Our firm represented the Opielas in two cases involving a Magnolia horizontal well in Karnes County: a suit against Magnolia in Karnes County, and a suit against the Texas Railroad Commission in Travis County. In both cases the Opielas contended that Magnolia had no right to drill a horizontal well located partly on their land.
Because this was a significant case addressing allocation and PSA wells, this post will go into the somewhat complex facts and history in some detail.
The Opielas’ lease covers some 640 acres; they acquired the property subject to an old existing lease that was held by production from vertical wells. Enervest and Magnolia drilled some horizontal EagleFord wells located wholly on the lease. The old lease provided for 1/8 royalty, and 3/4 of the royalty had been reserved or transferred to other owners long before Enervest acquired the lease, so the Opielas owned only 1/4 of 1/8 royalty. But the old lease prohibited pooling for oil wells. Enervest sought a lease amendment permitting pooling, but they were not able to reach agreement with the Opielas.
Enervest sought a permit for its Audioslave well in 2018, seeking a permit for an “allocation well”– a horizontal well that crosses lease boundaries without pooling the leases. The Opielas immediately filed a protest to the permit. Other landowners had previously protested permits for allocation wells, and in those proceedings the Commission, overruling the recommendation of its own administrative law judges, had determined that, until a court concluded that such wells are not authorized by landowners’ leases, it would issue such permits. So the Commission issued the Audioslave permit before granting the Opielas a hearing, and Enervest drilled the well despite the Opielas’ pending protest. The Opielas also sued Magnolia in Karnes County, challenging its right to drill the well.
Enervest then assigned its leases to Magnolia Oil & Gas. Magnolia completed the well and filed for an amended permit, this time for a “Production-Sharing” or PSA well. The Commission had previously agreed to issue permits for wells that cross lease boundaries if the operator had agreements (Production Sharing Agreements) from at least 65% in interest of the mineral and royalty owners in each tract crossed by the wellbore. The Opielas also protested this permit. After a hearing, the Commission granted the permit. (Magnolia also filed a pooled unit designation for the well; most of the royalty owners in the Opiela tract signed ratifications of the pooled unit, and Magnolia presented these ratifications as proof that it had agreements from at least 65% of the owners in the Opiela tract to drill the well.)
Appeals from an administrative order were at the time filed in district court in Travis County as an administrative appeal, based on the record of the hearing at the administrative agency. The Opielas filed an appeal in Travis County in 2020, challenging the Commission’s right to grant Magnolia’s permit for the Audioslave well. They also filed a motion for summary judgment in their suit against Magnolia in Karnes County.
In Travis County, the Opielas argued that the Commission had no authority to issue Magnolia’s permit because it had not adopted formal rules for issuance of PSA Well permits in compliance with Texas’ Administrative Procedures Act (APA). They also argued that Magnolia had not presented evidence showing that it had a good-faith claim of right under the Opielas’ lease to drill its well.
On May 12, 2021, the Travis County District Court ruled that (1) the Commission had violated the APA by adopting rules for allocation and Production Sharing Well permits without a formal rulemaking; (2) the Commission erred in concluding it has no authority to review the Opielas’ lease terms in judging whether the permit applicant has a good-faith claim of right to drill the well; and (3) the Commission erred in finding Magnolia showed a good-faith claim of right to drill its well. The Commission and Magnolia appealed that judgment to the Austin Court of Appeals.
On June 30, 2023 the Austin Court of Appeals issued its opinion, reversing the trial court and remanding the case to the Commission. It held that Magnolia had not violated the Opielas’ no-pooling provision because “a lack of pooling authority alone does not prohibit drilling under a PSA.” The Court also held, however, that the Commission erred in granting Mangolia’s PSA permit because Magnolia had not obtained Production Sharing Agreements from at least 65% in interest of the royalty owners in the Opiela lease, but instead relied on consents to pool; the Court held that, under the Commission’s informal rules then in place, Production Sharing Agreements were required. Notably, the Court did not rule on whether, in adopting these informal rules, the Commission had violated the APA. (In the meantime, the Opielas’ motion for summary judgment in its Karnes County case, filed in 2020, remained pending.)
The Opielas filed a petition for review in the Texas Supreme Court in November 2023. Without granting their petition, the Court asked the parties to file briefs on the merits, which the parties did. Before the Supreme Court could act on the Opielas’ petition, the parties settled.
