Oil and Gas Committee Report

I. Alaska

A. Federal Legislative Developments

On March 13, 2023, the Biden Administration approved the Willow Project (“Willow Project”). It is an oil drilling project by ConocoPhillips (“CPAI”) located on the North Slope in the National Petroleum Reserve (“NPR-A”) owned by the federal government.

The Biden administration canceled the seven remaining oil and gas leases in Alaska’s Arctic National Wildlife Refuge (“ANWR”) overturning sales made by the Trump administration. The administration stated that they will abide by the provision of the 2017 Tax Act that requires a second Arctic lease sale by the end of 2024.

B. Alaska Legislative Developments

Governor Dunleavy signed Senate Bill 48, which allows the state to use state land for carbon credits purchased by companies to offset their carbon emissions.

C. Judicial Developments

In AVCG LLC v. State of Alaska, Department of Natural Resources, Alaska Venture Capital Group, LLC (“AVCG”) owns interests in oil and gas leases on state lands on the North Slope and sought approval to create an overriding royalty interest (“ORRI”) on the lease. The Department of Natural Resources (“DNR”), denied AVCG’s request, as the royalty burdens jeopardized the state’s interest in sustained oil and gas development. AVCG appealed, and five years later, the DNR Commissioner affirmed the DNR decision. The Superior Court and the Alaska Supreme Court affirmed the Commissioner’s decisions. The Supreme Court held that the proposed ORRI’s were denied for a reasonable basis as they would amount to a $1 million loss to the state.

In Alaska Crude Corporation v. Alaska Oil & Gas Conservation Commission, Alaskan Crude Corporation (“Crude”) obtained three permits from the Alaska Oil and Gas Conservation Commission (“AOGCC”) and drilled three wells. At the time of purchase, the AOGCC’s regulation required a $200,000 blanket performance bond from operators with two or more wells. In 2019, AOGCC amended the bonding regulation to $400,000 per well. Crude asked for reconsideration of the increase and AOGCC denied the request. Crude filed an appeal with the Superior Court who ruled in favor of the AOGCC. On appeal, the Alaska Supreme Court ruled that the parties failed to argue the correct legal analysis of the Administrative Procedures Act (“APA”) during the administrative proceedings which is against the exhaustion of remedies doctrine. The case was remanded to AOGCC for a new hearing to apply the correct analysis of the APA’s retroactivity rule.

In ConocoPhillips Alaska Inc. v. AOGCC, CPAI had several 10-year federal leases in the NPR-A pursuant to the Naval Petroleum Reserves Production Act from the Bureau of Land Management (“BLM”). The leases stated that BLM would withhold CPAI’s “Well Data from the public during the ‘existence of [the] lease.’” CPAI received permits from AOGCC to drill the wells and, pursuant to Alaska Statute (“AS”) 31.05.035, AOGCC requested well data from CPAI. CPAI complied but also requested that the data remain confidential pursuant to federal law. AOGCC and DNR denied the request, quoting state disclosure laws AS 31.05.035(c) and 20 AAC 25.537(d). The Federal District Court for the District of Alaska held that the state disclosure laws impeded Congress’s intent to expeditiously advance private oil and gas development on the NPR-A as the disclosure of CPAI’s well data would cause CPAI to lose its competitive advantage. The case was dismissed in favor of CPAI.

The Alaska National Interest Lands Conservation Act (“ANILCA”) requires the Interior Secretary to conduct two lease sales for competitive oil and gas production on ANWR. The first lease sale was required no later than December 22, 2021, and the second no later than December 22, 2024. The first sale occurred in 2021, but President Biden issued EO 13990, directing a supplemental environmental review of the program, temporarily halting all activities. In Alaska Industrial Development and Export Authority, et al. v. Biden, et al., AIDEA, North Slope Borough, Artic Slope Regional Corporation, and Kaktovik Iñupiat Corporation (“Plaintiffs”) and Intervenor Plaintiff, State of Alaska (“State”), and the U.S. filed cross-motions for summary judgment. In granting the administration’s motion for summary judgment, the Federal District Court for the District of Alaska held that the Moratorium is only temporary and limited in nature, with the Defendants showing intent to release a Draft Supplemental EIS later that year. The court stated that a temporary pause on implementing the program is not a permanent cease in the implementation and the Moratorium is appropriately tailored “to address specifically identified legal concerns that, once addressed, should facilitate Agency Defendants’ efforts to implement the Program in accordance with the law.”

In Sovereign Iñupiat for a Living Arctic, et al., v. Bureau of Land Management & ConocoPhillips Alaska Inc. and Center for Biological Diversity v. Bureau of Land Management & ConocoPhillips Alaska Inc., the Federal District Court for the District of Alaska combined two related cases where Plaintiffs were challenging the BLM’s Record of Decision (“ROD”) for the Willow Project. Sovereign Iñupiat for a Living Arctic (“SILA Plaintiffs”) and the Center for Biological Diversity (“CBD Plaintiffs”) (collectively, “Plaintiffs”) separately filed suits pursuant to the APA, National Environmental Policy Act (“NEPA”), ANILCA, Endangered Species Act (“ESA”) and other federal statutes. The court addressed both cases in one decision and order, holding that BLM did not violate NEPA since its “decision to consider only those alternatives that constitute full field development, subject to reasonable mitigation measures, is consistent with the NPRPA’s policy objectives and the purpose and need of the Willow Project.” The court also held that climate change can damage NPR-A’s surface resources, but the Plaintiffs failed to causally link how emissions from the Willow Project would specifically harm NPR-A’s surface resources. Additionally, the court rejected Plaintiffs’ argument that NEPA was violated by the Defendants’ analysis of the greenhouse gas (“GHG”) emissions as the final EIS analysis provided “‘a reasonably thorough discussion of the significant aspects of the probable environmental consequences’ of Willow’s growth-inducing impacts, allowing for meaningful public participation and informed decision-making about the Willow Project” even though projected downstream emissions were not specifically included. Furthermore, the court held that the ESA was not violated when the Fish and Wildlife Service’s (“FWS”) biological opinion found that there would be no incidental taking of polar bears. FWS was within the bounds of reasoned decision-making when they “considered the relevant factors and articulated a rational connection between the facts found and the choice made.” The court dismissed all Plaintiffs’ claims with prejudice. The Plaintiffs have since requested an injunction pending appeal of this decision by the court. On December 18, 2023, the Ninth Circuit Court of Appeals denied the injunction without prejudice and expedited the appeal briefing schedule.

D. Alaska Regulatory Developments

On June 28, 2022, the AOGCC ordered CPAI to pay $913,796.80 in penalties for a well blowout that led to the release of natural gas. The release was discovered on March 4, 2022, and traced to freeze-protection. The commission concluded that CPAI had committed five separate violations that led to the blowout.

II. Arkansas

A. Legislative Developments

The 2023 Arkansas General Assembly enacted Act No. 140 which amended Arkansas’ Underground Gas Storage Act, Arkansas Code Annotated §§ 15-72-601 et seq., which, prior to amendment, covered only storage of natural gas. The amended act now includes additional gasses, carbon oxides, ammonia, hydrogen, nitrogen, and noble gas. Since the act provides a methodology for a gas storage operator to acquire reticent interests within its storage reservoir through eminent domain, it will now enable additional gas storage applications, including permanent carbon dioxide sequestration.

B. Judicial Developments

1. Restoration Standards

In its 1986 decision Bonds v. Sanchez-O’Brien Oil and Gas Co., the Arkansas Supreme Court recognized the existence of an “implied” covenant in an oil and gas lease which requires the lessee “to restore the surface, as nearly as practicable, to the same condition as it was before drilling.” Unfortunately, no subsequent decision of that court has defined the meaning of the phrase “as nearly as practicable.” More recently, in 2010, the Arkansas Oil and Gas Commission (“Commission”), adopted its General Rule B-9(e), setting its own standard for wellsite cleanup. The recent Arkansas Court of Appeals case Taylor Family Limited Partnership “B” v. XTO Energy Inc. involved the question whether compliance by a lessee with General Rule B-9(e) satisfies the restoration “as nearly as practicable” standard established in Bonds.

XTO was the successor operator of gas wells drilled in 1959 and 1961 by a predecessor lessee. XTO plugged two of the wells in 2017. In doing so, it complied with the dictates of General Rule B-9(e) to the satisfaction of the Commission inspector who enforces compliance with the rule. The surface owner, Taylor, sued XTO, contending that its cleanup efforts failed to restore the surface of its land to the degree required by Bonds. The trial court then granted XTO’s summary judgment motion, agreeing with XTO that, by enacting General Rule B-9(e), the Commission defined the standard of restoration mandated by the Supreme Court in Bonds.

The Arkansas Court of Appeals reversed that summary judgment and remanded the case for trial, holding that a lessee’s cleanup duties under Bonds and under General Rule B-9(e) were separate duties, both of which must be complied with. Thus, proof of its compliance with General Rule B-9(e) was a factor in determining whether XTO had performed its total cleanup duty, but was not conclusive, and issues of fact remained as to the extent of any remaining duty and compliance therewith.

2. Royalties

Two somewhat conflicting 2023 decisions involved Arkansas’ royalty blending statute, Ark. Code Ann. §15-72-305, which requires gas unit operators to combine and blend one-eighth of the proceeds of all unit participants’ gas sales for royalty payment purposes so that all royalty owners within a producing unit receive their proportionate share of that one-eighth at the blended price, rather than at the actual price received by each of their respective lessees. Specifically, the statute requires the selling parties to remit to the operator “one-eighth (1/8) of the revenue realized or royalty moneys from gas sales computed at the mouth of the well, less all lawful deductions, including, but not limited to, all federal and state taxes levied upon the production or proceeds….”

In J. R. Hurd, et al v. Flywheel Energy Production, LLC, the United States District Court attempted to certify to the Arkansas Supreme Court the question whether the statutory language “less all lawful deductions” overrode the provisions of a “gross proceeds” lease forbidding any deduction other than taxes with respect to allowable deductions, but that court refused the certification request. The district court then entered summary judgment for the lessee, holding that the statutory language did override the lease provision, thus permitting proportionate deduction of post-production expenses.

Subsequently, the Arkansas Oil & Gas Commission entered an order to the effect that the “lawful deductions” referenced in the statute permitted deduction of taxes and third-party charges, but did not permit deduction of other post-production expenses such as compression, treating and gathering. That Commission order was affirmed by the Arkansas Court of Appeals in Flywheel Energy Production, LLC v. Arkansas Oil and Gas Commission, which appears to be in direct conflict with Hurd.

Neither the United States District Court nor the Arkansas Court of Appeals is the final arbiter of Arkansas statutory interpretation, however. Only a decision from the Arkansas Supreme Court will resolve the conflict which arose, in part, by that court’s refusal to accept the certification request in Hurd. Counsel for Flywheel has petitioned the Arkansas Supreme Court for review of the court of appeals decision in Flywheel, so the answer may come in 2024, at least as far as “gross proceeds” leases are concerned.

Still unresolved is the application of the royalty blending statute to an oil and gas lease which expressly allows deduction of post-production expenses (“net proceeds” leases), as well as the related issue of how to blend proceeds of sales in a production unit where both types of leases are present.

In Cambiano v. Arkansas Oil and Gas Commission, the Arkansas Court of Appeals upheld the Oil and Gas Commission’s refusal to reopen and vacate a 2007 integration order for alleged due process violations in the hearing which resulted in that order, specifically lack of effective notice. That integration order had been entered upon application of SEECO, Inc., which held oil and gas leases covering most of the interests within its proposed drilling unit. The parties integrated by the order included the unknown heirs of Louis and Nola Conner, who had died intestate and without probate proceedings. The Conners’ heirs held disputed title to an unleased mineral interest within the unit. The identity of the heirs was unknown at the time SEECO’s application for integration was filed and only partially discovered by time of the Commission’s hearing. Thus, the only service upon them was by publication. Later, the Conner heirs employed Appellant Mark Cambiano’s father, Attorney Joe Cambiano, to represent them in a quiet title action which confirmed their mineral ownership versus adverse claimants. They then conveyed 35% of that interest to Joe Cambiano as his contingent fee.

After Joe Cambiano’s death, the Appellants inherited his interest and requested that the Commission vacate its 2007 order insofar as it applied to them. When the Commission declined to do so, Appellants unsuccessfully appealed to the circuit court and then to the Arkansas Court of Appeals. In so doing, Appellants argued that, if a unit contains unknown or missing owners, the Commission must delay issuing its integration order until such time as all have been found and personally noticed, a highly impractical proposition.

III. California

A. Legislative Developments

1. Enhanced CalGEM Enforcement and Penalty Authority

The enforcement authority of the California Geologic Energy Management Division (“CalGEM”) was significantly enhanced by the enactment of Assembly Bill (“AB”) 631. The bill’s amendments of the California Public Resources Code substantially increased civil penalty and administrative amounts which CalGEM could impose on operators. AB 631 also authorizes CalGEM to refer enforcement to a city attorney, district attorney, or the Attorney General to a bring civil action. The bill extended the statute of limitations for civil penalties for violations of the Public Resources Code to five years from the discovery of the violation. AB 1167 also authorized the Supervisor to order an operator to secure a site, to perform testing and remedial work, and to seek an emergency injunction to enjoin an operator from conducting specified activities that threaten to damage life, health, property, or natural resources, including waters suitable for irrigation or domestic purposes, or that violate the requirements of existing law and regulations. The amendments also modify the typical standard for the issuance of a temporary restraining order or a preliminary injunction to enjoin violations of the Public Resources Code to allow such an injunction to be issued without proof of potential irreparable damage or that the remedy at law is inadequate. The bill also allows cost recovery for CalGEM's response, prosecution, and enforcement costs incurred and, in certain cases, would create a lien against real or personal property of the operator, owner, or property owner who was ordered to do the work.

