On Petition for Review from the Court of Appeals for the Fourth District of Texas Argued September 13, 2023 CHIEF JUSTICE HECHT delivered the opinion of the Court, in which Justice Lehrmann, Justice Boyd, Justice Devine, Justice Blacklock, Justice Bland, and Justice Huddle joined. JUSTICE YOUNG filed a dissenting opinion, in which Justice Busby joined. Oil and gas can migrate or “drain” through a permeable formation into a vertical wellbore some distance away to be produced at the surface. In an impermeable shale formation, the minerals drain only through hydraulically created fractures in the formation radiating out from a horizontal wellbore over a shorter distance. The rule of capture “gives a mineral rights owner title to the oil and gas produced from a lawful well bottomed on the property, even if the oil and gas flowed to the well from beneath another owner’s tract.”[1] The rule “is a cornerstone of the oil and gas industry and is fundamental both to property rights and to state regulation.”[2] An owner concerned that a neighbor’s well is draining his property can drill an offset well to prevent the drainage[3] or offer to pool the properties to share in the production from the well. If agreement cannot be reached, he can apply to the Railroad Commission for forced pooling under the Texas Mineral Interest Pooling Act (MIPA or the Act).[4] The minerals in the present case lie in the impermeable Eagle Ford shale in a reservoir beneath a riverbed and land on both sides. Horizontal wells produce from the land beside the river but cannot be drilled entirely within the area beneath the riverbed itself because it is narrow and winding. The wells beside the river do not drain the minerals beneath the river because the fracking does not reach them, and their owner complains that without pooling, they are left stranded. With pooling, the riverbed owner would participate in production from the riverside wells but without contributing to it, unlike usual pooling with a vertical well. The Commission rejected applications to force-pool the minerals beneath the river—which are not being produced—with those beside it—which are. The lower courts affirmed the Commission’s order,[5] as do we, but for different reasons than the court of appeals gave. I A The State owns the minerals beneath its more than 80,000 miles of navigable rivers and waterways. The General Land Office leases these mineral interests to private parties. Royalties from production are dedicated to the permanent school fund,[6] which funds public K-12 education statewide. Ammonite Oil & Gas Corporation is a family business that, according to its owner, William Osborn, “focuses on [acquiring] State riverbed leases and stranded State tracts, [and] getting them included in adjacent pooled units.” “Stranded” minerals are those that cannot be extracted from a tract with usual production methods due to the tract’s size, configuration, and location. Ammonite acquires riverbed leases from the State and then offers to pool them with adjacent interest owners, thereby allowing production from the leases through drainage that would not otherwise be possible. The benefit of increased production to all interest owners in the pool incentivizes drilling that does not leave the State’s minerals stranded. Ammonite profits from its pooling, as does the State, which has greatly benefited from Ammonite’s efforts. Osborn testified that Ammonite holds “about 60″ riverbed leases statewide, has made “nearly 150″ pooling offers involving hundreds of wells, and has worked out voluntary pooling agreements in all but four cases. In this case, voluntary pooling agreements could not be reached because the lessee of the minerals beside the riverbed tract refused pooling on the ground that its wells do not drain the riverbed. B When pooling agreements cannot be reached, MIPA gives the Commission limited authority to order pooling of interests in a common reservoir. MIPA is “unique[] compared to the compulsory pooling acts of other states”[7] because it requires an applicant to make a good-faith effort to form a voluntary-pooling agreement with the other interest owners in the proposed unit before the Commission will entertain an application. “The obvious intent of the legislature” in crafting MIPA was “to encourage voluntary pooling”, and so it “is more aptly described as ‘an Act to encourage voluntary pooling—rather than an Act to provide compulsory state action.’”[8] “The spirit of the act” is “shown by the requirement that an applicant must exhaust all efforts at contractual agreements before compulsory pooling can be obtained”.