The Opielas’ case addressed only the PSA permit obtained by Mangolia, and so did not directly address allocation wells. But operators will undoubtedly point to the Court of Appeals’ opinion to support its argument that no agreement is needed from a mineral owner to drill a horizontal well located partly on their property without pooling. The Court of Appeals’ failure to address whether the Commission has violated the APA without first adopting APA-compliant rules for issuing allocation well an PSA well permits leaves that issue unresolved.
Because of the potential precedential value of the Court of Appeals’ opinion, I think it is good to review how we have arrived at the present moment on the important as-yet unresolved issues surrounding allocation wells.
Over the last two decades, the oil and gas industry has undergone dramatic changes. Magnolia refers to these changes as “the horizontal drilling revolution.” But while the industry has undergone revolutionary change, the rules that regulate the industry have not. Rather than issuing rules as required by the APA and the Commission’s own enabling statute (see Tex. Nat. Res. Code § 85.201 (“The commission shall make and enforce rules”)), the Commission has informally adopted a hodgepodge of requirements that are difficult to pin down and that frequently undergo informal changes. As two prominent commentators have explained in their treatise: “an understanding of PSA and allocation wells is hidden in the arcana of Railroad Commission forms, rejected staff Proposals for Decision, individual well permits and disclaimers, and legislative committee proposals.” Ernest E. Smith & Jacqueline Lang Weaver, 2 Tex. Law of Oil & Gas § 9.9(B) (emphasis added). Because of its failure to adhere to APA rulemaking requirements, the permitting requirements for horizontal wells evolved in a way that was hidden from public participation and prejudices the rights of lessors like the Opielas. The Commission’s decision was based on improperly adopted policies, and the district court correctly reversed.
The practice of combining multiple tracts into a single drilling unit—“pooling”—has been around for decades. The practice arose as a direct result of the Commission’s well-spacing and density rules. Over the decades, the Commission has adopted APA-compliant rules that protect landowners like the Opielas from unauthorized pooling. The modern practice of combining multiple tracts into drilling units for “PSA wells” and “allocation wells,” however, arose outside the APA framework.
The history of pooling smaller tracts into larger drilling units.
In the early days of oil and gas production, there was little knowledge of reservoir formations and their drive mechanisms. See A.W. Walker, Jr., Preface to Leo J. Hoffman, Voluntary Pooling & Unitization iii, iii-iv (Matthew Bender & Co. 1954). Thus, those early days were fraught with “chaotic and wasteful conditions that resulted from the overproduction of flush fields.” Id. at iv. To prevent waste from overproduction of fields, Texas—through the Commission—issued rules that regulate well spacing, well density, and allowable production. For example, under Commission statewide rules, a well cannot be closer than 1,320 feet from another well, and a drilling unit (the acreage assigned to a well) can be no less than 40 acres in size. See Robert E. Hardwicke, Oil-Well Spacing Regulations and Protection of Property Rights in Texas, 31 Tex. L. Rev. 99, 99 (1952). Similarly, to preserve reservoir characteristics, the Commission places limits on daily allowable production—i.e., the amount of hydrocarbons an operator can produce in a day. Id. Generally, larger drilling units get larger daily allowables. See Atlantic Refining Co. v. R.R. Comm’n of Tex., 346 S.W.2d 801, 811 (Tex. 1961) (holding that a proration formula that favored small tracts was invalid).
These regulations created problems for operators that leased tracts too small to accommodate a regulation-sized drilling unit or too small to be given a profitable daily allowable. One way to address this problem is by combining separate tracts into a single drilling unit. This combination or aggregation of multiple tracts became known as “pooling.” The term “pooling” quickly became a part of the oil and gas vernacular. One commentator, writing in 1952, defined it as follows: “[t]he term ‘pool’ or ‘pooling,’ . . . as commonly used by members of the petroleum industry, means the integration of areas and interests in order to form a drilling unit or to permit the location of a well so that it may be drilled in compliance with a spacing regulation.” Hardwicke, 31 Tex. L. Rev. at 100; see also Smith & Weaver, Tex. Law of Oil & Gas § 4.8 (“Pooling occurs when tracts from two or more leases are combined for purposes of drilling a single well.”). When separate tracts are pooled, a single well is deemed to drain minerals from all the pooled tracts and the owners of each tract are allocated a share of the production based on their pooling agreement. See, e.g., Se. Pipe Line Co. v. Tichacek, 997 S.W.2d 166, 170 (Tex. 1999) (citing Southland Royalty Co. v. Humble Oil & Ref. Co., 249 S.W.2d 914, 916 (Tex. 1952)).
