Enerquest Oil & Gas, LLC et al v. Plains Exploration & Production Company et al, No. 5:2012cv00542 - Document 145 (W.D. Tex. 2013)
Court Description: ORDER DENYING AS MOOT 105 Motion to Sever; DENYING 107 Motion for Leave to File; DENYING 113 Motion for Partial Summary Judgment; DENYING 122 Motion for Partial Summary Judgment; Joining and adopting 124 Motion for Summary Judgment; GRANTING 125 Motion for Summary Judgment; GRANTING 126 Motion for Summary Judgment. Signed by Judge David Ezra. (rg)
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Enerquest Oil & Gas, LLC et al v. Plains Exploration & Production Company et al Doc. 145 UNITED STATES DISTRICT COURT WESTERN DISTRICT OF TEXAS SAN ANTONIO DIVISION § § § § Plaintiffs, § § vs. § § PLAINS EXPLORATION & § PRODUCTION COMPANY, EOG RESOURCES INC., DENIS BRYSCH, § § RACHEL BRYSCH, LISA ANN LABUS, KEVIN V. LABUS, KAREN S. § § BRYSCH, LEONARD MOY JR., EDWIN MOY, DIANE PAPE, LEROY § § MOY, and ADELENE MANKA, § § Defendants. ENERQUEST OIL & GAS, LLC, and CHIEFTAIN ENERGY, LLC, No. SA:12-CV-542-DAE ORDER: (1) GRANTING MINERAL OWNERS’ MOTION FOR PARTIAL SUMMARY JUDGMENT; (2) DENYING PXP’S MOTION FOR PARTIAL SUMMARY JUDGMENT; (3) DENYING PLAINTIFFS’ MOTION FOR PARTIAL SUMMARY JUDGMENT; (4) GRANTING EOG’S MOTION FOR PARTIAL SUMMARY JUDGMENT ON SEISMIC CLAIMS; (5) DENYING AS MOOT PXP’S MOTION TO SEVER; (6) DENYING PLAINTIFFS’ MOTION FOR LEAVE TO FILE THIRD AMENDED COMPLAINT On October 10, 2013, the Court heard oral argument on the Opposed Motion for Leave to File Third Amended Complaint and the Motion for Partial Summary Judgment filed by Plaintiffs Chieftain Energy, LLC (“Chieftain”) and EnerQuest Oil & Gas, LLC (“EnerQuest”) (Dkt. ## 107, 122); the Opposed Motion to Sever and the Motion for Partial Summary Judgment filed by Defendant Plains 1 Dockets.Justia.com Exploration & Production Company (“PXP”) (Dkt. ## 105, 113), the latter of which Defendant EOG Resources, Inc. (“EOG”) has joined (see Dkt. # 124); EOG’s Motion for Partial Summary Judgment on Plaintiffs’ Seismic Claims (Dkt. # 125); and the Motion for Partial Summary Judgment filed by Denis Brysch, Karen S. Brysch, Rachel Brysch, Kevin V. Labus, Lisa Ann Labus, Adelene Manka, Edwin Moy, Leroy Moy, Leonard Moy, Jr., and Diane Pape (collectively, “the Mineral Owners”) (Dkt. # 126). John Matthew Sjoberg, Esq., and David E. Jackson, Esq., appeared on behalf of Chieftain and EnerQuest; Michael E. McElroy, Esq., appeared on behalf of PXP; J. Derrick Price, Esq., appeared on behalf of EOG; and John H.H. Bennett appeared on behalf of the Mineral Owners. After careful consideration of the memoranda and exhibits in support of and in opposition to the motions, and in light of the Parties’ arguments at the hearing, the Court, for the reasons that follow, GRANTS the Mineral Owners’ Motion for Partial Summary Judgment (Dkt. # 126); DENIES PXP’s Motion for Partial Summary Judgment (Dkt. # 113) and EOG’s motion joining and adopting it (Dkt. # 124); DENIES EnerQuest’s Motion for Partial Summary Judgment (Dkt. # 122); GRANTS EOG’s Motion for Partial Summary Judgment on Plaintiffs’ Seismic Claims (Dkt. # 125); DENIES AS MOOT PXP’s Motion to Sever (Dkt. # 105); and DENIES EnerQuest’s Motion for Leave to File Third Amended Complaint (Dkt. # 107). 2 BACKGROUND Plaintiffs EnerQuest Oil & Gas, LLC, and Chieftain Energy, LLC, are Oklahoma oil companies. Chieftain is wholly owned by its sole member, EnerQuest. (Dkt. # 66 (“SAC”) ¶¶ 5–6.) For purposes of this Order the Court will refer to these entities collectively as “EnerQuest.” In 2008, EnerQuest acquired two oil, gas, and mineral leases in Karnes County, Texas (collectively, the “Leases”). These lands are owned by Defendants Denis Brysch, Rachel Brysch, Lisa Ann Labus, Kevin V. Labus, Karen S. Brysch, Leonard Moy Jr., Edwin Moy, Diane Pape, Leroy Moy, and Adelene Manka (collectively, the “Mineral Owners”). The Leases, which were identical in all relevant respects, had two-year primary terms and could be maintained “for so long thereafter as a covered mineral [was] produced in paying quantities” or the Leases were “otherwise maintained in effect pursuant to [their] provisions . . . .” (Dkt. ## 114-2, 114-3 (“Leases”) ¶ 2.) Among the provisions capable of extending the Leases in the absence of actual production was the following “shut-in well” clause: [I]f, during or after the primary term one or more wells on the leased premises or lands pooled therewith are capable of producing oil and gas or other substances covered hereby in paying quantities, but such well or wells are either shut-in or production therefrom is not being sold by Lessee for a period of 90 consecutive days, then Lessee may pay shut-in royalty of one dollar per acre of land then covered by this lease, such payment to be made to Lessor on or before the end of said 90-day period and thereafter on or before each anniversary of the end of said 90-day period while the well or 3 wells are shut-in and it shall be considered that such well is producing paying quantities for all purposes hereof during any period for which shut-in royalty is tendered; provided that if this lease is otherwise being maintained by the payment of rentals or by operations, or if a well or wells on the leased premises is producing in paying quantities, no shut-in royalty shall be due until the end of the 90-day period next following the end of the rental period or the cessation of such operations or production, as the case may be. (Leases ¶ 3(c) (emphases added).) Although there were a number of old wells on the leased land, none was producing at the time EnerQuest acquired the Leases in 2008. (Dkt. # 126 Ex. G at 2–3.) For almost two years, EnerQuest made no attempt to produce oil or gas from the Leases. On June 2, 2010, however, EnerQuest ran a diagnostic test on an old oil well. (Id. Ex. K at 10–11.) That well was originally completed in 1961 and had been shut in by the prior operator approximately four years prior to the diagnostic test. (Dkt. # 122 Ex. F ¶ 6.) During the production test, the well produced about 47,000 cubic feet of gas. (Id. Ex. F ¶ 7.) After approximately nine hours, its pressure and flow rate dropped too low to measure. (Dkt. # 113 Ex. I at 13.) Once the test was completed, the well was shut in. (Dkt. # 122 Ex. E ¶ 12.) On June 3, 2010, EnerQuest changed out the wellhead and several valves. (Id. Ex. K at 6–7.) Based on the results of the June 2, 2010 test, EnerQuest reclassified the old oil well as a gas well, renamed it the Brysch No. 1 Well (the “Well”), and pooled the Leases’ acreage into a single gas unit. (Dkt. # 122 Ex. C.) EnerQuest 4 performed no additional operations on the Well before the Leases’ two-year primary terms expired on July 28, 2010, and August 4, 2010. (Dkt. # 122 at 5.) On September 10, 2010, the Brysches’ attorney sent a letter to EnerQuest’s president, Greg Olson, stating that the Leases had terminated. (Dkt. # 126 Ex. C at 1.) On September 14, 2010, EnerQuest attempted to pay shut-in royalties to the Mineral Owners (Dkt. # 126 Ex. D at 1; Dkt. # 122 Ex. E ¶¶ 15–18), arguing that the Well, while not actually producing, was “capable of producing in paying quantities” within the meaning of the shut-in well provision excerpted above (Dkt. # 122 Ex. E ¶¶ 13, 20; Dkt. # 126 Ex. L at 1). Believing that the Leases had expired, the Mineral Owners signed new leases with Dan Hughes Company, L.P. (“Dan Hughes”) a few weeks later. (Dkt. # 122 Exs. G–N.) In November of 2010, Dan Hughes assigned half of its interest in the new leases to Defendant EOG Resources, Inc. (“EOG”) and sold the remainder to Defendant Plains Exploration and Production Company (“PXP”). (Dkt. # 131 Exs. N, O.) In April 2011, EnerQuest—still maintaining that the Leases had not expired because it had timely tendered shut-in royalties—paid $84,000 to connect the Well to a pipeline so that its gas could be marketed. (Dkt. # 126 Ex. F at 1–2; id. Ex. G at 8.) Then, in early July 2011, EnerQuest began producing the well using unassisted intermittent flow. (Dkt. # 126 Ex. H at 6.) From July 20 to 22, 5 2011, EnerQuest acid washed and swabbed the Well’s tubing. (Id. at 11.) In January 2012, EnerQuest installed a rod pump, which enhanced and stabilized production. (Dkt. # 122 Ex. F ¶ 12.) On June 1, 2012, EnerQuest and Chieftain filed this lawsuit against PXP, EOG, and the Mineral Owners, bringing claims for breach of EnerQuest’s leases, trespass to try title, removal of cloud on title, and declaratory relief. (Dkt. # 1 ¶¶ 33–41.) PXP and EOG brought counter-claims for trespass, trespass to try title, conversion, and declaratory relief (Dkt. # 32 ¶¶ 62–65; Dkt. # 33 ¶¶ 62– 66); and the Mineral Owners brought counter-claims for bad-faith pooling, trespass, conversion, breach of contract, suit to quiet title, and declaratory relief (Dkt. # 31 ¶¶ 66–74). EnerQuest later amended its complaint to include additional claims against EOG that stem from an alleged seismic trespass. (See SAC ¶¶ 43– 49.) On June 3, 2013, PXP filed the Opposed Motion to Sever that is now before the Court. (Dkt. # 105.) Also before the Court are EnerQuest’s Opposed Motion for Leave to File Third Amended Complaint, which was filed on June 10, 2013 (Dkt. # 107); a number of cross-Motions for Partial Summary Judgment on the issue of whether EnerQuest’s leases terminated at the end of their primary terms or remain in effect (Dkt. ## 113, 122, 124, 126); and PXP’s Motion for Partial Summary Judgment on Plaintiffs’ Claims for Seismic Trespass, Assumpsit, 6 and Right to Exclusive Possession of Seismic Information and Injunctive Relief (Dkt. # 125). LEGAL STANDARD Summary judgment is granted under Federal Rule of Civil Procedure 56 when “the movant shows that there is no genuine dispute as to any material fact and the movant is entitled to judgment as a matter of law.” Fed. R. Civ. P. 56(a); see also Cannata v. Catholic Diocese of Austin, 700 F.3d 169, 172 (5th Cir. 2012). The main purpose of summary judgment is to dispose of factually unsupported claims and defenses. Celotex Corp. v. Catrett, 477 U.S. 317, 323–24 (1986). The moving party bears the initial burden of demonstrating the absence of any genuine issue of material fact. Id. at 323. If the moving party meets this burden, the non-moving party must come forward with specific facts that establish the existence of a genuine issue for trial. ACE Am. Ins. Co. v. Freeport Welding & Fabricating, Inc., 699 F.3d 832, 839 (5th Cir. 2012). In deciding whether a fact issue has been created, “the court must draw all reasonable inferences in favor of the nonmoving party, and it may not make credibility determinations or weigh the evidence.” Reeves v. Sanderson Plumbing Prods., Inc., 530 U.S. 133, 150 (2000). However, “[u]nsubstantiated assertions, improbable inferences, and unsupported speculation are not sufficient to defeat a motion for summary judgment.” Brown v. City of Houston, 337 F.3d 539, 541 7 (5th Cir. 2003). “Where the record taken as a whole could not lead a rational trier of fact to find for the non-moving party, there is no ‘genuine issue for trial.’” Matsushita Elec. Indus. Co., Ltd. v. Zenith Radio Corp., 475 U.S. 574, 587 (1986) (quoting First Nat’l Bank of Ariz. v. Cities Serv. Co., 391 U.S. 253, 289 (1968)). DISCUSSION I. The Parties’ Cross-Motions for Partial Summary Judgment on Claims Related to EnerQuest’s Leases EnerQuest’s Second Amended Complaint brings, inter alia, claims for breach of lease and trespass to try title, suit to remove cloud and quiet title, and a request for a declaration “that the Brysch Lease and the Moy Lease are valid and effective and that the Dan Hughes Leases are invalid and of no effect.” (SAC ¶¶ 35–42.) The Parties agree that these claims all turn on whether or not EnerQuest successfully maintained the Leases beyond their two-year primary terms, and they have filed cross-motions for partial summary judgment on this issue. (Dkt. ## 113 (PXP’s motion), 122 (EnerQuest’s motion), 124 (EOG’s motion (joining and adopting PXP’s motion)), 126 (Mineral Owners’ motion).) EnerQuest seeks summary judgment “declaring that Plaintiffs have maintained the Leases . . . by tendering shut-in royalty payments to the Lessors and by thereafter producing gas in paying quantities.” (Dkt. # 122 at 2.) Defendants insist that the Leases expired at the end of their primary terms because EnerQuest did not 8 properly invoke the Leases’ shut-in royalty clauses. (Dkt. # 113 at 1; Dkt. # 126 at 1; Dkt. # 124 at 2.) Specifically, EOG and PXP assert that EnerQuest’s tender of shut-in royalties was ineffective because the Well was incapable of producing in paying quantities. (See Dkt. # 113 at 1; Dkt. # 124 at 2.) The Mineral Owners separately assert that shut-in royalties were ineffective both because the Well was incapable of production in paying quantities and because those royalties were untimely tendered. (See Dkt. # 126 at 1.) For the reasons that follow, the Court concludes that there is a genuine issue of material fact as to whether the Well was capable of production in paying quantities when it was shut in and that summary judgment on that issue is therefore inappropriate. However, the Court concludes that there is no genuine dispute as to whether shut-in royalties were timely tendered: They were not, and the Leases therefore expired at the end of their primary terms. A. Background on Texas Oil and Gas Leases A Texas mineral lease grants a fee simple determinable to the lessee. Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002). “Consequently, the lease may continue indefinitely, as long as the lessee uses the land for its intended purpose,” but it “will automatically terminate if the event upon which it is limited occurs.” Id. (citing Tex. Co. v. Davis, 254 S.W. 304, 306 (Tex. 1923)). 9 A lease’s habendum clause defines the mineral estate’s duration. See id.; Grinnell v. Munson, 137 S.W.3d 706, 714 (Tex. App. 2004). “[A] typical habendum clause states that the lease lasts for a relatively short fixed term of years (primary term) and then ‘as long thereafter as oil, gas or other mineral is produced’ (secondary term).” Anadarko, 94 S.W.3d at 554; accord Grinnell, 137 S.W.3d at 714. During the short primary term, the lessee generally conducts the necessary operations to complete a well whose production will hold the lease into the secondary term. See AFE Oil and Gas, L.L.C. v. Armentrout, 2-07-100-CV, 2008 WL 623980, at *2 (Tex. App. Mar. 6, 2008) (citing Fox v. Thoreson, 398 S.W.2d 88, 91 (Tex. 1966)); Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law Abridged Fifth Edition [hereinafter Williams & Meyers, Oil and Gas Law Abridged Ed.] § 812 (LexisNexis Matthew Bender 2013). Many modern leases contain drilling and rental clauses that require the lessee to commence drilling operations within a certain period of time or to make additional payments—known as “delay rentals”—to maintain the lease without drilling. See Williams & Meyers, Oil and Gas Law Abridged Ed. §§ 601.5, 605; In re Estate of Slaughter, 305 S.W.3d 804, 811 (Tex. App. 2010) (“‘Delay rental’ is defined as ‘a periodic payment made by an oil-and-gas lessee to postpone exploration during the primary lease term.’” (quoting Black’s Law Dictionary 1411)). Delay rental 10 clauses provide both a time period covered by each payment (usually one year) and the amount due at the beginning of each period. See Williams & Meyers, Oil and Gas Law Abridged Ed. § 606. A typical “unless”-type delay rental clause1 reads as follows: 3. Rental Payment. If on or before the first anniversary date hereof operations for the drilling of a well for oil or gas or other substances covered hereby have not been commenced on the leased premises or lands pooled or unitized therewith, or if there is no production in paying quantities from the leased premises or lands pooled or unitized therewith, then . . . this lease shall terminate as to both parties unless lessee on or before that date pays or tenders to lessor or to lessor's credit in [name of bank] at [address of bank], . . . the sum of $[dollar amount of sum] as rental covering the privilege of deferring the commencement of operations for the drilling of a well for a period of [number of months] months from said anniversary date . . . . 6 West’s Tex. Forms, Minerals, Oil & Gas § 3:3 – Oil, gas and mineral lease— “Unless” form—With pooling provision—Modern form (emphases added); see also Williams & Meyers, Oil and Gas Law Abridged Ed. § 605.2 (explaining that such a clause “commonly . . . begins with a statement introduced by the word ‘if’ concerning some supposition as to operations or production, followed by a provision for the termination of the lease unless certain rentals are paid”). In general, if a lessee has not achieved actual production by the end of the primary term, or if actual production ceases during the secondary term—which lasts “as long as oil or gas is produced”—the lease automatically terminates. 1 Another common type of delay rental clause, which is not relevant to the present case, is an “or”-type rental clause. 