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The Year in Review

Environment, Energy, and Resources Law: The Year in Review 2024

Oil and Gas Committee Report

Keturah Brown, Rebecca Wright Pritchett, Priya Kareddy, Lydia Sidrys, Bree Mucha, George Lyle, Thomas Allen Daily, John Joseph Harris, Brian Annes, Stephanie Ann Morr, John Siragusa, Charles Christian Steincamp, Diana Elizabeth Stanley, April Rolen-Ogden, Michael H Ishee, John Michael Parker, Ann Cox Tripp, Andrew J Cloutier, Gregory D Russell, Ilya Batikov, Mark A Hylton, Matthew David Fazekas, Eric A Parker, Joseph Allen Schremmer, Nicolle R S Bagnell, Gina Marie Kantos, James Ashmore, Aaron C Powell, Anna Boyer, Kathryn Stewart, Seth Backus, Raquel Davis, Jeffrey Scott Pope, and Kirk D Bowersox

Summary

  • The Oil and Gas Committee Report for The Year in Review 2024.
  • Summarizes significant legal developments in 2024 in the area of oil and gas, including drilling leases on the Arctic National Wildlife Refuge, greenhouse gas emissions, minerals, and more.
Oil and Gas Committee Report
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I. Alaska

A. Federal Legislative Developments

On May 7, 2024, the Bureau of Land Management published updated standards for managing the oil and gas development activities of the National Petroleum Reserve to protect and support fish, wildlife, their habitats, and their subsistence use. On December 9, 2024, the Biden administration approved a plan for the sale of oil and gas drilling leases on 400,000 acres of the Arctic National Wildlife Refuge (ANWR).

B. Judicial Developments

1. Alaska Supreme Court Decisions

In City of Valdez v. Prince William Sound Oil Spill Response Corporations, the Alaska Supreme Court affirmed the superior court’s decision that AS 42.05.260 does not allow the assessment of oil and gas property taxes more than three years after the tax return was filed. As a result, the City of Valdez was precluded from seeking to recover taxes for the time period between 1997 to 2016 on certain oil spill prevention and response equipment and vessels that had not been assessed, or to argue that the property that was assessed was not correctly valued.

In City of Valdez v. Regulatory Commission of Alaska, Valdez requested to review the information that the Regulatory Commission of Alaska (RCA) relied upon when deciding to allow BP P.L.C. (BP) to sell its interest in the Trans-Alaska Pipeline System (TAPS) to Harvest Alaska, LLC (Harvest). Valdez appealed two RCA orders: Order 6, which approved the confidential treatment of financial statements by the oil companies, and Order 17, which approved the transfer of the certificate to operate TAPS to Harvest. The Alaska Supreme Court ruled that Valdez had standing on both orders as Valdez had a direct interest in the proceeding, was factually aggrieved, and had sufficiently participated in the proceedings. The Court also held that Valdez exhausted their remedies for Order 6, but failed to exhaust their remedies for Order 17. The Court further ruled that the appeals were not moot as they are “live controversies susceptible to judicial resolution, including disputes about the interpretation of AS 42.06.445(c) and the scope of Valdez's right to access certain financial statements relevant to Valdez's interests in future proceedings before the RCA.” The Supreme Court reversed the superior court’s dismissal of the appeal of Order 6 and affirmed the dismissal of the appeal of Order 17. The case was remanded for further proceedings.

2. Federal District Court of Alaska

In Alaska Industrial Development and Export Authority v. Biden, the plaintiffs challenged the temporary moratorium on all oil and gas activities in Alaska’s ANWR so that a supplemental environmental review could be conducted. In 2023, the court dismissed all claims with prejudice holding that President Biden acted within his powers to correct alleged legal deficiencies in the first environmental review and that the moratorium did not violate the Administrative Procedure Act (APA) as it was only temporary. The plaintiff filed a motion to alter or amend the ruling on summary judgment, requesting the court invalidate the moratorium to the extent that it would allow the plaintiffs to conduct surveys that would not impact the environment and require the defendant to carry out actions that were necessary to implement the leases at a pace required by Congress. A day later the Department of the Interior canceled the plaintiffs’ leases for pre-leasing legal defects. Plaintiffs then filed a motion for relief from judgment asserting the cancelation of the leases made all the claims moot. Concurrently, the plaintiffs filed a similar action in the U.S. District Court for the District of Columbia asking the Court to invalidate the cancelation and direct the defendants to proceed with the development of ANWR. The Court held that the claims were not moot because it is possible for a court to grant some effective relief since the plaintiffs were seeking much the same relief in the District of Columbia that the court had already denied. The Court further ruled on the motion to amend summary judgment, holding that the requests to conduct surveys was moot given the lease cancelations. Plaintiffs also failed to identify on which grounds they sought relief in requesting the defendants to follow a timeline on oil production in ANWR. Both motions were denied by the Court.