[9] Section 102.013(a) requires an applicant to “set forth in detail the nature of voluntary pooling offers made to the owners of the other interests in the proposed unit.”[10] “The commission shall dismiss the application if it finds that a fair and reasonable offer to pool voluntarily has not been made by the applicant.”[11] Otherwise, the Commission proceeds to determine whether forced pooling is appropriate under the Act. Section 102.011 sets out the Commission’s authority to issue a forced-pooling order. Preliminarily, there must be “two or more separately owned tracts of land . . . in a common reservoir . . . for which the commission has established the size and shape of proration units”; there must be separate interest owners within an existing or proposed unit who “have not agreed to pool their interests”; and it must be that “at least one of the owners . . . has drilled or has proposed to drill a well on the existing or proposed proration unit”.[12] If these prerequisites are satisfied, then “for the purpose of avoiding the drilling of unnecessary wells, protecting correlative rights, or preventing waste,” the Commission “shall” order pooling.[13] Section 102.017(a) provides that “all orders effecting the pooling shall be made on terms and conditions that are fair and reasonable and will afford the owner or owners of each tract or interest in the unit the opportunity to produce or receive his fair share.”[14] The Commission’s final order is subject to judicial review under the substantial-evidence standard in the Administrative Procedure Act.[15] C In January 2015, the General Land Office leased Ammonite the oil and gas beneath a winding stretch of the Frio River in McMullen County some 30 feet wide and 7 miles long, about 21 acres in all. The State reserved a 25% royalty, with Ammonite required to pay development and production costs out of its 75% working interest. EOG Resources, Inc. leases the minerals on the land adjoining the river on both sides. All the minerals in the area lie in a common subsurface reservoir, the Eagleville (Eagle Ford-1) Field. The Eagleville is impermeable shale from which oil and gas can be produced only by horizontal drilling. At the time Ammonite acquired its lease, EOG had permits for, and was somewhere in the process of drilling, 16 wells in the area—11 on one bank and 5 on the other. Between April and October 2015, Ammonite sent EOG a series of letters proposing the formation of 16 pooled units—one corresponding to each well. Ammonite attached to each offer letter the drilling plat for the corresponding well that EOG had filed with the Commission as part of its permit application. Each letter references “the existing well on the proposed unit” and “proposes that EOG contribute to the unit the acreage approximately as shown on [the] plat and outlined in yellow.” Each letter includes the approximate surface acreage for each party’s contribution to the proposed unit and a rough, narrative description of its location. The drilling plats show that none of EOG’s wells, as permitted, would reach the riverbed. None of Ammonite’s letters suggested that any well be modified to access riverbed minerals. Since all production would be from EOG’s leases and none from Ammonite’s, proceeds from the pool could not be allocated on the basis of the parties’ respective contributions to production. Instead, Ammonite proposed that proceeds be allocated based on each party’s leased acreage in the pool. Ammonite proposed to pay its share of production costs from its share of royalties, along with an additional “risk penalty”. A “risk penalty” is a charge on a nonoperator working-interest owner to ensure that the economic risk assumed by the operator in drilling and completing a well is reasonably shared by all who stand to benefit. MIPA requires that a forced-pooling order include “a charge for risk not to exceed 100 percent of the drilling and completion costs.”[16] For that reason, a risk penalty is commonly proposed in a voluntary-pooling offer though not statutorily required.[17] Ammonite’s offer letters to EOG provided for a 10% risk penalty “or such greater penalty as may be prescribed by the Railroad Commission if a[] MIPA case should have to be adjudicated before that agency.” EOG rejected Ammonite’s offers, citing the terms of its leases prohibiting it from accepting any voluntary-pooling offer.