2. New Bonding Requirements

AB 1167 expressed the “intent of the Legislature that the oil and gas industry pay for all necessary costs of plugging, abandonment, and site restoration of oil and gas wells” and “to minimize the risk that the state will be liable for costs of plugging and abandonment” by requiring that “no well be transferred to another owner until and unless a bond has been filed that would cover the full cost of plugging and abandonment and site restoration.” To implement this legislative direction, effective January 1, 2024, “[a] person who acquires the right to operate a well or production facility, whether by purchase, transfer, assignment, conveyance, exchange, or other disposition,” is required to notify CalGEM “not later than the date when the acquisition of the well or production facility becomes final” and allows CalGEM to obtain documentation regarding a transaction. The bill added section 3205.8 to the Public Resource Code to require anyone intending to acquire marginal or idle wells or production facilities to first obtain a determination from CalGEM of the estimated total costs associated with plugging and abandonment, decommissioning, and site restoration related to those wells and facilities and to file a bond in an amount determined by CalGEM. Since these new bonding requirements apply to the transfer of any well with an average daily production level less than or equal to 15 barrels of oil or 60,000 cubic feet of natural gas during the 12 months preceding the date of acquisition, the new law covers the great majority of producing wells in California. The bill also requires CalGEM to post its indemnity bond determinations on its website. AB 1167’s new requirements have the potential to significantly impact sale transactions and increase the cost and liabilities associated with the acquisition of producing properties in California. Governor Gavin Newsom acknowledged these concerns in his signing message, stating: “However, increasing the financial assurances required for oil and gas well transfers also potentially creates risk of current oil and gas well operators deserting these hazardous wells” and stating his intention to seek revisions of the law to align with the programs that CalGEM is developing to address orphaned and abandoned wells.

3. Coastal Zone Development

Senate Bill (“SB”) 704 amended the California Coastal Act of 1976 to, among other things, authorize the permitting of new or expanded oil and gas development if found to be consistent with all applicable provisions of the Coastal Act and to comply with certain additional conditions. SB 704 also authorizes the permitting of the repair and maintenance of existing oil and gas facilities if the repair and maintenance conform to certain requirements, including an existing requirement that all oil field brines be reinjected.

4. State Oil and Gas Supervisor

Governor Gavin Newsom returned without his signature SB 275 which would have required the Governor’s appointment of the State Oil and Gas Supervisor to be affirmed by the State Senate, effectively vetoing the bill.

B. Judicial Developments

The California Supreme Court affirmed the Court of Appeal’s opinion in Chevron U.S.A., Inc. v. County of Monterey (discussed in The Year in Review 2021), which had held that a Monterey County ordinance banning well stimulation treatments, wastewater injection and impoundment and the drilling of new wells in the County was preempted by state law. The court held that Public Resources Code section 3106, which gives the State Oil and Gas Supervisor and CalGEM the responsibility for oversight of drilling, operation, maintenance, and plugging and abandonment of oil and gas wells, implicitly preempted a local agency’s ability to regulate production methods.

In In re Venoco, LLC, the district court affirmed the decision of a bankruptcy court holding that the takeover by the California State Lands Commission and its operation of an offshore platform after the operator quitclaimed its leases back to the Commission and filed for bankruptcy was a reasonable exercise of the State’s police powers and not a taking in violation of U.S. and California Constitutions.

C. Administrative Developments

1. Suspension of Implementation of SB 1137.

The California Legislature passed SB 1137 in 2022 to ban drilling and reworking operations in any inhabited area within the State by prohibiting CalGEM from approving any “notice of intention” submitted by an operator under Public Resources Code section 3203 for the drilling of oil or gas wells or the reworking of existing oil or gas wells within a “Health protection zone,” defined as the area within 3,200 feet of a “Sensitive receptor.” CalGEM adopted emergency regulations implementing SB 1137 with an intended effective date of January 7, 2023. However, on February 3, 2023, the California Secretary of State certified a referendum challenging SB 1137. Accordingly, CalGEM issued Notice to Operators 2023-03 informing operators that the provisions of Senate Bill 1137 were stayed by operation of law pending a vote in 2024 on the referendum and that CalGEM’s implementing regulations were suspended. CalGEM added 14 C.C.R. section 1765.11 to the California Code of Regulations to ensure that the public was aware that, by operation of law, its emergency regulations were suspended.

2. Proposed Cost Estimate Report Regulations.

In August 2023, CalGEM released its proposed “Cost Estimate Regulations Oil & Gas Operations” for official public comment. The proposed regulations would require each operator to submit a report demonstrating its total liability to plug and abandon all wells and to decommission all attendant production facilities, including any needed site remediation. A revised draft of the regulations was released in November 2023.

3. New Bonding Requirements Implementing AB 1167.

CalGEM issued Notice to Operators NTO 2023-10 in December 2023 to inform operators of the new bonding requirements required by AB 1167 which must be complied with prior to the acquisition of certain wells and production facilities.

4. CalGEM Permits in Kern County.

Ongoing litigation over a 2015 Kern County ordinance intended to streamline the permitting process for new oil and gas wells has resulted in disruption of CalGEM’s administration of its own permits. In 2021, the Kern County Superior Court in Vaquero Energy Inc. v. County of Kern ordered the County to suspend the review and approval of oil and gas permits until the court determined that the ordinance complied with CEQA requirements. CalGEM issued Notice to Operators 2023-06 on May 31, 2023, advising operators that they should resubmit their applications designating CalGEM as the lead agency and with revised information to support CalGEM’s review.

IV. Colorado

A. Legislative Developments

1. Renaming of Regulatory Agency and Related Developments

On May 22, 2023, Colorado Governor Jared Polis signed SB 23-285 into law. Under SB 23-285, as of July 1, 2023, the Colorado Oil and Gas Conservation Commission was renamed the Colorado Energy and Carbon Management Commission (the “ECMC”). SB 23-285 updated ECMC’s regulations of geothermal resources and granted the ECMC sole authority to regulate intrastate underground natural gas storage facilities. It also requires the ECMC to create and maintain a website that serves as a state portal for information regarding the ECMC’s regulatory activities.

In tandem with SB 23-285, Governor Polis signed SB 23-016 into law, which amends the role of the Colorado Energy Office to include “[s]upport achieving legislative goals to reduce statewide greenhouse gas pollution” and to “[m]ake progress toward eliminating greenhouse gas pollution from electricity generation, gas utilities, and transportation.” It further declares that Colorado will reduce statewide greenhouse gas pollution by 26% by 2025, 50% by 2030, 65% by 2035, 75% by 2040, 90% by 2045, and 100% by 2050, all from the 2005 baseline. This reaffirms previous reduction targets set in 2019, with additional benchmarks.

Additionally, on March 16, 2023, Colorado Governor Jared Polis issued a signed letter announcing new action to curb “harmful air pollution from the oil and gas sector,” focusing on nitrous oxide (“NO_x”). The letter directs ECMC and the Colorado Department of Public Health and Environment to work together to develop rules by the end of 2024 that require upstream oil and gas producers in the nonattainment area (generally Colorado’s “Front Range” of Adams, Arapahoe, Boulder, Broomfield, Denver, Douglas, and Jefferson Counties, plus portions of Weld and Larimer Counties) to reduce NO_x by 30% in 2025 and 50% in 2030 from the 2017 baseline. The letter also directs ECMC to undertake a “rulemaking to solidify environmental best management practices addressing ozone.”

B. Judicial Developments

1. Colorado Supreme Court Declines to Adopt a Universal Definition of “Production” in Oil and Gas Leases

In Bd. of Cnty. Comm’rs of Boulder Cnty. v. Crestone Peak Res. Operating LLC, the Board of County Commissioners of Boulder County (“Boulder”), as the current lessor, sought to invalidate two leases (the “Leases”) held by Crestone Peak Resources Operating LLC (“Crestone”). Each of the Leases contained a habendum clause extending the life of the lease in a secondary term for “… as long thereafter as oil or gas … is produced” from the leased land. Each Lease additionally contained standard cessation-of-production and shut-in royalty clauses.

In 2014, during the secondary terms of the Leases, the gas sales pipeline operated by an unaffiliated third party and servicing the wells producing from the Leases was closed for repairs for four months. During this period, the affected wells remained commercially viable, and Crestone’s predecessor-in-interest regularly maintained the affected well sites. Boulder continued to accept royalty payments under the Leases, even while the suit was pending, and never claimed the Leases terminated.

In 2018, Boulder sued Crestone under a variety of theories, including the shut-in related to the pipeline maintenance constituted a cessation in production entitling Boulder to terminate the Leases. The District Court granted Crestone summary judgment, holding Crestone had merely ceased marketing, not producing, and the Leases remained valid. Boulder appealed, and the Colorado Court of Appeals affirmed the decision of the District Court. The Colorado Court of Appeals relied on Davis v. Cramer, which adopted the “commercial discovery” rule, interpreting the term “production” as capable of producing oil or gas “in commercial quantities.”

Boulder appealed to the Colorado Supreme Court, which rejected the Colorado Court of Appeal’s adoption of the commercial discovery rule, choosing instead to interpret the language of each Lease on its own terms and circumstances. Although the Court declined to adopt any general rule defining “production” under Colorado oil and gas leases, it held the 2014 shut-in at issue did not trigger termination under the cessation-of-production clauses under the Leases.

2. Colorado Supreme Court Clarifies ECMC’s Authority to Resolve Contractual Oil and Gas Payment Disputes

In Antero Res. Corp. v. Airport Land Partners, Ltd., the Colorado Supreme Court upheld the Colorado Court of Appeals’ holding that established the bounds of ECMC’s authority to resolve contractual disputes. Under Colo. Rev. Stat. section 34-60-118.5(5.5), the ECMC is required to decline jurisdiction over disputes regarding the interpretation of a contract for payment of oil and gas proceeds. In Antero Resources, Airport Land Partners, Ltd. and other royalty owners (collectively, the “Royalty Owners”) alleged Antero Resources Corporation (“Antero”) underpaid royalties due to the Royalty Owners by deducting various costs it was not entitled to deduct under the applicable leases. The Royalty Owners filed individual breach-of-contract suits against Antero, and Antero moved to dismiss, arguing that the claims should have been brought before the ECMC in the first instance. The District Court granted Antero’s motion to dismiss.

The Royalty Owners subsequently brought the matter before the ECMC, asking the agency to determine whether it had jurisdiction. The ECMC decided that it did not have jurisdiction to resolve the royalty payment dispute, and Antero sought judicial review of ECMC’s determination with the District Court. The District Court reversed ECMC’s determination, holding ECMC had jurisdiction to hear the dispute at issue, concluding that the applicable lease provisions were unambiguous, so ECMC was only resolving issues of fact, not law. The Royalty Owners appealed to the Colorado Court of Appeals, which reversed the District Court stating that relevant terms in the leases were subject to legal debate.

After granting de novo review, the Colorado Supreme Court stated that the “most sensible reading of these provisions together is that once parties whose mineral interests are the subject of a lease agreement have raised a nonfrivolous, genuine dispute about a contract term, jurisdiction to interpret that contract lies with the courts, and not with [ECMC],” holding that the ECMC does not have jurisdiction to review the lease provisions at issue, including whether or not the provisions are ambiguous.

V. Kansas

Kansas had a quiet year in both the legislature and the judiciary. Two decisions were issued of interest to practitioners. No statutes or regulations of import were enacted.

A. Judicial Developments

In Mog, Tr. of Craig M. Mog Living Tr. Dated Oct. 23, 2015 v. St. Francis Episcopal Boys’ Home of Salina, the Kansas Court of Appeals confirmed the conventional wisdom that plaintiffs in a partition action do not need to provide defaulting parties notice of filings or rulings in the case. Kansas does not recognize forced-pooling. As a result, operators must secure leases with all mineral owners before drilling or be willing to carry the unleased fractional interest. As a practical matter, this means that Kansas operators do not drill unless they have all the mineral estate leased, which can be difficult. As a solution, landowners use partition actions to clear title defects and consolidate ownership.

In Mog, the plaintiffs owned sixty percent of the mineral interest in the partitioned tracts. The McEwen Trust owned about two percent of the minerals. The Trust did not file an answer or other responsive motion to the petition for partition, but the trustee sent a letter to the Court saying that she opposed the partition. The trustee then appeared at a hearing pro se. The Court explained that the trustee could not represent an entity because she was not an attorney. After an extensive discussion, the trustee said that she would not hire an attorney or challenge the partition. The Court found the trust was in default. After the hearing, the partition proceeded, and the property was sold. When the plaintiffs filed a motion to approve the sale, the Trust claimed the sale should be set aside because it did not receive sufficient notice of developments in the case. The plaintiffs’ counsel had sent the trustee copies of pleadings via email which the trustee claimed was deficient. The Court of Appeals found that ongoing notice is not required when a party that has been properly served with a petition has opted not to respond or participate in the case, nor could the trust claim detrimental reliance on a statement by plaintiffs’ counsel that they would send the trustee copies of pleadings because the trust was a defaulting party.

This ruling is important because mineral partition actions typically have many defaulting defendants, including unknown and unascertainable parties. If parties were required to serve copies of all pleadings, it could substantially drive up the administrative costs of these routine actions.

In United States v. Coffeyville Res. Ref. & Mktg., LLC, the federal District of Kansas ruled on a dispute involving a refinery’s Clean Air Act and Kansas Air Quality Act violations. Most Kansas operators sell crude oil to one of two refineries in the state – CHS Refinery or Coffeyville Resources (“Coffeyville”). Coffeyville has had two consent decrees with EPA over Clean Air Act violations at its facility. In 2020, EPA and the Kansas Department of Health and Environment (“KDHE”) demanded stipulated penalties from Coffeyville pursuant to paragraph 202 of the 2012 Consent Decree. In December 2021, plaintiffs filed a supplemental complaint, alleging nine new claims based on “transactions, occurrences, and events” that occurred after the filing of the original complaint. In February 2022, plaintiffs filed an additional eight claims.

In October 2022, the District Court dismissed KDHE’s claims for civil penalties under a Kansas statute. The State then moved for leave to amend. Coffeyville did not oppose with one exception: KDHE asked to add claims for injunctive relief under K.S.A. section 65-3012. The magistrate judge granted leave to amend. The District Court then found that the plain language of the statute authorized suit to be filed in “any court of competent jurisdiction.” Coffeyville subsequently entered into a proposed settlement with EPA, agreeing to pay over $23 million, representing $13.25 million in penalties, $9 million on implementation measures to prevent future violations, and $1 million on a Supplement Environmental Project.