11 Anadarko, 94 S.W.3d at 554. However, to avoid termination of a non-producing lease, most modern leases contain savings clauses such as “shut-in royalty” clauses. See Williams & Meyers, Oil and Gas Law Abridged Ed. § 605.2. A shut-in royalty clause allows a lessee to extend a lease beyond the primary term by paying a specified royalty if the well is capable of producing oil or gas but is not actually doing so—that is, if the well is “shut in.” See Marifarms Oil & Gas, Inc. v. Westhoff, 802 S.W.2d 123, 125 (Tex. App. 1991) (“[A] lease will not terminate for lack of production if the shut-in clause is complied with.”); 55 Tex. Jur. 3d Oil and Gas § 283 (“The basic function of [shut-in royalty] clauses is to enable leases to continue in operation by virtue of the existence of wells capable of, but not actually engaged in, production.”). In other words, shut-in royalty clauses define the circumstances under which a lessee can “bring about constructive or contractual production” sufficient to keep the lease in effect after the expiration of the primary term. Gulf Oil Corp. v. Reid, 161 Tex. 51, 58 (1960). “Because payment of a shut-in royalty is a substitute for production that keeps the lease in effect, failure to make a timely shut-in payment is the equivalent of cessation of production, and the lease automatically terminates.” Amber Oil & Gas Co. v. Bratton, 711 S.W.2d 741, 743 (Tex. App. 1986) (citing Freeman v. Magnolia Petroleum Co., 141 Tex. 274, 278 (1943)). “The rule is generally applied rigidly against the lessee because time is of the essence in an oil 12 and gas lease.” Amber Oil, 711 S.W.2d at 743; see also Fain Family First Ltd. P’ship v. EOG Res., Inc., No. 02-12-00081-CV, 2013 WL 1668281, at *3 (noting that “[c]ourts construe shut-in royalty clauses strictly”). Thus, while “courts may generally be opposed to the construction which causes automatic termination, . . . the policy behind that rule does not apply to leases for oil and gas,” the main purpose of which is “to obtain production.” Riley v. Meriwether, 780 S.W.2d 919, 923 (Tex. App. 1989) (citing Williams & Meyers, 3 Oil and Gas Law § 604 (1989)); see also Woodson Oil Co. v. Pruett, 281 S.W.2d 159, 164 (Tex. Civ. App. 1955) (“There is no principle of forfeiture involved when a lease is terminated by its own provisions for cessation of production.”). B. Relevant Provisions of the Leases at Issue The Leases’ habendum clauses were identical and provided as follows: 2. Term of Lease. This lease shall be in force for a primary term of 2 years from the effective date hereof, and for as long thereafter as a covered mineral is produced in paying quantities from the leased premises or this lease is otherwise maintained in effect pursuant to the provisions hereof. (Leases ¶ 2.) The Leases also contained shut-in royalty clauses, which stated, in relevant part: [I]f, during or after the primary term one or more wells on the leased premises or lands pooled therewith are capable of producing oil and gas or other substances covered hereby in paying quantities, but such well or wells are either shut-in or production therefrom is not being sold by Lessee for a period of 90 consecutive days, then Lessee may 13 pay shut-in royalty of one dollar per acre of land then covered by this lease, such payment to be made to Lessor on or before the end of said 90-day period and thereafter on or before each anniversary of the end of said 90-day period while the well or wells are shut-in and it shall be considered that such well is producing paying quantities for all purposes hereof during any period for which shut-in royalty is tendered; provided that if this lease is otherwise being maintained by the payment of rentals or by operations, or if a well or wells on the leased premises is producing in paying quantities, no shut-in royalty shall be due until the end of the 90-day period next following the end of the rental period or the cessation of such operations or production, as the case may be. (Leases ¶ 3(c) (emphases added).) C. There Is a Genuine Issue of Material Fact as to Whether the Well Was Capable of Production in Paying Quantities As explained above, a shut-in royalty clause allows a lessee to avoid termination of the lease only if: (1) shut-in royalties are timely tendered and (2) the well was capable of producing oil or gas in paying quantities at the time shut-in royalties were tendered. See Hydrocarbon Mgmt., Inc. v. Tracker Exploration, Inc., 861 S.W.2d 427, 432–33 (Tex. App. 1993) (“[F]or a well to be maintained by the payment of shut-in royalties, it must be capable of producing gas in paying quantities . . . .”); 55 Tex. Jur. 3d Oil and Gas § 283 (“The basic function of [shut-in royalty] clauses is to enable leases to continue in operation by virtue of the existence of wells capable of, but not actually engaged in, production.”). The phrase “capable of production in paying quantities” sets up a two-prong test. First, the well must be “capable of production,” meaning that “if 14 the well is turned ‘on,’ . . . it begins flowing, without additional equipment or repair.” Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 558 (Tex. 2002) (emphasis added) (quoting Hydrocarbon Mgmt., Inc. v. Tracker Exploration, Inc., 861 S.W.2d 427, 433–34 (Tex. App. 1993)). A well would not be considered capable of production “if the well switch were turned ‘on,’ and the well did not flow, because of mechanical problems or because the well needs rods, tubing, or pumping equipment.” Id. (quoting Hydrocarbon, 861 S.W.2d at 433). Second, the well must be capable of producing in “paying quantities,” which means there must be “facilities located near enough to the well that it would be economically feasible to establish a connection so that production could be marketed at a profit.” Id. at 559 (emphasis added). Any profit, “even small, over operating expenses,” is sufficient to satisfy this test, even though the lessee “may never repay its costs, and the enterprise as a whole may prove unprofitable.” Clifton v. Koontz, 160 Tex. 82, 89 (1959); see also Blackmon v. XTO Energy, 276 S.W.3d 600, 603 (Tex. App. 2008) (“[T]he ‘paying quantities’ part of the definition requires that income from the sale of the gas must exceed production and marketing costs.” (citing Anadarko, 94 S.W.3d at 559)). Thus, to determine whether the Well was capable of production in paying quantities at the time EnerQuest tendered shut-in royalties, both of the following questions must be answered in the affirmative: (1) Would the Well have 15 “produced,” without additional equipment or repair, if it had been turned “on”? And (2) would EnerQuest have been able to market the oil or gas produced at a profit? For the reasons that follow, the Court concludes that there is a genuine issue of material fact as to whether the Well was capable of production in paying quantities. 1. Would the Well Have “Produced” If It Had Been Turned On? The Parties agree about the condition the Well was in at the end of the Leases’ primary terms; they disagree about whether a well in that condition should be considered “capable of production.” Specifically, the Parties disagree as to whether the lack of surface facilities is a relevant factor in this analysis. EnerQuest argues that surface facilities are not relevant: “‘Capable’ of production,” insists EnerQuest, “does not contemplate actual production and focuses only on the well, requiring that it be fully equipped and operational, but not requiring that all equipment downstream from the well be in place and operational . . . .” (Dkt. # 122 at 8 (emphases added).) “[T]he undisputed evidence,” EnerQuest argues, “establishes that the Well itself was fully equipped and would have produced gas when Plaintiffs shut it in.” (Dkt. # 119 at 4.) “[T]he only equipment missing when the Well was shut in was a separator, meter run, and flowline, and . . . the foregoing equipment is all located on the surface on the Well and not in the Well.” (Id.) The purpose of a shut-in royalty clause, says 16 EnerQuest, is “to permit the lessee to negotiate a contract for produced gas and, if successful in doing so, to give the lessee time to repair, install, or construct surface equipment to treat the produced minerals and transport them to a nearby pipeline.” (Id.) “This is precisely what Plaintiffs did during the time they shut-in the Well.” (Id.) In support of this argument, EnerQuest cites Blackmon v. XTO Energy, 276 S.W.3d 600 (Tex. App. 2008). (See Dkt. # 133 at 8–9.) In that case, the court rejected the lessors’ contention that the well at issue was not capable of producing in paying quantities because the lessee “could not sell the gas flowing from the well without installing the amine processing unit to satisfy the carbon dioxide requirements of [its contract].” Id. at 603. Citing Anadarko, the lessors had argued that the well at issue “was not capable of production in paying quantities ‘because it needed additional equipment or repairs in order to produce marketable gas.’” Id. However, the Blackmon court disagreed, insisting that “[t]he focus is on whether the well is capable of producing gas in a marketable quantity, not a marketable quality.” Id. Finding that “raw gas was capable of flowing from the wellhead . . . in a marketable quantity,” the Blackmon court concluded that the well was “capable of producing in paying quantities when it was shut in.” Id. In the instant case, argues EnerQuest, the Well itself was complete 17 and functional, and the fact that surface equipment “downstream” from the Well was missing is irrelevant. (Dkt. # 119 at 3.) Defendants, of course, disagree. First, they argue that, “in order to ‘produce’ a well, the operator must actually take oil or gas from the well in a captive state for either storing or marketing the product for sale.” (Dkt. # 126 ¶ 26 (citing Riley v. Meriwether, 780 S.W.2d 919, 923 (Tex. App. 1989).) “‘[P]roduce’ means more than spilling raw hydrocarbons onto the ground or venting them into the atmosphere,” insist Defendants. The Well was not equipped with a separator (which separates oil, gas, and water), a meter run (a gas measurement device), or a flowline (which connects these pieces of equipment) when the Leases’ primary terms expired (id. Ex. K at 9, 14–20), but Defendants insist that a well must have these surface facilities in order to be capable of production. Without a tank, oil and condensate could not be stored. (Id. at 19.) Without a separator, gas could not be purified into marketable form. (Id. at 18–19.) The test is not whether gas would have begun “flowing” if turned on, say Defendants; it is whether the Well would have “produced”—and “production” means marketable oil or gas. (Dkt. # 128 ¶ 32.) While Defendants acknowledge that a well “does not actually have to be hooked up to a commercial pipeline in order to be capable of producing in paying quantities,” they insist that it “must have everything needed to produce once connected, so that when it is connected and switched on, it can immediately begin 18 producing.” (Id. ¶ 34.) Because the Well was not capable of capturing gas and reducing it to a marketable state, argue Defendants, it was not capable of “production” at the end of the Leases’ primary terms. (Id. ¶¶ 33–34.) In support of their argument, Defendants explain that the word “production” has different meanings in different contexts. (Dkt. # 126 ¶¶ 28–31.) In the royalty context, where a royalty is generally defined as a share of the “production” from a lease, Texas courts have held that “production costs” are “the expenses incurred in exploring for mineral substances and in bringing them to the surface.” Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 444 (Tex. App. 2006) (emphasis added) (citing Parker v. TXO Prod. Corp., 716 S.W.2d 644, 648 (Tex. App. 1986)). “Post-production costs,” on the other hand, include “taxes, treatment costs to render the gas marketable, compression costs to make it deliverable to a purchaser’s pipeline, and transportation costs.” Id.; see also Heritage Res., Inc., 939 S.W.2d at 122 (“Post-production marketing costs include transporting the gas to the market and processing the gas to make it marketable.”). In other words, Defendants acknowledge that, in the royalty context, “production” does end at the wellhead. (Dkt. # 126 ¶ 29.) By contrast, argue Defendants, in the context of determining whether a lease’s habendum clause is satisfied because the well is “producing,” Texas courts have used a different definition: “The word ‘production’ means marketable 19 oil or gas.” Rogers v. Osborn, 152 Tex. 540, 542 (Tex. 1953) (emphasis added) (citing Garcia v. King, 139 Tex. 578 (1942)); see also Holchak v. Clark, 284 S.W.2d 399, 401 (Tex. Civ. App. 1955) (“Production has a commercial connotation. It means marketable oil or gas.” (emphasis added)). In other words, production requires that the oil or gas (1) be taken from the well “in a captive state” (2) for storage or marketing. See, e.g., Ice Bros., Inc. v. Bannowsky, 840 S.W.2d 57, 60 (Tex. App. 1992) (explaining that, in order to show that the well had “produced,” there had to be “some evidence . . . that first, gas was being taken from the Brookshier Well in a captive state, and second, that the gas so taken was either stored or marketed” (emphases added)); Riley v. Meriwether, 780 S.W.2d 919, 923 (Tex. App. 1989) (“Production of a well involves actually taking oil or gas from the well in a captive state for either storing or marketing the product for sale.” (emphasis added)); 2-26 Kuntz, Law of Oil and Gas § 26.6 (noting that “[i]n Texas, production of gas requires that it be taken from the well in a captive state and either marketed or stored” (emphasis added)). The Blackmon court determined that “production” was complete at the wellhead, Defendants insist, because it inadvertently overlooked the distinction between “production” in the context of royalty payments and “production” in the context of habendum and shut-in royalty clauses. (Dkt. # 126 ¶¶ 28–29.) In the context of habendum and 20 shut-in royalty clauses, say Defendants, “capable of production” means capable of taking marketable oil or gas. (Id. ¶ 29.) While Defendants’ argument is attractive in certain respects, the Court is not convinced that the definition they propose is consistent with Anadarko and Hydrocarbon—or that it would be a workable standard in practice. First, as EnerQuest notes, both Anadarko and Hydrocarbon focus on the well itself— whether the well needs additional equipment or repair—rather than on surface equipment: We believe that the phrase “capable of production in paying quantities” means a well that will produce in paying quantities if the well is turned “on,” and it begins flowing, without additional equipment or repair. Conversely, a well would not be capable of producing in paying quantities if the well switch were turned “on,” and the well did not flow, because of mechanical problems or because the well needs rods, tubing, or pumping equipment. Anadarko Petroleum Corp., 94 S.W.3d at 558 (emphases added) (quoting Hydrocarbon, 861 S.W.2d at 433–34). The term “well,” in turn, is defined as the “‘orifice in the ground made by drilling, boring or any other manner, from which any petroleum or gas is obtained or obtainable . . . .’” Petro Pro, Ltd. v. Upland Res., Inc., 279 S.W.3d 743, 751 (Tex. App. 2007) (quoting Williams & Meyers, Oil and Gas Law, Manual of Terms, 107, 1207 (9th ed. 1998)); see also Kothman v. Boley, 308 S.W.2d 1, 3 (Tex. 1957) (“A well is a shaft or hole bored or sunk in the earth through which the presence of minerals may be detected and their 21 production obtained.”). Consistent with this definition, all of the equipment Anadarko and Hydrocarbon mention as being necessary for a well to be capable of production—rods, tubing, and pumping equipment—are part of the well itself, not separate surface equipment. See Anadarko Petroleum Corp., 94 S.W.3d at 558; Hydrocarbon, 961 S.W.2d at 433–34. Had those courts intended to promulgate the standard Defendants propose—and had they understood the term “well” to encompass more than the definitions given above—they easily could have said something like: “We believe that the phrase ‘capable of production in paying quantities’ means a well that will capture paying quantities of marketable oil or gas if the well is turned ‘on,’ and it begins flowing, without additional equipment or repair.” In the same vein, they easily could have included among the examples of necessary equipment a piece of surface equipment, such as a tank, a separator, or any other equipment necessary to treat, measure, or transport oil or gas. However, neither court did so. Instead of focusing on whether oil or gas could be “captured” or made “marketable,” both courts agreed that the test was whether oil or gas would “flow” when the well was turned on, a choice of words that confirms that the relevant inquiry is whether the well is equipped to permit gas to flow from the wellhead. See Blackmon, 276 S.W.3d at 603 (explaining that “the Anadarko definition focuses on equipment or repairs necessary for raw gas to flow from the 22 wellhead when the switch is turned ‘on’ rather than on equipment installed downline to refine the raw product to marketable form equipment”). While Defendants acknowledge that a well need not be connected to a pipeline to be capable of production, they insist that “the well must have everything [else] needed to produce once connected, so that when it is connected and switched on, it can immediately begin producing.” (Dkt. # 128 ¶ 34 (emphasis added).) However, Defendants cite no authority for this proposition. Nor do Defendants provide a compelling explanation for why their strict, all-inclusive requirement—“everything needed to produce”—should not include a pipeline connection. A well cannot actually produce gas without pipeline facilities,2 yet Anadarko clearly holds that pipeline is not among the equipment that must be present and in working order when a well is shut in. See 94 S.W.3d at 553, 558; see also id. at 558 (citing Peveto v. Starkey, 645 S.W.2d 770, 771 (Tex. 1982), for the proposition that “a well is capable of production if it is shut-in because there is no available pipeline” (emphasis added)). The Court can discern no relevant distinction between pipelines and other surface facilities designed to treat and transport oil and gas obtained from a well; nor does the Court have any reason to think that the Anadarko court was drawing a line at “everything needed to 2 Oil is of such a nature that it need not be transported to market through a pipe line; it may be taken from the ground and stored in tanks to await shipment to market. However, the only storage for gas is the stratum in which it is found. See Joseph Shade, Primer on the Texas Law of Oil and Gas 51 (4th ed. 2008). 