VIII. Ohio
A. Judicial Developments
1. Lease and Royalty Disputes
In Gateway Royalty II, LLC, v. Gulfport Energy Corp., Ohio’s Seventh District Court of Appeals affirmed a trial court decision granting summary judgment to payees of overriding royalty interests (ORRIs) on their claim that the producer breached the ORRIs by deducting post-production costs. The parties’ contract granted an “an overriding royalty, free and clear of all cost and expense of development and operation.” Additionally, the contract provided that “[t]he overriding royalty interest conveyed shall be free and clear of all drilling, development, and operating expenses,” but would bear its share of certain other expenses, including severance taxes, fuel, and oil and gas used for treating production to make it merchantable. Over the producer’s objections that it was relying on erroneous dicta, the appeals court applied a definition of “overriding royalty interest” cited by earlier Ohio decisions to mean
[A] fractional interest in the gross production of oil and gas under a lease in addition to usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing, and other costs incident to the production and sale of oil and gas produced from the lease.
The appeals court held that “this definition excludes deductions for all expenses for the entire process of extracting, processing, and selling the oil and gas.” Nonetheless, the court held that “though overriding royalties are generally cost-free, parties to an overriding royalty contract ‘can agree to any manner of cost sharing they choose.’” Here, however, the court found that the parties did not contract around the cost-free definition of an ORRI. Namely, the contract provided that the ORRI would be expressly free of “operating expenses,” which the court defined to mean “expenses required to keep the business running, e.g., rent, electricity, heat. Expenses incurred in the course of ordinary activities of an entity.” “It is apparent that [the producer’s] claimed post-production costs are operating expenses,” the court found. The court also accepted the ORRI payees’ claim that parol evidence supported applying that definition to the disputed ORRIs.
In Kirkbride v. Antero Resources Corp., the lessor filed a class action complaint alleging that the lessee breached an oil and gas lease by improperly calculating royalty payments. The lessee moved to dismiss, contending that the lessor did not satisfy the lease’s pre-suit notice provision, which provided that service of such notice “shall be a condition precedent to the commencement” of an action for breach of the lease. Finding that the lessor failed to comply with the provision before suing, the trial court dismissed the complaint. On further appeal, the Sixth Circuit affirmed. The appeals court rejected the landowner’s argument that service of her complaint constituted sufficient notice. Rather, “the Lease expressly required pre-suit notice” that service of the complaint occurred after the lessor filed her suit, and thus “by definition, it cannot be pre-suit notice.”
In Hogue v. PP&G Oil Company, LLC, Ohio’s Seventh District Court of Appeals considered whether an “assignment of working interest” applied to the deep rights leased under an oil and gas lease. That assignment stated:
That the undersigned, [PP&G], … does hereby assign, transfer, sell and convey unto [the appellees] an undivided 2.5% working interest in and to [certain wells drilled to approximately 2,500 feet in depth] and the related 20 acre drill site unit, together with the rights incident thereto and the personal property therein.
The appeals court held the deep rights did not transfer to the appellees:
There is no dispute that the Ohio Administrative Code section in effect when the Assignment was executed limited 20-acre drilling units to depths of 4,000 feet. Insofar as [a]ppellees do not dispute the deep rights at issue in this case are below 4,000 feet, … we find the Assignment is unambiguous and … limited [a]ppellee’s working interest in the oil and gas to a maximum depth of 4,000 feet.
2. Trespass
In Tera, L.L.C. v. Rice Drilling D, L.L.C., the Supreme Court of Ohio addressed whether a lessee had the right to drill in the Point Pleasant formation. The lease granted the lessee the right to drill “in the formations commonly known as the Marcellus Shale and the Utica Shale.” The lessor expressly reserved all rights “in all formations below the base of the Utica Shale.” The lessor argued that the lessee committed a trespass by drilling in the Point Pleasant formation because it reserved the rights in that formation. The trial court granted summary judgment in favor of the lessor on the issue of liability and the Seventh District Court of Appeals affirmed. The Seventh District Court of Appeals also affirmed the trial court’s finding that the lessee committed a “bad faith trespass,” and held that the lessors were entitled to the full market value of the extracted gas without deduction for the cost of labor and other expenses incurred in producing and transporting gas to the point of sale. The Ohio Supreme Court reversed. It reasoned that the lease was ambiguous and that the extrinsic evidence submitted to the trial court demonstrated a triable issue of fact regarding whether the parties intended for Point Pleasant to be considered part of the Utica Shale.
In Honey Crest Acres, LLC v. Rice Drilling D, LLC, the Southern District of Ohio denied the defendant’s motion to dismiss the plaintiff’s declaratory judgment, trespass, conversion, and unjust enrichment claims. The plaintiff alleged that the producer obtained the rights to drill in the Marcellus Shale and the Utica Shale, but it did not have the right to drill into the Point Pleasant. The court determined that the complaint stated a plausible trespass claim because it alleged that Rice Drilling’s completion operations indirectly interfered with the plaintiff’s rights in the Point Pleasant formation. The district court also rejected the defendant’s argument that the “rule of capture” barred the plaintiff’s conversion claim because courts have recognized conversion claims based upon hydraulic fracturing. While the rule of capture generally protects a landowner who extracts oil from her property that migrated from a neighboring property, the district court recognized that the rule of capture is “an inefficient approach” and found that “the sparse case law on this topic recognizes a conversion claim predicated on natural resources that have been acquired by hydraulic fracturing that invades the plaintiff’s property.” Last, the district court held that an unjust enrichment claim could proceed because the landowner conferred a benefit by leasing its subsurface mineral rights to the lessee, and it would be unjust for the lessee to extract the minerals without compensating the landowner.
3. Ohio’s Marketable Title Act
In RL Clark, LLC v. Hammond, Ohio’s Seventh District Court of Appeals considered whether two statutory exceptions operated to prevent the extinguishment of a severed oil and gas royalty interest under the Ohio Marketable Title Act (MTA). In 1902, the then-owners sold the property, “excepting the one-half (1/2) of the oil and gas royalty.” While a subsequent 1908 deed excepted one-half of the royalty, the 1956 root of title deed conveyed the property “subject also to such interest in the oil and gas royalties as have heretofore been reserved by former grantors.” Under the MTA, an interest can be saved from extinguishment if there is a specific reference to the interest in the claimant’s 40-year chain of record title. The court undertook the three-part test established by the Supreme Court of Ohio in Blackstone v. Moore to determine whether the reference in the 1956 deed was specific or general. The court determined that the reference in the 1956 deed was general, as it did not identify who the “former grantors” were or even clarify what the actual royalty interest was (e.g., one-fourth, one-half, entire). Instead, the language in the 1956 deed (and later deeds) was “[b]oilerplate, generic, vague, and different than the original description of the property interest.” And because the general reference in the 1956 deed clearly did not identify any other recorded title transaction, the specific reference exception under the MTA could not prevent the extinguishment of the severed royalty interest.
The court also faced the question of whether certain oil and gas leases recorded within the 40-year period after the 1956 root of title saved the royalty interest from extinguishment. Under the MTA, any interest arising out of a title transaction that was recorded within the 40-year period following the effective date of the root of title will not be extinguished. There were several oil and gas leases covering the subject property recorded during that period. However, while oil and gas leases may be title transactions under the MTA, these leases were not entered into by the severed royalty owners, nor did the leases mention the severed royalty interest. The court noted that there “[i]s no connection between the recorded leases … and the [severed royalty interest]” and “[a]n interest does not arise from a title transaction simply by virtue of some amorphous connection to the title transaction.” As a result, the court held that the severed royalty interest was extinguished under the MTA.
In Wolfe v. Bounty Mins LLC, Ohio’s Seventh District Court of Appeals addressed whether the incorporation by reference doctrine could be used to preserve a severed oil and gas interest from extinguishment under the MTA. In this case, the oil and gas underlying the subject property was severed from the surface in a 1921 deed. The subsequent deeds in the chain of title up through and including a 1950 deed contained a verbatim repetition of the severance language; however, the 1966 deed that followed did not repeat the severance language, nor did it even include a legal description of the property. Rather, it referenced title instruments identified on an attached Exhibit A for a description of the properties, while also expressly incorporating the terms and conditions of said instruments. Exhibit A identified the prior 1950 deed by reference to its date, volume, page numbers, and names of the grantor and grantee. Affirming the trial court’s decision, the court found that (1) the inclusion of the 1950 deed on Exhibit A was sufficient for the 1966 deed to qualify as the root of title, and (2) the 1950 deed’s verbatim repetition of the oil and gas severance was properly incorporated into the 1966 deed. As a result, the court held that the severed oil and gas interest was not extinguished under the MTA.