Some states, in an effort to maximize production and minimize unnecessary wells, have gone so far as to compel operators and mineral owners to pool separate tracts into drilling units. See 6 Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil & Gas Law § 905.2 (surveying state compulsory pooling statutes). With one exception not applicable to this case, Texas has never adopted a compulsory pooling statute. See Ernest E. Smith, The Texas Compulsory Pooling Act, 43 Tex. L. Rev. 1003, 1004 (1965). And Texas courts have held that mineral owners cannot be compelled to pool their separate tracts. See Jones v. Killingsworth, 403 S.W.2d 325, 328 (Tex. 1965) (“The orders of the Railroad Commission cannot compel pooling agreements that the parties themselves do not agree upon.”).
Because Texas does not have compulsory pooling, an oil and gas lessee cannot pool a tract unless the lessee has express authority from the lessor. Browning Oil Co. v. Luecke, 38 S.W.3d 625, 634 (Tex. App.—Austin 2000, pet. denied) (citing Tichacek, 997 S.W.2d at 170).
The Commission’s APA-compliant regulations recognize that a lessee cannot pool without the lessor’s consent. When a lessee seeks a permit to drill a well on a pooled unit, the lessee must represent to the Commission that it has “appropriate contractual authority” to pool the tracts, and the lessee must submit a “Certificate of Pooling Authority.” 16 Tex. Admin. Code § 3.40(a). This Court has held that the Commission should deny permit applications when the applicant fails to show pooling authority. Cheesman v. Amerada Petroleum Corp., 227 S.W.2d 829, 832 (Tex. Civ. App.—Austin 1950, no writ).
The advent of horizontal drilling has required more pooling.
For most of the oil and gas industry’s history, oil and gas have been produced by traditional wells drilled in a vertical orientation. But some formations, in particular tight shale formations, are better produced using horizontal drilling and hydraulic fracturing. These relatively new technologies have allowed operators to produce from previously uneconomic formations. But because horizontal wellbores extend horizontally for miles from the surface location, it is often impossible to drill a horizontal well within a single tract. That is, horizontal wellbores often need to cross lease boundaries. See Bret Wells, Allocation Wells, Unauthorized Pooling, and the Lessor’s Remedies, 68 Baylor L. Rev. 1, 8–9 (2016). Thus, the need to combine multiple small tracts into larger drilling units has become increasingly important. See Smith & Weaver, 2 Tex. Law of Oil & Gas § 9.9(B) (noting that, while a 640-acre unit is a square mile, horizontal wellbores are sometimes three miles long).
To create larger drilling units that accommodate horizontal wellbores, the industry has used different legal theories. The first is uncontroversial. Lessees can create pooled units to accommodate a wellbore that traverses multiple tracts. This is done pursuant to contractual pooling authority and the well-known requirements for pooled-unit drilling permits under Statewide Rule 40. 16 Tex. Admin. Code § 3.40(a). As discussed above, because Texas does not have compulsory pooling except in very limited circumstances, a lessee needs express authority from its lessor to create a pooled unit. In fact, this Court has held that a lessee breached its lease by drilling a horizontal well across multiple tracts without a valid pooling agreement. Browning, 38 S.W.3d at 640–42; see also Wells, 68 Baylor L. Rev. at 13 (“[T]he lessee does not have authority to drill a multi-tract well except where specifically authorized by the pooling clause of the lease.”).
The industry, however, decided that negotiating for pooling authority with its lessors was too inconvenient and began searching for ways to permit multi-tract horizontal wells without having to negotiate with its lessors.
The Commission started issuing permits for PSA wells and informally adopting requirements for PSA wells.
Initially, the only way to obtain a permit for a multi-tract horizontal well was by creating a pooled unit and complying with Rule 40. That is still the only Commission rule that discusses combining multiple tracts “for the purpose of creating a drilling unit.” 16 Tex. Admin. Code § 3.40(a). This rule created problems in fields that already had a patchwork of existing pooled units. See Smith & Weaver, 2 Tex. Law of Oil & Gas § 9.9(B). In those fields, the extant pooled units often applied to all depths. Few leases authorize “unpooling,” so operators could not undo the pooled units and create new ones. But the horizontal wells needed a different pooled unit pattern than the original field. Thus, lessees needed a way to combine existing pooled units. They accomplished this by drafting production sharing agreements (“PSA”). A PSA, as its name implies, is an agreement between the owners as to how production from a well will be shared among the different tracts within the drilling unit. Because early PSA wells combined multiple pooled units into a larger drilling unit, Professors Smith and Weaver refer to PSA drilling units as “super-pooled units.” (“[PSAs] promote efficient oil and gas development on a joint basis by combining several pooled units into one larger one that can accommodate the length of the horizontal interval.”).