23 produce—except pipelines” rather than drawing that line at the wellhead, requiring only that the well itself be fully equipped and operational. Defendants argue that “logic” weighs against the Blackmon court’s interpretation of “capable of production,” because “[i]f a well can be said to ‘produce’ for the purposes of a habendum clause or a savings clause simply because raw hydrocarbons emerge from its wellhead when it is opened, then a lessee could preserve a lease beyond its primary term by venting marketable quantities of unmarketable raw gas into the atmosphere . . . .” (Dkt. # 126 ¶ 30.) However, Defendants’ standard (“everything needed to produce—except pipelines”) is vulnerable to a similar criticism, the only difference being that the gas wasted would be marketable. In the Court’s view, logic and policy considerations weigh in favor of the standard proposed by EnerQuest and applied by the court of appeals in Blackmon. Actual production is a complicated process involving, among other things, opening numerous valves, setting choke sizes, and using separators, compressors, heater treaters, dehydration units, line heaters, and other devices. Applying Defendants’ standard would mean that if there were a failure at any of the many points in this complex chain, anywhere before the gas entered the pipeline, a well would be in need of “repair” and would be declared incapable of production. See Anadarko Petroleum Corp., 94 S.W.3d at 558 (explaining that a 24 well is incapable of production if it needs “additional equipment or repair”). As an extreme example, if even a simple fuse were to blow on the well, and if that fuse could not be repaired for ninety days (due to weather conditions, lack of an appropriate part to repair the fuse, or lack of knowledge of the problem), the lease would terminate. The Court doubts that this is the standard the Supreme Court of Texas meant to impose in Anadarko. The realities of gas production also support this conclusion, because it is often undesirable to install certain surface equipment until a pipeline hookup has been secured. (See Dkt. # 126 Ex. H (“Smith Report”) at 5 (explaining that there may be “dependencies between production facility construction and pipeline connection” such that it “may not make sense to construct facilities until the date of connection can be estimated with reasonable certainty”).) For example, different pipelines have different pressure requirements, and operators must install specialized equipment to meet those requirements. See Ashleigh L. Boggs, Anadarko Petroleum Corp. v. Thompson: Interpretation of Oil and Gas Lease Habendum Clauses in Texas and Why Oklahoma Should Maintain Its Divergent Approach to Keep Leases Alive, 61 Okla. L. Rev. 341, 365 (2008). If a gas well’s pressure is lower than the line’s required pressure, a piece of equipment known as a compressor must be attached so the gas may be transported through the pipeline and marketed. Id. By contrast, if the well’s pressure is higher than the line’s 25 threshold, the operator must install equipment to regulate the pressure. Id. Under either scenario, the operator cannot determine which equipment, if any, is required until it knows the pipeline requirements. Id. More generally, an operator may not wish to install surface equipment merely to have it sit idle in the field, risking weather damage or theft, while the well is shut in. In light of the foregoing, the Court concludes that the lack of surface facilities, or the fact that surface facilities may need repair, does by itself not render a well incapable of production. In so concluding, the Court approves of and follows the decision of the Tenth Court of Appeals in Blackmon. See Blackmon, 276 S.W.3d at 603 (holding that a well was capable of producing in paying quantities despite lacking an amine processing unit because “raw gas was capable of flowing from the wellhead . . . in a marketable quantity”); accord Levin v. Maw Oil & Gas, LLC, 290 Kan. 928, 948, 234 P.3d 805, 819 (2010) (“Under Kansas case law . . . , the factors to be considered by the factfinder in determining whether a well is physically complete and capable of producing in paying quantities, i.e., shut-in, are those that affect the properties and potential of the well itself, rather than the likely success of any processing or transport of product that remains to be attempted or accomplished.” (emphases added)). 26 2. Would the Well Have Produced in “Paying Quantities”? Defendants insist that even if the Well was not rendered incapable of production by the lack of surface facilities, it was not capable of production “in paying quantities,” because “its potential production was too meager to justify the cost of connecting it to a pipeline.” (Dkt. # 126 ¶ 23; accord Dkt. # 128 ¶¶ 39–43.) EnerQuest, by contrast, insists that it is entitled to summary judgment on this issue because there is no genuine dispute that the Well was capable of production in paying quantities. (Dkt. # 122 at 10.) However, while the Parties suggest that no material facts are in dispute,3 the Court disagrees: There is a genuine dispute of material fact as to whether the Well was capable of yielding a profit over a “reasonable period of time” and as to whether a reasonably prudent operator would have continued to operate the Well in the manner in which it was operated. i. “Paying Quantities” Analysis To determine whether a well is producing in paying quantities, a court must first ascertain “whether the production yields a profit after deducting operating and marketing costs . . . .” Evans v. Gulf Oil Corp., 840 S.W.2d 500, 503 (Tex. App. 1992) (emphasis added) (citing Pshigoda v. Texaco, Inc., 703 S.W.2d 416, 418 (Tex. App. 1986); Ballanfonte v. Kimbell, 373 S.W.2d 119, 120– 3 The Court notes that each party asserts that there are no material facts in dispute with the assumption that the facts as they have stated them in their favor are correct. 27 21 (Tex. Civ. App. 1963)). Included among operating costs are “fixed or periodic cash expenditures incurred in the daily operation of a well,” such as taxes, overhead charges, labor, repairs, depreciation on salvable equipment, if any, and other such items of expense, if any.” Pshigoda v. Texaco, Inc., 703 S.W.2d 416, 418 (Tex. App. 1986) (citing Skelly Oil Co., 356 S.W.2d at 781). Marketing costs include the cost of connecting the well to a pipeline. See Archer v. Skelly Oil Co., 314 S.W.2d 655, 663 (Tex. App. 1958) (concluding that “the expense of pipe line facilities is part of the operating and marketing expense”); see also Anadarko, 94 S.W.3d at 559 (“[T]here must be facilities located near enough to the well that it would be economically feasible to establish a connection so that production would be marketed at a profit.” (emphasis added)); Hanks, 24 S.W.2d at 6 (holding that there was no evidence that a well was capable of production in paying quantities where there was “[no] evidence tending to show that the well was situated in such proximity to any prospective market which would justify the construction of a pipe line for marketing same” (emphasis added)). Contra Pray v. Premier Petroleum, Inc., 233 Kan. 351, 357 (1983) (explaining that under Kansas law, “[p]ipeline costs fall in the same category as costs of drilling and equipping a well” and “should not be taken into account” when determining whether a well will produce in paying quantities). On the other hand, “one-time investment expenses, such as drilling 28 and equipping costs[,] are to be treated as capital expenditures” and are not to be counted against income. Pshigoda, 703 S.W.2d at 418. “There is no arbitrary period, ‘whether it be days, weeks, or months, to be considered in determining’” whether a well has yielded a profit. Peacock v. Schroeder, 846 S.W.2d 905, 909 (Tex. App. 1993) (citing Clifton, 325 S.W.2d at 690). “Rather, profitability is to be determined over ‘a reasonable period of time under the circumstances.’” Id. (citing Clifton, 325 S.W.2d at 691; Pshigoda, 703 S.W.2d at 419); see also Dreher v. Cassidy Ltd. P’ship, 99 S.W.3d 267, 269 (Tex. App. 2003) (holding, where the well was not profitable for eight months, that the lessor was not entitled to summary judgment because it had “produced no evidence to show why the eight-month period was a reasonable period of time” over which to determine profitability). If the well’s production is sufficient to yield a profit, however small, over operating and marketing expenses—even though the cost of drilling the well may never be repaid—the test is satisfied and the inquiry ceases. Garcia, 164 S.W.2d at 511–12; Hydrocarbon Mgmt., Inc., 861 S.W.2d at 432 n.4. Even if a well has not yielded a profit over a reasonable period of time, a lease will not terminate for lack of production in paying quantities if a “prudent operator would continue, for profit and not for speculation, to operate the well as it has been operated.” Evans, 840 S.W.2d at 503 (emphasis added). In other words, to terminate a lease, a lessor must demonstrate both that the well has 29 not produced in sufficient quantities to yield a profit over a reasonable period of time and “that a reasonably prudent operator would not have continued under the circumstances in the attempts devoted to obtaining such production.” Cannon v. Sun-Key Oil Co., Inc., 117 S.W.3d 416, 422 (Tex. App. 2003) (citing Ballanfonte v. Kimbell, 373 S.W.2d 199, 120–21 (Tex. App. 1963)); see also Evans, 840 S.W.2d at 503 (explaining that to terminate a lease, both questions must be answered in the negative); Patton v. Rogers, 417 S.W.2d 470, 474 (Tex. App. 1967) (“[T]he law is well settled that even if a finding of no production in paying quantities is sustainable, in order to terminate the lease, there must also be a finding that a reasonably prudent operator would not have continued to operate the lease under the circumstances.”). Whether it is reasonable to expect profitable returns from a well is necessarily a fact-specific inquiry. As the court explained in Hanks v. Magnolia Petroleum Co., [w]hat might be determined to be gas in paying quantities in one well would not be so considered in another located in a different territory. A well producing much less gas than the one drilled by [the lessee] might be in paying quantities because of existing pipe line facilities furnishing a means of marketing the gas at a profit above the cost of operating the well. On the other hand, a well producing a large amount of gas drilled in territory remote from any market and without pipe line facilities might not be in paying quantities, unless it was shown that the amount of gas produced was sufficient to justify the construction of transportation facilities and the marketing of such gas would yield a return over and above the expense of providing the same. 30 24 S.W.2d at 6. Critically, when determining whether EnerQuest had “a reasonable basis for the expectation of profitable returns” from the Well, the relevant time period is the end of the Leases’ primary terms. See Hanks, 24 S.W.2d at 6–7 (“The burden was upon [the lessee] to prove that there was a reasonable expectation and probability of a market for the gas produced from his well at the time of its completion. The true test was as to whether the gas was in paying quantities under the conditions existing in 1909. The question could not properly be determined by the situation presented in 1923.”). If EnerQuest did not have a reasonable expectation of profitable returns from the Well at that time, based solely on the information available to it at the end of the Leases’ primary terms, the shut-in royalties were not effective, and the Leases automatically terminated for lack of production. ii. Potential Production and Revenue as of the End of the Leases’ Primary Terms EnerQuest asserts that “from its first month of production in July 2011 to September 2012, the Well produced a net profit to Plaintiffs of over $82,000.00, thus confirming the Well produced in paying quantities . . . .” (Dkt. # 122 at 15 (citing id. Ex. F).) However, the start of that period is over a year after the Well was shut in, and during that time EnerQuest performed work that increased the 31 Well’s production. In July 2011, for example, EnerQuest acidized and swabbed the wellbore, which more than doubled its rate of production. (See Dkt. # 122 Ex. F (“Smith Aff.”) Ex. 3; Dkt. # 128 Ex. H at 43–44.) In January of 2012, the Well’s production increased even more after—in the words of EnerQuest’s own expert—it “was worked over . . . to install a rod pump, and at the same time, replace the tubing string.” (Smith Report at 11; accord Dkt. # 113 Ex. I-28 at 3; Dkt. # 128 Ex. H at 45.) Again, the relevant question is whether the Well was capable of producing in quantities sufficient to recoup the cost of the pipeline hookup and other operating and marketing costs if it had produced long term in the state it was in at the end of the Leases’ primary terms, not what it was capable of producing after additional equipment was installed and repairs were performed at a later time. Basing this determination on the Well’s capability with additional equipment and after repairs would be inconsistent with Anadarko’s definition of “capable of production in paying quantities.” See Anadarko Petroleum Corp., 94 S.W.3d at 558 (“We believe that the phrase ‘capable of production in paying quantities’ means a well that will produce in paying quantities if the well is turned ‘on,’ and it begins flowing, without additional equipment or repair.” (emphases added)); id. (“To be ‘capable of producing gas,’ we conclude that a well must be capable of producing gas in paying quantities without additional equipment or repairs.” (emphasis added)). In other words, while the Court agrees with 32 EnerQuest that the Well was not rendered incapable of production merely because it lacked surface facilities, the paying-quantities analysis must still look to the quantities of oil and/or gas the Well would have produced if it had been turned “on” on the date it was shut in; its capability with additional equipment or repair is not relevant. By the time the Leases’ primary terms ended, EnerQuest had opened the Well one time and had performed a nine-hour deliverability test. (Dkt. # 122 Ex. F ¶ 7.) It had also changed out the wellhead and several valves. (Id. Ex. K at 6–7.) Had EnerQuest made no attempt to produce the Well after that time, the Court would be faced with the even more difficult task of speculating about what information a reasonable operator might have gleaned from the deliverability test and about how much operating and marketing costs may have been. However, even after the Mineral Owners asserted that the Leases had terminated, EnerQuest attempted to produce the Well, providing the Court with some evidence of the Well’s capabilities at the relevant time period. Specifically, in early July 2011, EnerQuest began intermittently producing the Well. (Dkt. # 126 Ex. I at 19; Smith Report at 6.) At this time, EnerQuest had installed surface facilities but had not yet made changes to the Well that would have increased its production. (Dkt. # 126 Ex. I at 19; Smith Report at 6.) 33 According to EnerQuest’s expert, S. Tim Smith, when EnerQuest produced the Well from July 7 to July 19, 2011, using intermittent unassisted flow, the Well produced oil and gas worth $696.41. (Smith Report at 14.) The Parties disagree about which of EnerQuest’s expenses should be included among the operating costs counted against this revenue. (Compare Smith Report at 14 (listing total operating expenses during this time period as $430.91), with Dkt. # 128 Ex. A (“Howell Aff.”) ¶¶ 8–10 (asserting that Smith incorrectly excluded from operating costs the charges from the consultant who supervised field work on the Well; the costs of treating the Well with acid; the costs of swabbing the Well, which allegedly would have had to occur every three months or so; the costs of attempting to install a plunger unit to stabilize production; and certain overhead costs).) However, even assuming that EnerQuest is correct and that total operating costs during that period were just $430.91, revenue exceeded operating costs by less than $21 per day. (See Smith Report at 14 (asserting that from July 7 to July 19, 2011, revenue exceeded operating costs by $265.50).) Of course, actual profit of even one dollar is sufficient to find as a matter of law that a well produced in paying quantities—but EnerQuest’s expert did not include the cost of the pipeline hookup in this tabulation. (See id.) Again, as EnerQuest concedes elsewhere (see Dkt. # 130 at 6–7), under Texas law pipeline costs fall into the category of marketing expenses that the lessee must be able to recoup within a reasonable 34 period of time. See Anadarko, 94 S.W.3d at 559; Archer, 314 S.W.2d at 663; Hanks, 24 S.W.2d at 6. If that $84,000 expense is taken into account, and if the Well was capable of producing enough oil and gas to exceed operating costs by just $21 per day, it would still have taken EnerQuest almost eleven years just to recoup the costs of the pipeline hookup ($84,000 ÷ $21/day ÷ 365 days/year = 10.96 years). Eleven years may well not be a reasonable period of time over which to recoup marketing and operating costs. This analysis is made even more complicated by the fact that the Well was capable of producing significantly more—and did in fact produce significantly more—after EnerQuest, from July 20 to 22, 2011, acid washed the tubing and swabbed to recover the wash residue. In an exhibit attached to his affidavit, EnerQuest’s expert, S. Tim Smith, presents figures demonstrating that the Well yielded over $27,000 in excess of operating expenses (not including pipeline costs) from July to December of 2011. (See Smith Aff. Ex. 3.) According to Defendants’ expert, Terry Payne, these washing and swabbing operations constituted a “workover” of the Well, and thus the Well’s capability after these operations (i.e., its capability after July 20, 2011) should not be considered in the paying-quantities analysis. (Dkt. # 113 Ex. I (“Payne Report”) at 12–13.) However, EnerQuest’s