VI. Louisiana

A. Legislative Developments

The Louisiana legislature amended the state statutes governing carbon capture and storage with Act No. 378 of the 2023 Regular Session. The governing authority of an affected parish must now receive notice in the following circumstances: (1) from the Office of Conservation when the application for a permit to construct/drill a Class V or Class VI injection well is complete, (2) any time notice is required under the Louisiana Geological Sequestration of Carbon Dioxide Act, (3) from the State Mineral and Energy Board before entering into an operating agreement, and (4) from an applicant applying for a permit to conduct geophysical and geological surveys for a carbon capture and storage project. Act No. 378 also amended La. R.S. 30:1104.1 to require any applicant to include an environmental analysis in its submission for a Class VI injection well permit. This analysis is to be considered by the Office of Conservation in its role as a public trustee. New statutes were also added to Title 30 to specify how carbon capture and storage revenues from leases and operating agreements must be split between the local governing authority of the affected parish and various state funds.

Significantly, the act increased the delay before liability is transferred to the State of Louisiana from ten to fifty years. The act also requires operators to provide quarterly reports to the Office of Conservation regarding their operations and to report within twenty-four hours in the case of a failure of mechanical integrity or if operations conducted may endanger or compromise underground sources of drinking water. The act allows for the recording of a “notice of geologic storage agreement” in the public records instead of the complete agreement. Finally, Title 30’s provisions related to the Carbon Dioxide Geologic Storage Trust Fund were also amended. The law now requires fees assessed to operators to recommence once the amount deposited for the site is reduced below $4 million due to state expenditures instead of the previous $5 million. Moreover, while an operator of multiple projects will not have an obligation to pay into the trust fund after reaching a balance of $10 million, the operator will be required to resume payments once the balance is reduced below $8 million.

B. Judicial Developments

Significant litigation is ongoing in the Western District of Louisiana regarding whether unleased mineral owners whose land is in a drilling unit created by the Commissioner of Conservation must bear their pro rata share of post-production costs when the unit operator markets and sells its share of production from the unit. After the District Court affirmed this obligation last year under the Civil Code regime of negotiorum gestio, it certified its decisions in Self v. BPX Operating Co. and Johnson v. Chesapeake Louisiana, LP for interlocutory appeal pursuant to 28 U.S.C. section 1292(b). Following a consolidated oral argument in December 2022 before the Fifth Circuit Court of Appeals, the Court issued nearly identical opinions in each case certifying the following question to the Louisiana Supreme Court: “Does La. Civ. Code art. 2292 apply to unit operators selling production in accordance with La. R.S. 30:10(A)(3)?” One of the judges on the panel dissented on the grounds that, in his opinion, this Civil Code regime was incompatible with La. R.S. 30:10(A)(3), and therefore, certification to the Louisiana Supreme Court was improper. At the time of this publication, the Louisiana Supreme Court has only granted certification in Self, and the briefing will be submitted in early 2024.

Air Products Blue Energy, LLC v. Livingston Parish Government is an important case in the context of carbon sequestration projects in Louisiana. The plaintiff, Air Products Blue Energy, LLC (“Air Products”), sought to drill a Class V test well beneath Lake Maurepas and within Livingston Parish. It also planned to perform a subsurface seismic survey of Lake Maurepas to construct a carbon sequestration facility beneath the lake pursuant to La. R.S. 30:209(4)(e)(ii). In addition to acquiring the necessary permits for the project, Air Products entered into a storage agreement with the State of Louisiana that provided Air Products with, among other things, “the sole and exclusive right to control, or perform all activities on the Property as may be necessary or incidental to the Permitted Purposes…” However, on October 13, 2022, Livingston Parish “adopted a twelve-month moratorium[] on ‘any activities associated with Class V wells where the well is specific to geologic testing of rock formation, monitoring, drilling, or injecting of CO2 [sic] for long term storage.’” In response, Air Products filed suit seeking declaratory and injunctive relief to enjoin any enforcement of Livingston Parish’s moratorium as it relates to seismic surveys, Class V injection wells, and associated activities on the grounds of federal and state preemption. The Middle District of Louisiana juxtaposed this moratorium with the legislation enacted by the Louisiana Legislature that empowers the Office of Conservation to regulate injection wells as part of the state’s EPA-approved program. The court concluded that the extensive nature of legislation was intended to preempt the field of underground injection wells and associated activities, as there was a need for state-wide uniformity. The court agreed the injury to Air Products constituted irreparable harm to support the issuance of the preliminary injunction.

In legacy litigation, Hero Lands Company, L.L.C. v. Chevron U.S.A., Inc. provides an extensive analysis of Act 312 and its application at trial. Plaintiff, Hero Lands Company (“Hero”), owns approximately 155 acres of land that has been subject to decades of oil and gas exploration and production. On March 5, 2018, Hero sued Chevron and eight other defendants alleging its property incurred harm due to the defendants’ oil and gas operations. At trial, the jury found that one of the allegedly impacted tracts suffered no “environmental damage,” as defined by Act 312, and that neither Chevron nor its assignees or lessees acted “excessively or unreasonably” on any of the Hero tracts. On appeal, several noteworthy issues were addressed. First, the Louisiana Fourth Circuit Court of Appeal interpreted Subpart M of Act 312 to allow damages for “unreasonable or excessive operations” based on the existing rules and standards at the time of the complained of activity. The Fourth Circuit determined that it was inappropriate to conclude that either Chevron’s or its assignees’ operations were “per se unreasonable or excessive based solely on the fact that the environmental compliance orders were issued.” Second, the Fourth Circuit held that the trial court was bound to allow argument and jury instruction as to the complexities of Act 312 because the jury was obliged to evaluate, as a preliminary matter, whether environmental damage existed. Third, and finally, the Fourth Circuit rejected Hero’s argument that the definition of environmental damage, which includes potential damage or injury, exists on a tract where the jury found there was no environmental damage merely because environmental damage existed on the surrounding tracts, noting that the testimony of several experts provided a more than reasonable basis for the jury to determine that there was no environmental damage on the tract notwithstanding the state of the adjacent properties.

Castex Development, LLC v. Anadarko Petroleum Corp. expressly declares a long line of Louisiana legacy cases to be dicta and finds it possible for a prior landowner to transfer rights to sue for environmental damage to the property to a buyer under a mineral lease after the lease has already expired. The plaintiff, Castex Development, LLC (“Castex”), purchased property from a prior owner years after alleged oilfield damage was sustained. Prior to finalizing the sale, Castex entered an agreement with the prior owner wherein Castex would acquire the prior owner’s interest in the property pursuant to the terms of a 1954 oil, gas, and mineral lease which had expired over thirty years prior to the sale. Thereafter, Castex sued Anadarko for tort and contract claims based on alleged breaches of the expired mineral lease which led to contamination of the property. Anadarko cited to LeJeune Bros., Inc. v. Goodrich Petroleum Co., L.L.C. and a string of cases citing LeJeune. The case, which has been heavily relied upon in similar arguments, holds that it is not possible to transfer rights under a lease that has expired. The Third Circuit, however, overturned its own prior rulings on the matter and held that LeJeune is contrary to the express provisions of La. C.C.P. arts. 1984 and 2642. Therefore, according to the Third Circuit, the holding in LeJeune and the cases following its ruling are “pure obiter dicta,” and that relying on them as law “simply is not supported by our civil law tradition.” The court went on to conclude that a subsequent landowner was not precluded from suing by the subsequent purchaser doctrine where the transfer of rights to sue was done pursuant to an expired oil, gas, and mineral lease.

Finally, in November 2023, the Louisiana First Circuit Court of Appeal provided further insight into what must be included in a “Most Feasible Plan” issued by the Louisiana Department of Natural Resources under Act 312 when it affirmed the trial court decision in Louisiana Wetlands, LLC v. Energen Resources Corp. The First Circuit found that a most feasible plan adopted pursuant to Act 312 “need not identify the specific numeric values to which constituents in the soil and groundwater may need to be remediated if remediation ultimately proves unnecessary after further evaluation.” The court further reasoned that if LDNR were required to “definitively grant or deny any exception from the remediation standards before the environmental damage is fully evaluated, Act 312’s option for evaluation plans is pointless.”

VII. New Mexico

A. Judicial Developments

The New Mexico Supreme Court resolved a lengthy and convoluted dispute between a sole heir, his successor-in-interest, and the distant devisees of Herbert and Marie Welch in the case of In re Last Will and Testament of Welch (Premier Oil & Gas, Inc. v. Welch, et al). The careful and narrowly crafted opinion resolves only one of the many thorny issues as to bona fide purchaser (“BFP”) protection under facially regular but void judgments, otherwise affirming the New Mexico Court of Appeals’ handling of other issues relating to notice, jurisdiction, and finality of probate judgments.

The facts are as follows: Marie and her husband had a joint will, probated after Herbert’s death in 1975. That joint will left everything to the surviving spouse, later devising Herbert’s share of the minerals to his brother (the Welch Heirs) upon the death of the surviving spouse. That will was probated after his death, resulting in a final judgment titling all minerals in Marie as her sole and separate property. Marie later moved to Florida and executed another will, the 1980 Will. After Marie died in 1988, her nephew (Griffin) knew Marie had a will but was unable to locate a copy. Some twenty years later, without any additional or renewed search, Griffin filed a determination of heirship proceeding in 2007, attesting that Marie died intestate and he was Marie’s only heir. Notice was provided only by publication in the same New Mexico county as the heirship proceeding and the Welch Heirs were neither named nor served. The 2007 judgment declared Griffin to be the sole heir and owner of Marie’s mineral interest.

In 2010, prior to acquiring a lease covering Griffin’s interest, Premier commissioned a title opinion. The title opinion indicated that Premier was entitled to rely on the 2007 judgment. In 2012, Marie’s cousin and devisee probated her 1980 Will, providing notice to Griffin and the Welch Heirs. Premier joined to quiet title. On summary judgment, the district court found in favor of Griffin and Premier, affirming the 2007 judgment and Premier as a BFP. The Court of Appeals reversed in favor of the Welch Heirs, finding the 2007 judgment void because Griffin failed to exercise reasonable diligence, but affirmed Premier’s BFP claim.

The New Mexico Supreme Court affirmed the Court of Appeals, clarifying that the actual notice prong of the BFP analysis hinges on the four corners of the judgment in question. The Court followed Archuleta v. Landers, which held that a purchaser of property sold under a facially valid judgment, later determined void as to excluded minor heirs, is entitled to bona fide purchaser protections. Therefore, extrinsic evidence cannot overcome the rights of a BFP who relies on a facially valid judgment. Moreover, the mere possibility of an adverse claim, which arises only from considering facts outside of a facially valid judgment, cannot be “actual notice of adverse title claims.” Here, the 1980 Will, upon which the Welch Heirs singularly relied to challenge the 2007 judgment and Premier’s title, was “only visible by looking at documents outside of its four corners.” The Court also noted that the improper exercise of jurisdiction by one court is not to be corrected at the expense of an innocent purchaser for value. The Court reasoned that holding otherwise invites second-guessing, speculation, and absurd outcomes that “diminish public trust in our judicial system.”

The U.S. Court of Appeals for the Tenth Circuit reviewed a multi-faceted NEPA case from the District of New Mexico. The Diné Citizens case involved a challenge by a coalition of environmental groups to the Bureau of Land Management’s (“BLM”) environmental assessments (“EAs”) and environmental assessment addendum (“EA Addendum”) analyzing the environmental impact of 370 applications for permits to drill (“APDs”) oil and gas wells in the San Juan Basin of New Mexico. The Tenth Circuit affirmed the district court’s decision to decline to review 171 of the APDs, as those had not been approved by the BLM and were not ripe for review.

Review of the BLM’s NEPA decisions was under the standard of whether those decisions were “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with the law.” The Tenth Circuit held that the BLM did not unlawfully predetermine the outcome of the EA Addendum when it did not revoke 199 APDs approved prior to beginning the EA Addendum process. The remainder of the decision concerned whether BLM took the requisite “hard look” at various environmental consequences of the proposed drilling activity. The Court held that the BLM’s NEPA analysis failed to take the requisite hard look at cumulative greenhouse gas (GHG) emissions limiting its analysis to direct GHG emissions from the first twenty years of the proposed wells rather than over the projected lifetime of the wells. It also held that the GHG analysis failed under the hard look test “by relying solely on percentage comparisons where at least one more precise method was available.” The Court rejected a challenge to BLM’s consideration of water usage in the wells and whether that usage would increase water insecurity in the region. The Tenth Circuit also ruled that the EA process failed to consider the cumulative effect of hazardous air pollutants resulting from the construction of approximately 3,000 wells over the years. The final dispute to resolve was the environmental groups’ request to vacate the EAs and EA Addendum or enjoin them given the deficiencies in the process. The Tenth Circuit adopted the test promulgated by the D.C. Circuit concerning vacatur: “(1) ‘the seriousness of the [agency action’s] deficiencies (and thus the extent of doubt whether the agency chose correctly),’ and (2) ‘the disruptive consequences of an interim change that may itself be changed.’” The Tenth Circuit determined that the vacatur and injunction issues were “fact intensive” and should be decided by the District Court in the first instance so remanded the case.

The U.S. District Court for the District of New Mexico declined to certify a class of San Juan Basin overriding royalty owners claiming underpayment of their interests by the operator. The court’s ruling turned on the lack of predominance of common questions. The District Court acknowledged that there were common questions concerning payment methodology and course of performance but determined that there would be no or very little trial time devoted to those questions. Conversely, testimony concerning differences in the language of various royalty provisions would occupy the bulk of the trial. Plaintiffs argued that certain variations in language could be managed by subclassification, but the Court determined that the “same concerns are prevalent” given the varying language and “the different industry-custom-and-usage evidence that will be needed to interpret” those language variations.

VIII. Ohio

The development of oil and gas law in Ohio continued in 2023, with significant cases addressing issues of subsurface trespass, the deduction of post-production costs from royalties, and whether off-lease operations were sufficient to maintain a lease even without pooling, just to name a few.

A. Legislative Developments

On July 4, 2023, House Bill 33 became effective, establishing, in part, a new permitting mechanism for stratigraphic wells in Ohio. Among other things, the legislation (i) provides that stratigraphic wells must be plugged within one year after drilling commenced on the well unless the owner applies to convert the well to another use within that one-year period or obtains financial assurance payable to the state in an amount equal to or greater than the estimated cost to plug the well and reclaim the associated well site; and (ii) allows the well owner to designate certain data and other information as confidential business information not subject to disclosure for a 5-year period.

