Supreme Court of Texas

══════════

No. 21-1035

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Ammonite Oil & Gas Corporation,

Petitioner,

v.

Railroad Commission of Texas and EOG Resources, Inc.,

Respondents

═══════════════════════════════════════

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 
2

“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 drainage3 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 

1 Coastal Oil & Gas Corp. v. Garza Energy Tr., 268 S.W.3d 1, 13 (Tex. 

2008).

2 Id.

3 See id. at 14 (“The rule of capture is justified because a landowner can 

protect himself from drainage by drilling his own well, thereby avoiding the 

uncertainties of determining how gas is migrating through a reservoir.”).

4 TEX. NAT. RES. CODE §§ 102.001-102.112.
3

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 

5 672 S.W.3d 33 (Tex. App.—San Antonio 2021).

6 See TEX. NAT. RES. CODE § 11.041(a)(1) (“In addition to land and 

minerals granted to the permanent school fund under the constitution and 

other laws of this state, the permanent school fund shall include . . . the 

mineral estate in river beds and channels . . . .”); see also TEX. CONST. art. VII, 

§§ 2, 5 (providing for the permanent school fund).
4

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 

7 R.R. Comm’n of Tex. v. Pend Oreille Oil & Gas Co., 817 S.W.2d 36, 40 

(Tex. 1991).

8 Id. (quoting Ernest E. Smith, The Texas Compulsory Pooling Act, 43 

TEXAS L. REV. 1003, 1009 (1965)).

9 Ernest E. Smith, The Texas Compulsory Pooling Act, 44 TEXAS L. REV.

387, 391 (1966).
5

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 

10 TEX. NAT. RES. CODE § 102.013(a).

11 Id. § 102.013(b).

12 Id. § 102.011.

13 Id.

14 Id. § 102.017(a).
6

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.” 

15 See id. § 102.111 (“A person affected by an order of the commission 

adopted under the authority of this chapter is entitled to judicial review of that

order in a manner other than by trial de novo.”); TEX. GOV’T CODE § 2001.174 

(providing that if the law authorizing judicial review of a decision in a 

contested case “does not define the scope of judicial review” then the 

substantial-evidence standard applies).
7

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.”

16 TEX. NAT. RES. CODE § 102.052(a).

17 See Am. Operating Co. v. R.R. Comm’n of Tex., 744 S.W.2d 149, 153 

(Tex. App.—Houston [14th Dist.] 1987, writ denied) (“There is no statutory 

requirement that an offer to voluntarily pool contain a risk penalty.”).
8

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 

18 EOG does not argue that the no-pooling clause in its lease would 

override the Commission’s statutory authority to force-pool EOG’s minerals. In 

this opinion, we assume without deciding that EOG’s contractual prohibitions 

against pooling would not prevent the Commission from force-pooling EOG’s 

minerals under MIPA.

19 MIPA does “not apply to land owned by the State of Texas nor to land 

in which the State of Texas has an interest directly or indirectly”, TEX. NAT.

RES. CODE § 102.004(a), but the State can consent to the statute’s application, 

id. § 102.004(d), and Ammonite obtained the consent of the Commissioner of 

the General Land Office to file its applications.
9

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—

20 See id. § 102.011.
10

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 
11

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 

21 One of the 16 proposed units would have contained 550 acres, 

exceeding the maximum size under MIPA. Id. (stating that a pooled unit “shall 

in no event exceed 160 acres for an oil well . . . plus 10 percent tolerance”). 
12

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 

22 As noted above, Ammonite does not argue that a forced-pooling order

would avoid the drilling of unnecessary wells.

23 672 S.W.3d at 41.
13

“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 

24 TEX. NAT. RES. CODE § 102.013(b).

25 See Pend Oreille, 817 S.W.2d at 40 (“If the commission finds that the 

applicant did not make a qualifying offer, it lacks jurisdiction over the 

petitioner’s application and must dismiss it.” (citing Carson v. R.R. Comm’n of 

Tex., 669 S.W.2d 315, 318 (Tex. 1984))).

26 Pike v. Tex. EMC Mgmt., LLC, 610 S.W.3d 763, 774 (Tex. 2020) 

(quoting Dubai Petroleum Co. v. Kazi, 12 S.W.3d 71, 76-77 (Tex. 2000)).

27 One provision states that an offer by an interest owner “within an 

existing proration unit to share on the same yardstick basis as the other 

owners within the existing proration unit are then sharing shall be considered

a fair and reasonable offer.” TEX. NAT. RES. CODE § 102.013(c). Another states

that an “offer to pool . . . is not considered fair and reasonable if it provides for 

an operating agreement containing” certain enumerated terms. Id. § 102.015. 

Neither provision applies here.

28 Pend Oreille, 817 S.W.2d at 40.
14

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 evidence31—“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 

29 Carson, 669 S.W.2d at 318.

30 Pend Oreille, 817 S.W.2d at 40.

31 Id. at 42 (stating that “courts must apply the substantial evidence 

rule” in Section 2001.174(2)(E) of the Administrative Procedure Act when 

reviewing the Commission’s decision under Section 102.013 of MIPA).

32 R.R. Comm’n of Tex. v. Torch Operating Co., 912 S.W.2d 790, 792 

(Tex. 1995).