expert, S. Tim Smith, insists that “[a] workover is an operation requiring a material expense that results in . . . a material change to the 35 mechanical configuration of the wellbore” and that a swabbing operation does not constitute a workover because it “is a minor expense, and does not cause a mechanical change to the wellbore.” (Smith Report at 11.) Smith further explains that “[i]t would not make sense to perform the swabbing operation until it was time to produce the well lest it may have to be performed again.” (Id.) In other words, Smith insists that the Well’s production during this time should be considered evidence of what the Well was capable of producing at the time it was shut in. To place Smith’s testimony in the context of Anadarko’s holding, Smith appears to be arguing that the operation neither installed “additional equipment” nor constituted “repairs.” See Anadarko, 94 S.W.3d at 558. Whether the operations EnerQuest performed from July 20 to 22, 2011, constituted a “workover” of the Well is the first of a number of genuine issues of material fact that preclude summary judgment on the question of whether the Well was capable of production in paying quantities. If Defendants’ expert is to be believed, these were substantial operations that materially changed the way the Well operated. On the other hand, if EnerQuest’s expert is correct—if this is a minor operation, one that makes no mechanical changes to a well and that is generally not performed until a well is connected to a pipeline and ready to produce—then it would seem that the Well, at the time it was shut in, was “capable 36 of producing” the amount of gas that it did produce from July to December of 2011.4 Assuming that EnerQuest is correct and that the washing and swabbing operation did not constitute a “workover” of the Well, there is still a genuine issue of material fact as to whether EnerQuest would have recouped its operating and marketing costs within a “reasonable” period of time. At a rate of $27,000 every six months, EnerQuest would have recouped the cost of the pipeline hookup in approximately two years. But is this a “reasonable” period of time? The Court has no way of making that determination, because the Parties have presented no evidence as to what is a reasonable amount of time over which to recoup operating and marketing costs. Perhaps it is common for oil and gas companies not to recoup the cost of a pipeline hookup for five years. On the other hand, it may be that in the oil and gas industry there is consensus that a “reasonable” period of time to recoup such costs is, for example, a year or less. The Court simply cannot interpose its own view one way or the other without an adequate and credible foundation upon which to determine what constitutes a “reasonable” period of time. See Dreher, 99 S.W.3d at 269 (holding, where the well was not profitable for eight months, that the lessor was not entitled to 4 Even EnerQuest acknowledges that the Well “was worked over in January 2012 to install a rod pump, and at the same time, replace the tubing string.” (Smith Report at 11.) Accordingly, what the Well was capable of producing after that time is not relevant to the present inquiry. 37 summary judgment because it had “produced no evidence to show why the eight-month period was a reasonable period of time” over which to determine profitability). On the other hand, if Defendants are correct and the washing and swabbing operation constituted a workover of the Well, there is still a genuine issue of material fact as to whether a reasonably prudent operator would have continued to operate the well in the manner in which it was being operated. See Cannon, 117 S.W.3d at 421 (explaining that to terminate a lease a lessor must show both (1) that the lease failed to yield profit over reasonable period of time and (2) that a reasonably prudent operator would not have continued operations for the purpose of profit, as opposed to mere speculation). Defendants point to a series of emails in which EnerQuest’s president, Greg Olson, wrote that “the well [was] not capable of producing that much” and that “the well’s potential profit from existing production probably isn’t worth the cost of the facilities installation and pipeline hook-up, but at least the hook up will hold the lease.” (Dkt. # 126 Ex. F at 2.) Defendants argue that Olson’s admissions are “dispositive” and that they demonstrate that “his only justification for spending so much on a well then capable of producing so little was the speculative value holding [the] lease might have or which working over the Well might produce.” (Dkt. # 126 at 13.) However, the Court is not convinced that these statements are dispositive of the 38 issue: Olson made these statements while attempting to arrange a pipeline hookup and testified during his deposition that they were merely negotiation ploys, complaints that he thought might help him obtain a lower price. (Id. Ex. G at 4– 10.) Whether Olson is credible is a question for a jury, not for this Court. If the Well at issue had been located over a dry hole, there could be no doubt that a reasonably prudent operator would not have continued to attempt to produce oil and gas from it, and this prong of the test would favor Defendants. In reality, however, the Well was located over a large gas reserve, and EnerQuest did eventually achieve substantial production from it. EnerQuest’s expert testified that EnerQuest, based on the results of the June 2, 2010 production test, could reasonably have expected the Well to produce in paying quantities: After the June 2, 2010 production test, given the well performance and pressure build-up during the production test, existing agreements with Regency covering other wells in the area, the low pressure gas pipeline infrastructure in close proximity to the [Well], and the low cost of producing gas wells using an intermittent flow regime, EnerQuest had a reasonable basis for the expectation of a profit in excess of operating and marketing expenses once the [Well] could be connected to sales and allowed to produce. (Smith Aff. ¶¶ 7, 10.) Defendants’ experts disagree, of course. (See Payne Report at 10 (implying that the production test suggested the Well would not be capable of producing in paying quantities); Dkt. # 113 Ex. J (“Payne Aff.”) ¶¶ 11, 14 (same); Howell Aff. ¶¶ 8–10 (“I am not of the opinion . . . that any operator who wished to make a profit off the Well as it was on August 4, 2010, would have believed it to 39 be a reasonable investment.”).) But that is precisely why there is a genuine issue of material fact here: The Court cannot conclude with certainty that a reasonably prudent operator would or would not have continued to attempt to produce the Well after seeing the results of the June 2, 2010 production test. It is not at all clear, based on the conflicting evidence the Parties have presented, what a reasonably prudent operator would have done. Because there are a number of genuine issues of material fact— namely, (1) whether the work that EnerQuest performed on the Well in July of 2011 constituted a “workover” such that any production achieved after that workover should not be considered for purposes of this inquiry; (2) whether, if washing and swabbing did not constitute a workover, two years is a “reasonable” period of time over which to recoup marketing and operating expenses; and (3) whether, even if the Well was not actually capable of making a profit at that time, a reasonably prudent operator would nevertheless have continued to attempt to produce the Well—the Court DENIES EnerQuest’s, PXP’s, and EOG’s cross-motions for partial summary judgment on the issue of the Well’s capability of production in paying quantities. D. Shut-in Royalties Were Not Timely Tendered The Parties agree that EnerQuest first tendered shut-in royalties on September 14, 2010. The Parties also agree that, by the time EnerQuest tendered 40 the first shut-in royalty payments, the Leases’ two-year primary terms had in fact expired, and the Well had been shut in for 103 days. (Dkt. # 122 at 5.) What the Parties disagree about is whether payments made on September 14, 2010, were timely under the terms of the Leases. As discussed in more detail below, this question turns on whether the Leases provided that EnerQuest would prepay delay rentals to cover the Leases’ primary terms. If the answer is yes, EnerQuest had an additional ninety days following the expiration of the Leases’ primary terms to tender shut-in royalty payments. (See Leases ¶ 3(c) (providing that “if this lease is otherwise being maintained by the payment of rentals . . . no shut-in royalty shall be due until the end of the 90-day period next following the end of the rental period . . . .”).) If the answer is no—that is, if the Leases did not provide for delay rentals and EnerQuest therefore did not pay any—then EnerQuest was required to tender shut-in royalty payments by the end of the Leases’ primary terms, and the Leases terminated when it failed to do so. (See Dkt. # 122 at 12 (showing that the Leases’ primary terms ended on July 28, 2010, and August 4, 2010, and that EnerQuest tendered the first shut-in royalties on September 14, 2010).) For the reasons that follow, the Court concludes that the Lease did not provide for delay rentals, whether paid annually or up front, and that shut-in royalties were therefore due at the end of the Leases’ primary terms. 41 1. Principles of Lease Interpretation An oil and gas lease is a contract and must be interpreted as such. TSB Exco v. E.N. Smith, III Energy Corp., 818 S.W.2d 417, 421 (Tex. App. 1991). As with any contract, the ultimate goal in interpreting a lease is to determine the parties’ intent. Sun Oil Co. (Del.) v. Madeley, 626 S.W.2d 726, 727–28 (Tex. 1981); Kiewit Texas Min. Co. v. Inglish, 865 S.W.2d 240, 244 (Tex. App. 1993). When construing a lease to seek the intention of the parties, a court must consider all the provisions of the lease and use the applicable rules of construction to harmonize, if possible, those provisions that appear to conflict. Ogden v. Dickinson State Bank, 662 S.W.2d 330, 332 (Tex. 1983); Coker, 650 S.W.2d at 393. However, no single provision taken alone will be given controlling effect; rather, all the provisions must be considered with reference to the whole lease. Coker, 650 S.W.2d at 393. Because the parties to a lease intend every provision to have some effect, a court will not strike down any portion unless there is an irreconcilable conflict. Ogden, 662 S.W.2d at 332. “‘Whether a [lease] is ambiguous is a question of law that must be decided by examining the contract as a whole in light of the circumstances present when the contract was entered.’” BP Am. Prod. Co. v. Zaffirini, --- S.W.3d ----, 2013 WL 4634589, at *9 (Tex. App. 2013) (citing Anglo–Dutch Petrol. Int’l, Inc. v. Greenberg Peden, P.C., 352 S.W.3d 445, 449–50 (Tex. 2011)). A court 42 “construe[s] a contract or lease ‘to give effect to the parties’ intent expressed in the text as understood in light of the facts and circumstances surrounding the contract’s execution, subject to the parol evidence rule.’” Id. (citing Houston Exploration Co. v. Wellington Underwriting Agencies, Ltd., 352 S.W.3d 462, 469 (Tex. 2011)). The parol evidence rule “does not prohibit consideration of surrounding circumstances that inform, rather than vary from or contradict, the contract text.” Houston Exploration Co., 352 S.W.3d at 469. “Those circumstances include . . . ‘the commercial or other setting in which the contract was negotiated and other objectively determinable factors that give a context to the transaction between the parties.’” Id. (quoting 11 Richard A. Lord, Williston on Contracts § 32.7 (4th ed.1999)). If the lease is so worded that it can be given a certain or definite legal meaning or interpretation, then it is not ambiguous and the court will construe it as a matter of law. Universal C.I.T. Credit Corp. v. Daniel, 243 S.W.2d 154, 157 (Tex. 1951); R & P Enters. v. LaGuarta, Gavrel & Kirk, Inc., 596 S.W.2d 517, 519 (Tex. 1980). However, a lease is ambiguous when its meaning is uncertain and doubtful or it is reasonably susceptible to more than one meaning. Skelly Oil Co. v. Archer, 356 S.W.2d 774, 778 (Tex. 1962). A court “may conclude a contract is ambiguous, even though the parties do not so contend.” Zurich Am. Ins. Co. v. Hunt Petroleum (AEC), Inc., 157 S.W.3d 462, 465 (Tex. App. 2004). When a 43 lease contains an ambiguity, the granting of a motion for summary judgment is improper, because the interpretation of the instrument becomes a fact issue. See Coker, 650 S.W.2d at 394 (citing Harris v. Rowe, 593 S.W.2d 303, 306 (Tex. 1980)). 2. The Leases Do Not Provide for Delay Rentals or Recite that EnerQuest Paid Such Rentals EnerQuest insists that at the time the Leases were executed it prepaid all the delay rentals that would have been due during the Leases’ two-year primary terms, thereby maintaining the Leases for the entirety of their primary terms and affording EnerQuest an additional ninety days to tender shut-in royalties pursuant to the following provision: 3. Royalty. . . . . (c) [I]f, during or after the primary term one or more wells on the leased premises or lands pooled therewith are capable of producing oil and gas or other substances covered hereby in paying quantities, but such well or wells are either shut-in or production therefrom is not being sold by Lessee for a period of 90 consecutive days, then Lessee may pay shut-in royalty of one dollar per acre of land then covered by this lease, such payment to be made to Lessor on or before the end of said 90-day period and thereafter on or before each anniversary of the end of said 90-day period while the well or wells are shut-in and it shall be considered that such well is producing paying quantities for all purposes hereof during any period for which shut-in royalty is tendered; provided that if this lease is otherwise being maintained by the payment of rentals or by operations, or if a well or wells on the leased premises is producing in paying quantities, no shut-in royalty shall be due until the end of the 90-day period next following the end of the rental period or the cessation of such operations or production, as the case may be. 44 (Leases ¶ 3(c) (emphases added).) In other words, EnerQuest insists that because it prepaid all rentals when the Leases were executed, the Leases were “being maintained by the payment of rentals” during the entirety of their two-year primary terms, and “‘the end of the rental period’ . . . thus coincides with the end of the Leases’ two-year primary terms,” affording EnerQuest an extra ninety days to timely tender shut-in royalties. (Id. at 4.) The biggest difficulty with EnerQuest’s argument is that there is no evidence that the Leases provided for the payment of any delay rentals, whether annually or in an up-front, lump-sum payment. Most obviously, the Leases do not contain delay rental clauses stating how much delay rentals payments were, when they were due, or the period of time such a payment would cover. While Paragraph 3(c) does mention “rentals,” it does so only in a conditional way, listing them among other options for maintaining the lease during the primary term (“provided that if this lease is otherwise being maintained by the payment of rentals or by operations, or if a well . . . is producing in paying quantities . . . .” (emphases added)), suggesting that this stray mention of “rentals”—which is not grounded in the context of a delay rental clause—is merely boilerplate not applicable to these particular leases. After all, if all delay rentals had been prepaid, and if the Parties had actually bargained for this language (rather than merely neglected to remove it upon deleting a drilling/delay rental provision), the Leases’ 45 drafters could easily have stated that delay rentals had been prepaid and that such rentals would delay the due date of shut-in royalties for the entire primary term and for ninety days thereafter. In the same vein, if delay rentals had been prepaid, the word “during” in the phrase “during or after the primary term” would be rendered meaningless, because shut-in royalties could never have become due during the primary term (the earliest due date being ninety days after the primary terms expired). The only other time “rentals” are mentioned is in Paragraphs 20 and 21, and the context further supports the conclusion that they are mentioned only in boilerplate language. Paragraph 20.A., which discusses the effect of pooling acres covered by the lease “with other properties not covered by this lease,” states in part: Should all or a portion of the above described premises be combined in a pool or unit with other properties not covered by this lease, and should production be obtained from a well or wells located within such pool or unit, then, production from such well located in such pool or unit shall be sufficient to maintain this lease in force only as to such properties described hereinabove that are actually included in such pool or unit. Properties lying outside of such pool or unit will not be deemed to be held by production from the well located within such pool or unit, but rather may be held under the terms of this lease only in accordance with other terms of the lease (i.e. payment or tender of delay rentals, shut-in royalties, production from other wells), or such property must be released. (Dkt. # 122 Ex. A at 9 ¶ 20 (emphasis added).) Again, there simply are no “other terms of the lease” explaining that EnerQuest can pay delay rentals to maintain the 46 Leases in force during the primary term; there is no delay rental clause. And why, if the Leases provided that all delay rentals would be paid upon execution, would it be necessary to state that the lessee was obligated to pay rentals on any lands not included in a pool held by production? Prepaying all delay rentals would have maintained the entire property covered by each lease for the entire primary term; there would have been no need to state that the lessee would have to pay delay rentals to maintain those acres not included in a pool with a productive well.5 Similarly, Paragraph 21, dealing with royalties, states in part: Should Lessee . . . enter on the above described property and drill a well which is capable of and does produce oil, gas, or other minerals in paying quantities so as to maintain this lease in force beyond the primary term hereof, or so as to maintain this lease in force without the payment of delay rentals as provided for above, then . . . Lessor shall be entitled to a minimum royalty out of the production . . . . (Id. ¶ 21 (emphasis added).) This Paragraph, too, refers to a phantom delay rental provision that does not exist; the “payment of delay rentals” is not “provided for above.” And again, if the Leases had contemplated that EnerQuest would prepay delay rentals to the lessors, why would this provision contain language suggesting that the payment of delay rentals had not taken place and that EnerQuest might 5 Recall that delay rentals can only maintain a lease in the absence of drilling during the primary term. See In re Estate of Slaughter, 305 S.W.3d at 811 (“‘Delay rental’ is defined as ‘a periodic payment made by an oil and gas lessee to postpone exploration during the primary lease term.’” (citing Black’s Law Dictionary 1411)). 