4. Ohio’s Dormant Mineral Act
In Henderson v. Stalder, Ohio’s Seventh District Court of Appeals was once again faced with the question of whether a surface owner properly complied with the mandates of the Ohio Dormant Mineral Act (DMA) when serving a notice of abandonment by newspaper publication. In this case, an oil and gas interest was severed in the early 1900s by the Eggers. In 2014, on behalf of the surface owners, a research company searched the public records of the county where the property is located but was unable to identify any heirs of the Eggers. The company conducted additional internet research and identified Vivian Egger Henderson as an heir of the Eggers; pursuant to this information, the surface owners attempted, albeit unsuccessfully, to serve Vivian via certified mail. Subsequently, the surface owners published a notice of abandonment that identified the Eggers as the holders but failed to name Vivian. The issues before the court were whether the surface owners exercised reasonable diligence in attempting to identify and locate heirs of the Eggers and whether the notice by publication was ineffective because it failed to specifically identify Vivian. The court found that the surface owners “[w]ere reasonably diligent in their search before resorting to notice by publication.” Specifically, the surface owners’ search of the public records complied with the Supreme Court of Ohio’s Gerrity v. Chervenak. The court held that the surface owners failed to comply with the requirements of the DMA by failing to name Vivian in the published notice. The DMA requires the notice of abandonment to contain “the name of each holder and the holder’s successors and assignees, as applicable.” Therefore, the court held that the DMA abandonment was not completed.
In Cardinal Minerals LLC v. Miller, Ohio’s Seventh District Court of Appeals addressed a mineral buyer’s attempt to invalidate the abandonment of a severed mineral interest under the DMA. After signing an oil and gas lease, the surface owners sought to abandon the severed mineral interest under the DMA, resorting to serving the notice of abandonment by newspaper publication. Almost a decade after the abandonment proceedings were completed and accounted for in the public records, Cardinal Minerals sought out the heirs of the original reserving parties and purchased any remaining mineral interests they may have held, along with an assignment of claims. Cardinal subsequently filed suit against the surface owners, challenging the validity of the earlier abandonment due to the use of newspaper publication. While the DMA abandonment was the focal point of the suit, the issue of standing was ultimately dispositive. Here, affirming the lower court’s decision, the court held that Cardinal could not “step in the shoes” of the mineral reserver’s heirs. Because the abandonment process had concluded years prior, the mineral reserver’s heirs could not sell—nor could Cardinal buy—an interest that no longer existed in the public record. Instead, because the heirs did not successfully challenge the abandonment, the severed mineral interest ceased to exist and could no longer be transferred. The court reasoned that their interests had already been deemed abandoned of record and vested in the surface owners for almost a decade. Further, the court noted that Cardinal “[i]s in the business of buying lawsuits” and its purchase of rights from the heirs, for the sole purpose of filing suit to undo the DMA abandonment, was barred under the doctrines of champerty and maintenance.
5. Development Disputes
In EOG Resources, Inc. v. Lucky Land Management., LLC, Lucky Land Management acquired the surface of the disputed property. EOG, which owned an oil and gas lease covering the property’s subsurface minerals, sought to use the surface to construct two horizontal well pads to produce oil and gas from underneath the property and other nearby properties. Lucky objected to EOG’s plans as an unreasonable use of its surface that would impede Lucky’s enjoyment of the property as a hunting ground. EOG sued and moved for a preliminary injunction to prohibit Lucky from interfering with EOG’s development activities. The district court granted the injunction, finding that under “[w]ell-settled law in Ohio [] the owner of a mineral interest has the right to use the surface to develop and produce minerals, while exercising due regard for the owner of the surface.” Here, the amount of surface EOG proposed to use was not more than is reasonably necessary and showed due regard for Lucky as the surface owner.
Lucky appealed to the Sixth Circuit, which stayed the injunction. The Ohio law that the district court relied on was “[s]ilent as to whether the mineral owner can use the surface of one property to mine minerals from adjacent properties. . . .” However, “there is a wealth of persuasive authority addressing that very issue,” holding that “[i]n the absence of an express agreement, the mineral owners or lessees cannot use the surface for the production of minerals from other lands.” Lucky had, therefore, shown “a likelihood of success on appeal,” which warranted staying the injunction.
6. Regulatory Disputes
In State ex rel. AWMS Water Solutions, LLC v. Mertz, the Eleventh District Court of Appeals addressed whether a 2014 shutdown order issued by the Ohio Department of Natural Resources caused the plaintiff to suffer partial or a categorical taking. In 2014, the plaintiff began injecting wastewater brine on the property at issue through two separate wells. After an induced seismic event was traced to the plaintiff’s primary injection well, ODNR issued the shutdown order enjoining the plaintiff’s use of the primary well, which was not lifted until May 2021. The court determined that a categorical taking did not occur because the plaintiff could have applied for a permit to drill with a different well on the property, could have sought a modification order for the enjoined well, and could have applied to drill a third well on the property. In other words, the shutdown order did not fundamentally deprive the plaintiff of all economically viable use of the property. However, ODNR did effect a partial taking because the plaintiff suffered an economic impact based on the shutdown order, and the shutdown order interfered with the plaintiff’s reasonable and distinct investment-back expectations.
IX. Oklahoma
A. Legislative Developments
During the 2024 legislative session, the Oklahoma legislature adopted House Bill 2197 to amend existing statutes to authorize the Executive Director of the Oklahoma Water Resources Board to issue 90-day permits for stream water and groundwater use for oil and gas drilling and completion operations. As amended, these permits may be renewed up to three times (in most cases) but are conditional on the permittee’s filing an annual report with the Water Resources Board. By Senate Bill 1514, the legislature also amended the Production Revenue Standards Act (PRSA) to extend its five-year statute of limitations to apply to claims brought under the act by the Commissioners of the Land Office. Finally, through passage of Senate Bill 1505, the legislature extended the Oklahoma Emissions Reduction Technology Incentive Act to provide rebates for the costs of implementing emissions reduction projects on downstream oil and gas operations and refining and distribution activities, in addition to upstream and midstream operations.
B. Judicial Developments
The Oklahoma Supreme Court decided whether and when quiet title suits are subject to a statute of limitations in Base v. Devon Energy Production In 1973, the plaintiff’s predecessors in interest executed an oil and gas lease in favor of the Rodman Corporation. The 1973 lease provided for a five-year primary term ending on December 4, 1978, and a 1/8 lessor’s royalty on oil and gas production. Within the lease’s primary term, Rodman Corporation assigned the 1973 lease to Partnership Properties Co. and on July 24, 1978, the plaintiff’s predecessors executed a lease in favor of Petro-Lewis Funds, Inc. This lease was to commence a three-year primary term on December 4, 1978, the date when the 1973 lease was to expire. The 1978 lease provided for a lessor’s royalty of 3/16. Petro-Lewis Funds, Inc. then filed a pooling application with the Oklahoma Corporation Commission for the drilling of a well on the premises covered by both leases and completed a producing well. Production was achieved in November 1978, before the expiration of the 1973 lease. The plaintiff’s predecessors subsequently signed division orders certifying their right to a 1/8 royalty under the 1973 lease. Shortly thereafter, the owner of the 1973 lease, Partnership Properties Co., also acquired the 1978 lease. While the 1973 lease would be assigned many times over the intervening years, no evidence indicated that Partnership Properties Co. ever assigned the 1978 lease.
In 2008 Chesapeake Operating, Inc. apparently acquired the 1973 lease, drilled a second well, and began paying a 3/16 royalty “[a]s if the 1978 [l]ease had superseded or amended the terms of the 1973 [l]ease.” Ten years later, Devon Energy Production Company acquired the 1973 lease, drilled eight multi-unit horizontal wells, and began paying a 1/8 royalty, “[a]s if the 1973 [l]ease controlled over the 1978 [l]ease.” The plaintiff filed suit against Devon Energy in 2019 after refusing to sign division orders certifying the plaintiff enjoyed only a 1/8 royalty interest. The suit brought claims for quiet title and declaratory judgment as well as for accounting and payment under the Production Revenue Standards Act (PRSA). The plaintiff’s underlying theory was that the terms of the 1978 lease “[s]upplanted or amended by the terms of the. . .” 1973 lease.