[18] EOG also considered the offers not to be fair and reasonable because, since none of its wells could reach the minerals beneath the riverbed, Ammonite was proposing to share in production from EOG’s wells without contributing to it. As EOG explained: Any recoverable oil and gas that may exist beneath Ammonite’s lease will remain beneath its lease regardless of any pooling of the acreage into EOG’s producing wells. The sole effect of force pooling in these cases would be to transfer the revenues from oil and gas produced entirely from EOG’s leases and units to Ammonite. D Ammonite filed 16 MIPA applications with the Commission, one for each proposed unit, and the parties proceeded to a consolidated contested-case hearing on all applications.[19] By the time of the hearing in January 2017, each well was completed, and none was draining the riverbed tract. Ammonite’s counsel announced in his opening statement to the hearing examiners that “Ammonite [would] not . . . put on a technical case, and . . . [would] not put on evidence that [EOG is] draining the riverbed” because Ammonite’s position is that MIPA “does not require drainage.” All MIPA requires, according to Ammonite, is “that the tract with which you seek to pool is embraced in a common reservoir with the unit for the existing well.” Ammonite argued that two of MIPA’s bases for requiring forced pooling with EOG’s wells applied: to prevent waste and protect correlative rights.[20] Ammonite called only one witness, its owner, Osborn, who testified as a fact witness about Ammonite’s business and its voluntary-pooling offers to EOG. Osborn testified that he chose 10% for his risk-penalty offer because Professor Ernest Smith of The University of Texas School of Law “suggests that as a minimum one should offer 10 percent.” Osborn testified that his letters also specified his willingness to pay any penalty prescribed by the Commission to convey that “whatever [the Commission] think[s] is fair works for me.” Ammonite’s counsel asked Osborn about the feasibility of drilling his own horizontal well to drain the riverbed minerals included in his lease. He testified that he had not “seen an instance where an operator has been able to drill a horizontal well that meanders along the course of the river”. Asked whether he “[thought] it would be possible” to drill such a well, the examiners sustained EOG’s objection that the opinion “is . . . not an opinion that a layman can give.” EOG argued that, as a matter of law, Ammonite’s offers were not fair and reasonable—and MIPA does not authorize forced pooling— because EOG’s wells do not drain the riverbed. Ammonite, EOG argued, is “asking the owners of all of the oil and gas under our tract from which the oil is being produced from all 16 wells, to give up a part of that oil or gas to a tract that’s not contributing anything.” EOG put on one witness, petroleum engineer Tim Smith, who testified as an expert. Smith explained that “the Eagle Ford formation is an unconventional resource play” with unique “reservoir and rock characteristics.” Specifically, the shale in the Eagle Ford Field has “ultralow permeability”, such that “there’s no flow through the reservoir rock unless there’s a fracture”. This means that “[h]orizontal drilling and hydraulic fracture stimulation techniques are required if the wells are going to have a chance at commerciality.” “Any individual well and resource play”, Smith said, “is anything but a sure thing. The nature of these reservoir rocks is they’re extremely heterogeneous”. Although “[m]ost wells will succeed in establishing production”—absent a mechanical failure, “there won’t be any dry holes”—”not all wells will generate enough revenue after drilling, production, [and] stimulation . . . to return those costs and a profit for the operator.” To be successful in an unconventional resource play like the Eagle Ford Field, an operator must drill “a whole portfolio” of wells, and the wells must be “optimal[ly] spac[ed]” with respect to the operator’s lease line and one another to “ maximiz[e] recovery and prevent[] waste to the greatest extent possible.” Smith noted that “EOG has 500,000 acres in the resource play” and its success will be determined “at the portfolio level”, not by any individual well. Smith elaborated that ultimate commercial success in a resource play like the Eagle Ford Field requires “[i]mmense capital investment in leasehold expense, acquired drilling expertise, acquired completion expertise, scientific data accumulation, experimentation, and technology development.” Those capital costs to understand the “science in a particular basin” amount to hundreds of millions of dollars, Smith stated. For that reason, Smith testified, “a risk factor of 100 percent is appropriate for a single well in a[] MIPA proposal.” About whether the riverbed minerals could ultimately be recovered, Smith testified that while none of EOG’s existing 16 wells are capable of draining the minerals, they