Without adopting any APA-compliant rules, the Commission began issuing permits for PSA wells. At first the Commission issued permits only when 100% of the owners within the proposed drilling unit had signed a PSA. But in 2008, Devon Energy applied for a PSA well permit after obtaining less than 90% agreement of interest owners. The Commission voted 2-1 to approve the permit and to instruct its staff to issue permits when at least 65% of the interest owners have signed PSAs. Since then, the Commission has used this 65% threshold as a bright-line rule when determining whether to issue a PSA well permit, but the threshold appears nowhere in the Commission’s APA-compliant regulations. The 65% threshold is particularly important in the Opielas’ case because Magnolia claims it satisfied the threshold with a 65.625% sign-up.
The Commission rejected allocation wells and then reversed course.
The 65% threshold for PSA wells, however, proved too inconvenient for some operators. Lessees began requesting permits for multi-tract horizontal wells with no PSAs. Initially the Commission rejected these entreaties. But eventually it reversed course and began issuing permits for “allocation wells,”—multi-tract wells with no agreements from mineral owners as to how production will be allocated.
In September 2009, Devon Energy petitioned the Commission for a fieldwide rule that would have allowed it to drill horizontal wells across lease or unit boundaries “as long as the operator has a lease or other mineral ownership right to produce from each such unit or lease.” Under its proposed “allocation rule,” Devon would allocate production among the tracts according to a formula. In a proposal for decision (“PFD”), Commission hearings examiners noted that the proposed rule would allow drilling across lease boundaries “without the agreement of any royalty or working interest owners.” The examiners recommended rejecting the proposed rule: “Although Devon may argue that it is not pooling portions of existing units, this is, in fact, what it is doing.”
Devon is not the owner of the minerals under the various tracts it operates . . .. It is the lessee and its rights are controlled by the terms of the leases it took from the owners of the minerals. Devon itself acknowledges that those lease terms do not authorize it to pool the tracts as it desires. Devon is seeking a Commission field rule that would endorse its desires to effectively amend terms of its agreements with the mineral owners, authorize it to combine the tracts and direct that the mineral owners be paid in a manner different than is provided in the lease contracts. Such a field rule would be unprecedented in Commission practice and would far exceed the Commissions statutory authority.
The Commission signed a final order approving the PFD on December 15, 2009.
The Commission later reversed course and began issuing permits for allocation wells. See 2013 Commission memo stating: “Most recently, operators have been obtaining drilling permits without the existence of any agreement between the interest holders.”. It is unclear when the Commission began issuing permits for allocation wells. Part of this uncertainty is because of the Commission’s failure to adhere to the APA. Or as Professors Smith and Weaver explain:
The informal, PSA/allocation well permitting system was becoming a standard part of the Railroad Commission’s decision-making, even though no fieldwide or statewide rule authorized such. This situation may have developed so quietly because royalty interest owners did not receive notice of the permit applications for PSA or allocation wells, so the permitting process was largely hidden from their view.
Smith & Weaver, 2 Tex. Law of Oil & Gas § 9.9(B).
It did not take long, however, for landowners to begin voicing their concerns about the silent degradation of their rights at the Commission. Yet the validity of PSA and allocation wells has escaped judicial review until now.
The Klotzman Case
In 2013, a group of mineral owners (the Klotzmans) challenged the validity of an allocation well permit on their land. This was the first contested case challenging the Commission’s authority to issue allocation well permits. The lessee and other industry intervenors argued to the Commission that pooling authority is unnecessary when the lessee has leases on every tract that would comprise the multi-tract unit. The Klotzmans argued that the Commission lacked the authority to issue permits for allocation wells and that doing so violated existing Commission rules. The Texas General Land Office—the steward of 13 million mineral acres for the State of Texas—intervened and argued that allocation wells are “effectively pooling.”