47 choose “to maintain this lease in force without the payment of delay rentals” (e.g., by actual production)? In addition to lacking a delay rental clause, the Leases do not recite that EnerQuest paid delay rentals in advance. See 28A West’s Legal Forms, Specialized Forms § 22:87 – Paid-up delay rentals (4th ed. 2012) (recommending the following language be included where the lessee intends to prepay delay rentals: “Lessor acknowledges that all of the delay rentals required annually under Paragraph __ have been prepaid at the time of Lessor’s execution and delivery of this lease”); Crain v. Chesapeake Appalachia, L.L.C., CIV A 3:12-CV-2343, 2013 WL 4419023, at *1 (M.D. Pa. Aug. 14, 2013) (“The Lease secured the terms through an up-front payment of $65 per acre, along with continuing annual payments for each year the Lessor delayed drilling operations within that term, yet the language of the Addendum provides that all rentals due were deemed paid upon execution of the Lease.” (emphasis added)). Thus, even assuming that the stray mentions of “rentals” described above were not boilerplate, the Leases simply give no indication that delay rentals, rather than being optional, were actually paid. In the end, EnerQuest’s argument hinges on one thing: the fact that the Leases both contain the notation “Paid Up” in the top right-hand corner of each page, beneath the words “Prod 88 (Rev. 8/93)”. (Dkt. # 122 at 3.) “Under a paid-up lease,” insists EnerQuest, “the delay rentals are paid when the lease is 48 executed, and this single payment maintains the lease during the primary term.” (Id.) In other words, EnerQuest argues that “Paid up” is a term of art in the oil and gas business, one that is universally understood to mean: (a) that the lease at issue calls for the payment of delay rentals even though it lacks a delay rental clause, and (b) that the lessee paid all of the delay rentals upon execution, even if the lease does not acknowledge such a payment and there is no other evidence that such a payment was ever made. Notably, EnerQuest does not cite a single Texas case in support of this argument. Indeed, while many other oil and gas terms are well defined under Texas law, the Court has searched in vain for a case defining the term “paid up” or holding that every lease labeled “paid up” should be construed as providing for prepaid delay rentals. Instead, EnerQuest relies entirely on (1) treatises and (2) deposition testimony from David Nichols Frye, a landman for EOG. (See Dkt. # 122 at 3.) For the reasons that follow, however, the Court concludes: (1) that the term “paid up” simply means that the lessee has no drilling obligations during the primary term and (2) that a paid-up lease without a drilling/delay rental clause is maintained during its primary term by a bonus payment, not by “prepaid rentals.” 3. Delay Rentals and Bonuses Compared Before addressing EnerQuest’s argument about “paid-up” leases, the Court defines two terms relevant to the inquiry: “delay rental” and “bonus.” Each 49 of these terms has a “well-understood meaning in the oil and gas business.” Schlittler v. Smith, 128 Tex. 628, 630 (1937). A “delay rental,” as explained briefly above, is “a periodic payment made by an oil and gas lessee to postpone exploration during the primary lease term.” In re Estate of Slaughter, 305 S.W.3d 804, 811 (Tex. App. 2010) (quoting Black’s Law Dictionary 1411)); see also Griffith v. Taylor, 156 Tex. 1, 6 (1956) (defining “rental” as “the consideration for the privilege of delaying drilling operations”). A “bonus,” on the other hand, is “the cash consideration paid or agreed to be paid for the execution of the lease.” Griffith, 156 Tex. at 6. In other words, a bonus is “[a] payment that is made in addition to royalties and rent as an incentive for a lessor to sign an oil-and-gas lease.” In re Estate of Slaughter, 305 S.W.3d at 811 (emphasis added) (quoting Black’s Law Dictionary 206 (9th ed. 2009)); accord E. Energy, Inc. v. SBY P’ship, 750 S.W.2d 5, 6 (Tex. App. 1988). A bonus may be paid “either in cash on execution of the lease, or out of production at some later date.” 55A Tex. Jur. 3d Oil and Gas § 354 (2013) (citing Lane v. Elkins, 441 S.W.2d 871 (Tex. Civ. App. 1969); Parmelee v. Nueces Royalty Co., 361 S.W.2d 585 (Tex. Civ. App. 1962)). Bonuses are also frequently computed at a cash amount per acre. See Morriss v. First Nat’l Bank of Mission, 249 S.W.2d 269 (Tex. Civ. App. 1952). 50 In simple transactions, it is not difficult to designate a particular payment as a bonus or a delay rental; many leases call for both. See, e.g., Hlavinka v. Hancock, 116 S.W.3d 412, 415 (Tex. App. 2003) (describing “a three year lease paying a $250.00 per acre bonus, with delay rentals of $50.00 per year for the second and third years, and a one-fourth royalty interest”); Otter Oil Co. v. Exxon Co., U.S.A., 834 F.2d 531, 535 (5th Cir. 1987) (“The parties intended that Exxon would pay a bonus of $90.00 per acre and a rental of $45.00 per acre . . . .”). However, whether a lease labels a certain payment a “delay rental” or a “bonus” is not controlling, and sometimes the proper classification is not immediately obvious. The defining characteristic of a delay rental, as opposed to a bonus, is that it is an alternative to drilling. In other words, while commencing drilling operations does not relieve a lessee from its obligation to pay any bonus provided for in the lease, a lessee may avoid paying delay rentals by drilling. Thus, in Fuller v. Rainbow Resources, Inc., 744 S.W.2d 232 (Tex. App. 1987), the court of appeals held that the trial court had erred when it had construed the $1,000 payment provided for in the following provision as a delay rental: 13. Notwithstanding anything to the contrary, in order to maintain this lease in force and effect [for the last year of the primary term], lessee will pay to lessors as additional consideration $1,000.00. 51 Id. at 233. The trial court had ruled that when the lessee failed to timely tender the $1,000 “rental,” the lease had automatically terminated. Id. However, the court of appeals reversed. Paragraph 13 was “not a drilling clause,” the court explained, because it “contain[ed] no reference to drilling activity as an alternative to paying the $1,000.00 . . . .” Id. Construing this paragraph as a delay rental clause—and, accordingly, construing the $1,000 payment as a delay rental—“would produce the bizarre result of the lease being automatically terminated during the primary term for failure to pay additional consideration when the lessee had not only already begun drilling operations, but had already obtained production.” Id. at 234 (emphasis added).6 “Such a result,” the court explained, “would defeat the purpose of a drilling clause.” Id. In other words, because the payment had to be made even if the lessee had begun drilling operations—because it could not be avoided by drilling—it was an “additional consideration” (i.e., a bonus), not a delay rental. Federal courts have made precisely the same distinction between bonuses and delay rentals in the context of taxation, because the two types of payments are treated differently for tax purposes. In Bennett v. Scofield, for example, the Fifth Circuit held that a payment provided for in a Texas oil and gas 6 For reasons not relevant here, construing the payment as a bonus rather than a delay rental meant that the lessee was entitled to an opportunity to cure after notice of breach. 52 lease was a bonus, not a delay rental, because “[n]o further payments, as an alternative to drilling, were necessary to continue the lease in force and effect over the fifteen-year period, and production in paying quantities alone could keep it in force after that period.” 170 F.2d 887, 889 (5th Cir. 1948). The court emphasized that the payment at issue was not a delay rental because it could not be avoided: “It is to be paid by the lessee and retained by the lessor, regardless of whether oil or gas or other mineral be found there and irrespective of whether a well is ever drilled there.” Id.; see also White Castle Lumber and Shingle Co., Ltd. v. United States, 481 F.2d 1274, 1276 (5th Cir. 1973) (Goldberg, J., concurring) (“Generally speaking a bonus payment is a consensually bargained-for fixity for anticipated or hoped for production. To be depletable a bonus must be payable in all events with no conditions precedent or subsequent to subvert the payments. Conversely, a delay rental is an avoidable payment for deferring the development of mineral lands.”); 5 Mertens Law of Fed. Income Tax’n § 24:29 (“What in reality is a bonus retains its nature even though it takes the form of a delayed bonus, or a bonus payable in installments and even though it is called a ‘rental.’ Implicit in the tax treatment of a bonus is the concept that the nature and character of the payment is fixed at the time the leasing arrangement is entered into by the parties. Furthermore, a true bonus is a payment which the lessee is obligated to make in all 53 events, with or without production, which cannot be avoided by termination or abandonment of the lease arrangement.”). 4. Paid-up Leases Without Drilling Clauses Are Maintained During Their Primary Terms by Bonus Payments, Not By Delay Rentals Keeping in mind the distinction between delay rentals and bonuses, the Court turns to the treatises EnerQuest cites in support of its interpretation of “paid up.” First, EnerQuest cites Ernest E. Smith and Jacqueline Lang Weaver’s treatise, Texas Law of Oil & Gas. (See Dkt. # 122 at 3.) The Court does not have a copy of this treatise, and EnerQuest did not provide one. Accordingly, the Court cannot ascertain exactly what this treatise states, whether it cites any cases in support of its conclusion or, if it does cite cases, whether it correctly interprets them. However, the Court will assume for present purposes that EnerQuest properly cited this treatise for the proposition that “[u]nder a paid-up lease, the delay rentals are paid when the lease is executed, and this single payment maintains the lease during the primary term.” (Dkt. # 122 at 3.) Next, in its Response to the Mineral Owners’ Motion for Partial Summary Judgment, EnerQuest cites a second treatise, Eugene Kuntz’s A Treatise on the Law of Oil and Gas (1989). (See Dkt. # 133 at 3.) EnerQuest does not quote from this treatise, and the Court has access only to the 2013 revised edition. However, 54 EnerQuest cites § 28.6, which in the 2013 edition is entitled “Paid-up leases,” so the Court assumes that EnerQuest was relying on the following language from that section: A lessee may enter into an oil and gas lease with the fixed intention to hold the lease for at least the entire primary term, may desire to avoid the inconvenience of making annual delay rental payments, and may desire to avoid the perils of an inadvertent failure to make payment of such rentals properly. Such lessee may attempt to accomplish this desire by paying in advance an amount equal to all delay rentals which could be paid under the lease and by striking the drilling clause in the common oil and gas lease form. The lessee may also attempt to accomplish such desire by using the common oil and gas lease form, leaving the drilling clause intact, and by paying all rentals in advance at one time. Neither method is entirely satisfactory. 3-28 Eugene Kuntz, A Treatise on the Law of Oil and Gas § 28.6 (Matthew Bender, Rev. Ed. 2013) (emphases added). Notably, this treatise describes two methods for maintaining the lease during its primary term by making a lump sum payment upon execution: (1) by “striking the drilling clause” and “paying in advance an amount equal to all delay rentals” that could have been paid under the now-stricken delay rental clause (which is what EnerQuest argues it did); or (2) by “leaving the drilling clause intact, and by paying all rentals in advance at one time.” Under the second scenario, where the delay rental provision is intact, the lump-sum payment could certainly be construed as a “rental” payment, especially if the lease recited that the parties acknowledged the prepayment of 55 rentals, see 28A West’s Legal Forms, Specialized Forms § 22:87 – Paid-up delay rentals (recommending the following language be included where the lessee intends to prepay delay rentals: “Lessor acknowledges that all of the delay rentals required annually under Paragraph __ have been prepaid at the time of Lessor’s execution and delivery of this lease”), or that the lessee would be entitled to partial refund if drilling were to be commenced during the first year, see Richard A. Freling, Bonus or Delay Rental—Their Distinction for Tax Purposes and the Jefferson Lake Case, 35 Tex. L. Rev. 211, 218 (Dec. 1956) (“If the lessor was entitled to retain the entire sum even though the lessee achieved production within one year, can it be said the money was paid to secure delay in development? Obviously, the answer is ‘no.’”). However, the same cannot be said of the first scenario. As a matter of lease construction, once the drilling/delay rental clause is stricken, why should a lump-sum payment paid upon execution of the lease—even one that happens to be in “an amount equal to” the delay rentals that might have been paid under the stricken delay rental clause—be considered a “rental” payment? In other words, in the absence of a drilling/delay rental clause, can the lease still be said to provide for “rentals”? Or does striking that clause eliminate the concept of rentals from the lease? Under the reasoning of the cases discussed above, the answer appears clear: Unless there is some indication that the lump-sum payment can be avoided (or 56 partially refunded) by drilling, it should be construed as a bonus, not a delay rental. Consistent with this reasoning, Professor Kuntz’s treatise, in the same section EnerQuest cites, states: “A paid-up lease does not contain a drilling clause, and an additional consideration provided for in such a lease is not a delay rental.” 3-28 Kuntz, Law of Oil and Gas § 28.6 (emphasis added) (citing Fuller, 744 S.W.2d at 232). Stated plainly, increasing a bonus payment by “an amount equal to delay rentals” does not transform that bonus into a delay rental. What, then, should the Court make of the treatises EnerQuest cites? Frankly, with due respect to their authors, the answer in light of the facts of this particular case is “not much.” First, it goes without saying that treatises are not binding on this Court; they are useful only insofar as they are persuasive. While some treatises do make broad pronouncements about paid-up leases involving the prepayment of delay rentals, none points to a Texas case making the same unequivocal declaration (and again, neither does EnerQuest). And, for the reasons given in the preceding paragraphs, the Court has reason to believe that these treatises improperly conflate (a) leases that do not contain drilling clauses and that maintain the lease during the primary term with a bonus payment with (b) leases that achieve the same effect by prepaying the rentals provided for in a drilling clause. In most cases, perhaps, the distinction is unimportant; however, it is critical here. 57 Moreover, for every treatise that says paid-up leases involve prepaid rentals, there are others indicating that paid-up leases with no drilling clauses are maintained during the primary term by bonus payments. For example, the commentary to the model “Paid-up delay rentals” clause in West’s Texas Forms explains: When lease forms requiring delay rental payments were the norm, a lessee negotiating a paid-up lease would usually offer to increase the bonus paid on lease execution by an amount representing the delay rental that would have been paid under a traditional lease, often $1.00 per acre for each anniversary of the lease before the end of the primary term. Bonuses for paid-up leases are now more routinely offered as a lump sum per acre without reference to any increase as a substitute for annual delay rentals. 6 West’s Tex. Forms, Minerals, Oil & Gas § 3:65 – Paid-up delay rental clause (emphases added). In other words, while early paid-up leases involved a bonus payment that had been increased “by an amount representing the delay rental payment,”7 it is now more common for paid-up leases to provide for lump-sum bonus payments and to eliminate any mention of rentals. See also 6 MS Prac. Encyclopedia MS Law § 53:8 (“Recent oil, gas and mineral leases often do away with the concept of delay rentals. These ‘paid up’ leases do not require annual payment of delay rentals. Instead, an amount equivalent to delay rentals that 7 The Court reiterates that under the substance-over-label principles discussed above, even a bonus payment “increased by an amount representing the delay rental payment” should be construed solely as a bonus payment unless the lease provides that the lessee is entitled to a partial refund upon the commencement of drilling operations. 