could possibly be recovered in the future. “You cannot draw the conclusion . . . that these minerals . . . are stranded and will not be recovered”, Smith stated. “[I]t is very conceivable . . . that under the right economic climate, after there’s more development out here, that . . . technology would find a way to do that. And so [recovery] is not a foregone conclusion.” “[H]orizontal wells of a commercially viable drainhole length could be drilled” to reach the riverbed minerals “[u]nder the right economic conditions,” Smith testified, although “a different economic climate with higher oil prices” would probably be needed. E The hearing examiners recommended approval of 15 of Ammonite’s applications.[21] The Commission rejected the examiners’ proposal for decision, giving two reasons: “Ammonite failed to make a fair and reasonable offer to voluntarily pool as required by [MIPA Section 102.013]“, and “[f]orce pooling will not prevent waste, protect correlative rights, or avoid the drilling of unnecessary wells as required by [MIPA Section 102.011].”[22] The Commission found that formation of the proposed pooling units would not “access or produce any of the hydrocarbon reserves under Ammonite’s adjacent riverbed tracts” and that “Ammonite offered no . . . evidence of drainage” of its minerals by EOG’s wells. Ammonite does not contest these findings but argues that pooling is required to prevent its minerals from being stranded, resulting in waste. Ammonite filed a petition for judicial review. The trial court issued an order denying the petition and ruling that Ammonite take nothing, noting that “there is more than a scintilla of evidence to support the findings and decision” of the Commission. The court of appeals affirmed, holding only that because Ammonite’s pooling offers proposed a 10% risk factor when Smith testified without contradiction that a 100% risk factor would be appropriate, substantial evidence supports the Commission’s finding that Ammonite’s offers were not fair and reasonable.[23] We granted Ammonite’s petition for review. II We first consider whether Ammonite’s pooling offers to EOG were fair and reasonable. Because MIPA requires the Commission to “dismiss” an application if it finds that a fair and reasonable voluntary-pooling offer has not been made,[24] our older cases referred to this initial inquiry as jurisdictional.[25] Since then, “we have been clear . . . that the question whether a [party] has . . . ‘satisfied the requisites of a particular statute’ pertains ‘in reality to the right of the [party] to relief rather than to the . . . jurisdiction of the [tribunal] to afford it.’”[26] Satisfying the Commission that a fair and reasonable offer was made is merely the first of two hurdles an applicant must clear to obtain a forced-pooling order under MIPA. It is not a prerequisite to the Commission’s jurisdiction. MIPA does not define a fair and reasonable offer to pool.[27] “Reasonable minds may, of course, differ on what constitutes a fair and reasonable offer.”[28] It “must be one which takes into consideration those relevant facts, existing at the time of the offer, which would be considered important by a reasonable person in entering into a voluntary agreement concerning oil and gas properties.”[29] But absent a statutory definition, a decision whether an offer is fair and reasonable “is left to the commission’s discretion.”[30] The decision must only be supported by substantial evidence[31]—”a limited standard of review that gives significant deference to the agency in its field of expertise.”[32] “At its core, the substantial evidence rule is a reasonableness test or a rational basis test.”[33] “The commission’s application of the statutory term to the facts in each case is conclusive, unless it is unreasonable.”[34] A The Commission did not explain why Ammonite’s pooling offers were not fair and reasonable, and two of its observations have proven misleading. First, the Commission noted in its findings that “Ammonite did not provide survey data or a metes and bounds description of the riverbed to establish the precise acreage to be force pooled into any of the [16] wells.” Ammonite complains that the finding is irrelevant because no more detailed description of the area to be pooled was required. But Ammonite suggests that an inadequate description played a role in the Commission’s denial of the applications. There was no complaint, and the Commission did not indicate, that the omissions made the pooling offers confusing or uncertain. To the contrary, Ammonite supplied plats showing where EOG’s wells were located and what acreage was proposed to be