In a 2-1 decision, the court of appeals affirmed the district court’s grant of summary judgement, holding that the plaintiff’s quiet title claim accrued in 1978 when the 1978 lease resulted in a cloud on title to the plaintiff’s interest under the 1973 lease, and that the claim was barred by the 15-year statute of limitations for the recovery of real property contained in 12 O.S. § 93(4).
The Oklahoma Supreme Court affirmed the court of appeals on three issues relating to Devon Energy’s limitations defense: (1) whether the plaintiff’s quiet title claim is subject to a statute of limitations at all, (2) if so, whether the 15-year statute governing actions to recover real property is applicable, and (3) if so, whether the claim only accrued when the plaintiff made a demand under Claude C. Arnold Non-Operated Royalty Interest Properties, L.L.C. v. Cabot Oil and Gas Corp.
Beginning with the threshold issue of whether any statute of limitations applies to the plaintiff’s quiet title claim, the Oklahoma Supreme Court held that a limitations period does apply. The general rule is that “[t]he statute of limitations never runs against the plaintiff in a quiet title action who is in possession of the property at issue” but when the plaintiff has not been in continuous possession, “[h]is equitable claim to quiet title will be viewed as a legal claim to recover the property, which is subject to a statute of limitation.” Thus, the question in the case boils down to whether the plaintiff was in or out of possession of the subject mineral interest; if the former, her quiet title would be equitable and thus not barred by a statute of limitations, but if the latter, the claim for recovering possession of the property would be time limited.
The court made what is probably the opinion’s most significant pronouncement of law in response to this question. In holding that the plaintiff was out of possession of her mineral interest, the court explained that one method for demonstrating possession of mineral interests is by holding unencumbered record title. Another method, “[t]ypically used by parties asserting adverse possession,” is “show[ing] that they have taken steps toward reducing the minerals to possession through drilling operations.” Interpreting the court’s meaning here, Oklahoma law requires mineral owners to timely sue (a) persons in actual possession of the minerals to avoid adverse possession of the mineral interest, as well as against (b) persons whose claims cloud record title to the mineral interest despite not being in actual possession of the minerals. Thus, a mineral owner’s failure to timely assert a claim to quiet title against a mere cloud on title results in the de facto perfection of the defendant’s adverse claim in the minerals, without any requirement that the defendant be in possession of the minerals. In the case at bar, the court concluded that the plaintiff fell into the second category and were time-limited in bringing their claims: Plaintiff “[s]hould have seen that her possession of the mineral interests was encumbered by the existence of two leases and should have been on notice that she needed to quiet title in favor of her preferred lease through cancellation of the opposing lease .”
Having concluded that the plaintiff’s claim was subject to a statute of limitations, the court next considered which statute was applicable—the 15-year statute for actions to recover real property or the five-year statute for actions brought under the PRSA. Finding that the action was to resolve a cloud on title and that the PRSA claims were merely derivative of that resolution, the court affirmed the court of appeals’ application of the catchall 15-year period of 12 O.S. § 93(4).
The third limitations issue is more difficult: when did the plaintiff’s quiet title claim accrue? Devon Energy argued that the claim accrued in 1978 or 1979, when the plaintiff’s predecessor executed the 1978 lease and signed a division order reflecting the 1/8 royalty under the 1973 lease. The plaintiff argued that under Claude C. Arnold, her claim accrued only after she demanded payment of the higher royalty percentage under the 1978 lease.
Distinguishing Claude C. Arnold, the Base court held that the plaintiff’s predecessor was first on notice of the potential cloud on her mineral interest when she executed the 1978 lease or when she signed the 1979 division order reflecting the lower royalty percentage. Unlike the plaintiff in Claude C. Arnold, who had no role in drafting or recording the subsequently recorded leases that clouded title to her interest and no notice of them until she demanded payment of the higher royalty percentage, the predecessor of the plaintiff at bar was herself a party to the very transaction that she claimed to cloud her title. The court thus affirmed dismissal of the plaintiff’s claims.
The Oklahoma Supreme Court also decided Latigo Oil & Gas v. BP America Production Co., involving the construction of a preferential right to purchase in a joint operating agreement (JOA). Latigo sought a preliminary injunction against BP from selling certain assets subject to Latigo’s preferential right to purchase under the parties’ JOA. BP had entered an agreement with a third party to sell a package of oil and gas interests nationwide, which included a few interests that were subject to the parties’ JOA. As required by the preferential right to purchase, BP offered the burdened interests to Latigo, attaching a copy of the purchase price allocation contained in BP’s purchase and sale agreement with the third party. The purchase and sale agreement allocated a uniform value of $60,000 to every interest that was burdened by a preferential right. Latigo rejected the offers, arguing that the allocated price exceeded the interests’ market value and that the price allocation was made in bad faith to discourage Latigo from exercising the preferential right to purchase.
The district court preliminarily enjoined BP’s sale and the court of appeals reversed, citing that Latigo failed to establish a likelihood of success on the merits of its breach of contract claim. The Oklahoma Supreme Court reversed the court of appeals and affirmed the preliminary injunction, holding that the district court did not abuse its discretion in finding that BP may owe a duty to allocate the value of the burdened interests in good faith. The court relied on Ollie v. Rainbolt, whereby the court held that a seller in such a situation breaches the essence, if not the express requirements, of a preferential right by offering the burdened property as an all-or-nothing package with other property that is not burdened by the preferential right. Citing opinions from courts in Iowa, Georgia, and Idaho, the court concluded that authority exists in other jurisdictions to support a theory that package-deal sellers have a duty to allocate the purchase price or value of interests burdened by a preferential right in good faith.
In In re Chisolm Oil and Gas Nominee, the operator under a JOA declared Chapter 11 bankruptcy against nonoperator parties to the JOA. Before the bankruptcy, the nonoperator parties elected not to participate in subsequent drilling operations, subjecting their interests to risk penalties under the JOA’s non-consent provisions. Under the JOA, the nonoperators’ shares of production were directed to the consenting parties until such time as production from the drilling operations repaid expenses and fully satisfied the risk penalties.
In the bankruptcy proceeding, the debtor operator rejected the JOA as executory contracts pursuant to section 365 of the Bankruptcy Code. In response, the nonoperators asserted that rejection of the JOA restored the parties a common law co-tenancy relationship. Under common law principles, cotenants that elect not to consent to drilling operations owe no risk penalty and retain their interests. Therefore, the nonoperators argued their working interests reverted to them as of the date of the bankruptcy petition. The court rejected this theory, citing United States Supreme Court authority that rejection of an executory contract under section 365 merely breaches the contract but does not rescind it. Thus, the operator’s rejection of the JOA did not unwind the nonoperators’ elections under the JOA’s nonconsent provisions and the nonoperators were not entitled to immediate payment of their proportionate shares of production.
In Lazy S Ranch Properties v. Valero Terminaling & Distribution Co., the owner of a ranch brought claims of public and private nuisance and negligence per se under various Oklahoma statutes, alleging that leaks from defendant’s refined products pipeline contaminated the ranch. The district court found that no reasonable trier of fact could have found the trace amounts of petroleum products detected on plaintiff’s property constituted a nuisance or rendered the environment harmful, detrimental, or injurious as required by Oklahoma law. Additionally, the court found that even if legal injury occurred, the plaintiff failed to introduce sufficient evidence of causation and failed to rule out other potential sources of contamination.
The Tenth Circuit held the plaintiff’s evidence created a triable issue of whether the defendant’s pipeline created a nuisance under this definition. In particular, the plaintiff showed that caves on the ranch smelled of hydrocarbons, which caused headaches, prevented the mapping of caves, and made a geologist hesitate about using a lighter to ignite a cigarette on the ranch. The court held further that because 27A O.S. § 2-6-105(A) mandates that “pollution of any waters of the state is a public nuisance,” the plaintiff’s claim of private nuisance based on hydrocarbon pollution logically also establishes a claim for public nuisance. Based on the same evidence of harm, the court held that the plaintiff established triable claims for negligence per se for breach of statutes and regulations prohibiting pollution of soil and water resources. On the issue of plaintiff’s evidence of causation, the Tenth Circuit again reversed the district court, finding enough evidence that the defendant’s pipeline was to blame that a reasonable jury could decide either way.