58 would normally be paid over the primary term is included as a part of the bonus tendered to the lessor upon execution of the lease.” (emphases added)); Owen W. Anderson, David v. Goliath: Negotiating the ‘Lessor’s 88’ and Representing Lessors and Surface Owners in Oil and Gas Lease Plays, 27 RMMLF-INST 2 (1982) (“In ‘paid-up’ leases, the bonus pays for a primary term lease of three years, five years, or ten years and ‘so long thereafter as oil or gas is produced in paying quantities.’ During the primary term, there is then no commitment on the part of the lessee to either drill or pay delay rentals . . . . Lessors who own small fractional interests need not object to a paid-up lease provided that the primary term is very short and the bonus is sufficient. Paid-up leases have the advantage of both parties knowing that the lease will remain in full force and effect during the expressed primary term.” (emphases added)); Baldwin’s Oh. Prac. Real Est. § 47:6 (2012–13 ed.) (“[M]ost of the recent shale leases utilize an up-front, per-acre bonus payment to the landowner rather than the concept of delay rentals. The use of this type of payment arrangement is classified as a ‘paid up lease.’” (emphases added)); David E. Pierce, Incorporating A Century of Oil and Gas Jurisprudence into the “Modern” Oil and Gas Lease, 33 Washburn L.J. 786, 805–06 (1994) (“Instead of chasing delay rental obligations, why not eliminate the clause? Since the primary term of the oil and gas lease is generally shorter than in the past, the economic significance of delay rental becomes less important to the lessor. If the 59 lessor is hesitant to break with tradition, this can usually be dealt with in the bonus payment.” (emphasis added)). While the Court is aware of no Texas case explicitly stating that paid-up leases with no drilling clause are maintained during the primary term by a bonus payment, a number of Texas cases describe leases under which the lessee tendered a paid-up bonus as opposed to paid-up rentals. See, e.g., Zaffirini, --S.W.3d ----, 2013 WL 4634589, at *5 (“Part of the consideration herein paid by Lessee to Lessor for this lease agreement includes One Thousand Seven Hundred– Fifty ($1,750.00) Dollars per net mineral acre as paid up bonus . . . .” (emphasis added)); Adams v. Chesapeake Exploration, L.L.C., 9:12-CV-2, 2012 WL 4433294, at *5 (E.D. Tex. Sept. 5, 2012) (stating that the defendant allegedly “intended to lease all of Plaintiffs’ unleased minerals . . . for a lease bonus of $4,800.00 per net mineral acre, . . . send Paid Up Oil and Gas lease forms to Plaintiffs for execution and notarization . . . and pay the lease bonuses on or before the scheduled closing dates” (emphases added)), report and recommendation adopted, 9:12-CV-2, 2012 WL 4343383 (E.D. Tex. Sept. 21, 2012). And West recommends the following language in its model Texas paid-up lease, which lacks a drilling/delay rental clause: 1. Description. In consideration of a cash bonus in hand paid and the covenants herein contained, lessor hereby grants, leases and lets exclusively to lessee the following described land . . . . 60 .... 2. Term of Lease. This lease, which is a “paid-up” lease requiring no rentals, shall be in force for a primary term of [identification of years] years from the date hereof, and for as long thereafter as oil or gas or other substances covered hereby are produced in paying quantities . . . . 6 West’s Tex. Forms, Minerals, Oil & Gas § 3:4 – Oil, gas and mineral lease— Paid-up Form—With Pooling Provision—Modern Form (4th ed. 2012) (emphases added); accord Cardinale v. R.E. Gas Dev. LLC, --- A.3d ----, 2013 WL 3213321, at *3–*4 (Pa. Super. June 19, 2013) (describing a lease that stated: “Lessee agrees to pay to the Lessor the sum of One Hundred Five Thousand Eight Hundred Seventy-five and 00/100 Dollars $(105,875.00) as full and complete bonus payment for this lease for the entire primary term of this lease. This is a paid-up lease and no delay rentals shall be due. The bonus paid hereunder is consideration for this lease and shall not be allocated as mere rental for a period.” (emphases added)). In light of the foregoing, the second source that EnerQuest cites in support of its interpretation of the term “paid up”—the testimony of EOG landman David Nichols Frye—actually cuts against EnerQuest’s interpretation. During Mr. Frye’s deposition, EnerQuest’s counsel questioned him about what the term “paid up” meant, resulting in the following exchanges: 61 Q. Now, each one of these leases in its title says it’s a “Paid-Up Oil, Gas, and Mineral Lease.” 8 What does “paid up” mean in this context? A. There are no rentals required during the primary term of the leases. .... Q. Thank you. Back -- back to my question, each one of these is entitled “Paid-Up Oil, Gas and Mineral Lease,” and if you would, please, tell me again what “paid up” means. A. The -- the “paid up” implies that there are -- are no rentals or other payments due during the primary term to maintain the lease. (Dkt. # 122 Ex. O at 68:9–14; id. at 69:5–11 (emphases added).) In both of these exchanges, Mr. Frye confirmed that under a paid-up lease the lessee is not required to pay rentals during the primary term—an idea about which the Parties do not disagree. Shortly thereafter, however, EnerQuest’s counsel asked the following question: Q. Okay. So when -- when we’re looking at these leases and they’re paid-up mineral leases, . . . once these leases have been signed by the landowners and Dan A. Hughes paid them whatever bonus consideration was paid, . . . Dan A. Hughes . . . doesn’t have to do anything else for three years if -- if they -- if they choose not to, correct, to hold these leases? A. Yes. 8 EnerQuest’s counsel was referring to the leases that the Mineral Owners signed with Dan A. Hughes, not to the Leases at issue in this case, which are entitled “OIL, GAS AND MINERAL LEASE.” 62 (Id. at 69:21–70:5 (emphases added).) In other words, EnerQuest’s counsel asked Mr. Frye whether the payment of a bonus—not the “prepayment of delay rentals”—maintained the lease at issue during the primary term. Mr. Fry, consistent with the above analysis, answered in the affirmative: A paid-up lease is one under which the lessee has paid a bonus for the privilege of holding the lease during its primary term—a lease with “no rentals.” See Dkt. # 123 Ex. G (Brysch-Hughes Lease) ¶ 3 (“This is a PAID UP LEASE. In consideration of the cash payment tendered upon execution of this lease, Lessor agrees that Lessee shall not be obligated, except as may otherwise be provided herein, to commence or continue any operations during the primary term or to make any shut in royalty payment during the primary term.” (emphasis added)). The preceding discussion leads inexorably to the following conclusion: Contrary to EnerQuest’s contentions, calling a lease with no drilling/delay rental clause “paid up” does not mean, as a matter of law, that the lessor paid “delay rentals” at execution; a bonus payment, not rentals, maintains such a lease during the primary term. 63 5. The Leases’ Scattered References to Rentals Are Meaningless In the Absence of a Drilling Clause and Are Clearly the Result of a Drafting Oversight That the Leases’ scattered references to “rentals” were inadvertently left in the Leases becomes even clearer when one looks at form “unless”-type delay-rental leases and form paid-up leases. The leases at issue in this case were not drafted from scratch: Not only does the notation in the Leases’ top right corner contain the words “Prod 88 (Rev. 8/93)”—short for “Producer’s 88,” a now-generic term for an “unless”-type delay-rental lease9—but the language of each of the Leases’ provisions is nearly identical to the language of model leases contained in West’s Texas Forms. See 6 West’s Tex. Forms, Minerals Oil & Gas §§ 3:3, 3:4 (4th ed. 2012). More specifically, the Leases’ provisions are nearly identical to the provisions in West’s model lease entitled “Oil, gas and mineral lease—‘Unless’ form—With pooling provision—Modern form.” See id. § 3:3. 9 See 6 West’s Tex. Forms, Minerals, Oil & Gas § 3:1 (“The structure of oil and gas lease with a finite primary term subject to . . . an ‘unless’ type delay rental clause and an indefinite secondary term was first used in Oklahoma. Because the form was the printer’s 88th form, it carried the notation ‘Producers 88 Form Lease.’ Although it has become commonplace to refer to this type of oil and gas lease as a Producer’s 88 lease, that is a generic term and does not describe the particulars of the lease itself. The type of lease provisions contained and their individual content varies greatly from form to form, and each form must be carefully studied.”); Fagg v. Tex. Co., 57 S.W.2d 87, 89 (Comm. App. 1933) (holding that because of the great variety of specific provisions in leases, a reference to “an 88-form lease” is not recognized by the law as sufficient to specify any particular content). 64 That model form is a template for a lease that is not paid up, and it does contain a drilling/delay rental clause. It also contains a shut-in royalty clause that provides, in pertinent part: If for a period of [X] consecutive days such well or wells are shut in or production therefrom is not sold by lessee, then lessee shall pay an aggregate shut-in royalty of one dollar per acre then covered by this lease, such payment to be made to lessor or to lessor’s credit in the depository designated above, on or before the end of said [X]-day period and thereafter on or before each anniversary of the end of said [X]-day period while the well or wells are shut in or production therefrom is not being sold by lessee; provided that if this lease is otherwise being maintained by the payment of rental[s] or by operations, or if production is being sold by lessee from another well or wells on the leased premises or lands pooled or unitized therewith, no shut-in royalty shall be due until the end of the [X]-day period next following the end of the rental period or the cessation of such operations or production, as the case may be. Id. (emphases added); accord 5A Vernon’s Okla. Forms 2d, Real Estate § 10.26 (2012) (recommending essentially the same language for an Oklahoma “unless” lease). Because this model lease does contain a delay rental provision, this paragraph’s references to “the payment of rentals” and “the end of the rental period” make sense: Delay rentals allow the lessee to maintain the lease during the primary term without drilling. By contrast, West’s model Texas “Paid Up” form (1) is entitled “Paid Up Oil and Gas Lease”; (2) eliminates the delay rental clause entirely; (3) recites in the habendum clause that the lease “is a ‘paid-up’ lease requiring no rentals”; and 65 (4) contains a shut-in royalty clause that eliminates any mention of rentals or rental periods, stating, in relevant part: [I]f this lease is otherwise being maintained by operations, or if production is being sold by lessee from another well or wells on the leased premises or lands pooled or unitized therewith, no shut-in royalty shall be due until the end of the [X]-day period next following cessation of such operations or production. 6 West’s Tex. Forms, Minerals, Oil & Gas § 3:4 - Oil, gas and mineral lease— Paid-up form—With pooling provision—Modern form (emphases added). Because this model paid-up lease contains no delay rental clause—and thus does not provide for delay rentals—it need not and does not mention delay rentals in the shut-in royalty provision. Comparing the Leases to the aforementioned model forms makes clear that the Leases’ drafter(s) simply deleted the drilling clause from an unless-type lease in an attempt to transform it into a paid-up lease. Once the drilling clause was removed, there was no need for the shut-in royalty clause to mention delay rentals; however, the drafter(s)—here, EnerQuest—inadvertently left that language in. See 3-34 Kuntz, Law of Oil & Gas § 34.5 (explaining that “strik[ing] the drilling clause[] and insert[ing] another clause which will contain substantially the same provisions that are contained in a paid-up lease with respect to the implied covenant to drill an exploratory well” is “less attractive than the use of the paid-up lease” due to “the possibility of error or oversight in the 66 modification of a lease form which is not designed for the specific purpose for which it is used”); Frank H. Houck, How to Modify a Lease Without Screwing It Up, Proceedings of the Rocky Mountain Mineral Law Thirtieth Annual Institute, 30 RMMLF-INST 4 (1984) (noting that parties sometimes delete the delay rental clause, “intending thereby to make the lease a paid-up lease,” but warning that to avoid drafting errors “it is always preferable to use a printed form Paid-Up Lease when a paid-up lease is desired”). When interpreting a lease, “no single provision taken alone [should] be given controlling effect.” Coker, 650 S.W.2d at 393. Accepting EnerQuest’s interpretation would give controlling effect not merely to a single provision but to scattered, orphaned language. 6. Mr. Olson’s Assertion that EnerQuest Paid Delay Rentals Is a Legal Conclusion For the reasons given in the preceding section, EnerQuest’s argument that this Court is constrained to find that the Leases, being “paid up,” necessarily provided for prepaid rentals—and thus that the word “rentals” in Paragraph 3(c) necessarily refers to those prepaid rentals—is without merit. The Leases are unambiguous and do not provide for delay rentals. Even if that were not the case, however, EnerQuest has simply not shown that it made a payment that represented delay rentals. 67 The Court is entitled to examine “the facts and circumstances surrounding [a lease’s] execution,” including “objectively determinable factors that give a context to the transaction between the parties.” Zaffirini, --- S.W.3d ----, 2013 WL 4634589, at *9. Accordingly, in support of its argument that it prepaid “rentals” rather than a bonus, EnerQuest might have submitted prior versions of the Leases that contained delay rental clauses, along with copies of checks to the Mineral Owners in an amount equal to what would have been due in rentals. See Houston Exploration Co. v. Wellington Underwriting Agencies, Ltd., 352 S.W.3d at 469–72 (allowing courts to consider the parties’ act of deleting contract language when discerning the parties’ intentions in the contract language). Alternatively, EnerQuest might have submitted a copy of a letter memorializing the payment it made, ideally one that acknowledged that the payment represented delay rentals. See Price v. Elexco Land Servs., Inc., 3:09CV433, 2009 WL 2045135 (M.D. Pa. July 9, 2009) (noting, where the lease recited that “[i]n consideration of one ($1.00) dollar in hand paid and the covenants herein contained, Lessor hereby grants leases and lets exclusively to Lessee the following described land,” that the lease “[did] not reference any other form of payment” but that the defendant “[had] submitted . . . a ‘consideration letter’ or ‘payment letter’”, signed by both parties, “contain[ing] the $4,168.00 that the parties agree defendants paid the plaintiff in exchange for the lease”). Perplexingly, however, 68 EnerQuest did not even state in its pleadings the amount it allegedly paid or the date on which that payment was made. In its Motion for Partial Summary Judgment, EnerQuest did not point to any evidence in support of its claim that it had prepaid delay rentals; it relied entirely on its argument about the meaning of “paid up.” (See Dkt. # 122 at 3–4, 11–12.) Eventually, EnerQuest attached to its Response to the Mineral Owners’ Motion for Partial Summary Judgment the affidavit of EnerQuest’s president, Greg Olson. (See Dkt. # 133 Ex. A.) In that affidavit, Olson stated that EnerQuest had “paid all delay rentals to the Lessors at signing . . . .” (Id. ¶ 12.) However, Mr. Olson attached no exhibits to his affidavit and did not explain why any lump-sum payment that EnerQuest made at signing should be construed as “all delay rentals” rather than as a bonus. See Ragas v. Tenn. Gas Pipeline Co., 136 F.3d 455, 458 (5th Cir. 1998) (“The party opposing summary judgment is required to identify specific evidence in the record and to articulate the precise manner in which that evidence supports his or her claim.”). His assertion is nothing more than a legal conclusion. At the hearing, the Court asked EnerQuest’s counsel what evidence there was that delay rentals had been paid at signing in addition to the bonus. EnerQuest’s counsel responded that there was “no distinction” between bonus and delay rentals and that the two had been “wrapped into one payment.” (Tr. at 5:4, 69 5:9.) “There’s no evidence, of which I’m aware,” said counsel, “that says the bonus was ‘X’ dollars per acre for these leases, and the delay rentals were ‘Y’ dollars per acre.” (Id. at 5:10–12.) Instead, counsel argued that delay rentals were “deemed to have been paid” at execution by virtue of the fact that the leases were called “paid-up.” (Id. at 5:16.) In other words, EnerQuest’s counsel admitted that the only payment made at execution was a bonus payment that allegedly had delay rentals “wrapped in[].” For the reasons given above, it is simply not correct that there is “no distinction” between a delay rental and a bonus payment. And merely increasing a bonus payment by an amount representing delay rentals that might have been called for under hypothetical versions of the Leases containing drilling clauses does not transform that bonus payment into a delay rental. Again, whether a payment should be categorized as a delay rental or a bonus payment depends on the effect the payment had and whether it could be avoided by drilling; simply calling a payment a “delay rental” is insufficient. In the instant case, EnerQuest has presented no evidence to suggest that the payment made at signing could be avoided or partially refunded if EnerQuest chose to drill during the primary term and has thus given the Court no reason to conclude that the payment at issue was a delay rental rather than a bonus. See Freling, Bonus or Delay Rental—Their Distinction for Tax Purposes and the Jefferson Lake Case, 35 Tex. L. Rev. at 218 70 (“Theoretically, a single cash payment upon execution of a lease could be allocated between consideration for the lease and advance delay rental, determined by the usual delay rental paid in that area at that time. Such an allocation, however, would impute at least a partially fictitious intention to the parties and would contravene a basic premise—that a delay rental is paid to secure delay in development. In the absence of a provision for proportionate reimbursement in the event drilling is begun or the lease forfeited before the end of the primary term, it cannot be said that payment is made to defer drilling.”). 