In December 2023, the Ohio General Assembly introduced two companion bills (House Bill 358 / Senate Bill 200) declaring its intent to establish a regulatory framework for the safe and secure deployment of carbon capture and storage technologies in Ohio. We anticipate further action on this legislation in 2024.

B. Judicial Developments

In TERA, LLC v. Rice Drilling D, LLC, Ohio’s Seventh District Court of Appeals affirmed a trial court decision granting summary judgment to lessors on their trespass claim and finding the lessees liable for $40 million in damages. The parties’ oil and gas leases granted the right to develop the “formation commonly known as the Utica Shale.” The lessees had produced from the Point Pleasant, which they maintained was an interval within the formation commonly known as the Utica Shale. The appeals court disagreed, finding that the lease language unambiguously excluded the Point Pleasant from the grant. The court concluded that because the lease language was unambiguous, there was no set of facts by which the oil and gas companies could demonstrate a good faith belief that they had the right to produce from the Point Pleasant, and were thus bad faith trespassers as a matter of law and subject to the associated harsh penalties. Finally, the court upheld the jury’s damages award based on a NYMEX price for natural gas rather than a local price actually available to a producer in Ohio. The Supreme Court of Ohio accepted jurisdiction and heard oral argument in November 2023.

In Golden Eagle Resources II LLC v. Rice Drilling D, LLC, the U.S. District Court for the Southern District of Ohio granted, in part, and denied, in part, a producer’s motion to dismiss a complaint alleging that it trespassed into the Point Pleasant formation under the plaintiff’s property. The parties held competing oil and gas leases to a property. The plaintiff alleged that the defendant’s leases did not cover the Point Pleasant formation, but that the defendant nonetheless drilled into and produced from it, resulting in a subsurface trespass. The court rejected two of the plaintiff’s theories, including that a trespass resulted merely by including the plaintiff’s property in a pooled unit, although the court did recognize that a lessee does not necessarily physically enter a property that it pools into a unit. But the court did find viable the plaintiff’s theory that a producer may commit a subsurface trespass by injecting fluids and proppants into a property’s subsurface as part of the hydraulic fracturing process. The court also found that the rule of capture does not preclude a plaintiff from asserting a conversion claim for produced oil and gas acquired by hydraulic fracturing that invades the plaintiff’s property.

In Grissoms, LLC v. Antero Res. Corp., the U.S. District Court for the Southern District of Ohio held in favor of the lessors in a suit alleging the breach of an oil and gas lease. The issue was whether the lessee was entitled to deduct a pro rata share of post-production processing and fractionation costs from royalty payments under the lease’s market enhancement clause. That clause provided, in part:

[All] royalties or other proceeds accruing … shall be without deduction … for the cost of … processing, transporting, and marketing the oil, gas and other products produced hereunder to transform the product into marketable form; however, any such costs which result in enhancing the value of the marketable oil, gas or other products … may be proportionally deducted[.]

Following the Fourth Circuit’s decision in Corder v. Antero Resources Corp., the court held that the phrase “other products” included natural gas liquid (“NGL”) purity products, and thus “when [the lessee] pays royalties from the sale of a particular product, it may deduct actual and reasonable costs it incurred after that product became fit for sale[.]” Costs to process the gas stream into residue gas and Y-Grade, and then fractionate the Y-Grade into individual NGL purity products therefore could not be shared with the lessors. The lessee is expected to appeal to the Sixth Circuit Court of Appeals.

In Sabre Energy Corp. v. Gulfport Energy Corp., the U.S. District Court for the Southern District of Ohio considered whether ORRIs in the drilling units of shallow vertical wells attached to subsequently drilled deep horizontal wells. The plaintiff was assigned ORRIs in specified wells and associated drilling units, but the assignments provided that the ORRIs would not extend to “undrilled acreage.” Decades later, defendant lessees drilled horizontal wells to produce from the Utica/Point Pleasant formation, and certain of these wells traversed those drilling units, producing from beneath the shallow vertical wells. While the plaintiff believed they were entitled to proceeds from any well producing from acreage included in those drilling units, the court disagreed, finding that the plaintiff’s ORRIs did not attach to horizontal wells. In doing so, the court focused on the language of the ORRI assignments, which were limited to referenced wells and their “drilling units,” and further limited to exclude “undrilled acreage.” As to those drilling units smaller than forty acres, the ORRIs did not attach to any deep horizontal well because the court determined that “drilling units” were limited in depth to the depths identified in Ohio regulatory spacing law. In other words, the court found that inherent in the grant of ORRIs in drilling units under forty acres was a 4,000-foot depth restriction, which is well above the Utica/Point Pleasant formation. And while the ORRI grant would encompass the Utica/Point Pleasant formation for the larger drilling units, the court held that in the context of the ORRI assignments, “undrilled acreage” included a depth component. As a result, the ORRIs did not attach to depths below the deepest of the shallow vertical wells.

In Lehman v. Gulfport Energy Corp., the U.S. District Court for the Southern District of Ohio rejected a claim that the lessee had breached an oil and gas lease by releasing the plaintiff’s property rather than drilling an offset well to protect the land from drainage after another producer drilled adjacent wells. The lease included a reasonable development clause providing that “[i]f oil or gas should be produced in paying quantities from a well on adjacent acreage that is draining any acreage of the leased premises that is not pooled or unitized with that well,” then the lessee must begin efforts to drill an offset well “within six (6) months after the earlier of: (1) notice from the Lessor of such producing well or (2) Lessee’s knowledge of such well having been drilled . . . .” The court agreed that, under this language, the lessee’s obligation to drill an offset well did not trigger until it had knowledge that an adjacent well was, in fact, producing, rather than merely having been drilled. By the time two of the adjacent wells had commenced production, the lessee had already released the property. And, while the third adjacent well began producing before the lessee released the lease, the release still occurred within the six-month deadline to drill an offset well as provided in the reasonable development clause. The lease’s release clause, which stated that the lessee was “relieved of all obligations as to the released acreage,” terminated that obligation.

In Faith Ranch & Farms Fund, Inc. v. PNC Bank, Nat’l Ass’n, Ohio’s Seventh District Court of Appeals analyzed whether the phrase “other minerals” used in a 1953 reservation was intended to include oil and gas rights. The grantor in the 1953 deed reserved coal “and other minerals, with the right to mine and remove such coal or other minerals … using any convenient underground mining methods.…” Relying on its earlier decision in O’Brandovich v. Hess Ohio Devs., LLC, the court began its analysis with the presumption that “other minerals” includes oil and gas. The court’s next step was to determine whether the reservation language demonstrated the parties’ intent to either include or exclude oil and gas interests. In doing so, the court looked at the easement language included in the reservation. The court determined that the references to “right to mine” and “mining methods” as the method of removal, as opposed to “drilling,” suggested that “other minerals” was not intended to include oil and gas. The court further found that the reservation language was ambiguous and went on to consider parol evidence, including language used by the same grantor in earlier deeds. Because the grantor had explicitly reserved oil and gas in earlier deeds, the court held that the phrase “other minerals” used in the 1953 deed did not include oil and gas rights.

In Ischy v. Northwood Energy Corp., plaintiff lessors contended that defendant lessee’s pooling of only 0.19 acres of their 297-acre lease into a production unit where the 0.19 acres would not even be drained by the unit well was done in bad faith solely to maintain the lease’s primary term without paying to exercise the extension option. Ohio’s Seventh District Court of Appeals rejected that claim, noting that the lease gave the lessee the right to pool all or any portion of the leased premises and to determine the size and shape of the unit in its sole discretion, and a party does not breach the implied covenant of good faith and fair dealing simply by exercising its rights under the express terms of the lease. Further, had the lease not been properly pooled into that unit, the court opined that the lease was still extended into its secondary term by certain off-lease activities related to another well due to the lease’s broad definition of “operations.”

In Scenicview Ests., LLC v. SWN Prod. (Ohio), LLC, the United States Court of Appeals for the Sixth Circuit considered whether a lease expired as to acreage outside of a producing unit at the expiration of its primary term by operation of the lease’s Pugh clause. Here, the lease’s habendum clause provided that operations conducted on the leasehold or lands pooled therewith would serve to extend the lease into its secondary term. And based on the language of the lease’s pooling provision, the court found that the land in question was properly pooled into the new unit. The lease defined “operations” to include “any preliminary or preparatory work necessary for drilling, conducting internal technical analysis to initiate and/or further develop a well, [and] obtaining permits and approvals associated therewith.” In addition to filing a declaration of pooling, the lessee was engaged in a number of activities involving the creation of the unit prior to the expiration of the lease’s primary term. These activities included, but were not limited to, title research, budgeting activities, surveying, negotiations with other working interest owners, and cellar digging (which constitutes the “first step of a drilling operation”). The court held that these activities, despite being off-lease, were sufficient to continue the lease into its secondary term.

In Kocher v. Ascent Res.-Utica, LLC, Ohio’s Seventh District Court of Appeals addressed whether a deed conveying a fractional interest in the subject property could serve as a root of title to extinguish previously reserved mineral interests under the Ohio Marketable Title Act, Ohio Rev. Code Ann. section 5301.47, et seq. (“MTA”). In this case, the property was owned by ten individuals as tenants-in-common. By way of two deeds, each recorded on February 9, 1957, the collective owners of a 9/10 interest in the property conveyed their interests to a company, excepting and reserving the mineral rights. A third deed (“Rembish Deed”) was also recorded on February 9, 1957 after the two reservation deeds whereby the owner of the remaining 1/10 interest conveyed “an undivided one-tenth (1/10th) interest in” the property to the same company. Importantly, the Rembish Deed did not contain a mineral reservation, and it was this deed that the surface owners relied on as their root of title to claim that the severed mineral rights were extinguished under the MTA. In order for an interest to be extinguished under the MTA, the claimant must have a root of title, which consists of two distinct components, one temporal and one substantive. Here, the temporal element was not in dispute, so the question was whether the Rembish Deed purported to create the interest claimed by the surface owners. While the trial court had focused on the nature of ownership rights afforded to individual co-tenants (i.e., ownership of an undivided share and the right of possession of the entirety of the property), the appellate court instead focused on the language utilized in the Rembish Deed. By its plain language, the Rembish Deed only purported to convey an undivided 1/10 interest in the property, while the surface owners were claiming a 100% interest. As a result, the appellate court held that the Rembish Deed did not satisfy the root of title’s substantive element because it purported to create a lesser interest than that claimed by the surface owners. Moreover, even if the Rembish Deed qualified as a root of title, the appellate court explained that the MTA could not extinguish the severed mineral rights because the two reservation deeds and the Rembish Deed were all recorded on the same date. While the reservation deeds were recorded before the Rembish Deed, the MTA only extinguishes interests “existing prior to the effective date [(i.e., the recording date)] of the root of title” (emphasis added).

In Crozier v. Pipe Creek Conservancy, LLC, the Seventh District Court of Appeals was faced with the oft-litigated question of whether a reference in a deed to a prior reservation was specific or general. Under the MTA, an interest can be saved from extinguishment if there is a specific reference to the interest in the claimant’s forty-year chain of record title. In this case, the severance language was as follows: “EXCEPTED AND RESERVED, all the oil & gas rights and privileges on and underlying the above described tract of land.” The court undertook the three-part test established by the Supreme Court of Ohio in Blackstone v. Moore to determine whether a reference to the severance in the surface owner’s root of title deed was specific or general. Here, the root of title contained the following language, being a repetition of the original severance: “Excepting and reserving all the oil and gas rights and privileges on and underlying the above described tract of land.” After comparing and contrasting several prior decisions applying the Blackstone test—both its own and the Supreme Court of Ohio’s—the court acknowledged that the only difference between the reference and the original severance is the change of tense from “excepted and reserved” to “excepting and reserving.” However, even after concluding that the change in tense “does not affect the repetition,” the court found the reference to be vague, as the use of “excepting and reserving” left it unclear whether the repetition was a reference to a prior reservation or an entirely new, original reservation. Because the reference was subject to two interpretations, it was a general reference and the severed mineral interest was extinguished under the MTA.

IX. Oklahoma

A. Judicial Developments

In likely the most significant case of the year in Oklahoma oil and gas law, the Oklahoma Supreme Court interpreted an oil and gas lease cessation of production clause. In Tres C, LLC v. Raker Resources, LLC, the issue before the court was whether the defendant’s oil and gas lease terminated following ninety days of no production in paying quantities because the defendant failed to commence drilling or reworking operations within the sixty-day grace period provided under the lease’s cessation of production clause. The clause provided as follows: “If, after the expiration of the primary term of this lease, production on the leased premises shall cease from any cause, this lease shall not terminate provided the lessee resumes operations for drilling a well within sixty (60) days from such cessation . . . .” Due to difficulty bucking pipeline pressure, the defendant struggled to sell natural gas for a period totaling approximately ninety days. No drilling or reworking operations were commenced on the lease until sixty days following the end of this period of unprofitability. The plaintiff, which held a top lease on the premises, asserted that the defendant’s bottom lease terminated for lack of production in paying quantities and was not salvaged by the cessation of production clause because the cessation continued for greater than 60 days without resolution or new drilling or reworking operations. The district court agreed, finding the lease terminated for lack of production in paying quantities based on the 90-day period of unprofitability. On appeal, the defendant argued that the cessation clause provided 60 days in which to commence drilling or reworking operations following a permanent cessation of production in paying quantities, and that 90 days of unprofitability was not long enough to establish such a cessation.

The Oklahoma Supreme Court held that ninety days of continuous lack of profit from operations was insufficient as a matter of law to establish a cessation of production in paying quantities. It further concluded that the grace period furnished by the cessation of production clause did not start running until a permanent cessation of production, or a cessation of production in paying quantities, was established. The clause’s grace period did not set the accounting period for determining whether the lease had terminated for lack of production in paying quantities. Instead, the cessation clause saved the lease that had otherwise expired for want of production. This is the interpretation of the cessation clause advanced in Kuntz, Law of Oil and Gas. In adopting this interpretation, the Tres C court disapproved of the view that the time period defined in a cessation of production clause displaces or overrides the reasonable time period for determining whether a lease has terminated for lack of production under the temporary cessation of production doctrine.