X. Pennsylvania
A. Legislative Developments
On July 11, 2024, Governor Shapiro approved Pennsylvania Senate Bill 654 which permits taxpayers to claim a deduction for the percentage depletion of certain natural resources, including oil and gas wells. The percentage depletion rate is based on revenue and is set at 15% for oil and natural gas. This Bill brings Pennsylvania into conformity with federal regulations that allow a tax deduction for percentage depletion. Previously, Pennsylvania taxpayers seeking to claim a deduction for natural resources could do so only for cost depletion, which required a more complex calculation involving the resource’s exhaustion rate.
B. Judicial Developments
In KEM Resources, LP v. Deer Park Lumber, Inc., the Pennsylvania Supreme Court considered which statute of limitations period applies to a co-tenant’s accounting claim against a fellow co-tenant. The co-tenants each owned a 50% interest in the oil and gas underlying the property. In 2008, the defendant co-tenant entered a lease for the entirety of the oil and gas estate and received a bonus payment. In July 2014, the plaintiff co-tenant filed suit, arguing, among other things, that it was entitled to an accounting for the money the defendant received from leasing the oil and gas attributable to the plaintiff co-tenant’s interest. The defendant argued that the accounting claim was barred by the statute of limitations because the claim “at its core” was either a breach of fiduciary duty claim subject to a two-year statute of limitations or an unjust enrichment claim subject to a four-year statute of limitations. The superior court rejected that argument, concluding that the plaintiff’s accounting claim constituted a statutory claim under 68 Pennsylvania Statute section 101 which permits “tenants in common, not in possession, to sue for and recover from such tenants in possession his or their proportionate part of the rental value of said real estate.” Because no statute of limitations is specified for this type of action, the superior court concluded that Pennsylvania’s catch-all six-year statute of limitations applied. The Pennsylvania Supreme Court affirmed, reasoning that, although the plaintiff had not explicitly pleaded section 101 in its complaint, it had alleged all of the facts necessary for section 101 to apply. The court further agreed that, because neither section 101 nor any other statutory section specified the statute of limitations applicable to an accounting claim between co-tenants, the catch-all, six-year statute of limitations applied. Because the action was filed within six years after the defendant co-tenant received the lease bonus, the court concluded it was timely filed.
In Frye v. Penn View Exploration, Inc., the Pennsylvania Superior Court concluded that a lease remained in effect despite the lessee’s failure to timely pay shut-in royalties because the lease’s shut-in royalty provision did not state that non-compliance would result in lease termination. The plaintiffs entered a lease providing that it would remain in effect for as long after the primary term as “[o]il or gas or their constituents are produced or are capable of being produced on the premises in paying quantities, in the judgment of Lessee.” The lease further provided that, if the lessee was unable to market the production from a well it drilled or shut-in a producing well, the lessee would pay an advanced royalty to the lessor within one year of the date the well stopped producing or was shut-in. After a connecting pipeline was abandoned, the defendant shut-in wells drilled beneath the plaintiffs’ property but did not issue a shut-in royalty payment to the plaintiffs. Three years after the wells were shut-in, the plaintiffs notified the defendant they intended to terminate the lease and subsequently initiated suit arguing that the lease had become void when the defendant failed to timely pay shut-in royalties. The defendant counterclaimed arguing that the plaintiffs breached the lease by failing to provide notice and an opportunity to cure as the lease required. The defendant further argued that because the lease was capable of producing in paying quantities the lease remained in effect.
After both parties filed motions for summary judgment, the trial court denied the plaintiffs’ motion and granted the defendant’s motion. Regarding lease termination, the trial court reasoned that the plaintiffs failed to satisfy their burden to prove termination when the evidence showed that the defendant made “[s]ignificant efforts to get the well back into productive status” which “at a minimum” created issues of fact as to whether it had “[a]cted in good faith in continuing to attempt to operate the well as required” by Pennsylvania case law. With respect to notice and cure, the trial court found that by filing suit 20 days after they informed the defendant of the lease’s termination, the plaintiffs failed to provide the defendant with the requisite 30-day period to cure. The superior court affirmed the denial of the plaintiff’s summary judgment motion, noting that the shut-in royalty provision did not state that the lease would become void if such payments were not timely made. However, the superior court disagreed with the trial court’s ruling on the plaintiffs’ failure to satisfy the notice-and-cure provision of the lease. According to the superior court, regardless of when they filed the original complaint, the plaintiffs’ filing of an amended complaint rendered their original complaint a nullity. Because the amended complaint was filed beyond the 30-day cure period, the court concluded the plaintiffs had satisfied the lease’s notice-and-cure provision.
In A&B Campbell Family LLC v. Chesapeake Energy Corp., the Middle District of Pennsylvania concluded that allegations regarding the defendants’ engagement in related schemes to underpay royalties based on “unauthorized or artificially inflated deductions” failed to state a claim under the Sherman Act or RICO. The court first concluded that the plaintiffs lacked standing to assert a claim under the Sherman Act because they alleged no facts showing “[a] reduction in competition stemming from their alleged injury,” as required for an antitrust claim, instead “[o]nly alleg[ing] harm to themselves through the underpayment of royalties.” Further, because the plaintiffs were royalty interest owners and “neither consumers nor competitors in the alleged relevant markets,” they were not permitted to bring an antitrust action. Even if the plaintiffs had standing, the court concluded they failed to state a claim under the Sherman Act because “[a]t most Plaintiffs have alleged parallel conduct ‘entirely consistent’ with each Defendant pursuing its own interests by underpaying Plaintiffs’ royalties by deducting post-production costs,” which was insufficient to establish that they had acted in concert to restrain trade.
With respect to the RICO claim, the court granted the motion to dismiss based on the lack of factual allegations establishing the defendants “[k]nowingly agreed to participate in an enterprise intended to defraud Plaintiffs” or engaged in “global, coordinate, and unified activity” rather than “independent and varied conduct” insufficient to establish a RICO enterprise. The court also dismissed the plaintiffs’ state law claims for breach of contract, conversion, civil conspiracy, and accounting, all of which were based on their allegations regarding the impermissible deduction of post-production costs. In doing so, the court pointed out that the lease’s royalty clause providing that the “[m]arket value at the well shall not exceed the amount realized by lessee for such production computed at the well” had been interpreted by other courts as requiring calculation of royalties “at the wellhead” which permitted the deduction of post-production costs.
In Chambers v. Equinor USA Onshore Properties Inc., the Middle District of Pennsylvania considered whether a lease requiring royalties to be paid for the oil and gas “marketed and used off the premises” created “[a]n implied duty to market gas produced under the Leases to downstream third parties.” While the defendant argued that it complied with the lease by paying royalties based on the price it sold gas at the wellhead to an affiliated entity, the plaintiffs argued that royalties should be calculated based on downstream sales to third parties. The court concluded that the phrase “marketed and used off the premises” was ambiguous, acknowledging merit in both the defendant’s argument that this phrase historically was understood “[t]o delineate merely whether any royalty was owed at all” and the plaintiffs’ argument that the oil and gas industry has evolved such that oil and gas is no longer sold at the wellhead. Although the court noted that the leases were proceeds leases and the defendant’s interpretation of the royalty provision did not treat them as such, the court recognized that other courts have “[i]nterpreted the term ‘marketing’ to mean sold in this context.” The court further noted that, here, “market” could mean “[t]o incur post-production costs to prepare the gas for sale” because the parties had crossed out language permitting the deduction of post-production costs but kept the marketing language. Without expert testimony regarding the language of this particular type of lease, the court concluded the phrase “marked and used off the premises” was reasonably susceptible to multiple interpretations that must be resolved by the finder of fact. Additionally, the court reiterated well-established law that the plaintiffs’ breach of contract claim subsumed their breach of the implied duty of good faith and fair dealing claim.