7. Because EnerQuest Did Not Tender Shut-in Royalties by the End of the Leases’ Primary Terms, the Leases Automatically Terminated The Leases’ habendum clauses provided that they would “be in force for a primary term of 2 years . . . and for as long thereafter as a covered mineral is produced in paying quantities from the leased premises or [the Leases were] otherwise maintained in effect pursuant to [their] provisions . . . .” (Leases ¶ 2.) At the end of the Leases’ primary terms, the Well was not actually producing in paying quantities. In order to maintain the Leases into their secondary terms, EnerQuest must have satisfied the requirements of the shut-in royalty clause, which created a contractual substitute for production. For the reasons given above, the shut-in royalty clause required EnerQuest to pay shut-in royalties within ninety 71 days of the Well being shut in. Because the Well was shut in on June 2, 2010, shut-in royalties were due on August 31, 2010. When the Leases’ two year-primary terms ended and shut-in royalties still had not been paid, the Leases automatically terminated, because EnerQuest had achieved neither actual nor constructive production. See Reid, 161 Tex. at 58 (holding that the lease expired automatically at the end of the primary term when there was neither production nor a substitute therefor); Freeman v. Magnolia Petroleum Co., 141 Tex. 274, 279 (1943) (explaining that “[i]f respondents had wanted to prevent lapsation of the lease for nonproduction, they could easily have done so by paying the [shut-in royalty] on or before the last day of the primary term” and holding that “[t]he lease lapsed as a matter of law when they so failed”); Marifarms Oil & Gas, Inc. v. Westhoff, 802 S.W.2d 123, 125–26 (Tex. App. 1991) (holding, where “[n]o shut-in royalty was ever paid,” that “there was no production and no substitute for production and therefore the trial court was correct in decreeing that the lease terminated by its own terms”); Bratton, 711 S.W.2d at 743 (“Because payment of a shut-in royalty is a substitute for production that keeps the lease in effect, failure to make a timely shut-in payment is the equivalent of cessation of production, and the lease automatically terminates.” (emphasis added)); 18-283 Dorsaneo, Texas Litigation Guide § 283.03 (“The basic requirement is that there be no time gap between the end of the primary term and production. Thus, the first shut-in royalty 72 must be paid during the primary term or some extension of it under other lease clauses, and subsequent payments must be made before expiration of the period covered by the previous payment.”). Accordingly, the Court DENIES Plaintiffs’ Motion for Partial Summary Judgment on Maintenance of Their Leases and Repudiation (Dkt. # 122) and GRANTS the Mineral Owners’ Motion for Partial Summary Judgment (Dkt. # 126). II. EOG’s Motion for Partial Summary Judgment on Plaintiffs’ Claims for Seismic Trespass, Assumpsit, and Right to Exclusive Possession of Seismic Information and Injunctive Relief When EnerQuest moved to file its Second Amended Complaint on November 30, 2012, it added new factual allegations and a number of claims against EOG. (SAC ¶¶ 32–33, 43–49.) Briefly, EnerQuest alleged that in October of 2009, “in exchange for viewing rights and other consideration,” it had “granted Defendant EOG the right to conduct a three-dimensional seismic program (‘the Karnes Program’) on specific EnerQuest oil and gas leases in Karnes County, Texas, known as the Winshert and Roberts leases, and totaling about 242.0 acres.” (SAC ¶ 32.) In 2011, however, EnerQuest learned that EOG, this time without authorization, had conducted another three-dimensional seismic program (the “Typhoon Program”) that covered an additional 600.50 acres of EnerQuest’s leases. (Id. ¶ 33.) 73 Based on this allegedly unauthorized seismic program, EnerQuest added to the SAC a claim for seismic trespass.10 (Id. ¶¶ 33, 43–46.) In the alternative, EnerQuest argued that the trespass should be treated as an assumpsit, with Plaintiffs recovering “the value of Defendant EOG’s occupation and use of” the land on which EOG allegedly trespassed. (Id. ¶¶ 47, 48.) Finally, based on the same alleged seismic trespass, EnerQuest added to the SAC a claim for “Right to Exclusive Possession of Seismic Information and Injunctive Relief,” requesting that the Court order EOG to turn over the seismic data created by its alleged trespass and not to share it with any third parties. (Id. ¶ 49.) The Court will refer to these claims collectively as the “Seismic Claims” and to the claims raised in the Original Complaint as the “Lease Claims.” EOG moves for summary judgment on the Seismic Claims on the grounds that they are barred by the two-year statute of limitations for trespass to real property. (Dkt. # 125 at 9; see also Tex. Civ. Prac. & Rem. Code § 16.003(a) (“[A] person must bring suit for trespass for injury to the estate or to the property of another . . . not later than two years after the day the cause of action accrues.”).) EnerQuest does not dispute that it moved to file the Second Amended Complaint 10 Seismic trespass, also known as geophysical trespass, is the “wrongful entry on land for the purpose of making a geophysical survey on land.” 8-G Williams & Meyers, Manual of Oil and Gas Terms G; see also Villareal v. Grant Geophysical, Inc., 136 S.W.3d 265, 270 (Tex. App. 2004) (explaining that “trespass under Texas law includes subsurface trespass as in the oil and gas context”). 74 more than two years after the alleged seismic trespass occurred; however, it insists that the Seismic Claims relate back to the date of the Original Complaint under Federal Rule of Civil Procedure 15(c) and are thus not barred. (Dkt. # 131 at 2.) Alternatively, EnerQuest insists that its claims are not barred (1) because the “general discovery rule” applies (id. at 11) and (2) because a special discovery rule “inherent in actions for injury to land” applies because EOG’s seismic trespass resulted in “permanent” damages (id. at 7). None of these arguments has merit. A. The Seismic Claims Do Not Relate Back to the Original Complaint Federal Rule of Civil Procedure 15 provides, in pertinent part, that an amendment to a pleading “relates back to the date of the original pleading when . . . [it] asserts a claim or defense that arose out of the conduct, transaction, or occurrence set out—or attempted to be set out—in the original pleading . . . .” Fed. R. Civ. P. 15(c)(1)(B). In essence, “relation back depends on the existence of a common ‘core of operative facts’ uniting the original and newly asserted claims.” Mayle v. Felix, 545 U.S. 644, 659 (2005). “Amendments that correct technical deficiencies in a pleading or serve to expand the facts alleged in the original pleading satisfy the relation back requirements of rule 15(c).” McClellon v. Lone Star Gas Co., 66 F.3d 98, 102 (5th Cir. 1995). Similarly, if an amended complaint presents a new legal theory based on the same operative facts, the amendment will relate back. See F.D.I.C. v. Bennett, 898 F.2d 477, 477, 479 (5th Cir. 1990). The 75 relation-back doctrine is “liberally applied . . . ‘based on the idea that a party who is notified of litigation concerning a given transaction or occurrence is entitled to no more protection from statutes of limitation than one who is informed of the precise legal description of the rights sought to be enforced.” Williams v. United States, 405 F.2d 234, 236 (5th Cir. 1968) (quoting 3 Moore, Federal Practice ¶ 15.15[2]). By this reasoning, to determine whether an amendment relates back, the “‘critical’” inquiry is “whether the opposing party was put on notice regarding the claim raised [by the amendment].” Holmes v. Greyhound Lines, Inc., 757 F.2d 1563, 1566 (5th Cir. 1985) (quoting Woods Exploration & Producing Co. v. Aluminum Co. of Am., 438 F.2d 1286, 1299 (5th Cir. 1971)). “[W]hen new or distinct conduct, transactions, or occurrences are alleged as grounds for recovery, there is no relation back, and recovery under the amended complaint is barred by limitations if it was untimely filed.” Id.; see also F.D.I.C. v. Connor, 20 F.3d 1376, 1385 (5th Cir. 1994) (“If a plaintiff attempts to interject entirely different transactions or occurrences into a case, then relation back is not allowed.”). In McGregor v. Louisiana State University Board of Supervisors, for example, McGregor’s original complaint brought claims under the Rehabilitation Act based on his school’s alleged failure to reasonably accommodate his disability, which allegedly caused him to flunk out. 3 F.3d 850, 854 (5th Cir. 1993). Having 76 repeatedly petitioned to be re-admitted subject to special scheduling accommodations, McGregor later amended his complaint to add claims that the school had deprived him of due process by failing to provide a written procedure or policy for notifying him of his right to appeal the denial of those petitions. Id. at 863. However, the Fifth Circuit found that these claims did not relate back even though “[t]he original complaint [did] contain reference to McGregor’s requests for scheduling accommodations . . . .” Id. at 864. “The test,” the court noted, “is whether the original complaint apprised the Law Center of the due process claims [added to] the second amended complaint.” Id. (citing Holmes, 757 F.2d at 1566). In that case, while the original complaint “may [have] suggest[ed] that McGregor was not satisfied with the Law Center’s decisions, . . . it [did] not plead, even when liberally construed, that the Law Center’s decision-making process was inadequate under the Fourteenth Amendment Due Process Clause.” Id. In other words, “McGregor’s amendment attempted to add a new legal theory unsupported by factual claims raised in the original complaint.” Id.; see also Holmes, 757 F.2d at 1566 (holding that amended complaint did not relate back because, inter alia, the original and amended claims called for proof of different conduct by separate parties); In re Coastal Plains, Inc., 179 F.3d 197, 216 (5th Cir. 1999) (holding that Coastal Plains’ claim that a creditor interfered with business relations by attempting to sell Coastal Plains to a third party did not relate back to a claim 77 based on the creditor’s failure to return inventory to Coastal Plains, even though both claims were linked to the creditor’s alleged “broader plan to destroy Coastal [Plains]”). In the instant case, the Seismic Claims do not relate back to the Original Complaint, because the Original Complaint simply did not put EOG on notice regarding those claims. The subject of EnerQuest’s original suit was the continued validity of EnerQuest’s leases on certain land and the invalidity of the leases the Mineral Owners later executed with Dan Hughes. (Dkt. # 1 ¶¶ 1–2.) The allegations in the Original Complaint focused on the Leases’ provisions, EnerQuest’s alleged perfect compliance with those provisions, and the Defendants’ allegedly wrongful actions after the Leases’ primary terms expired. All of EnerQuest’s claims—breach of lease, suit to remove cloud and quiet title, and a request for declaratory relief (id. ¶¶ 33–40)—arose from the Mineral Owners’ alleged repudiation of the Leases. By contrast, the Seismic Claims stem entirely from a seismic trespass that allegedly took place before the Leases’ primary terms expired—before the Mineral Owners ever purported to execute new oil and gas leases with Dan Hughes—a time when all parties agree the Leases were in effect. This alleged seismic trespass was not mentioned at all in the Original Complaint. In fact, the Original Complaint makes no mention of any seismic exploration activities, 78 permits, or agreements, much less a specific seismic trespass perpetrated by EOG. In order to support the Seismic Claims, EnerQuest had to add completely new factual allegations to the SAC, expanding this lawsuit from one about whether the Leases had terminated to one also about a “three dimensional seismic program” and the right to “seismic data, including, but not limited to, field tapes, observer notes, geometry corrected gathers, CDP gathers, stacked and migrated data, interpretations of that data, and other information acquired and performed by Defendant EOG as a result of its [allegedly] unauthorized seismic operations on Plaintiffs’ land.” (SAC ¶¶ 32–33, 43–49.) EnerQuest argues that “the ‘transaction’ that gives rise to and is common to both Plaintiffs’ Seismic Claims and their Lease Claims against EOG is the EOG-Hughes Agreement.” (Dkt. # 131 at 7.) Pursuant to that agreement, claims EnerQuest, “EOG and Hughes performed the unauthorized seismic program . . . and Hughes acquired the Dan Hughes Leases, and Hughes assigned to EOG a fifty percent interest in the Dan Hughes Leases.” (Id.) Thus, “[w]hen the Plaintiffs filed their original complaint alleging the Lease Claims, which challenge the validity of the Dan Hughes Leases[,] owned fifty percent by EOG, EOG was put on notice that the ‘whole transaction’ that forms the basis for those claims—the EOG-Hughes Agreement—would be ‘fully sifted.’” (Id. (quoting Barthel v. Stamm, 145 F.2d 487, 491 (1944).) 79 EnerQuest’s argument is unavailing. The EOG-Hughes Agreement was not even expressly identified in the Original Complaint. Instead, the closest the Original Complaint came to mentioning any “agreement” between Hughes and EOG was in Paragraph 28, wherein EnerQuest merely noted that Hughes assigned EOG an undivided fifty-percent interest in the disputed leases. None of the Original Complaint’s allegations concerned the terms of this assignment or placed it in the context of a larger relationship between EOG and Dan Hughes. Instead, the Original Complaint mentioned the assignment from Hughes to EOG simply to establish why EOG purported to have an interest in the Leases. (See id. ¶¶ 35, 38.) The only allegation against EOG in the Original Complaint was that it “assert[ed] title and interest” to the Leases. (Id.) While there is some overlap between the lands involved in the alleged wrongful conveyance of the Leases and the lands involved in the Seismic Claims, these are plainly separate transactions or occurrences. The allegations supporting EnerQuest’s Lease Claims, which arise out of the allegedly wrongful conveyance from the Mineral Owners to Dan Hughes, did not put EOG on notice of the Seismic Claims, which are based on actions EOG allegedly took in violation of a separate seismic survey agreement with EnerQuest. Accordingly, the Seismic Claims do not relate back to the Original Complaint. 80 B. The General Discovery Rule Does Not Apply EnerQuest argues that, even if the Seismic Claims do not relate back, they are not barred by limitations because the discovery rule applies. (Dkt. # 131 at 7.) This argument also fails. “‘As a rule, . . . a cause of action accrues when a wrongful act causes some legal injury, even if the fact of injury is not discovered until later, and even if all resulting damages have not yet occurred.’” Murphy v. Campbell, 964 S.W.2d 265, 270 (Tex. 1997) (quoting S.V. v. R.V., 933 S.W.2d 1, 4 (Tex. 1996)). “Under this legal injury rule, the date of the legal injury is not the time the injury is discovered or the date when the actual damage is fully ascertained; rather, the date of legal injury is the date the wrongful act is committed and damage is suffered.” Hues v. Warren Petroleum Co., 814 S.W.2d 526, 529 (Tex. App. 1991) (citing Black v. Wills, 758 S.W.2d 809, 816 (Tex. App. 1988)). The Supreme Court of Texas has recognized that the “discovery rule” may apply to extend the statute of limitations. BP Am. Prod. Co. v. Marshall, 342 S.W.3d 59, 65 (Tex. 2011) (citing Computer Assocs. Int’l, Inc. v. Altai, Inc., 918 S.W.2d 453, 455–56 (Tex. 1996)). Under the discovery rule, “the cause of action does not accrue until the injury could reasonably have been discovered.” Id. (citing Computer Assocs. Int’l, 918 S.W.2d at 455–56; S.V. v. R.V., 933 S.W.2d 1, 4 (Tex. 1996)); see also Trinity River Auth. v. URS Consultants, Inc., 889 S.W.2d 81 259, 262 (Tex. 1994) (explaining that deferring accrual and thus delaying the commencement of the limitations period differs from suspending or tolling the running of limitations once the period has begun). The discovery rule applies only “if (1) the nature of the injury incurred is inherently undiscoverable and (2) the evidence of injury is objectively verifiable.” Beavers v. Metro. Life Ins. Co., 566 F.3d 436, 439 (5th Cir. 2009) (emphasis added) (citing Altai, 918 S.W.2d at 456; S.V. v. R.V., 933 S.W.2d 1, 6 (Tex. 1996)). If a claim fails either prong of this test, the discovery rule does not defer accrual of a cause of action. See id. (“Because the appellants’ injury from breach of contract was not inherently undiscoverable, we do not address whether it is objectively verifiable.”). “An injury is inherently undiscoverable if it is, by its nature, unlikely to be discovered within the prescribed limitations period despite due diligence.” Wagner & Brown, Ltd. v. Horwood, 58 S.W.3d 732, 734–35 (Tex. 2001). “The question is not whether the particular injury was actually discovered by the claimant within the limitation period, but whether ‘it was the type of injury that is generally discoverable by the exercise of reasonable diligence.’” Wells Fargo Bank Nw., N.A. v. RPK Capital XVI, L.L.C., 360 S.W.3d 691, 702 (Tex. App. 2012) (emphasis added) (quoting HECI Exploration Co. v. Neel, 982 S.W.2d 881, 886 (Tex. 1998)). “In other words, whether the discovery rule applies is determined on a categorical basis, because such an approach ‘brings predictability 82 and consistency to the jurisprudence.’” Id. (quoting Apex Towing Co. v. Tolin, 41 S.W.3d 118, 122 (Tex. 2001)). Texas courts have repeatedly rejected application of the discovery rule to claims involving oil and gas operations. (Dkt. # 131.) In HECI Exploration Co. v. Neal, for example, the plaintiffs, members of the Neel family, owned royalty interests under an oil and gas lease. 