The dispute in Oil Valley Petroleum, LLC v. Moore centered around a lease allegedly held by production from a shallow gas well. The leasehold interest in the shallow zones where the well was producing was held by Staab subject to an overriding royalty interest held by the plaintiff, Moore. Moore also owned the leasehold interest in the formations below the deepest producing formation. Staab executed a release of the shallow rights, which caused a top lease held by Oil Valley to spring into effect, covering all formations. Oil Valley sued to quiet title to the working interest in all depths, asserting that Moore’s interest in the deep rights terminated for lack of production when Staab released the lease as to those depths where the only existing well produced. Moore argued that the release did not extinguish his overriding royalty interest or his working interest in the deep zones because the well was producing in paying quantities and the release was given fraudulently for the purpose of washing-out Moore’s interests. The district court granted summary judgment in favor of Oil Valley against Moore’s claims, finding that Moore failed to furnish evidence to support his claim that the well was producing in paying quantities. Moore’s only evidence of the well’s profitability consisted of receipts or check stubs indicating revenues from the sale of natural gas; he provided no evidence of operating costs as would be necessary to demonstrate whether production was in paying quantities. The Oklahoma Supreme Court affirmed and remanded the case for further fact finding. Pending further factual development, the court declined to opine on Moore’s legal theory that Staab’s release improperly washed-out Moore’s overriding and working interests.

The Oklahoma Supreme Court clarified the extent of a trial court’s discretion in dividing property interests related to oil and gas in divorce proceedings in Fitzpatrick v. Fitzpatrick. Husband appealed a trial court order that deferred distribution of certain equity interests in oil and gas exploration and production companies acquired by husband during the marriage, requiring husband to hold the equities in constructive trust for the benefit of both spouses. The Oklahoma Supreme Court affirmed the order, holding that when faced with an asset, “the value of which could not be determined at the time of property division,” trial courts should use a deferred distribution method rather than attempt to value and equitably divide the assets at the time of the divorce. The court further held that trial courts are within their discretion to impose constructive trusts on marital assets in the hands of one spouse when equitable under the circumstances.

In Hitch Enters., Inc. v. Key Prod. Co., the plaintiffs, lessors under oil and gas leases operated by the defendant, alleged that the defendant breached its implied duty to market and Oklahoma’s marketable product doctrine by deducting from the royalty paid under their leases the costs of removing NGLs from gas extracted from wells on their lands. The trial court certified the plaintiffs as a class, and defendants appealed. The defendant argued that class adjudication was inappropriate because individual issues of fact predominated common questions. The fact issues, argued defendant, concerned the quality or condition of the gas in its raw state from the class wells and the proper interpretation of the defendant’s individual oil and gas leases with members of the class. The Court of Civil Appeals affirmed the trial court’s order, finding that individual fact issues did not predominate because neither the quality of the raw gas from each individual well nor the language of particular leases was necessary to determine whether the gas was marketable when sold. The fact that the class leases included various types of clauses that calculated royalty on “actual proceeds,” based on the value of “raw gas” or “gas in its natural state,” or “at the well,” did not matter to the appellate court because most of these provisions existed in some form in the leases at issue in the trilogy of cases establishing Oklahoma’s marketable product rule, and thus have implicitly been found not to abrogate the common law rule.

In federal cases, the Eastern District of Oklahoma heard a case similar to Hitch in Sagacity, Inc. v. Magnum Hunter Prod., Inc. Like Hitch, Sagacity involves putative class action claims for underpaid royalties based on allegedly improper deductions under the marketable product rule. Unlike Hitch, which was an appellate court opinion, Sagacity is the ruling of the trial court on class certification. The merits of the claims in Sagacity and in Hitch are substantially similar, as were the primary legal issues involved in the plaintiffs’ respective motions for class certification. As in Hitch, the Sagacity court found that class certification was appropriate because facts regarding the quality of raw gas at the defendant’s wellheads and the particular language of most of defendant’s leases did not predominate given that all leases and gas are subject to the marketable product rule. The Sagacity court did, however, exclude two categories of oil and gas leases owned by the defendant from the class. These leases used language indicating an intent that royalties be paid on “raw gas,” called Whisenant leases, and so-called Fankhouser leases calculating royalties on “net proceeds,” “net amount,” and “gas sold.” Sagacity also made clear that although it is unsettled in Oklahoma at what point or in what condition gas may be “marketable” for purposes of the marketable product rule, the question is ultimately one for the trier of fact. The factual question may be resolved, according to the court, on the basis of expert testimony that all the gas from defendant’s wells was required to undergo at least some gathering, compression, dehydration, treatment, or processing before it could be sold into the interstate pipeline market.

The Western District of Oklahoma interpreted the state’s anti-indemnity statute not to apply to a master services agreement (“MSA”) for oilfield services in Chesapeake Operating, LLC v. C.C. Forbes, LLC. Chesapeake had settled a personal injury claim with an employee of the defendant who was injured at a Chesapeake wellsite while conducting work contracted for under the parties’ services agreement. Chesapeake brought this suit to recover from the defendant under the parties’ mutual indemnity clause in their agreement. The defendant argued that the indemnity clause was void under Oklahoma’s anti-indemnity statute, which prohibits such provisions in “construction contracts.” The court held that the services provided under the MSA were not “construction” under the statute. A previous case also decided in the Western District of Oklahoma, Jet Maint., Inc. v. Devon Energy Prod. Co., L.P., held that the anti-indemnity statute applied to an MSA when the underlying injury occurred during construction of a well pad for a drilling rig, because a drilling rig constitutes a “structure.” The Chesapeake Operating court declined to follow Jet Maintenance, however, because the underlying injury in this case occurred at the wellhead. The common, ordinary meaning of “structure” would not, in the court’s view, encompass a well, which is little more than a hole in the ground. Moreover, the court cited to the legislative history of the anti-indemnity statute which indicated that the provision was not meant to apply to oilfield services contracts.

The Eastern District of Oklahoma dismissed a landowner’s damages claims for contamination allegedly caused by defendant’s leaking refined-products pipeline. In Lazy S. Ranch Props., LLC v. Valero Terminaling & Distrib. Co., the court first granted summary judgment in defendant’s favor, then denied the plaintiff’s motion to alter or amend the judgment. The court found the plaintiff had no cause of action because no reasonable trier of fact could have found that the trace amounts of petroleum products detected on plaintiff’s property constituted a nuisance or rendered the environment harmful, detrimental, or injurious. In making this determination, the court did not hold that contamination must exceed regulatory limits to be actionable. However, the court was persuaded by the fact that the contaminants found on plaintiff’s land did not reach, let alone exceed, applicable regulatory limits for such contaminants.

The Eastern District of Oklahoma interpreted the Class Action Fairness Act (“CAFA”) to determine whether the plaintiff’s class claims satisfied the Act’s jurisdictional requirement for amount in controversy in Colton v. Cont’l Res., Inc. CAFA requires plaintiffs in class actions to demonstrate that the amount in controversy exceeds $5 million “exclusive of interests and costs” to confer diversity jurisdiction on federal courts. The plaintiffs in this case sued alleging entitlement to more than $5 million in interest due on late-paid gas royalties under the Oklahoma Production Revenue Standards Act (“PRSA”). Previously, in Whisenant v. Sheridan Prod. Co., LLC, the 10th Circuit dismissed class claims for underpaid royalties under oil and gas leases because the amount in controversy satisfied CAFA only by including interest on the amount of royalties alleged to have been underpaid. Distinguishing Whisenant, the court in Colton found that interest may be counted under CAFA “[i]f the amount in controversy itself is the failure to pay interest.” Thus, since the Colton plaintiffs sought only unpaid interest under the PRSA, those amounts could be counted toward CAFA’s jurisdictional requirement.

The 10th Circuit Court of Appeals ruled in an appeal of a $155 million judgment for failure to pay interest under the PRSA in the ongoing case of Cline v. Sunoco, Inc. The judgment debtor, Sunoco, has attempted multiple times to appeal the trial court’s judgment in the case, and each time it has failed because the Circuit Court has found the order fails to satisfy the requirements of finality for a judgment in a class action. In this latest order, the 10th Circuit reversed the district court’s denial of Sunoco’s motion for relief from judgment in which Sunoco sought amendments to the district court’s judgment on the merits that, Sunoco argued, were necessary to make it appealable. The 10th Circuit explained the consequences of its order:

We note, however, that the necessary consequence of our analysis is that the district court has yet to enter a final judgment. So although we do not yet decide whether Rule 60(b)(6) relief is appropriate, we urge the district court to promptly take whatever steps it deems necessary to cure the allocation plan’s defects and produce a final judgment that complies with our precedents.

In Hayes v. Halland, the Northern District of Oklahoma found that the Bureau of Indian Affairs (“BIA”) failed to comply with NEPA in issuing oil and gas leases and permits to drill on the Osage mineral estate. The court agreed with the plaintiff, who owned the surface estate overlying the subject leases, that the Osage Agency’s environmental assessment and Finding of No Significant Impact did not satisfy the requirements of NEPA because they lacked sufficient site-specific analysis of the leases’ environmental impacts. Because actual drilling operations on the surface of the land subject to the leases was reasonably foreseeable at the time the agency issued the leases, NEPA required analysis of the foreseeable impacts. The court further found that BIA acted arbitrarily and capriciously in its analysis of two leases it previously issued without conducting site-specific analyses and under which surface-disturbing activities had previously been undertaken, explaining that “the BIA has an obligation under NEPA to include additional terms [in its environmental assessment] to remedy that default.” The court declined to vacate the environmental assessments at this stage, instructing the parties to brief the issue of remedies for further proceedings.

An opinion and order from the Northern District of Oklahoma is the latest in the long-running litigation in United States v. Osage Wind, LLC. In the latest development in over ten years of litigation over a wind turbine farm, the district court entered a permanent injunction ejecting the wind farm from its continuing trespass on the Osage mineral estate. The court will hold a trial on damages for the plaintiffs’ trespass and conversion claims. This order follows the 10th Circuit’s determination that the wind farm project constituted mining that required a lease under BIA regulations, which the developers did not obtain. The issue before the district court was whether the developers’ lack of a lease constitutes a continuing trespass for which injunctive relief and damages are appropriate. The court found that the developer’s “use of crushed rocks as backfill for support [for its wind towers] falls within the definition of ‘mining’ and required a lease . . . [and therefore] that Defendants are liable for continuing trespass because of the continuing use of the minerals as backfill for support.” The court then concluded that the remedy of ejectment is appropriate because the continuing trespass has caused irreparable harm by interfering with the sovereignty of the Osage Nation, that the balance of harms weighs in the tribe’s favor, and that ejectment would serve the public interest in preserving the Osage Nation’s tribal sovereignty.

Finally, in New Dominion, LLC v. H&P Invs., LLC, the Northern District of Oklahoma held that nonoperating working interest owners under participation agreements and AAPL Model Form Joint Operating Agreements (“JOA”) were not liable for any of the operator’s costs of litigating claims related to earthquakes allegedly caused by the operator’s saltwater disposal wells. The operator, NDL, argued that the language of the parties’ participation agreements required the nonoperating parties to pay their share of legal expenses that result from “operations under the operating agreement” and that are “necessary to protect or recover the Joint Property.” The nonoperating working interest owner, H&P, asserted that the saltwater disposal wells and earthquake litigation were not “operations under the operating agreement” and that the disposal wells were the operator’s sole property.

The court interpreted the JOA to cover only operations relating to oil and gas wells, including drilling, reworking, recompleting, sidetracking, plugging back, and deepening wells. The operator’s disposal wells were merely “ancillary production facilities” under the JOA. Moreover, while accounting procedures incorporated into the JOA allowed the operator to charge nonoperators for legal expenses “necessary to protect or recover the Joint Property,” the court concluded that the disposal wells did not qualify. The accounting procedures defined “Joint Property” as the “real and personal property subject to the Operating Agreement to which this Accounting Procedure is attached.” Each participation agreement contained language that conditioned the agreement “on the parties’ recognition that the saltwater disposal wells ‘shall remain the property of NDL and [H&P] will have no ownership interest therein, beneficial or otherwise.’”

NDL also argued that defending the claims for earthquake damage brought against its disposal operations was necessary to protect the Joint Property because those claims involved requests for injunctive and other relief that would have interfered with the ongoing disposal of wastewater from the parties’ joint oil and gas wells. The court found the argument “baseless,” responding: “NDL can dispose of saltwater elsewhere. H&P has no working interest in the saltwater disposal wells. The saltwater disposal wells are ancillary to the operations under the agreements; they are not joint property.” In addition, much of the litigation costs NDL incurred were not necessary to protect the continued operation of the disposal wells, but rather to pursue affirmative claims against NDL’s insurer in a dispute over coverage for the underlying earthquake-damage claims. NDL was held liable for reimbursing H&P for past charges for these legal expenses because they were not authorized under either the parties’ participation agreements or the JOA.

X. Pennsylvania

A. Legislative Developments

On March 3, 2023, Act 153 of 2022 went into effect. This law amends several sections of Title 58 (Oil and Gas) of the Pennsylvania Consolidated Statutes. One of the amendments requires unconventional oil and gas operators to provide production and sales information for each well when remitting payment to the royalty owner. If this information is not provided with payment, it must be provided within 60 days after receipt of a written request via certified mail from the royalty owner. If a royalty owner does not receive the requested information or an explanation for the payor’s failure to provide it within this time period, the Act authorizes the filing of a civil action and the recovery of any resulting attorney fees and court costs. The Act also requires all royalties to be paid within 120 days from the date of first sale and within 60 days thereafter “after the end of the month when the production is sold”. Failure to remit payment within this period will result in a mandatory interest penalty set at the legal rate of interest until all required payments are made, unless the lease provides otherwise.