The court in Gerfin v. Southwestern Energy Production Co. considered whether a lease requiring the lessee to obtain the lessor’s written consent for “additional pooling/unitization or other forms of pooling/unitization” with properties other than those identified in the lease prohibited cross-unit drilling without the plaintiffs’ written consent. The defendant filed a motion to dismiss the plaintiff’s breach of contract claim, arguing that it was only obligated to obtain the plaintiffs’ written consent for pooling and unitization, which are distinct from cross-unit drilling. The defendant further argued that Pennsylvania statutory law permits cross-unit drilling in the absence of an express prohibition in the lease which the plaintiffs’ lease lacked. The court rejected the plaintiffs’ argument that pooling, unitization, and cross-unit drilling were interchangeable terms all of which required the plaintiffs’ written consent. The court concluded that the inclusion of the language “other forms of pooling/unitization” in addition to “pooling/unitization” suggested the parties intended this language to mean something different than mere pooling and unitization and the phrase was “[i]f not an ambiguity in and of itself, the ‘contractual hook’ upon which a latent ambiguity may rest.” Based on this and the parties’ failure to address the impact of Pennsylvania’s requirement that a lease contain an “express prohibition” in order for cross-unit drilling to be prohibited, the court denied the motion to dismiss.
XI. Texas
A. Judicial Developments
In the wake of Van Dyke v. Navigator Group, Texas courts are still being called upon to address the interpretation of the historical 1/8 landowner’s royalty in conveyances and leases. The rebuttable presumption that 1/8 represents the entire leasehold estate has largely helped Texas courts clarify conflicting interpretations of double fractions. In Powder River Mineral Partners, LLC v. Cimarex Energy Co., the issue was whether a deed conveyed a fixed 3/128 royalty interest or a floating 3/16th interest. In the deed, the grantors conveyed “[a]n undivided three sixteenths (3/16ths) interest in and to all the oil, gas and other minerals in and under that may be produced from the ... described land.” The deed went on to say:
In the event the above land should be loaned for the mining of oil and gas or other minerals, then Grantees shall be entitled to receive under this conveyance free of cost in the pipe line to which any well or wells on said land may be connected, 3/16ths of one-eighth of all the oil and/or gas or other minerals produced therefrom under such lease.
The double fraction nature of the deed required the court to determine the parties' intent by looking at the document in its entirety. The court noted a rebuttable presumption that 1/8 was historically used as a “placeholder for future royalties generally,” and not as a mathematical value, so the court presumed that the parties intended for the 1/8 to be used in its historical standard, thus intending a 3/16 floating royalty. The grantors’ successors argued that the royalty conveyance only applies if the subject property was leased for minerals, and that the double fraction language rebuts the presumption. The court disagreed with these arguments because of the deed’s language and the necessity of double fraction presumption. The court did not identify language in the deed to rebut the presumption and held that the deed conveyed a floating 3/16 royalty.
In Montgomery, Trustee of Tri-Mont Irrevocable Trusts v. ES3 Minerals, the court addressed the question of a double fraction in a conveyance of a non-participating royalty and whether it created a fixed or floating royalty. Following the precedent set by Van Dyke v. Navigator Group, the court found that 1/4 of 1/8, in the context of the conveyance language, did not mean 1/32. Rather, the rebuttable presumption that “1/8” in a conveyance represents the grantor’s entire leasehold interest was not overcome. Additionally, the inclusion of the language “of the landowner’s usual one-eighth royalty” further demonstrated that the original parties meant for 1/8 to symbolize the entire estate rather than as a fixed limitation on the ¼ non-participating royalty interest.
Texas courts also received a fair amount of litigation regarding interpretation of deeds. In Liska v. Dworaczyk, the court was tasked with taking contested language in a will and determining both whether the testator bequeathed an interest in an entire tract of land or just a specific unit and whether the inclusion of two fractions resulted in the beneficiaries receiving a reduced amount. The will stated that the testator would bequeath to the ten named individuals “[a] ONE-TENTH (1/10) interest in the Mineral Interest I own in 118.4 acres near Gillet, Karnes County, Texas, known as the Dragon Unit…” followed by the name of each beneficiary with the words “A ONE-TENTH (1/10).” The court found that the mineral interests included just the Dragon Unit and not the entire 118.4 acres. The 118.4 acres were split into “the Dragon Unit” and “the Bowers Unit,” thus, an interpretation that the beneficiaries were given all 118.4 acres would have erroneously rendered the chosen language “known as the Dragon Unit” pointless. Additionally, each restatement of “A ONE-TENTH (1/10)” meant that each beneficiary was to receive an undivided one-tenth interest in the property, not that each beneficiary’s interest is further divided into a one-hundredth interest, which would have resulted in less than all of the testator’s interest being disposed of by the will.
In Gardner Energy Corp. v. McNeil, McNeil, & Holt the court determined whether the grantors of a fee mineral interest intended to convey the proportionate burden of a third party’s non-participating royalty interest (NPRI) to the grantees, or on the other hand, whether the grantors intended the entire burden to be allocated to their reserved ½ interest. “In 1951, the State of Texas conveyed the subject property” while reserving a 1/16 NPRI. The grantors became successors-in-interest and in 1976, conveyed by mineral deed an undivided ½ mineral interest in the property to the grantees. The successors-in-interest for the grantors eventually sought a declaratory judgment that the burden of the State’s NPRI should be borne by both parties in proportion to their respective interests. The successors-in-interest for the grantees argued that the failure to mention the State’s NPRI in the mineral deed reflects the grantors’ intent to convey an undivided ½ mineral interest in fee simple in the subject property, unburdened by the NRPI. Interpreting the parties’ intent as expressed in the mineral deed, the court held that the grantors intended to convey the proportionate burden of the State’s NPRI to the grantees based on the subject-to clause. Though the mineral deed did not explicitly mention the State’s NPRI, the court reasoned that the subject-to clause confirms that the grantees were subject to “any rights now existing to any lessee or assigns under any valid and subsisting oil and gas lease,” entitling them only to the royalty interest to which the grantors were entitled. Therefore, the subject-to clause’s reference to the grantors’ right to receive royalties under the existing leases put the grantees on notice that their rights were being limited at which point the grantee’s could have made inquiries and discovered the burden of the State’s NPRI.
Courts also issued a couple of opinions dealing with depth limitations in conveyances (or the lack thereof). In Rock River Minerals, LP v. Pioneer Natural Resources USA, Inc., the court analyzed whether an overriding royalty interest (ORRI) conveyance included a depth limitation. The grantor owned an ORRI in all depths of various leases in a unit. At the time of the conveyance, the leases were subject to a unit agreement as to the Spraberry formation. However, the exhibits to the conveyance referenced that the conveyance was as to “all depths located within the geographic boundaries” of the unit. Eventually, Wolfcamp formation wells were drilled (which is below the Spraberry). The grantor’s successors argued that the Spraberry unit agreement operated as a depth limitation on the conveyance, such that the overriding royalty interest remained with them for the deeper Wolfcamp depths. The court reasoned that geography is a science of the surface, and the reference to the unit was merely a reference to the horizontal limitations of the land description. Thus, confining the land description to the unit was not express or sufficient enough language to create a depth limitation in the conveyance of an overriding royalty.
Occidental Permian, Ltd. v. Citation 2002 Investment LLC also involved alleged depth limitations in a conveyance. The Texas Supreme Court held that an assignment of mineral interests listing certain depth descriptions could not be read to reserve “deep-rights” interests to the assignor. In 1987, Shell Western E&P, Inc. (Shell) sold oil-and-gas properties to Citation 2002 Investment LLC (Citation) in an assignment of mineral interests (1987 Assignment). A decade later, Shell purported to assign some of the same interests to Occidental Permian. Exhibit A of the 1987 Assignment described the conveyed interests in a table of leases with depth references. The parties disputed whether the 1987 Assignment was depth-limited, with Occidental Permian arguing that Shell had reserved interests beyond the depth specifications indicated in Exhibit A. The court relied on Piranha Partners v. Neuhoff to find that Exhibit A presented an ambiguity because it contained no language directing the proper method for reading its tables. The court turned to the 1987 Assignment’s other terms, which provided that Shell assigned “all rights and interests now owned by Shell . . . in the leases and other rights described herein . . . .” The court concluded that by specifying the “leases” as “described herein,” Shell intended to convey its rights to Citation in such leases without any depth limitation.
In Unitex WI, LLC v. CT Land & Cattle Company, LLC, the court determined that a surface owner, who was not a party to an oil and gas lease, lacked the ability to enforce a pipeline burial covenant that was reserved to the lessor of a mineral lease. CT Land & Cattle acquired the surface rights to property subject to an existing mineral lease. It sought to enforce a pipeline burial provision in the original lease. The court noted that while burial provisions generally run with the land, the provision did not do so in this case because of the precise wording of the lease and other instruments in the surface owner’s chain of title. Effectively, the court found no authority on behalf of CT Land & Cattle to enforce the pipeline burial provision.