pooled. Both the Commission and EOG argue here that Ammonite’s applications were denied because of the effect of the pooling offers, not the imprecise boundaries of the proposed units. Ammonite’s concerns about this finding are misplaced. Second, the Commission’s findings note that “[a]t the hearing, Ammonite agreed with a greater charge for risk than the 10% listed in its voluntary pooling offer[s] . . . if the Commission recommended same.” The court of appeals concluded that Ammonite’s willingness to agree to a higher risk penalty and Smith’s testimony that the penalty should be 100% show that Ammonite’s offers of a 10% penalty were not fair and reasonable when made. But the court’s conclusion cannot be squared with the text of Ammonite’s offers, which were for a 10% penalty “or such greater penalty as may be prescribed by the Railroad Commission”. And the court’s conclusion cannot be squared with the lack of any requirement that a pooling offer include a risk penalty at all. Understandably, the Commission has not undertaken here to defend the court’s conclusion. There is no evidence that EOG rejected Ammonite’s pooling offers because of the proposed risk penalty, especially when Ammonite was willing to pay any penalty the Commission determined was appropriate.[35] B So why did the Commission conclude that Ammonite’s offers were not fair and reasonable? Because they were based solely on EOG’s wells as permitted, which did not drain Ammonite’s riverbed tract, and Ammonite made no effort to show that it was possible for EOG to redo its drilling plans or extend existing wells to reach the riverbed. Thus, as EOG argued, it is undisputed that Ammonite proposed to obtain a share of EOG’s production without Ammonite’s contributing any minerals of its own. Section 102.017(a) of MIPA requires that pooling orders afford each interest owner “the opportunity to produce or receive his fair share.”[36] The offer Ammonite made required it to produce nothing and EOG’s lessors to receive less, which the Commission could consider unfair on its face. Further, Smith testified that commercial success in the Eagle Ford Field requires a massive capital investment. Because of the field’s geological characteristics, “any single well[] carries a significant inherent risk of commercial failure.” For EOG to give Ammonite a share of production would only increase the risk that these wells would not generate enough revenue to cover costs and return a profit. The Commission’s conclusion here is also consistent with one of its prior decisions, upheld in Railroad Commission of Texas v. Broussard.[37] There, the Commission’s order dismissed a pooling application under Section 102.013 because the evidence showed that the offerees’ wells were not draining the offeror’s minerals at the time the offer was made.[38] The opinion quotes the Commission’s order as stating that “[t]he critical factor to be considered as regards Broussard’s offer being fair and reasonable from the protestants’ view point is that their well is not draining the Broussard tract at present”.[39] While discussing Broussard, notable commentators on Texas oil and gas law observed that “[i]t is unfair to let an applicant share in production from a well that does not drain any oil or gas from the applicant’s tract.”[40] Ammonite argues that its offers must be viewed in the context of the time they were made, when most of the 15 wells at issue had not been spudded, much less completed. From a map of the wells’ locations vis-à-vis the riverbed, Ammonite asserts that “it would have required little additional drilling for each well to reach the riverbed tracts”. In fact, the completion status of each well at the time the offers were made is hotly contested, but the Commission did not have to resolve that dispute because Ammonite’s offers were based solely on the wells as permitted, which the letters referred to as “existing” and “recently drilled”. The letters do not mention the possibility of extending any well. When EOG responded that “no well [is] actually capable of draining Ammonite acreage” and, thus, pooling to reduce its own share of production would not be fair and reasonable, citing Broussard, Ammonite offered no technical solution.[41] For these reasons, we hold that the Commission’s conclusion that “Ammonite failed to make a fair and reasonable offer to voluntarily pool as required by [MIPA Section] 102.013″ is reasonable. C The dissent faults EOG for refusing to negotiate a pooling agreement with Ammonite.