B. Administrative Developments

In 2019, the Alaska Oil and Gas Conservative Commission (AOGCC) increased the bonding amount for 1-5 wells to $400,000 per well. Alaska Crude Corporation (Crude) asked for reconsideration on the increased bond amount for three of their wells, and the AOGCC denied the request. In an appeal filed by Crude, the Alaska Supreme Court remanded the case to the AOGCC to apply the correct analysis of the APA’s retroactivity rule. The AOGCC decided that one well was located on privately owned land, and the cost to plug and abandon the well was less than $400,000, so the amount of the bond was lowered to $200,000. The AOGCC further held that the other two wells were discharged from Crude’s control during its bankruptcy in 1990 and Crude was not responsible for bonds for those two wells.

II. Arkansas

A. Legislative Developments

There were no 2024 Arkansas legislative developments. The Arkansas General Assembly meets in general session biannually, in odd-numbered years.

B. Federal Legislative Developments

Last year’s Year-In-Review discussed two conflicting 2023 decisions involving Arkansas’ royalty blending statute, 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.”

The U.S. District Court in Hurd v. Flywheel Energy Production, LLC (Hurd) and the Arkansas Court of Appeals in Flywheel Energy Production, LLC v. Arkansas Oil and Gas Commission (Flywheel) reached conflicting results as to the meaning of “less all lawful deductions.” In both, the plaintiff royalty owners’ interests were subject to “gross proceeds” leases, forbidding any deduction other than taxes.

The Federal District Court in Hurd ruled that the statute overrode such lease provisions, as to that portion of the royalty contributed to the Arkansas’ blended one-eighth royalty pool, thus permitting the deductions as to the pooled one-eighth. Flywheel arose in state court as an appeal from an Arkansas Oil and Gas Commission ruling that the “lawful deductions” reference in the statute only permitted deduction of taxes and non-affiliated third-party transportation charges. Thus, the Commission forbade deduction of other post-production expenses such as compression, treating, and gathering. After Flywheel Energy Production unsuccessfully challenged that ruling, both in circuit court and then in the Arkansas Court of Appeals, it petitioned for review by the Arkansas Supreme Court. That petition was denied, thus placing Flywheel in direct conflict with Hurd.

The Hurd royalty owners then moved the federal judge to reconsider his ruling permitting the deductions, arguing that he was bound by the state appeals court’s decision under the Erie doctrine. The district judge declined to do so. He disagreed with the logic of the state appeals court’s decision and concluded that he was not absolutely bound by a decision of that court (as opposed to the Arkansas Supreme Court). The district court also dismissed the complaint in a near-identical case, Pennington v. BHP Billiton Petroleum (Fayetteville) on the basis of his ruling in Flywheel. The time for appealing the district court’s latest Hurd decision to the Eighth Circuit Court of Appeals has passed, with no appeal taken, so the state/federal conflict on this important issue remains unresolved.

Harts v. Damsky, interpreted section 28-40-104(b), which provides limited exceptions to the general rule that unprobated wills are ineffective to pass title to a decedent’s property. One exception allows an unprobated will to be admissible provided that no proceeding in circuit court regarding the decedent’s estate has occurred and either that its devisee is in possession of the property, or no one has possessed the property during the time-window for proper administration of the will. The decedent, Eleanor Cosden, was the owner of a 30.6% interest in a vast array of severed mineral interests spanning six Arkansas counties. The appellants were Ms. Cosden’s Arkansas intestate heirs, while the appellees, also her relatives, were the devisees under her New York will. Notwithstanding that Ms. Cosden’s will was never probated in Arkansas, her Arkansas mineral interests had been claimed by her devisees for many years and those devisees had even been paid royalty on the interests from production in other Arkansas counties. The Arkansas Court of Appeals affirmed the trial court’s ruling that the requirements of the statutory exception had been met and that the will established the appellees’ claim.