Lee v. Memorial Production Operating arose from an improperly installed additional packer on a saltwater-disposal well that resulted in toxic saltwater breaking through the surface on the plaintiff landowners’ property. Seeking recovery for the damage to their cattle operation and enjoyment of the land, the landowners sued the current and previous well operators. One claim by the landowners was for the operators’ breach of the oil and gas lease, which required the landowners to prove that they were the mineral owners (thus parties to the oil and gas lease). The court of appeals affirmed the district court’s grant of summary judgment on the grounds that the landowners only produced evidence of owning the surface estate, not the mineral estate, thus failing to prove a contract between the parties.
The court in Darkhorse Water, LP v. Birch Operations, Inc. focused on whether a surface lease for saltwater disposal was more similar to a traditional occupancy lease (which conveys no right to ownership and title), or a “typical oil and gas lease…[that] conveys the mineral estate as a determinable fee,” and therefore a right to ownership which would be necessary for claims to quiet title and for an accounting. Though Darkhorse’s alleged ownership interest related to the subsurface reservoir storage space—not minerals—the court found that “reservoir storage space is an attribute of the surface estate” and can be depleted in the same way minerals can be extracted. Further, the language in Darkhorse’s lease pertaining to the term of operation mirrors the language in typical oil and gas leases; it provides for an initial five-year term that continues indefinitely as long as operations are actually conducted. Thus, the court held that the reservoir storage space was conveyable as a determinable fee interest and that the lease provided a right to ownership and title.
In Samson Exploration, LLC v. Bordages, the court determined that, without express language demonstrating an intent to the contrary, there is a presumption in Texas against compound interest calculations. The Bordages, royalty owners in mineral leases held by Samson Exploration, sued for unpaid royalties on those leases. The Bordages interpreted the late-payment provision in the leases to require compounding interest on the resulting late charges from late royalty payments at the end of each month. The court noted that Texas law favors simple interest unless there is a clear, express provision in the instrument indicating the parties explicitly contemplated compound interest. Because the court found no language in the Bordages’ leases to satisfy this requirement, the court held that the late charges were subject to simple interest.
In Nortex Minerals, L.P. v. Blackbeard Operating, LLC, the court was tasked with determining whether a sale of equity interests in a lessee constitutes a transfer of the lease, thus triggering the lessor’s consent right pursuant to the limited assignment provision. The limited assignment provision of the lease stated: “Except as provided herein, Lessee may not assign or otherwise transfer an interest in this Lease without prior written consent of Lessor.” The court approached the issue with a three-step framework: (1) whether a transfer occurred; (2) if a transfer occurred, whether it was a permitted transfer; and (3) if the transfer was not permitted and consent was required, whether the provision is an unenforceable restraint on alienation. The court determined that since the sale of the lessee’s equity occurred through a merger, which is not a transfer in the interest of the leases, it need not continue through steps (2) and (3) of the analysis. Texas Business Organizations Code section 10.008(a)(2)(C) dictates that a merger is not a transfer. Here, the limited assignment provision required a transfer of interest in the lease, and since there was no change-of-control provision, only a transfer of interest could have triggered the consent right. Since the equity sale was not a transfer of the lease rights, the lessor’s consent rights were not triggered pursuant to the limited assignment provision.
Hamilton v. ConocoPhillips Co. involved the interpretation of surface use provisions of a production-sharing agreement. After leasing their minerals to Burlington, the Hamilton family partitioned the land, and Lloyd Hamilton received a separate surface tract subject to an oil and gas lease. The family then signed a production sharing agreement (PSA) pursuant to which Burlington began constructing a well pad. Mr. Hamilton argued Burlington breached the lease and the PSA for failing to obtain his consent before constructing the pad site, arguing that although the PSA provided an easement for drilling a horizontal well, the PSA and the lease nevertheless required Burlington to seek a separate surface use agreement to receive the exact easements otherwise granted by the PSA. The court found that such a reading would render the entire purpose of the PSA meaningless as, under a plain meaning, it was entered into to grant an easement and right of way to conduct operations for a sharing well.
Repsol Oil & Gas USA, LLC v. Matrix Petroleum, LLC involved a complex dispute amongst non-operators and an operator. Among other claims related to the validity of participation elections, unilateral expenses incurred by the operator, and take-in-kind rights of non-operators, the non-operators asserted claims about missing volumes due to commingling under a joint operating agreement. The non-operators argued that the operator’s method of allocating hydrocarbons resulted in underreporting and underpayment for the hydrocarbons produced from their leases, which led to financial discrepancies. The court found that the non-operators did not adequately plead their “missing volumes” claim because allegations regarding “improper commingling” and “unreliable allocation methodology” do not give notice of a “missing volumes” claim.
In Carl v. Hilcorp Energy Company, the plaintiffs, Carl and White, filed a class action on behalf of royalty owners in leases operated by defendant Hilcorp. The leases stated that Hilcorp must pay royalties “on gas . . . produced from said land and sold or used off the premises . . . the market value at the well of one-eighth of the gas so sold or used.” The leases provided that Hilcorp also “shall have free use of . . . gas . . . for all operations hereunder.” The parties disputed whether Hilcorp owed royalties on gas used off-lease for post-production activities. The Fifth Circuit certified two questions to the Texas Supreme Court, given that court’s decision in BlueStone Natural Resources, II, LLC v. Randle,: “(1) [a]fter Randle, can a market-value-at-the well lease containing an off-lease-use-of-gas clause and free-on-lease-use clause be interpreted to allow for the deduction of gas used off lease in the post-production process?” and “(2) If such gas can be deducted, does the deduction influence the value per unit of gas, the units of gas on which royalties must be paid, or both?” The Texas Supreme Court answered the first question yes. It reasoned that under longstanding caselaw, gas used for post-production activities should be treated like other post-production costs where the royalty is based on the market value at the well. Randle involved a gross-proceeds royalty and its discussion of a free-use clause had no bearing on the outcome of this dispute. As to the second question, the court noted that the parties did not fully engage on this issue, but the court’s rough mathematical calculations indicated that either of the accounting methods referenced in the second question would yield the same royalty payment. The court did not state a preference for any particular method of royalty accounting.
Rights of way and easements are extremely important to the successful operation of mineral leases and production of oil and gas. As with other contract provisions, Texas courts try to discern what each party expressly intended with the chosen easement language. However, the courts’ job gets much more difficult when such language never existed. The court in Premcor Pipeline Company v. Wingate analyzed whether a trial court could rewrite a general pipeline easement to include a fixed permanent width for a pipeline right of way. When the pipeline easement was originally created, it gave the grantee “the right to do whatever may be requisite for enjoying the rights herein granted,” but did not specify a width for the pipeline. After a dispute developed between respective successors to the grantor and grantee, the grantor’s successor sought to have the trial court determine a fixed boundary based on previously laid pipelines. The trial court concluded that the pipeline’s dimensions became fixed and certain based on sixty-seven years of operation and maintenance. The appellate court overruled this and highlighted the Supreme Court of Texas’s reluctance to write fixed widths into easements when the parties did not agree to such easements. Therefore, the appellate court held that “the use of a general easement without a fixed width is a strategic decision that does not render an easement ambiguous or require a court to supply the missing term.”
In Iskandia Energy Operating, Inc. v. SWEPI LP, the court evaluated the nature of trespass claims in the context of deep subsurface wastewater migration. There, an oil and gas operator brought a trespass claim against a neighboring operator, alleging that the defendant operator injected waste saltwater into the plaintiff’s producing zones. The court held that a trespass claim based on an unauthorized interference with a lessee’s development right is recognized by recent Supreme Court jurisprudence as long as the injury is not outweighed by competing interests in the oil and gas context.
ETC Texas Pipeline, Ltd. v. Ageron Energy, LLC also involved a dispute between two neighboring well operators. The court dismissed negligence and trespass claims against ETC arising from poisonous and corrosive hydrogen sulfide gas from an ETC well that damaged Ageron’s wells. The court held that any injury to Ageron’s leasehold occurred before Ageron acquired its working interest. Because Ageron’s predecessor did not assign its causes of action related to the leases and wells, Ageron lacked standing to sue. The court noted: “[t]he right to sue belongs to the person who owns the land when the injury occurs and does not pass to a subsequent owner without an express assignment.” The court observed that Ageron could only have standing if: (1) it holds assigned claims (which it did not); or (2) the mineral interests it asserts were first injured after it acquired its leases in January 2020. The court found that the claims accrued to members of the Dickinson family—who owned the surface estate and mineral estate in common when the land was first injured in November 2012 by hydrogen sulfide that migrated to the surface, killing a few of the Dickinsons cows, giving “rise to a single, indivisible action in which the claimant might pursue all claims for all damages resulting from all injuries that arise from the wrongful conduct.”
