Injunction Act instead) did not preclude the court of appeals from considering the facts and equitable factors dispositive for a determination of whether an injunction should be forthcoming, the appellate court went ahead with such a determination. Observing that Boerschig’s challenge was one of constitutionality and was not related to the traditional factors involved with determining whether an injunction could be forthcoming (such as claims related to the actual parameters of the land or Trans-Pecos use of it), the court denied the injunction.

The court then turned to Boerschig’s claim that Texas’ private eminent domain ability for pipelines was an unconstitutional delegation of powers to private entities.129 After considering the

128 This Act prohibits federal courts from enjoining ongoing state proceedings. See 28 U.S.C. § 2283.129 In other words, a “private nondelegation” claim rooted in the Due Process Clause that stands in contrast to

another type of delegation that can be found unconstitutional: delegation by Congress of its powers to executive branch agencies.

40

three private nondelegation opinions that have been handed down by the U.S. Supreme Court,130 the court found that the Texas “scheme” avoided the two pitfalls encountered in the USSC nondelegation cases—it both imposed a standard to guide the pipelines—“public use” was necessary for a taking—and also allowed for judicial review that could trump the pipeline’s initial determination on public use. Ultimately, the court held that the Texas private eminent domain law could stand.

130 Eubank v. City of Richmond, 226 U.S. 137 (1912); Seattle Title Trust Co. v. Roberge, 278 U.S. 116 (1928); Carter v. Carter Coal Co., 298 U.S. 238 (1936).

41