C. Administrative Developments

Since the Arkansas Oil and Gas Commission’s regulations are constantly revised, the practitioner is advised to check these regulations online here.

III. California

A. Legislative Developments

1. Extensions of Senate Bill 1137 Deadlines

Senate Bill 1137, passed in 2022, banned drilling and reworking operations in any inhabited area within the State by prohibiting the California Geologic Energy Management Division (CalGEM) from approving any “notice of intention” submitted by an operator under section 3203 of the Public Resources Code 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.”The law also included new operator reporting requirements. However, a voter initiative to repeal the new law was certified, which stayed its provisions pending a vote in November 2024 on the referendum. When the initiative was withdrawn in June 2024, the requirements of SB 1137 immediately became effective, including certain January 1, 2025 deadlines for operators to submit required plans. Assembly Bill 218 extended several deadlines in the original bill to ensure reasonable reporting timeframes. The bill also allows CalGEM to impose supplemental assessments on operators to ensure funds to enforce the provisions of SB 1137 and allows regulatory agencies’ emergency regulations to remain in effect until July 1, 2026.

2. Local Regulation of Downhole Operations

In Chevron USA, Inc. v. County of Monterey (discussed in the 2021 and 2023 Year-In-Reviews), the California Supreme Court invalidated a Monterey County ordinance, which banned well stimulation treatments, wastewater injection and impoundment, and the drilling of new wells in the county. As a result, other local ordinances, such as those adopted by the County of Los Angeles and the City of Los Angeles, have been challenged on similar preemption grounds. In response, the California Legislature enacted Assembly Bill 3233, which authorizes local governments to limit or prohibit oil and gas operations or development in their jurisdiction by ordinance, notwithstanding CalGEM’s approval of any permit. The new law does not state whether it was intended to apply to existing ordinances or to be retroactive.

3. Idle Well Fees and Management Plans

Operators of any idle well are required under section 3206 of the California Public Resources Code to either (1) pay an annual fee for each well that was an idle well at any time in the last calendar year, based on the length of time a well has been idle, or (2) file a plan with the supervisor to provide for the management and elimination of all of its long-term idle wells. Assembly Bill 1866 increased those idle well fees and increased the number of wells that an operator must eliminate under its idle well management plan.

4. Prohibition of Operation of Wells in the Inglewood Field

The Legislature passed Assembly Bill 2716 to prohibit the operation of “low production wells” in a single location—the Inglewood Field in Los Angeles County, commencing March 1, 2026. The bill also requires all wells within that field to be plugged and abandoned by December 31, 2030. The bill provides for administrative penalties of $10,000 a month for each non-complying well. Since most of the producing wells in the field would likely fall within the definition of “low production wells,” despite being profitable, the operator of all of the wells in the field, Sentinel Peak Resources California LLC, filed a lawsuit challenging the statute on constitutional and other grounds.

5. UIC Aquifer Exemption Submissions

Senate Bill 1304 amended section 3131 of the Public Resource Code to extend the administrative process for the submission and approval of exempt aquifer determinations for Class II underground injection wells by requiring CalGEM and California Regional Water Quality Control Boards to prepare a report for submission to the State Water Resources Control Board (SWRCB), and requiring the SWRCB, after public comment and a hearing, to determine whether a proposed aquifer exemption merits consideration for submission to the U.S. Environmental Protection Agency (EPA).