B. Judicial Developments

In Warner Valley Farm, LLC v. SWN Prod. Co., the Middle District of Pennsylvania upheld the validity of Act 85, which eased regulatory barriers to cross-unit drilling, concluding that it did not violate the Contracts Clause of both the Constitution of the United States and the Constitution of the Commonwealth of Pennsylvania because it allowed the parties the freedom to allow or prohibit cross-unit drilling in their leases. The court concluded that the plaintiff’s lease permitted cross-unit drilling. The court rejected the plaintiff’s argument that a provision stating that the lease would remain in effect as long as “a well capable of producing oil and/or gas is located … on lands pooled, unitized or combined with all or a portion of the Leasehold” meant that the wellbore must be drilled on the surface of lands pooled, unitized, or combined with the leasehold. The court found this argument was “too far a stretch” in light of the lease provision permitting the defendants “in their sole discretion . . . to pool, unitize, or combine all or any portion of the Leasehold with any other land or lands, whether contiguous or not contiguous . . . to create one (1) or more drilling or production units” and “to change the size, shape and conditions of any unit created.” The court reasoned that this provision did not limit the defendants to unitizing or pooling – terms of art in the industry – but also allowed them to combine the leasehold with contiguous or non-contiguous lands necessarily including lands “beyond unit boundaries” and permitting cross-unit drilling. The court also rejected the argument that the defendants were limited to creating one unit that included the leasehold and combining the leasehold only with lands in that same unit. The court concluded that the lease language “expressly contemplates the creation of one or more units” and that “[t]he additional use of the word ‘combine’ after ‘unitize’ strongly suggests that the 2006 Lease contemplated that the Leasehold might be combined in an arrangement containing more than one unit.”

In Bootes v. PPP Future Dev., Inc., the court denied a motion to dismiss claims based on the defendant’s purported material breaches of their lease. After the plaintiffs sent the defendant a notice that they were terminating the lease based on the defendant’s breaches, the defendant rejected the lease termination and the plaintiffs filed suit. The defendant filed a motion to dismiss based on failure to state a claim upon which relief could be granted arguing that, because the lease granted the lessor the option of purchasing the wells and pipeline or having the wells plugged when the lessee determined “in its sole discretion” that operations of the wells were “no longer commercially feasible,” the plaintiffs could not terminate the lease until the defendant made such a determination. The court disagreed, explaining that this provision gives the plaintiffs the option to purchase the wells and pipelines but “does not, in any way, make termination of the Lease solely contingent upon Defendant’s discretionary determination that the wells are no longer feasible, nor does it foreclose Plaintiffs’ right to terminate the Lease based upon Defendant’s material breach of other provisions of the Lease.” The defendant also argued that the claim for negligence per se based on its alleged contamination of the property in violation of the Oil and Gas Act and the Solid Waste Management Act must be dismissed because the plaintiffs failed to allege how these Acts were intended to protect their specific interests rather those of the public generally. The court agreed as to the Solid Waste Management Act, but disagreed as to the Oil and Gas Act based on Roth v. Cabot Oil & Gas Corp., which found that people residing less than 1,000 feet from gas wells, similar to the plaintiffs, were “within the particular group of individuals that the Act is intended to protect.” The court also refused to dismiss the plaintiffs’ breach of contract claims finding that there could be no anticipatory repudiation when they were alleging the lease terminated after the defendant’s material breaches of the lease.

In Douglas Equip. Inc. v. EQT Prod. Co., the Pennsylvania Superior Court affirmed a grant of summary judgment for the defendants concluding that the original lessees’ sale of the property included the right of reversion of the oil and gas after the lease terminated. In 1994, the Willisons entered an oil and gas lease with Douglas Equipment (the “Douglas Lease”) and ownership of the well on the property was transferred to Douglas Equipment. The Douglas Lease provided that it would remain in effect for as long as the property “is operated for the exploration or production of gas or oil, or as gas or oil is found in paying quantities thereon” and for annual payments for up to three years as the shut-in royalty for wells that were no longer profitable to operate. While the Douglas Lease remained in effect, in 1999, the Willisons conveyed the land via general warranty deed to the Holts and Lee which included an exception for “all rights, title, and interest” in the Douglas Lease and a provision that conveyed the land with all reversions belonging to the Willisons (the “1999 Conveyance”). In 2008, production stopped from the well subject to the Douglas Lease and Douglas Equipment began paying the required shut-in royalty. In 2016, the Holts and Lee entered an oil and gas lease with EQT (the “EQT Lease”). The plaintiffs filed suit arguing that the Douglas Lease remained in effect and had become an at-will lease when the well stopped producing. The defendants argued that the Douglas Lease expired in 2011 after production ended and three years of shut-in royalties were paid, at which point the oil and gas rights reverted back to the Holts and Lee. The court concluded that the 1999 Conveyance “conveyed the surface estate and the possibility of reverter of the oil and gas rights as they were not excepted or reserved” which resulted in the revision of the oil and gas rights to the Holts and Lee when the Douglas Lease expired in 2011. Important to the court’s decision was that the Douglas Lease did not include language permitting the modification, amendment, ratification, or termination of the lease but provided that it would terminate upon the failure to produce in paying quantities and preserved only the Willisons’ right to royalties, household gas, and the possibility of reverter. The court rejected the plaintiffs’ argument that the provision of the 1999 Conveyance excepting “all right, title, and interest” in the Douglas Lease resulted in the Willisons retaining the oil and gas rights. The court concluded that the phrase “‘all right, title, and interest’ . . . specifically related to the Douglas Lease—not to the oil and gas itself” meaning that the Willisons did not retain any interest in the Douglas Lease after the 1999 Conveyance other than in the royalties owed under the Douglas Lease that were specifically excepted from the conveyance. The court thus concluded that, “even if an at-will tenancy survived the termination of the Douglas Lease in 2011, that tenancy expired when the Holts and Lee entered into the EQT lease and defended against the Douglas Appellants’ claims in court.”

In Marcellus Shale Coal. v. Dep't of Envtl. Prot., the Pennsylvania Supreme Court considered whether oil and gas regulations extending protections to areas and entities not included in Act 13 were void, unenforceable and unreasonable. After Act 13 of 2012 amended Pennsylvania’s Oil and Gas Act, the Pennsylvania Department of Environmental Protection (the “DEP”) and Environmental Quality Board (the “Board”) promulgated regulations for unconventional gas wells expanding the types of “public resources” which, if potentially impacted by a proposed well, required well permit applicants to notify the associated entity and permitted the DEP to consider comments from those entities when reviewing permit applications. The Marcellus Shale Coalition argued that, without express statutory authority, the DEP and the Board could not expand the definition of “public resources” beyond those identified in 58 Pa.C.S. Section 3215. By using the term “public resources” deriving from the Environmental Rights Amendment (“ERA”) that includes a broad and undefined conception of such resources, the court concluded that the General Assembly intended to allow the DEP and the Board “a large degree of [] flexibility” in defining those resources. Because the challenged definitions fell within the ERA’s broad conception of public resources, the court upheld the definitions. The court further found that these definitions were reasonable and not at odds with the statutory scheme in light of their link to the ERA, rejecting the lower court’s finding that these definitions “upset the balance between industry and the environment” as “just an alternative way of saying that they are ‘unwise or burdensome or inferior to another.’”

C. Administrative Developments

In Protect PT v. Commonwealth, the Pennsylvania Environmental Hearing Board (the “Board”) refused to dismiss an appeal challenging the issuance of two gas well permits. Protect PT appealed the issuance of two gas well permits arguing that the Pennsylvania Department of Environmental Protection (the “DEP”) failed to properly consider the release of per- and polyfluoroalkyl chemicals (collectively, “PFAS”) into the environment when issuing the permits. The permittee filed a motion to partially dismiss the appeal arguing, among other things, that the appeal sought to have the Board exceed its authority to promulgate regulations of PFAS or compel the DEP to do the same and sought a ruling beyond the scope of the case that would impact the entire oil and gas industry. The Board concluded that the crux of the appeal was “to determine whether the Department’s action in issuing the permits is in accordance with the law and supported by the facts of this case,” which was within the scope of the Board’s authority. The Board further rejected the permittee’s arguments regarding the broader applicability of the case, reasoning that its decisions “routinely have broad applicability” but “[t]his is not a basis to avoid exercising [its] statutory duty to hear appeals” from DEP action.

XI. Texas

A. Judicial Developments

In 2023, Texas courts issued several impactful opinions clarifying numerous oil and gas issues. The clarifications addressed the interest assigned, fixed vs flowing royalty calculations, covenants running with the land, adverse possession of a working interest, the timely payment of royalties, clarification of common contract terms, the ownership of produced water, cotenancy issues, and allocation wells.

In Davis v. COG Operating, LLC, the Eight Circuit Court of Appeals of Texas was asked to construe a 1939 warranty deed between the Sesslers, as grantors, and Dora Roberts, as grantee. In March 1926, the Sesslers signed a mineral lease in favor of F. K. Campbell covering Section 45 (the “Campbell Lease”). Later that year, the Sesslers executed an instrument titled “Royalty Deed” (the “1926 Deed”), which conveyed part of their interest in Section 45 to W. H. Haun. Then in 1939, the Sesslers executed an instrument (the “1939 Deed”) which purported to convey to Roberts the remainder of their interest in Section 45, except for a 1/4 non-participating royal interest (NPRI). The 1939 Deed mentioned twice that an interest in the land had previously been conveyed to Haun. Since the execution of the 1939 Deed, the remaining 3/4 of the royalties have been paid to Roberts and her successors. However, no royalties have been paid to the Sesslers or their heirs/successors (the “Appellants”).

On appeal, the Appellants argued that they own a portion of the Sesslers’ NPRI pursuant to the 1939 Deed. The court first looked to the 1926 Deed, which conveyed to Haun a 1/32 interest in and to all of the oil, gas, and other minerals, in and under the lands. The court clarified that the 1926 Deed clearly and unambiguously conveyed an interest in the mineral estate itself, not merely a royalty interest. The court then looked to the 1939 Deed, explaining that the language of the deed stated that 1/32 of the oil, gas and other minerals had been conveyed to Haun. Additionally, the 1939 Deed stated that

[W]e [the Sesslers] reserve unto ourselves, our heirs and assigns, one-fourth (1/4) of the 1/8 royalty usually reserved by and to be paid to the landowner in event of execution of oil and gas leases, so 1/4 of the 1/8 royalty to be paid to us, our heirs or assigns, if, as and when produced from the above described land.

The court explained that “the Sesslers’ and Roberts’ intent behind the use of the 1/32 fraction in the 1939 Deed turns on whether they were operating under an “estate misconception”” (where historically lessors believed that a 1/8 royalty reservation reserved one-eighth of the mineral estate instead of merely a 1/8 royalty interest and a fee simple determinable with the possibility of reverter in the entire mineral estate). If they were not operating under a misconception, then the Sesslers failed to provide adequate notice to Roberts regarding their prior conveyance to Haun. However, if Roberts and the Sesslers were operating under the estate misconception, Roberts would have notice that the Sesslers had previously conveyed a 1/4 interest in the minerals to Haun. The court found that the parties were operating under the estate misconception due to the 1939 Deed’s plain language. Specifically, the court found: (1) the date of the deed was 1939, at the height of the relevant period of the estate-misconception; (2) 1/32 is a product of multiplying 1/4 of 1/8; (3) the use of a double fraction in the reservation was found in the third paragraph of the deed. Consequently, the parties’ intent was to reserve a 1/8 mineral interest, not just a 1/8 royalty interest.

In Devon Energy Prod. Co. v. Enplat II, LLC, the court was asked to determine whether the grantors in a 1940 deed reserved a 1/16th fixed royalty interest or a 1/16th non-executive mineral interest when conveying their property. The deed provided that the grantors reserved “an undivided one-sixteenth (1/16) of any and all oil, gas or other mineral produced on or from under the land” and that the grantees “shall have the right to lease said land for mineral development without the joinder of Grantors..., and to keep all bonus money, as well as all delay rentals, but when, if and as Oil, Gas or other mineral is produced from said land, one-sixteenth (1/16) of same, or the value thereof, shall be the property of Grantors....” The court held that the deed reserved a mineral estate shorn of all attributes but for the right to receive a royalty interest if and when there was production on the land. Because the deed did not use any terms historically associated with a post-production royalty interest (minerals “produced and saved”), and rather used terms traditionally associated with a mineral interest (minerals “in, on and under”), the deed reserved a mineral estate. Turning to the remaining provisions of the deed, the court concluded that an attribute-stripping approach was appropriate to harmonize the provisions and that the grantors stripped themselves of the rights to develop, lease, receive bonus payments, and receive delay rentals, but retained the right to receive royalty payments. The court reasoned that had the grantors intended only to reserve a royalty interest, the remaining provisions would be unnecessary.

It was an active year in the Texas courts for fixed or floating royalty interpretations. Pacer Energy, Ltd. v. Endeavor Energy Res., L.P. involved a fixed-versus-floating dispute and highlighted the grant wording for a fixed royalty. A 1923 warranty deed conveyed “One-Eighth of the Oil and Mineral rights…conveyed as a royalty.” In two 1960 declarations of interest, the parties described the 1923 interest as “1/8 of all of the oil, gas and mineral rights…as a free royalty interest.” Following Texas Supreme Court guidance in Watkins v. Slaughter, Temple-Inland Forest Prods. Corp. v. Henderson Family P’ship, Ltd., and distinguishing French v. Chevron U.S.A. Inc., the court held that the 1923 deed conveyed a fixed 1/8 royalty interest.

The common use of 1/8 creates different interpretations as seen in Permico Royalties, LLC v. Barron Props. Ltd. A 1937 deed reserved

[A] one-sixteenth (1/16) free royalty interest, (being 1/2 of the usual 1/8th free royalty) in and to all of the oil and gas in and under, and that may be produced from, the above described land…and the Grantors…shall be entitled to receive 1/16th of the oil and/or gas produced, saved and sold from said land, being 1/2 of the usual 1/8 royalty therein.

The court held that the deed reserved a 1/2 floating royalty interest, rather than a 1/16 fixed royalty. Based on the related doctrines of the “legacy of the 1/8 royalty” and “estate misconception”, the court held that

[T]he use of a double fraction involving 1/8th creates a rebuttable presumption that the parties intended to use the 1/8th as a placeholder for the royalty provided for in a lease (the legacy doctrine) or as a placeholder for the grantor’s entire mineral estate (the estate misconception doctrine).

The court dispensed with numerous arguments by the appellees that the legacy-of-the-eighth doctrine should not apply to the deed here and held that it reserved a floating 1/2 royalty. The court noted that if the parties had intended a fixed 1/16 royalty, there would’ve been no reason for them to include the parenthetical “1/2 of the usual 1/8 royalty”. The court also pointed out that Texas law creates a presumption that drafters believed that 1/8 would always be the royalty interest under future leases, bolstering their intent to reserve a 1/2 floating royalty.