982 S.W.2d 881, 884 (Tex. 2001). Their lessee and operator, HECI Exploration Company, discovered that AOP, a producer on an adjoining lease, had damaged the common reservoir through overproduction. Id. HECI sued AOP in 1988, and obtained monetary and injunctive relief in the trial court. Id. HECI and AOP eventually settled the suit and filed a release of judgment. Id. The Neels sued HECI in 1994, more than four years after damage to the reservoir had occurred. Id. Among other things, they alleged that HECI had violated an implied covenant to notify them of the need to sue AOP. The Supreme Court of Texas assumed without deciding that such an implied covenant exists but held that the statute of limitations barred the claim, observing: As owners of an interest in the mineral estate, the Neels had some obligation to exercise reasonable diligence in protecting their interests. This includes exercising reasonable diligence in determining whether adjoining operators have inflicted damage. Royalty owners cannot be oblivious to the existence of other operators in the area or the existence of a common reservoir. In some cases, wells visible on neighboring properties may put royalty owners on inquiry. In any event, a royalty owner should determine whether a common reservoir underlies its lease because it knows or should know that, when there are other wells drilled in the reservoir, there is the potential for drainage or damage to the reservoir. 83 Id. at 866. Finding that damage to the common reservoir was not inherently undiscoverable, the court held that neither was the lessee’s failure to notify the Neels of their potential claims. Id. at 877. Similarly, in Taub v. Houston Pipeline Company, the court refused to apply the discovery rule to trespass claims concerning oil and gas operations, reasoning that those operations “involve[d] tangible things,” including “exploration activities occurring on the surface of the land,” that were “readily apparent by mere viewing.” 75 S.W.3d 606, 619 (Tex. App. 2002). Underlying the holdings of these cases is the idea that owners of oil, gas, and mineral interests have a duty to exercise reasonable diligence in protecting those interests. See Taub, 75 S.W.3d at 619–620 (“Diligence is required by the owner of the surface as to the operation of oil and gas leases, particularly where operation or lack thereof at the lease site is legally significant.”). In Neel, for example, the court “held [that] the owner’s obligation of due diligence went beyond mere passive visual observation, but also extended to inquiries of the lessees as to their activities.” Id. (emphasis added) (citing Neel, 982 S.W.2d at 886). Recognizing Texas courts’ aversion to applying the discovery rule to trespass claims involving oil and gas operations, EnerQuest argues that “unauthorized seismic operations should not be categorized with ‘oil and gas 84 operations’ for purposes of the application of the discovery rule.” (Dkt. # 131 at 11.) Seismic trespasses, insists EnerQuest, do not involve “frequent, numerous, or continuing physical activities that remain visible on the surface.” (Id. at 12.) “There are no visible physical injuries as to the land, as the survey is accomplished by trucks and receivers on the surface of the ground.” (Id.) The Court is unconvinced. Again, whether type of injury is inherently undiscoverable is a “legal question” and is “determined on a categorical basis.” Shell Oil Co. v. Ross, 356 S.W.3d 924, 930 (Tex. 2011) (emphasis added). The summary judgment evidence shows that seismic operations, as a class, do involve significant surface activities that are sufficient to alert a reasonably diligent lease holder of the possibility of a seismic trespass. EOG points to the deposition of testimony of David Frye, a veteran landman, who testified as follows regarding the circumstances surrounding seismic operations: [I]f you’re driving down the road, you’ll see the gates will be flagged with orange . . . ; you’ll see cables taped across the road where they’re working; you’ll see the -- the guys with the ATVs running around with cables on them, geophones on them. [. . .] [Y]ou’ll see the big . . . Vibroseis buggies, . . . , all-terrain vehicles with, you know, six- to eight-foot-tall tires and nothing but steel . . . . [T]hey can only put one on a semi at a time. So there’s lots of activity, lots of things out there. (Dkt. # 125 Ex. L at 163:3–21.) Mr. Frye testified that “cabling and geophones” are “always involved in the seismic shoot” and that “crews are [generally] 25 to a hundred people or maybe more . . . to operate on a daily basis.” (Id. at 161:14–25.) 85 The evidence shows that to prepare for the seismic survey, EOG’s contractors flagged the gate, cut back brush across the property, and laid cables for the geophones across the entire tract, operations that took place for several days before the Vibroseis trucks performed shoots. (Dkt. # 125 Ex. L at 160:21–163:21.) Until the foliage that had been cut down grew back, it too provided evidence of EOG’s entry onto the leased lands. EnerQuest does not seem to dispute the general proposition that seismic shoots require crews to enter the land to cut brush, lay cable for geophones, and drive large buggies around the property; instead, it argues that the seismic trespass alleged in this case would have involved far fewer people due to the relatively small amount of land involved. (See Dkt. # 131 at 9.) “EOG fails to note with particularity Mr. Frye’s testimony regarding the ‘few people’ who might have been on the properties described in the Leases during EOG’s trespass,” insists EnerQuest. (Id.) Again, however, this is beside the point: Whether a type of injury is inherently undiscoverable is determined on a categorical basis, and the evidence shows that seismic operations, as a class, involve physical trespasses onto the property, alteration of the property (e.g., cutting back brush and laying cable), and visible operations. These kinds of operations simply are not “inherently undiscoverable.” Compare Taub, 75 S.W.3d at 619 (holding that trespass claims concerning oil and gas operations were not inherently undiscoverable because they 86 “involve[d] tangible things,” including “exploration activities occurring on the surface of the land,” that were “readily apparent by mere viewing”), with Wells Fargo Bank Nw. N.A., 360 S.W.3d at 702 (holding that “the category of cases in which a lessee lawfully in possession of a lessor’s property secretly sells or transfers the lessors property to a third party, but continues to comply with its obligations under the lease” was inherently undiscoverable). Because seismic operations are not inherently undiscoverable, the discovery rule does not apply to defer the accrual of causes of action arising out of EOG’s allegedly unauthorized seismic operations. C. Even Assuming EOG’s Alleged Seismic Trespass Caused “Permanent” Damages, EnerQuest’s Claims Are Untimely Finally, EnerQuest argues that there is a “discovery rule ‘built in’ to claims for injury to property under Texas law” and that this rule permits a plaintiff to bring an action for “permanent” damages within two years of discovery of the injury. (Dkt. # 131.) Arguing that “[t]he damages here are permanent” because the land’s potential for mineral production has been revealed, EnerQuest insists that it had to bring suit within two years of discovering that EOG had committed a seismic trespass—that is, within two years of June 2011. (Id. at 8.) EnerQuest is correct that Texas law distinguishes between permanent and temporary damages to land. However, even assuming that the allegedly 87 unauthorized seismic survey caused EnerQuest “permanent” damages, this distinction does not save EnerQuest’s untimely Seismic Claims. “Permanent injuries to land give rise to a cause of action for permanent damages, which are normally measured as the difference in the value of the property before and after the injury.” Bayouth v. Lion Oil Co., 671 S.W.2d 867, 868 (Tex. 1984). By contrast, “[t]emporary injuries give rise to temporary damages, which are the amount of damages that accrued during the continuance of the injury covered by the period for which the action is brought.” Id. As the Supreme Court of Texas explained in Schneider National Carriers, Inc. v. Bates, “[a] permanent nuisance claim accrues when injury first occurs or is discovered,” but “a temporary nuisance claim accrues anew upon each injury.” 147 S.W.3d 264, 270 (Tex. 2004). Thus, “[w]hile a cause of action for permanent injury to land must be brought within two years, damages for temporary injury to land may be recovered for the two years prior to filing suit.” ACCI Forwarding, Inc. v. Gonzalez Warehouse P’ship, 341 S.W.3d 58, 63–64 (Tex. App. 2011) (emphases added) (citing Bayouth v. Lion Oil Co., 671 S.W.2d 867, 868 (Tex. 1984)). The distinction between permanent and temporary damages does not, as EnerQuest seems to suggest, allow a plaintiff to avoid the strict requirements of the discovery rule: that the injury be one that is both inherently undiscoverable and objectively verifiable. See Jones v. Texaco, Inc., 945 F. Supp. 1037, 1043 (S.D. 88 Tex. 1996) (noting that the discovery rule does not delay accrual of a cause of action “when permanent damage to land is not ‘inherently undiscoverable’” (citing Hues, 814 S.W.2d at 529)). In other words, while the Supreme Court of Texas stated that an action for permanent damages accrues “upon discovery of the first actionable injury,” Bayouth, 671 S.W.2d at 868 (emphasis added), it was not discarding the more general rule that an injury is “knowledge of facts that could cause a reasonably prudent person to make an inquiry that would lead to discovery of the cause of action is ‘in the law equivalent to knowledge of the cause of action for limitation purposes.’” Mitchell Energy Corp. v. Bartlett, 958 S.W.2d 430, 436 (Tex. App. 1997). Instead, the court was merely contrasting the more restrictive rule for permanent injuries (i.e., that the action accrues as soon as the plaintiff knew or should have known of the injury) with the less restrictive rule for temporary damages, which permits a plaintiff to recover any damages that were incurred within two years of filing suit—the reasoning being, again, that “a temporary nuisance claim accrues anew upon each injury.” ACCI Forwarding, Inc., 341 S.W.3d at 63–64 (Tex. App. 2011) (citing Schneider, 147 S.W.3d at 270); see also Marty’s Food & Wine, Inc. v. Starbucks Corp., No. 05-01-00008-CV, 2002 WL 31410923, at *7 (Tex. App. Oct. 28, 2002) (“If this action arises from a temporary injury, Marty’s timely filed this suit. Conversely, if this suit is for permanent injuries, it is barred by the statute of limitations.”). In other words, a 89 plaintiff bringing a claim for permanent damages is not entitled to wait until “the extent of the damages to the land [is] fully ascertainable.’” Hues, 814 S.W.2d at 529 (quoting Bayouth Lion Oil Co., 671 S.W.2d at 868). For the reasons given above, seismic operations are not inherently undiscoverable, and the discovery rule does not apply to delay the accrual of the cause of action until EnerQuest actually knew of the alleged trespass. Additionally, in this particular case, EOG’s communications with EnerQuest’s president, Greg Olson, put EnerQuest on inquiry notice of the alleged trespass. In January of 2010, EOG informed Olson, in an email, that EOG intended to conduct “another” seismic shoot in Karnes County, Texas, and that the acreage covered by EnerQuests’s Brysch and Moy Leases were inside the intended shoot lines. (See Dkt. # 125 Ex. E.) The email stated: Hi Greg, I spoke to you before the holidays about our 3D seismic shoot that we permitting [sic] for EOG Resources. I have attached two leases and a plat of the tracts that are within our shoot lines and are leased to EnerQuest and Chieftain. I know that you and Roger Motley of EOG had worked together on a mineral permit for tracts in another shoot in Karnes County, and was hoping that we could work on a permit for this shoot as well. Please give me a call or email after you have had a chance to review the attached information and we can discuss further. Thank you very much. Bernie Dwyer 90 (Id. (emphasis added).) The “two leases” to which the email refers are the Leases at issue in this case: the Brysch and Moy Leases. (Id.) Then, in May of 2010, EOG’s Roger Motley informed Mr. Olson that both of the seismic shoots that EOG had planned for Karnes County (called “Karnes 3D” and “Typhoon 3D”) were at that time being conducted simultaneously, as one shoot. (Dkt. # 125 Ex. B.) While this second email did not explicitly state that the Typhoon 3D shoot included land covered by the Leases, and while Olson would not necessarily have known exactly which lands were included within the Typhoon 3D project, he had enough information to be put on inquiry notice as to a potential seismic trespass. First, Olson was aware that the Karnes 3D shoot, pursuant to an agreement between EnerQuest and EOG, covered certain lands EnerQuest had leased. Second, Olson knew that EOG had requested permission to conduct “another” shoot on the land covered by the Brysch and Moy leases. And finally, Olson received an email in which EOG talked about performing a second shoot on additional acreage (“We are currently in the process of the Karnes 3D shoot, which is being shot together with our Typhoon acreage as one shoot.” (Dkt. # 125 Ex. B)). Such facts, in addition to the physical manifestations of a seismic shoot described above (cutting brush, laying cable, driving Vibroseis buggies, etc.), would have alerted a reasonably diligent oil and gas leasehold owner that a seismic trespass may have occurred. Accordingly, 91 EnerQuest’s Seismic Claims accrued no later than July 2010, when the last of the seismic shoots took place. Because EnerQuest filed its Motion for Leave to File Second Amended Complaint on November 30, 2012, more than two years after the alleged seismic trespasses occurred, these claims are barred by the two-year statute of limitations. Accordingly, the Court GRANTS EOG’s Motion for Partial Summary Judgment on Plaintiffs’ Seismic Claims. (Dkt. # 125.) III. Motion for Leave to File Third Amended Complaint On June 10, 2013, EnerQuest filed an Opposed Motion for Leave to File Third Amended Complaint. (Dkt. # 107.) EnerQuest stated that it “only recently discovered evidence, after Defendant [PXP] resisted disclosure, linking PXP to the claims Plaintiffs have pleaded against [EOG] for trespass, assumpsit, and injunctive relief related to unauthorized seismic operations on land covered by Plaintiffs’ leases (the ‘Seismic Claims’).” (Id. ¶ 1.) In light of this allegedly newly discovered evidence, EnerQuest moves to file a Third Amended Complaint adding PXP as a Defendant in the Seismic Claims. (Id.) For the reasons given in the preceding section, EnerQuest’s Seismic Claims are barred by limitations. Accordingly, it would be futile to permit EnerQuest to amend its complaint to add PXP as a defendant in those claims. See Foman v. Davis, 371 U.S. 178, 182 (1962) (listing factors that justify denying 92 leave to amend a complaint, including the “futility of amendment”). EnerQuest’s Motion (Dkt. # 107) is DENIED. IV. Motion to Sever On June 3, 2013, PXP filed an Opposed Motion to Sever. (Dkt. # 105.) The motion seeks to sever EnerQuest’s Seismic Claims—which at the time the motion was filed were brought only against EOG—from the Lease Claims EnerQuest has brought against all Defendants. (Dkt. # 105 ¶ 1.) PXP insists that severance is proper because EnerQuest’s Seismic Claims (1) are distinct and separate from the Lease Claims and should not have been joined in a single lawsuit, and (2) the claims for seismic trespass should be tried separately in the interests of justice, to promote judicial economy, and to avoid jury confusion. (Id. ¶ 3.) Because the Court has concluded that the Seismic Claims are barred by limitations, the need for severance has been obviated. Accordingly, the Court DENIES AS MOOT PXP’s Motion to Sever. (Dkt. # 105.) CONCLUSION For the foregoing reasons, the Court GRANTS the Mineral Owners’ Motion for Partial Summary Judgment (Dkt. # 126); DENIES PXP’s Motion for Partial Summary Judgment (Dkt. # 113) and EOG’s motion joining and adopting it (Dkt. # 124); DENIES EnerQuest’s Motion for Partial Summary Judgment 93 (Dkt. # 122); GRANTS EOG’s Motion for Partial Summary Judgment on Plaintiffs’ Seismic Claims (Dkt. # 125); DENIES AS MOOT PXP’s Motion to Sever (Dkt. # 105); and DENIES EnerQuest’s Motion for Leave to File Third Amended Complaint (Dkt. # 107). IT IS SO ORDERED. DATED: San Antonio, Texas, November 7, 2013. _____________________________ David Alan Ezra Senior United States District Judge 94
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