[42] The evidence is that the parties communicated their respective positions at some length. After Ammonite filed its applications with the Commission but before the hearing, EOG’s counsel wrote to review their course of dealing. The parties, he said, had engaged in “a number of emails and other discussion[s] over the past year or more relating to [Ammonite's] proposals”. To summarize, he wrote, “EOG respectfully declines” Ammonite’s offers because of “the fact that none of EOG’s wells are capable of draining any portion of Ammonite’s leasehold.” Ammonite’s minerals could not be pooled with EOG’s because EOG could not access them. “[L]ack of drainage”, he wrote, “is of controlling importance.” Ammonite has not disputed that EOG’s wells could not access its minerals. It stipulated to that fact before the Commission. Offering to pool with EOG minerals it could not access was not reasonable. The only possible way to form a pool was for EOG to modify or extend its wells, or drill additional wells, to reach the riverbed. If that were Ammonite’s proposal, it would have been required to demonstrate that such operations were feasible. It did not do so, and there was evidence it could not do so. The dissent complains that the Commission’s order was not more discursive. But the obstacle to Ammonite’s pooling proposals was simple and unavoidable. No further explanation was required. The dissent’s insistence on more from the Commission is inconsistent with Ammonite’s burden of proof and the deferential substantial-evidence review this Court is bound to apply. If the Commission was authorized to compel EOG to modify or increase its wells to access the riverbed, it could do so only if access was possible. To be reasonable, Ammonite’s pooling offers must have shown that it was possible. They did not.[43] III Having concluded that Ammonite did not make a fair and reasonable pooling offer, the Commission was required to dismiss Ammonite’s application for forced pooling under Section 102.013. But the Commission went further[44] and addressed Ammonite’s application under Section 102.011, concluding that Ammonite’s request would not prevent waste or protect correlative rights, the two statutory bases for requiring forced pooling that Ammonite invoked.[45] Thus, we do not end our analysis with the terms of Ammonite’s offers but examine whether the Commission’s interpretation of MIPA as applied to this case is correct. Ammonite argues that this case presents “a narrow legal question—whether proof of drainage is required to obtain MIPA pooling to ‘prevent waste’”. Ammonite contends that if proof of drainage is not required, then the location and completion of EOG’s wells leaves the riverbed minerals stranded, resulting in waste and requiring pooling. In this Court, the Commission assumes Ammonite’s minerals are stranded but asserts that granting Ammonite’s applications will not prevent waste or protect correlative rights. We disagree that Ammonite has correctly stated the issue before us. It is not whether the Commission could ever force-pool stranded minerals like Ammonite’s even though they were not being drained. The Commission has refused to foreclose that result. Rather, the issue is whether the Commission could have concluded in the circumstances presented in this case that forced pooling would not prevent waste—or relatedly, protect correlative rights—given the undisputed lack of drainage of Ammonite’s minerals by EOG’s wells. “Waste” is defined by statute to include “loss incident to or resulting from drilling, . . . locating, spacing, or operating a well or wells in a manner that reduces or tends to reduce the total ultimate recovery of oil . . . from any pool”.[46] “Pool” is defined as “a common reservoir.”[47] The parties agree that their minerals are in a common reservoir in the Eagleville Field.[48] “Correlative rights guarantee a mineral interest owner an opportunity to produce a ‘fair share’ of the reserves underlying his land.”[49] Ammonite’s stranded minerals cannot presently be produced because EOG has located and completed its wells in such a way that they do not reach the riverbed. Without forced pooling with EOG’s wells, Ammonite reasons, its minerals are stranded—wasted—and it cannot produce its fair share of the minerals in the reservoir shared with EOG’s minerals. But a forced-pooling order could not, at the time the Commission reached its decision, have prevented waste. The Commission made no finding about whether the riverbed minerals are stranded, but if they are, a forced-pooling order would not change that fact because, as the Commission’s order states, “the wells have been drilled and are producing; they do not and will not produce riverbed minerals.” The Commission likewise could have concluded that a forced-pooling order would not