33 Pend Oreille, 817 S.W.2d at 41.

34 Id. at 42.
15

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 
16

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 

35 In the dissent’s view, the court of appeals’ risk-penalty analysis is the 

specific issue that warranted our granting Ammonite’s petition for review. Post

at 1 (Young, J., dissenting). Now that we have concluded that analysis was 

wrong, the dissent would have us end our review here and remand the case to 

the court of appeals, thereby condemning the parties to additional years of 

litigation and their associated costs. Yet we frequently address issues the court 

of appeals did not reach in the interest of judicial economy. Because the 

remaining issues in this case are fully briefed and their resolution clear, 

judicial economy supports our making this Court the final stop for this 

litigation.

36 TEX. NAT. RES. CODE § 102.017(a).
17

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

37 755 S.W.2d 951 (Tex. App.—Austin 1988, writ denied). 

38 Id. at 952-954.

39 Id. at 953.

40 3 ERNEST E. SMITH ET AL., TEXAS LAW OF OIL AND GAS § 12.3[B][1] at 

12-38 (LexisNexis Matthew Bender 2023).

The dissent criticizes our citation to Broussard. Broussard is one of the 

only published judicial decisions in Texas—maybe the only one—involving 

comparable facts. We cite it to show that the Commission’s position here is 

consistent with the position it took four decades ago, which is surely a factor 

that goes towards the reasonableness of the Commission’s decision in this case.
18

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 

41 Cf. Carson, 669 S.W.2d at 318 (observing that the offeror’s “refus[al] 

to negotiate” because “it did not feel obligated to do so” is inconsistent with 

Section 102.013, which requires “a bona fide attempt to reach a contractual 

agreement” (quoting Smith, supra note 9, at 393 (third quotation))).

42 After all, the dissent observes, Ammonite had made many successful 

voluntary-pooling offers before. But Ammonite has not argued, and there is no 

evidence, that any of those offers involved horizontal wells incapable of 

reaching riverbed minerals, like EOG’s.
19

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 
20

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 further44 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 

43 A 100% risk penalty would not have made Ammonite’s offers 

reasonable. In claiming otherwise, the dissent relies on a paraphrasing of Tim 

Smith’s testimony that takes it out of context. See post at 11 (Young, J., 

dissenting). Smith did not testify that including a 100% risk penalty would 

have transformed Ammonite’s offers into reasonable ones under MIPA. Smith 

testified that because of the risk that any individual well drilled in the Eagle 

Ford will not return enough revenue to offset its costs, “a risk factor of 100 

percent is appropriate for a single well in a[] MIPA proposal.”

44 As we explained in Part II, the requirement of a fair and reasonable 

offer affects the applicant’s right to relief—not the Commission’s jurisdiction 

to grant it. No jurisdictional issue is presented in this case, and it is well within 

the Commission’s discretion to address the requirements of both 

Section 102.013 and Section 102.011 to promote efficiency by eliminating the 

need for a second round of administrative adjudication after judicial review.

45 TEX. NAT. RES. CODE § 102.011. Ammonite did not argue that forced 

pooling with EOG would avoid the drilling of unnecessary wells, the third basis 

for pooling under MIPA.
21

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 

46 Id. § 85.046(a)(6); see also Gulf Land Co. v. Atl. Refin. Co., 131 S.W.2d 

73, 80 (Tex. 1939) (“The term ‘waste,’ as used in oil and gas Rule 37, 

undoubtedly means the ultimate loss of oil.”). 

47 TEX. NAT. RES. CODE § 85.001(a)(2). 

48 Tim Smith testified that no geographical formations separated 

Ammonite’s riverbed minerals in the field from EOG’s.
22

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 

49 R.R. Comm’n of Tex. v. Lone Star Gas Co., 844 S.W.2d 679, 683 n.2 

(Tex. 1992) (quoting Texaco Producing, Inc. v. Fortson Oil Co., 798 S.W.2d 622, 

624 (Tex. App.—Austin 1990, no writ)).
23

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.

50 The dissent acknowledges that Ammonite had the burden of proof on 

this issue and “shares [our] doubt” that Ammonite carried it. Post at 26 (Young, 

J., dissenting). But the dissent faults the Commission for failing to make a 

finding on an issue that Ammonite did not present, and going further, would 

remand to the Commission to give Ammonite a do-over.

51 See 16 TEX. ADMIN. CODE § 3.37(a)(1) (statewide spacing rule 

prohibiting an oil well from being “drilled nearer than 467 feet to any property 

line[] [or] lease line”). Through field rules, the Commission can make different 

spacing requirements for a particular field than are in the statewide rule. See 

Torch Operating Co., 912 S.W.2d at 791.

52 See 16 TEX. ADMIN. CODE § 3.37(a)(1) (stating that “the commission, 

in order to prevent waste or to prevent the confiscation of property, may grant 

exceptions to” the statewide rule).
24

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 

53 755 S.W.2d at 953.

54 TEX. NAT. RES. CODE § 102.011.

55 3 SMITH ET AL., supra note 40, § 12.3[A][6], at 12-28.
25

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.

56 TEX. NAT. RES. CODE § 85.046(a)(6).
26

* * * * * 

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