In Ammonite Oil & Gas Corp. v. R.R. Commission of Texas, the Texas Supreme Court analyzed the voluntary pooling requirements that must be met before the occurrence of forced pooling under the Texas Mineral Interest Pooling Act (MIPA). Ammonite, the lessee of State-owned minerals in a riverbed, sought to force pool those minerals, under MIPA, with minerals being produced by EOG on either side of the riverbed. EOG’s wells did not extend to the riverbed; thus, their position was that Ammonite was trying to receive revenue through pooling without actually contributing to production. The court ultimately held that, due to the requirement for a fair and reasonable offer to voluntarily pool before a MIPA application can be successful, the Railroad Commission’s denial of Ammonite’s applications was sound. Ammonite’s initial offer to EOG did not contemplate extending the wells to reach Ammonite’s minerals, so the offer did not satisfy MIPA’s fair and reasonable effort requirement. Additionally, because EOG’s wells were already drilled, force-pooling them now would not do anything to prevent waste.
In ETC Texas Pipeline, Ltd. v. XTO Energy Inc., the court analyzed whether a dedicated acreage map relating to a gas gathering and processing agreement (the GPA) contained enough information to satisfy the land description requirement of the statute of frauds. The GPA was between XTO, as the producer, and ETC, as the gas gatherer. The GPA included a map that purported to delineate a specific geographic area. For any XTO leases within that area, ETC had the right to provide gathering and processing services (and be paid therefor). XTO argued that the dotted boundary on the map was made up of circles that, when considered to scale on a map, had a width of approximately 4,000 feet. XTO argued this made the map void under the statute of frauds for insufficient land description. The court disagreed, finding that the acreage map merely provided the general area that was to be further defined by XTO. The court also found that the parties had amended the gas purchase agreement several times with references to the latitude and longitude of receipt points subject to the agreement. This, coupled with XTO’s agreement to provide further specific lease information, constituted additional written information to aid in determining the area described by the dedicated acreage map.
While not involving oil and gas matters as such, Donnan v. RTJ Capital Group, LLC is pertinent to how a Texas court might approach a dispute involving preferential purchase rights, which are commonly found in joint operating agreements. The Donnans acquired a preferential purchase right for a tract of land. RTJ later acquired the property that was subject to the Donnans’ preferential purchase right. When RTJ realized that the Donnans claimed a preferential purchase right, RTJ’s counsel emailed the Donnans’ counsel with information about the purchase. Two months later, RTJ notified the Donnans that the tract was not subject to their preferential purchase right because the Donnans had not notified RTJ that they would purchase the tract. The court ultimately found in favor of RTJ and reasoned that RTJ, through the email correspondence, had satisfied their “offer” obligation to inform the Donnans of the sale. The court noted that the preferential provision did not require RTJ to offer to sell the entire tract to the Donnans, and when the holder of a preferential right learns of a sale in violation of that right, the preferential right is triggered. Additionally, the preferential purchase right expired thirty days after receiving an offer, and the Donnans’ lack of action following receipt of the email constituted a waiver of the preferential right.
In Pruett v. River Land Holdings, LLC, the court reversed summary judgment, holding that genuine issues of material fact existed as to whether a lease terminated due to either (1) total cessation of physical production or (2) cessation of production in paying quantities. The lease provided that following its primary term of three years, if “oil, gas, and mineral is not being produced, . . . the lease shall remain in force so long as operations are prosecuted with no cessation of more than sixty (60) consecutive days.” To support its total-cessation-of-production claim, River Land Holdings presented evidence of Texas Railroad Commission records showing that no production on the property had been reported by any operator for more than five years between 2006 and 2012. In response, Pruett asserted that he would routinely pump oil from a handful of wells on the property. River Land Holdings responded that since he was not the operator of record this self-production was irrelevant to the cessation-of-production issue, but the court disagreed. In the alternative, River Land Holdings asserted that the Texas Railroad Commission records established that the lease had terminated due to a failure to produce in paying quantities. However, River Land Holdings did not provide evidence of profitability, nor of any timeframe within which to measure profitability, as required under relevant authorities. Neither did it establish that a reasonably prudent operator would not have continued to operate the wells in the manner in which Pruett was operating them. Thus, the court concluded that summary judgment for River Land Holdings was improper.
In Elmen Holdings, L.L.C. v. Martin Marietta Materials, Inc., the Fifth Circuit assessed whether a sand and gravel mining lease terminated. The lease was between Elmen Holdings, L.L.C., the successor to the original lessor, and Martin Marietta Materials, Inc., the successor to the original lessee. Martin Marietta inadvertently made royalty payments to the incorrect person for a period of time. Based on the court’s interpretation of the lease, the court held that Martin Marietta’s failure to pay royalties to the correct people was appropriate grounds for Elmen to terminate the lease. The court interpreted paragraph two of the lease to create a special limitation on Martin Marietta’s leasehold interest, but when viewed in conjunction with the notice-and-cure provision of paragraph six, the court reasoned that a missed royalty payment would not automatically terminate the lease until Martin Marietta was notified and subsequently failed to cure the payment. The court’s rationale was that because Martin Marietta (1) failed to pay the royalties to the proper party, (2) received adequate notice of non-payment via email from the proper party on the basis of the substantial compliance standard, and (3) still did not cure within ten days of said notice, the sand and gravel mining lease terminated.
XII. West Virginia
B. Legislative Developments
H.B. 5268 amended three sections of the West Virginia Natural Gas Horizontal Well Control Act at §§ 22-6A-4, 22-6A-5, and 22-6A-6 to permit enhanced oil and gas recovery techniques in horizontal wells and horizontal drilling. The amendments to the Act expanded the definition of horizontal drilling and horizontal wells to explicitly include enhanced recovery methods for oil and natural gas using fluid or gas injection as long as those methods are not otherwise prohibited by law. Next, the amendments added new provisions under § 22-6A-5 that expanded regulations to allow both fluids and gas injection, particularly carbon dioxide, for enhanced recovery of both oil and natural gas, while maintaining the existing regulatory framework and permitting processes for these expanded activities. Finally, the amendments added “enhanced recovery” as an aspect of oil and gas operations in West Virginia over which the Secretary of the Department of Environmental Protection exercises exclusive authority.
H.B. 4850 amended § 11-1C-10 of the West Virginia Fair and Equitable Property Valuation statute by removing a sunset provision due to take effect July 1, 2025, thus permitting the use of the current valuation procedure for determining the value of personal property that produces oil, natural gas, and natural gas liquids for use by the West Virginia State Tax Division going forward. Under this formula, the Tax Division appraises the value of property producing oil, natural gas, and natural gas liquids by applying a yield capitalization model that combines both a working interest component and a royalty interest component. The working interest component is based on net proceeds after costs while the royalty interest component reflects the mineral owner’s share of production, with both components adjusted by capitalization and decline rates to account for future value. The current procedure was established during the State’s 2022 Legislative Session through H.B. 4336, which based the oil and gas well tax valuation formula on actual prices from only the prior tax year instead of the weighted three-year average price previously used for assessment.
H.B. 5045 amended multiple sections of the West Virginia Code, all related to the administration of the West Virginia Water Pollution Control Act and Underground Carbon Dioxide Sequestration and Storage statute, to provide assurances to the EPA regarding West Virginia’s application for primary enforcement authority, or primacy, over the federal Class VI injection well program. The EPA opened a 45-day comment period on the proposal after determining, subject to public comment, that the State’s application meets all applicable requirements for approval.
Cross-references between the West Virginia Water Pollution Control Act and Underground Carbon Dioxide Sequestration and Storage statute were inserted to safeguard water resources, and the amendments established more stringent requirements for obtaining a certificate of completion for carbon storage projects. Most notably, the amendments extended the minimum post-injection monitoring period from 10 to 50 years between the end of injections and the issuance of the certificate of completion, though it maintains flexibility by allowing for site-specific timeframes as determined by Department of Environmental Protection rules.