protect Ammonite’s correlative rights. Ammonite’s right to all the minerals beneath the riverbed was undisturbed by EOG’s wells. However, neither Ammonite nor EOG could produce them given the location of EOG’s wells. The Commission does not concede that forced pooling is beyond its power. It contends that forced pooling is not required in these circumstances when EOG is not depriving Ammonite of its minerals. Ammonite argues that EOG, in seeking permits for its 16 wells, should have proposed that they be located and drilled to extend beyond its lease boundaries and into the riverbed. Ammonite does not suggest that its property could be invaded without its consent, nor did it offer to consent when making its pooling offers while EOG was permitting and completing its wells. As the Commission points out, Ammonite never offered technical evidence showing that drilling and completing EOG’s wells differently to reach the riverbed minerals was feasible, reasonable, or economically viable.[50] EOG argues that the Commission’s spacing rules would have precluded drilling its wells as Ammonite suggests.[51] Tim Smith also testified that because of the low permeability of rock in the Eagle Ford Field, to achieve commercial success, an operator must space its wells optimally with respect to one another and its lease line. Ammonite responds that the Commission may grant an exception to spacing rules when one is necessary to prevent waste.[52] But Ammonite points to no authority requiring an operator to seek a spacing exception for the purpose of preventing a neighbor’s minerals from being stranded, especially if doing so could result in a failure to maximize production of the operator’s own minerals. Finally, Ammonite argues that a pooling order allowing it to share in production would prevent waste by incentivizing EOG now to drill new wells or rework its existing ones, allowing production of the riverbed minerals as part of the pool. The Commission’s refusal to stretch its limited authority to force pooling this far is consistent with past decisions and not unreasonable. The Broussard court, before affirming the Commission’s order dismissing Broussard’s MIPA application, observed that “the Commission based its decision primarily on the fact that, although recovery operations might cause drainage to occur sometime in the future, no gas was being drained” from Broussard’s tract at the time the pooling offer was made.[53] Ammonite’s theory also contravenes MIPA’s policy of “avoiding the drilling of unnecessary wells”.[54] Commentators have explained that “if an additional well is necessary to drain the acreage sought to be forcibly pooled, then pooling should also be denied because pooling would not avoid the drilling of unnecessary wells” or further another statutory policy.[55] Ammonite, as the MIPA applicant, had the burden of proof to demonstrate to the Commission the technological and economic feasibility of reworking EOG’s wells to reach the riverbed, which it did not do. Ammonite argues that the case should be remanded to the Commission for additional evidence and findings regarding the viability of extending or altering EOG’s wells going forward to access the riverbed minerals. But Ammonite chose to present its applications for pooling without such changes. The Commission fully decided the issues presented by the applications and evidence. A remand to give Ammonite the chance to present a different case is not appropriate. Waste “reduces or tends to reduce the total ultimate recovery of oil . . . from any pool”.[56] There is no evidence that Ammonite’s minerals cannot ultimately be produced. The evidence is to the contrary. Tim Smith testified that while it may not presently be possible to drill a horizontal well within the confines of a winding riverbed, changes in technology and markets may make such drilling viable. “You cannot draw the conclusion”, he stated, that Ammonite’s minerals are stranded and “will not be recovered.” Ammonite criticizes Smith’s testimony as “beyond speculative”, but Ammonite—the party with the burden of proof before the Commission—failed to put on any expert testimony of its own. Ammonite has failed to show that forced pooling of its acreage with EOG’s wells is necessary to prevent its minerals from ultimately being lost. Ammonite applied for a share of EOG’s revenue without contributing to it. The Commission’s conclusion that forced pooling would not prevent waste or protect correlative rights is not unreasonable. * * * * * The judgment of the court of appeals affirming the Commission’s final order is affirmed. Nathan L. Hecht Chief Justice OPINION DELIVERED: June 28, 2024