The hearings examiners agreed with the Klotzmans and the GLO, and recommended that the permit application be denied “for lack of proper pooling authority and consequent lack of good faith claim to drill the proposed well.” The examiners also concluded that there was “no Texas statute, Commission Statewide Rule or Commission Final Order authorizing ‘allocation’ wells.” The examiners stated that if the lessee wanted to include the Klotzmans’ land in a multi-tract unit, it had one choice: “negotiation in good faith with the lessors for their retained property interest, which is pooling authority for oil.”
But a proposal for decision is just that, a proposal. The Commission rejected the PFD in Klotzman. With no explanation, the Commission overruled the examiners and approved the allocation-well permit. While Klotzman was pending, they and a group of owners petitioned the Commission to commence a formal rulemaking under the APA addressing allocation wells; the Commission refused. The Klotzmans appealed to the district court, but the case settled soon after.
After Klotzman, there were other challenges to PSA/allocation wells, but each one either settled or became moot when the applicant withdrew the permit application.
Proposed legislation addressing allocation wells
Following the uncertainty created by Klotzman, there was a concerted effort to pass legislation that would authorize allocation/PSA wells. The Legislature has considered at least four bills that would allow such wells. Each has failed.
Most significantly, in 2015 the Legislature considered passing a law that would have allowed allocation wells. Tex. H.B. 1552, 84th Leg., R.S. (2015). The statute would have allowed a lessee, “unless expressly prohibited by a lease,” to “drill, operate, and produce oil or gas from an oil or gas well that traverses multiple tracts.” Id. In the absence of a pooling agreement or PSA, the proposed law would have allowed lessees to determine how much production to allocate to each separate tract. Id.
House Bill 1552 did not pass. The bill faced significant opposition from landowner groups. And perhaps more importantly, the University of Texas System Administration and the General Land Office—both of which oversee vast swaths of state-owned minerals—filed a fiscal note stating that the bill would result in a substantial reduction to the state’s income from its oil and gas producing properties. Fiscal Note, Tex. H.B. 1552, 84th Leg., R.S. (2015). The UT System stated that the bill would allow “certain oil and gas operators and lessees the ability to make mineral and surface ownership decisions without UT System agreement.” The bill “would also allow lessees to determine the allocation of production and pay royalties on that basis on applicable [Permanent University Fund] lands without UT System input.” The UT System determined that, if passed, the bill would result in a revenue loss of $390 million per fiscal year. The GLO determined that the bill could result in a loss of $100 million per fiscal year to GLO lands.
Similar bills failed in 2013, 2017, and 2021. Tex. H.B. 100, 83rd Leg., R.S. (2013); Tex. S.B. 177, 85th Leg., R.S. (2017); Tex. S.B. 367, 87th Leg., R.S. (2021) (as amended, H.J. of Tex., 87th Leg., R.S. 3670 (2021)).
Today most operators who want to drill multi-tract horizontal wells obtain allocation well permits, even though they may also obtain production sharing agreements from mineral owners. If an operator does not request a PSA, most mineral owners don’t learn of the drilling of an allocation well on their property until they receive a division order.In most cases the operator calculates each royalty owner’s interest based on lateral length–the royalty owner’s interest in their tract time a fraction, the numerator of which is the number of lateral feed on their tract and the denominator of which is the total productive lateral length. Generally no explanation is given for how the operator calculated the interest, and mineral owners are forced to inquire of the operator if they want to verify their interest on the division order. Even though there is no agreement with the royalty owner for this method of allocation, operators refuse to pay royalty unless and until the royalty owner signs and returns the division order, thereby in effect agreeing to the allocation well. Some mineral owners may be fine with this; but if a royalty owner wants to contest the allocation method they must do so without being paid. Allocation wells may also affect how much acreage is retained under lease under a pooling clause or retained acreage clause in the lease. Careful negotiations of these clauses are simply ignored when the allocation well is drilled.
I have represented land and mineral owners in oil and gas matters for more than 40 years. In my opinion the Commission’s acquiescence in the industry’s adoption of allocation wells has severely eroded mineral owners’ rights. Leases I now negotiate for mineral owners routinely prohibit allocation wells without lessors’ consent, as do the leases granted on University lands and Texas Relinquishment Act lands. In my view allocation wells are a form of forced pooling, without the necessary legislation to protect the rights of mineral owners. The development of allocation wells has sadly eroded Texas’ reputation for protecting the rights of land and mineral owners.
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