In Bridges v. Uhl, the court analyzed the language of reserved NPRI to determine the nature and quantum of the interest. The court focused on the following language: reserving “an undivided one half (1/2) of the usual one-eighth (1/8) royalty in, to and under the above[-]described land” and “if, as and when production is obtained,” the grantor “shall receive one-half (1/2) of the usual one-eighth (1/8) royalty, or one-sixteenth (1/16) of the total production….” The parties disputed whether this language reserved a fixed 1/16 royalty or a 1/2 floating royalty. Applying U.S. Shale Energy II, LLC v. Laborde Props., L.P. and Hysaw v. Dawkins, the court interpreted the royalty reservation holistically, not mathematically. The court held that “descriptive language in the text, as well the deed’s overall structure, confirms the grantors’ intent to reserve a 1/2 floating royalty.”

Practitioners should not rely on the 1/8 reference alone to opine on the royalty granted. In Van Dyke v. Navigator Group, the court once again held, in line with Hysaw v. Dawkins, that a royalty reservation of “1/2 of 1/8” does not always equal 1/16. In analyzing a 1924 conveyance, the court reiterated the effect of the estate misconception theory in the drafting of historical conveyances. Here, there was also a ninety-year history of the parties treating the reservation of “1/2 of 1/8” as 1/2 of the minerals for royalty purposes. The court noted that, regardless of how “1/2 of 1/8” would be read today, the analysis should focus on how the original parties to the 1924 conveyance would have understood the language to be read. The court added that even if the reservation was to be read as 1/16, the ninety-year history of the parties treating the reservation as 1/2 of the mineral estate satisfied the three-part test of the presumed grant doctrine.

In Royalty Asset Holdings II, LP v. Bayswater Fund III-A LLC, the court analyzed whether the NPRI reserved in a 1945 deed was fixed or floating. When conveying the land through the 1945 deed, the original grantor reserved an “undivided 1/4^th of the land owner’s usual 1/8^th royalty interest” in existing and future oil, gas and mineral leases on the conveyed land. When a new lessee acquired an existing lease, it argued that the NPRI should be a floating 1/4^th, not a fixed 1/32^nd. Analyzing the deed’s text based on the ordinary meaning at the time of drafting, the court held that the deed’s use of multiple fractions with 1/8^th implicated a rebuttable presumption of a floating interest. The court reasoned that the “usual 1/8^th royalty interest” referred to the entire mineral estate. Though the multiple fractions are followed by a parenthetical, which on its own may imply a fixed 1/32^nd royalty interest, the court interpreted the parenthetical as an explanation for the multiple fraction clause. Coupled with references to future leases, the court concluded that the deed’s text supports the presumption of a floating 1/4^th interest.

The Texas courts provided guidance on assignment provisions in numerous cases. The Eighth Court of Appeals of Texas was tasked with determining whether an assignment of oil and gas interests conveyed the assignor’s interest in a 1998 oil and gas lease in Mark S. Hogg, LLC v. Blackbeard Operating, LLC. The assignment’s granting clause provided that the assignors transferred all of their identified “properties and assets,” which it defined in separate subparagraphs, including “leases, lands, wells, units, and properties” that were identified and described in exhibits. The exhibits made explicit reference to prior leases, but not to the 1998 lease. Because the exhibits named a well that was drilled under the 1998 lease, the court held that the assignors intended to transfer all of their interests, including the 1998 lease. Noting that courts typically construe deeds to confer upon the grantee the greatest estate permitted, the court held that the deed lacked evidence of any intent to grant a lesser estate than what the grantor owned because the assignment neither contained an express reservation nor did it grant only a portion, thus conveying the entire estate, including the 1998 oil and gas lease.

In Armour Pipe Line Co. v. Sandel Energy, Inc., the court addressed the reservation of an ORRI in favor of a party to the assignment that did not have title in the leases prior to that reservation. The assignees argued the reserved royalty was ineffective and void as it was reserved to the plaintiff, a party that was a stranger to title as to the leases. Holding for the plaintiff, the court heavily leaned on the holding of Greene v. White in applying the doctrine of estoppel-by-deed. Ultimately, the court held that regardless of the status of title prior to the reservation, the assignees, as parties to the assignment, were bound under the recitals of the assignment asserting the reserved royalty. In harmonizing the stranger to title rule with estoppel-by-deed, the court emphasized estoppel-by-deed only implies the recognition of the reserved royalty as between parties to the assignment, even if one of those parties to the assignment is a stranger to title.

The court in Citation 2002 Inv. LLC v. Occidental Permian, Ltd. analyzed whether the assignment at issue was a depth-limited grant, conveying only certain shallow rights or an unlimited grant of all depths. The granting language of the assignment read, “it is the intent of this assignment to transfer and convey… [and] hereby [does] convey… all rights and interests now owned… regardless of whether the same may be incorrectly described or omitted from Exhibit A….” Exhibit A described the conveyed interests, sometimes referring to the depths of the interests. Both parties conceded that the assignment and exhibit were unambiguous. However, they disputed whether the assignment was depth-limited. Using the four-corners rule and harmonizing, the court concluded that the plain language showed an intent to convey all of the rights and interests and the exhibit was included merely to provide relevant information to the agreement. The court has ruled that when an agreement references an exhibit to describe the property conveyed, the description of the interest in the exhibit controls the scope of the grant. However, an exhibit is only relevant because of the relevant granting language. Here, the exhibit contained no limiting language; it merely contained depth references among other information about the conveyed interests. Additionally, while the granting language of the assignment directed attention to the exhibit, it also made the grant “subject to the terms and conditions contained herein.” The express granting language of the assignment which conveyed “all rights and interests now owned… regardless of whether the same may be incorrectly described or omitted from Exhibit A” combined with the exhibit demonstrated the parties’ intent to convey all of the interests owned.

Royalty calculations and payment obligations remain a longstanding issue for Texas courts. Devon Energy Prod. Co., L.P. v. Sheppard resolved one wrinkle in this ongoing issue: calculating a landowners’ royalty under the terms of a mineral lease. In this case of first impression, the Supreme Court of Texas affirmed that owners of oil and gas royalties are owed more than gross proceeds under unique “proceeds plus” lease provisions. Specifically, the court analyzed the following provision,

[I]f any disposition, contract or sale of oil or gas shall include any reduction or charge for the expenses or costs of production, treatment, transportation, manufacturing, process[ing] or marketing of the oil or gas, then such deduction, expense or cost shall be added to … gross proceeds so that Lessor's royalty shall never be chargeable directly or indirectly with any costs or expenses other than its pro rata share of severance or production taxes.

The court reasoned that a plain reading of the provision unambiguously established a royalty payable on an amount that exceeded gross proceeds and could even exceed the profits accruing to the producers. The court noted that the provision's language clearly expressed an intent to deviate from the usual expectations of allocation of postproduction costs. Thus, the court found that the lease language created “proceeds plus” leases. Under this type of lease, royalties were payable on gross proceeds “plus sums identified in producers’ sales contracts as accounting for the actual or anticipated postproduction costs, even if such expenses are incurred only by the buyer after or downstream from the point of sale.” Specifically, the court ruled that proceeds plus leases require a two-prong calculation of the royalty base. First, the producer must determine gross proceeds, and then “when the producers’ contracts, sales, or dispositions state that enumerated postproduction costs or expenses have been deducted in setting the sales prices, those costs and expenses shall be added to the … gross proceeds.”

In Brooke-Willbanks v. Flatland Mineral Fund, LP, the court determined that the two previously reserved non-participating royalty interests (“NPRI”) proportionally burdened the mineral interest Kay Brooke-Willbanks (“KBW”) conveyed to Flatland. In 2014, KBW was conveyed a 45/100 mineral interest, equivalent to a 144-acre mineral interest. In 2016, KBW conveyed “an undivided seventy-two (72) Net mineral acres” to Flatland subject to the terms of any valid and subsisting oil, gas and other mineral lease. While selling an undivided thirty-six net mineral acres, Flatland became aware of two NPRIs, from a conveyance in the 1940s, that burdened the royalty interest. Flatland requested that KBW execute a correction deed to clarify the interests. In response, KBW filed suit claiming the NPRIs in the chain of title proportionately burdened the entire mineral estate including the mineral interest conveyed to Flatland. Interpreting the parties’ intent as expressed in the deed, the court ruled that the interest KBW conveyed to Flatland was proportionally burdened by the previously reserved NPRIs based on the use of “net mineral acre” and the “subject to” clause.

The Texas courts also upheld covenants running with the land. In In re KrisJenn, Ranch LLC, the district court looked to whether a net profits interest ran with a pipeline right-of-way as a real property covenant. Regarding the element of intent, the court found that the contracts in question “unambiguously” state an intent for the covenant to run with the land. Although the Bankruptcy Court relied on In re Chesapeake to find otherwise, the district court differentiated the KrisJenn case from the Chesapeake case because it departed from the recognized general rule that express language of an intent of an obligation to run with the land is sufficient. Regarding the element of touch and concern, the district court found that the “shall attach and run” provision within the contracts supported interpreting the term “assigns” to include future owners of the ROW. Regarding the element of notice to successors of the burden, the district court agreed with the Bankruptcy Court finding that the element of notice was satisfied. Regarding the element of privity of estate, the district court found that to the extent Texas requires horizontal privity, the successive grants of property interests satisfy the requirement. Therefore, the district court found that all required elements for a real covenant that runs with the land were satisfied and held that the Bankruptcy Court erred in “finding that the net-profits-interest assignments owned by Appellants were personal covenants rather than real covenants running with the land.”

Adverse possession was at issue when a party attempted to correct a prior misstatement. In PBEX II, LLC v. Dorchester Minerals, L.P., the court held that a non-operating working interest may be adversely possessed. In 1990, Torch, a non-operating working interest owner, mistakenly notified the operator that Torch had assigned its leasehold to Dorchester’s predecessors. In 2016, Torch assigned the same interest to PBEX II, LLC. Torch notified Dorchester one year after the twenty-five year statute of limitation period passed and subsequently attempted to negotiate the execution of a correction, which Dorchester refused. Texas law establishes that both operating and non-operating working interests are possessory, and adverse possession can occur through a tenant. Over the past twenty-six years Dorchester and its predecessors were hostile by performing all the functions required of a working interest owner such as collecting the revenues of its share of production from the operator’s sale, collecting payment invoices from the operator, and paying all taxes due on the working interest. Furthermore, the court held that the operator adversely possessed the working interest on behalf of Dorchester and its predecessors for the twenty-six years prior to this case. Thus, adverse possession of the non-operating working interest occurred since Torch failed to exercise its rights with regard to the working interest during the statute of limitations period and Dorchester and its predecessors usurped all the benefits, liabilities, and obligations for the working interest.

The Texas courts provided guidance on the timeliness of royalty payments. In Freeport-McMoRan Oil & Gas LLC v. 1776 Energy Partners, LLC, the court analyzed whether the safe-harbor provision of the Texas division order statute applied during the pendency of a title dispute. The statute permits operators to withhold production payments “without interest” under certain circumstances. Longview, a non-party, sued 1776 Energy, a non-operator, alleging that the leases owned by 1776 Energy were actually acquired on behalf of Longview instead. Operator suspended 1776 Energy’s royalties until Longview’s suit was resolved. After the Longview suit was resolved in favor of 1776 Energy, the operator released the suspended funds but did not remit interest. The operator argued that the safe-harbor provisions of Section 91.402(b) of the Texas Natural Resources Code allowed them, as payor, to withhold payments from the payee “without interest” under certain circumstances. The first circumstance is if a title dispute would affect the distribution, and the second is if there is reasonable doubt that the payee has clear title to proceeds. The court held that until it had issued its final mandate in the Longview suit, the suit created the required circumstances that satisfied the elements of both Section 91.402(b)’s safe harbor circumstances and, thus, held that the operator “established as a matter of law that it was entitled to withhold distribution of production payments without interest under the statutory safe-harbor provisions . . . .”

Taylor Props. v. Scout Energy Mgmt. answered the question of whether paying two shut-in royalty payments in one year extends the lease by two years. Two wells in Moore County, Texas allowed the lessee to pay a royalty of “$50.00 per well per year, and upon such payment it will be considered that gas is being produced…” The lessee made two fifty-dollar payments within one month of each other and claimed that this had the effect creating a two-year shut-in period. The appeals court disagreed and found that the unambiguous and plain language in the lease that “upon such payment” “per year” extended the lease for twelve months from the time the payment. Payments that act as a substitution for production serve to prevent the expiration of the primary term and must be consistent with and satisfy the habendum clause.

The Texas courts provided guidance on various contract provisions. In Apache Corp. v. Apollo Exploration, LLC, the Texas Supreme Court analyzed the common law rules in contract cases regarding the meaning of the words “from” and “after” in the calculation of deadlines. The Texas Supreme Court reaffirmed the default rule that the measuring date—the date “from” or “after” a period is to be measured—is excluded in calculating time periods unless a contrary intent is clearly manifested by the contract. For example, for periods of years, the period ends on the anniversary of the measuring date, not the day before the anniversary. Departing from the rule does not require specific language, but the lease’s text must include something that either expressly describes how the date will be calculated or that, at a minimum, is clearly incompatible with the default rule.

In Finley Res., Inc. v. Headington Royalty, Inc., the Texas Supreme Court addressed the meaning of “predecessors” within a release provision of an acreage-swap agreement. The release provision provided that “[Headington] waives, releases, acquits, and discharges Petro Canyon and its affiliates and their respective . . . predecessors . . . for any liabilities, claims, demands, causes of action or obligations . . . related to [a certain tract of land].” The Court reiterated past precedent that a release only discharges “persons named or identified with such descriptive particularity that their identify or connection to the released claims is not in doubt.” In analyzing the plain meaning of the word, the Court noted that “predecessors” is often shorthand for predecessors in title or interest. However, in the immediate agreement, the Court held the word referred not to predecessors of the tract, but predecessors of Petro Canyon, as the “syntactic use of ‘predecessors’ thus connotes a prior connection to the corporate entities themselves, not the land.”