Per the amended Code sections, the requirements for a certificate of completion of injection operations include post-injection site care and closure requirements as well as providing for liability when fluid migration has occurred that causes or threatens water resources.The amendments clarified liability provisions, maintaining operator responsibility in cases where fluid migration threatens underground sources of drinking water. Further, under the amendments, a release from liability does not apply to current or former owners or operators of a storage facility whose liability arises from noncompliance with applicable law, permits, or regulations prior to issuance of the certificate of completion.
C. Judicial Developments
On November 1, 2024, the Supreme Court of Appeals of West Virginia published two interdependent opinions relating to royalty provisions in oil and gas leases. First, in Romeo v. Antero Resources Corp., the court held that when an oil and gas lease expressly or impliedly contains a duty to market, operators must bear the costs associated with the exploration, production, transportation, and sale of the oil and gas to the point of sale. By applying the “point of sale” approach, the court places West Virginia in the minority of oil and gas producing states, which generally apply the “first marketable product rule,” which allows operators to deduct from royalties any postproduction expenses incurred before the oil and gas becomes marketable.
Furthermore, the court in Romeo held that, unless a lease provides otherwise, any royalties payable to the lessor must include not only profits from the lessee’s sale of wet gas and residue gas, but also any profits from the lessee’s sale of any byproducts of the natural gas, including natural gas liquids (NGLs).
Next, the court ruled on Kaess v. BB Land, LLC, determining that when oil and gas leases contain an in-kind royalty provision, there is an implied duty to market the minerals. When a lease grants a lessee the right to drill and extract oil and gas, the royalty payments are “in-kind” and the lessee elects to sell the lessor’s share on their behalf, then the lessee is required pay the lessor a royalty payment equal to the lessor’s share of the gross proceeds. Furthermore, the lessor is not permitted to deduct any postproduction expenses “received at the first point of sale to an unaffiliated third-party purchaser in an arm’s length transaction for the oil or gas so extracted, produced or marketed.”
The Intermediate Court of Appeals of West Virginia (ICA) has also ruled on two cases that carry significant weight for oil and gas jurisprudence in West Virginia. First, in Venable Royalty, Ltd. v. EQT Production Co. the ICA held that unaccrued non-participating royalty interests (NPRIs) are a vested real property interest that converts to a personal property interest upon production. Additionally, the ICA ruled in Nicholson v. Severin POA Group, LLC that when a deed clearly and unambiguously reserves a one-sixteenth oil and gas interest, it is not conveying a one-half interest in oil and gas, despite “the commonly accepted practices and customs used” throughout the industry which understood that a “reservation of one-sixteenth of an oil and gas mineral interest was actually a reservation of one-half of that interest.” The ICA’s rulings are contingent upon any upcoming contrary appellate decisions.
D. Administrative Developments
The legislature enacted rules in section 53-5-1 of the West Virginia Code of State Rules setting forth requirements and administrative procedures for decommissioning of, or deconstruction activities for, coal, oil, or natural gas-fueled power plants.
The Rules, codified in W. Va. Code sections 53-5-3 and 53-5-4, establish requirements that must be met for a facility to be eligible for consideration of decommissioning or deconstruction activities. A petition for decommissioning or deconstruction activities must be accompanied by analysis performed by a third-party evaluator on the social, environmental, and economic “impact[s] the decommissioning or deconstruction activities will have at a local and statewide level . . . .”
Under these Rules, Notices and Petitions must be filed with the West Virginia Public Energy Authority, with copies sent to local authorities and various government agencies. The petition process must include a period for public comment. A party seeking judicial review of the Public Energy Authority’s actions concerning a Petition must follow the process outlined in the State Administrative Procedures Act, codified in W. Va. Code section 53-5-10. The State Administrative Procedures Act requires a party seeking judicial review to file an appeal to the intermediate court of appeals. The Rules went into effect on June 17, 2024, and will remain in force until August 1, 2029.
XIII. Wyoming
A. Legislative Developments
The Wyoming legislature has amended several aspects of the law on carbon sequestration. The law has and continues to allow the Wyoming Oil and Gas Conservation Commission to issue unitization orders. The orders enable the injection of carbon dioxide into pour space below the surface and bounded within the ordered units. Two changes most directly affect traditional oil and gas exploration and production. First, the changes made clear that unitization orders cannot prohibit the owner of a mineral estate from development of its minerals. Second, the legislature expanded the notification requirement for any person who desires a sequestration unitization order. It must now notify those with property interests within a half mile of the proposed pore space.
The legislature also made a substantial change to the Board of Land Commissioners’ authority over state land leases for oil and gas development. The Director of the Board must now review the highest bid offered for an oil and gas lease on state lands to ensure the bidder is “qualified.” The law also requires the Board to define “qualified” by regulation. If the bidder is determined to be unqualified, the bidder is subject to a civil penalty in the amount of the unqualified bidder’s highest bid.
B. Judicial Developments
In Phoenix Capital Group Holdings, LLC v. Woods, the Wyoming Supreme Court addressed whether the phrase “in and under and that may be produced” was sufficient to show that the holder of a life estate retained the right to produce the minerals from its property and the ancillary right to receive royalties from that production. The deed contained a qualification, conveying the right “for the remainder of their life.”
The holder of the life estate had entered into oil and gas lease agreements, but the remainderman of the estate sought to receive the royalties from the lease. The court reiterated the Wyoming rule that a life estate’s right to a mineral interest requires “express deed language that indicates the parties’ intent to defeat the general rule” against waste in which “a life estate owner has no unilateral right to develop minerals and no right to receive royalties.” The court held that an interest “in and under and that may be produced” from a parcel was not enough to defeat the general rule against waste when a life estate qualifies the right. The remainderman of the life estate was then entitled to any royalty payments associated with the mineral interest.
In Chipcore, LLC v. Leadership Circle Energy LLC, the Wyoming Chancery Court concluded that certain terms of an oil and gas contract—“capable of producing,” “equipped for production,” and “production”—were ambiguous. The contract was silent as to their meanings. These terms identified three phases of incurred costs, each of which allocated costs differently. The second phase covered the costs to “drill, complete, and equip wells for production.” The working interest owners (WIOs) were to pay all phase two costs. Phase three included all costs after production commenced, which were to be split between the WIOs and the operator.
The question was whether any production—though not in paying quantities—was enough to initiate phase three and the associated cost sharing. The operator contended that without paying quantities, it was not obligated to pay any costs including those associated with plugging and reclaiming the wells. After concluding that the text alone was ambiguous, the court permitted extrinsic evidence to resolve the matter. However, the movants submitted only unsigned affidavits from non-expert witnesses and Wyoming Oil and Gas Conservation Commission reports. Neither were adequate to remove all doubt as to the meaning of the agreements and the court denied summary judgment.
C. Administrative Developments
The Board of Land Commissioners promulgated rules for 2024 Wyoming Session Law 64, which relates to the Director’s responsibility to ensure the qualifications of a bidder for an oil and gas lease. The Board defined a “qualified bidder” to mean a “person, entity, or agent thereof, engaged in any phase of exploration for, or production of Oil and Gas as a primary component of their business.”
In In the Matter of the Appeal of Pacificorp, the State Board of Equalization overturned a 2023 determination of the Department of Revenue, finding that electricity used to power horizontal, submersible pumps fit the meaning of “the transportation business” for purposes of taxation under Wyo. Stat. Ann. § 39-15-105(a)(iii)(E). This order follows a 2023 Board order, which had already interpreted § 39-15-105(a)(iii)(E) to include such use. The Department subsequently disregarded the 2023 interpretation and denied the refund associated with this use of electricity.
Wyoming law imposes a sales tax on “the sales price paid for all services and tangible personal property used in rendering services to real or tangible personal property within an oil or gas well site.” The Board considered electricity to be personal property. Property is, however, exempt from this tax when it is involved in the “[s]ales of power or fuel to a person engaged in the transportation business.”
The Board looked to the Wyoming Supreme Court’s definition of “engaged in a trade of business” to interpret § 39-15-105(a)(iii)(E). The phrase requires only that 1) “the taxpayer must be involved in the activity with continuity and regularity;” and 2) “the taxpayer’s primary purpose for engaging in the activity must be for income or profit.” The Board concluded that the petitioner’s use of the electricity met these two requirements. The Board denied the Department’s attempt to add a third requirement—that “the transportation business must be an entity’s ‘predominant activity”—as unsupported by the plain statutory language and ordered the Department to issue the refund.