In Point Energy Partners Permian, LLC v. MRC Permian Co., the court determined a force majeure provision did not encompass an operator’s “30-hour slowdown of an essential operation that was already destined to be untimely due to a scheduling error.” The operator, needing to drill a well within 180 days after the spudding of their previous well to extend the secondary term of the lease, made a scheduling error in which the new well would not have been drilled until after the deadline. The operator noticed this error after the deadline to drill, and relied on the force majeure provision to extend the secondary term. The alleged force majeure event was a thirty-hour delay in a drilling operation – that used the drilling rig intended for the lease at issue – about a month before the deadline. The court reasoned that the force majeure clause must be understood in its entirety, rather than just a literal interpretation of “Lessee’s operations are delayed by an event of force majeure.” Holding that the force majeure provision was intended to prevent lease termination when an event occurs outside of the lessee’s control, the court reasoned that the wrongfully scheduled and untimely drilling operation would not have suspended termination of the lease even with a delay. Thus, the risk of lease termination was due to a scheduling error which did not fall under the agreed upon force majeure provision.

Conflicting grants of produced water was at issue in a 2023 case. In Cactus Water Servs. LLC v. COG Operating LLC, the court held that an oil and gas lease granted the mineral lessee the rights to produced water. The Collier family owned the surface and minerals under 37,000 acres in Reeves County. They leased this acreage in various oil and gas leases, and eventually COG acquired the leases. Later the Colliers entered into an agreement with Cactus, giving Cactus the rights to own all water “produced from oil and gas wells and formations on or under” the Collier’s acreage. Cactus notified COG that Cactus owned the produced water, and COG sued Cactus for declaratory judgment that COG owned the produced water. Holding for COG, the court held that because produced water is a waste byproduct of the oil and gas stream of production, the mineral lessee owned the produced water. The court relied on the distinction between potable groundwater and hazardous produced water, which appears in various statutory and regulatory contexts. The court also noted that as a matter of historic practice, industry has traditionally treated produced water as a liability and not an asset, and that to hold for Cactus would have been to give it the “benefit of costs and risks [COG] voluntarily undertook.” The Texas Supreme Court has granted review.

One 2023 case highlighted the cotenancy limitations when a non-operator refuses to be a party of the joint operating agreement. In Cromwell v. Anadarko E & P Onshore, LLC, Cromwell acquired a minority working interest in two leases in Loving County, Texas. Prior to that, Anadarko had entered into joint operating agreements with other working interest owners and was named as the operator for the leases. Although he paid some expenses, Cromwell later disputed his status as a “Working Interest Owner” since he had not signed any joint operating agreements with Anadarko and began to refuse to pay invoices. Anadarko believed Cromwell’s leases expired due to lack of production, and the landowner then leased such properties to Anadarko. The court looked to the habendum clause in each lease, and while the parties both agreed the leases were producing in paying quantities, Anadarko asserted that since it drilled the wells, Cromwell’s actions were insufficient to constitute production, whereas Cromwell claimed that the fact he participated in the liabilities, risks, and costs of production is sufficient. Under Cimarex v. Anadarko, Cromwell needed to “take some action to cause production” on the leases, and the court found Cromwell’s actions did not reach the necessary level. Cromwell’s costs that he asserted as “construction participation” were merely his proportionate share of a production well’s operating expenses by a nonparticipating cotenant.

One last 2023 case worth of note, is Railroad Comm’n v. Opiela, which addressed the Railroad Commission’s (“RRC”) authority to issue drilling permits for production sharing agreement (“PSA”) wells. A PSA is an agreement among the owners of a horizontal well’s production (working and royalty interest owners) on how to allocate production among the various tracts. The mineral owners’ lease prohibited the lessee from pooling the lease, and they had not signed any PSA. The RRC nevertheless issued the drilling permit, and mineral owners sought review. The court noted that Texas law requires a permit applicant to demonstrate to the RRC a good-faith claim of the right to operate the well. The court also observed that the RRC has historically granted PSA well permits where the operator certifies that at least 65% of the working and royalty interest owners in each tract have signed a PSA. Given that less than 65% of the tract’s owners had signed a PSA in this case, the court held that the RRC erred in concluding that the operator had shown a good-faith claim to the well in question.

XII. West Virginia

A. Legislative Developments

One law was amended and another enacted during the 2023 Legislative Session that will affect the oil and gas industry in the State of West Virginia. First, S.B. 609 amended the West Virginia Public Energy Authority (“WVPEA”) Act at § 5D–1–1 et seq. to add a new section, § 5D–1–5c. Under this new section, existing coal-fired, natural gas-fired, and oil-fired power plants must petition the WVPEA to begin decommissioning and deconstructing any utility or non-utility plants. Said petition must include an analysis by an WVPEA-approved third party that “evaluates the social, environmental, and economic impact at a local and statewide level of such decommissioning and deconstruction” and accounts for potential alternatives to the decommissioning and deconstruction of the plant, including “the reconstruction that make[s] use of other technologies, including novel technologies and green technologies as alternative fuel sources.” Additionally, the amendment empowers the WVPEA to propose rules for legislative approval and promulgate emergency rules to implement the new section.

Second, S.B. 188, or the Grid Stabilization and Security Act of 2023 (“Act”), became effective on June 4, 2023. Codified at § 5B-2N-1 et seq. in the West Virginia Code, the Act directs state agencies to streamline their procedures to simplify the generation of electricity from natural gas. Under the Act, the Secretary of the West Virginia Department of Economic Development is directed to identify and designate economically viable sites suitable for natural gas electric generation facilities. Then, in a timely fashion, the Secretary must consider and render a decision on applications for permits to construct and operate natural gas electric generation facilities and communicate the designated sites to the West Virginia Department of Environmental Protection’s Division of Air Quality and the West Virginia Public Service Commission (“WVPSC”). In keeping with the intended efficiency of the Act, any application for a siting certificate filed with the WVPSC to construct, or construct and operate, a natural gas electric generation project at a designated site shall be adjudicated and a final order issued by the WVPSC within 270 calendar days after the initial date of the filing of the application.

B. Judicial Developments

In Collingwood Appalachian Minerals III, LLC v. Erlewine, the Supreme Court of Appeals of West Virginia examined whether a purchaser of a delinquent oil and gas interest could have its tax deed invalidated due to it being erroneously and separately assessed from the surface estate. It also examined whether a prior deed in the chain of title effectively conveyed all interest the grantor had in the oil and gas, thereby preventing a delinquent interest from being sold at a future date, or alternatively, whether a partial interest was conveyed, thereby permitting a tax sale of the remaining interest. The Court held that “[u]nder West Virginia Code § 11A-3-63, no such irregularity, error, or mistake invalidates a tax-sale purchaser’s tax deed unless the Legislature created a specific cause of action allowing it.” Here, the Court determined that the delinquent taxpayer of the original 1989 sale did not pay taxes on either the oil and gas or the surface estate.

In addition, the Court noted that the West Virginia Legislature has not specified a cause of action that “allows a third party such as Respondent, not related to the delinquent owner, to challenge a tax deed on the grounds that the delinquent owner was improperly taxed or that the tax sale severed a mineral estate.” Accordingly, the Petitioner’s title as to the 1989 tax sale and subsequent tax deed is protected from the claims of the Respondent. Regarding the 1993 tax sale, the Court determined that the prior owner did not convey an undivided fifty percent interest in all the oil and gas, being all he owned at the time, but rather, only conveyed a twenty-five percent interest, thereby leaving a residual twenty-five percent interest that would remain taxed, and later delinquent, in the 1993 tax sale.

In L&D Invs. Inc. v. Antero Res. Corp., the Supreme Court of Appeals of West Virginia examined whether an attorney who represented plaintiffs in a case to recover royalties for oil gas production was entitled to attorney’s fees and reasonable expenses undertaken for the benefit of unknown heirs. The Court notably adopted the persuasive authority of the Restatement (Third) of Restitution and Unjust Enrichment § 29 (Am. Law Inst. 2022) in its entirety, as the law of West Virginia. The Court also held that “[c]ounsel is entitled under the common fund doctrine to ‘require those beneficiaries for whom [he] is not acting by agreement to contribute to the reasonable and necessary expense of securing the common fund for their benefit, in proportion to their respective interests therein, as necessary to prevent unjust enrichment.’”

C. Administrative Developments

The West Virginia Code of State Rules Section 53-5-1, as applicable to S.B. 609, as codified in W. Va. Code Section 5D-1-5c(c), referenced within the Legislative Developments hereinabove, was enacted via Emergency Action effective July 27, 2023.

XIII. Wyoming

A. Legislative Developments

During Wyoming’s 2023 Legislative General Session, the Legislature amended the Wyoming Energy Authority’s authority to include the ability to finance oil and gas refinery construction and expansion projects in Wyoming. The Wyoming Energy Authority’s purpose is to support the energy industry including securing federal grants and loans, assisting in permitting, engaging stakeholders on potential market opportunities, and financing certain projects directly. This amendment permits the Wyoming Energy Authority to finance oil and gas refinery construction and expansion activities through outstanding bonds.

B. Judicial Developments

In EOG Res., Inc. v. JJLM Land, LLC, the Wyoming Supreme Court concluded that Wyo. Stat. Ann. § 30-5-405(b) requires operators to pay double damages when it fails to pay any portion of an installment payment owed under a surface use and damage agreement and fails to cure the underpayment after sixty days of receiving a notice of default. EOG argued that the statute only affected installment nonpayment as opposed to installment underpayment. But the Court disagreed, finding that § 30-5-405(b)’s text includes both nonpayment and underpayment.

In Chesapeake Operating, LLC v. Dep’t of Revenue, the Wyoming Supreme Court held that a facility is not a processing facility under Wyo. Stat. Ann. § 39-14-203(b)(iv) based only on the volume of gas it receives, the size of its separators, the occurrence of separation, or the presence of a triethylene glycol (TEG) dehydrator. Chesapeake produces oil and gas from horizontal wells within a complex system. A separator near the wellhead separates liquids and gas. The gas then passes through a custody transfer meter and flows through a natural gas pipeline to one of seven facilities. Once at a facility, the gas undergoes more separation, pressurization, and water remove by way of a TEG dehydrator. The gas then moves through transport lines to natural gas liquids (NGL) extraction facilities.

Wyoming’s tax code permits deduction of costs incurred in the processing of oil and gas from severance and ad valorem taxes though it does not permit deductions for production costs. Wyoming law does not define “processing facility.” But it defines processing to include “dehydration within a processing facility” and “separation which occurs within a processing facility”. The Department of Revenue maintained that the seven facilities were not processing facilities under § 39-14-203(b)(iv) and that Chesapeake could not deduct costs until the natural gas arrived at the NGL extraction facilities. Chesapeake contended that the seven facilities were processing facilities based on the volume of gas received and separation and dehydration occurring at the facilities.

Relying on case law to further clarify processing, the Wyoming Supreme Court decided that—while the facilities did separate byproducts from large volumes of gas and dehydrate the gas—the facilities did not engage in enough processing functions to be considered a processing facility. Thus, Chesapeake could not deduct costs associated with the seven facilities from its severance and ad valorem tax balance.

C. Administrative Developments

In In re Devon Energy Prod. Co. LP, the Wyoming Board of Equalization ruled that the purchase of fracking services to improve state lands is not exempt from sales tax, but intrastate water transport is exempt. Devon purchased fracking services to enhance oil and gas production on state lands. Devon also hired contractors to transport water to the production site. Most of the water transportation took place outside of the site and all water transportation took place within state lines. When the water did arrive, Devon Energy stored it in tanks just inside the site’s boundaries. Within the invoices, Devon contractors did not distinguish between taxed and untaxed water transportation.

Wyoming law imposes sales tax on services used in rendering services to real or tangible property within an oil and gas well site. Devon accepted that the fracking services fell within this description. But the law exempts services “sold to government … organizations” for “improvement of real property … owned by, or incorporated in projects under contract to the state of Wyoming…” Devon contended that the fracking services fell within this exception. The Board ruled that “sold to government organizations” requires the services to be purchased by a government organization and not a private organization. Thus, the § 39-15-104(a)(iv)(F) exception did not apply to Devon and it was left to pay the corresponding sales taxes.

But the Board did not require Devon to pay taxes on its water transportation. Wyoming law offers another exception to § 39-15-103(a)(i)(K). Section 39-15-105(a)(viii)(A)(II) exempts intrastate transportation of freight and property. The Department of Revenue argued that transportation within the site’s boundaries became an indispensable fracking function and thus taxable. The Department also has a rule that if taxable charges are not separated from non-taxable charges, the entirety of the service is taxable. The Board ruled against the Department. It found that § 39-15-105(a)(viii)(A)(II)’s text unambiguously excluded all intrastate transportation—including within the site’s boundaries—of freight and property from sales tax. It also found that water was both freight and property. So, the law did not require Devon to pay sales tax on any of the water transportation services.

In In re Merit Energy Co., LLC, the Wyoming Board of Equalization ruled that a sales tax exemption exists for the portion of electricity purchased to transport fluids from the wellhead to custody transfers even when the source powered by the electricity resides within the wellbore. Merit uses submersible pumps installed in wellbores which—in one continuous, uninterrupted movement—convey the crude oil not just from the wellbore to the wellhead, but from the wellhead to surface facilities and custody transfers as well.

Wyoming law imposes sales tax on tangible personal property consumed in oil and gas production. Merit accepted that electricity fell within this definition but fell within a sales tax exemption. The law makes an exception to the tax for tangible personal property consumed in production and consumed directly in generating motive power for actual transportation business. The Board moved step by step through each phrase of the statutory text. It held that Wyoming law defines electricity as personal property. The Board then determined that the electricity was consumed in production based on statutory text that defined “the production process for crude oil” to include various activities which occur before custody transfer. The parties agreed that the electricity was consumed directly in generating motive power. But they did not agree that the power was used for actual transportation business. Citing Meriam Webster’s Collegiate Dictionary, the Board found that the pumps transported the fluids. Thus, the electricity—used to transport the fluid from wellhead to custody transfer—that powered the wellbore-residing pumps was consumed in production and consumed directly in generating motive power for actual transportation business. So, the law did not require Merit to pay sales tax on that portion of the electricity.

On July 12, 2023, the Wyoming Department of Environmental Quality (“DEQ”) announced that it will create, in partnership with the University of Wyoming, a data-verified Class VI geologic database to provide geotechnical information that has been compiled and verified from public geologic databases. This effort will be partially funded by the U.S. Department of Energy. The purpose is to make the application process for carbon storage projects more efficient with all necessary information located in one database.