B. Judicial Developments

Many heavy oil-producing fields in California require cyclic steaming. TRC Operating Company, Inc. v. Chevron USA, Inc. dealt with an operator’s liability when a surface expression resulted in a sinkhole and a geyser of pressurized steam and oil released from the defendant Chevron’s well and resulted in CalGEM issuing orders directing operators in the area to suspend steam injection in the area of the surface expression for nearly five years. TRC, the plaintiff adjoining operator, suspended steaming operations based on its own safety concerns in addition to the CalGEM orders. TRC then sued Chevron for its lost production during the suspension period. After a jury award in the plaintiff’s favor, Chevron appealed on the basis (among a number of other procedural grounds) that CalGEM’s orders suspending steaming operations were a superseding cause of the plaintiff’s damages and a complete bar to the claims. The trial court and the Court of Appeal rejected the argument, finding that CalGEM’s production suspension orders were a foreseeable result of Chevron’s actions. The Court held that when a tortfeasor’s actions cause injury in combination with other non-tortious sources of injury, such as the CalGEM orders in this case, the plaintiff may recover the entirety of its damages, less the amount that can be apportioned to the other sources of injury, and that the defendant, Chevron, had the burden of establishing the amount of any damages attributable to the CalGEM orders.

A related case, TRC Operating Company, Inc. v. Shabazian, addressed the procedural problems associated with the administrative appeal process for notices and directives by CalGEM. California Public Resources Code section 3225 provides for administrative appeals only of orders issued by CalGEM’s Supervisors, but does not allow an appeal for regulatory notices of violation or notices directing an operator to stop an operation. TRC received a notice from CalGEM, pursuant to 14 C.C.R. §§ 1724.11 and 1724.12, to cease operations of its wells near a longstanding “surface expression.” After complying with the notice but never receiving authorization from CalGEM to resume production, TRC filed an administrative appeal under California Public Resources Code § 3225(d), which permits an appeal from a written order by the supervisor or a district deputy supervisor. CalGEM refused to proceed with the appeal since a regulatory notice is not expressly appealable under Public Resources Code section 3225. TRC then filed suit against CalGEM, and the trial court held that CalGEM’s regulations requiring the cessation of operations once a surface expression was encountered were invalid on the basis that the regulatory-violation notices bypassed the administrative appeal process under section 3225. The Court of Appeal reversed, holding that the regulations were valid and consistent with the Public Resources Code and that an operator only has a statutory right to an administrative appeal after it chose to not comply with a notice and forced CalGEM to issue a statutory order to enforce the notice and imposing penalties. The Court did, however, remand the case to the trial court to determine if CalGEM’s actions were arbitrary or capricious.

In 2015, Kern County adopted an ordinance intended to streamline the permitting process for new oil and gas wells. In 2020, the Court of Appeal in King & Gardiner Farms, LLC v. County of Kern determined that the County’s environmental impact report (EIR) prepared under the California Environmental Quality Act (CEQA) was defective. The County then prepared a revised supplemental EIR, which was again challenged. The superior court determined that the CEQA violations had been corrected. The Court of Appeal in V Lions Farming, LLC v. County of Kern reversed, holding that the supplemental EIR failed to comply with CEQA in a number of respects and setting aside any well permit approvals that the County had already issued.

C. Administrative Developments

1. Regulatory Implementation of SB 1137

Following the passage of SB 1137 in 2022, 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 which stayed the provisions of SB 1137 pending a vote in 2024 on the referendum and CalGEM’s implementing regulations. The referendum’s proponents withdrew it on June 27, 2024, and CalGEM’s implementing regulations became effective as of June 28, 2024. CalGEM returned all permit applications subject to SB 1137 that were pending for resubmission to conform to the requirements of CalGEM’s emergency regulations. CalGEM also issued Notice to Operators 2024-09 clarifying that the requirements of SB 1137 are only applicable to drilling-related notices of intent to drill within a health protection zone where the planned work involves drilling through previously unexposed rock or formation.

2. Cost Estimate Reports Regulations

CalGEM’s final “Cost Estimate Regulations Oil & Gas Operations” became effective on October 1, 2024. These regulations require each operator to submit a report estimating its total liability to plug and abandon all wells and to decommission all attendant production facilities, including any needed site remediation. CalGEM issued Notice to Operators 2024-08 informing operators producing less than an average of 3.5 total barrels a day per well that they were required to submit their initial Cost Estimate Reports by January 1, 2025. The Cost Estimate reports of operators producing more than 3.5 barrels per day per well are due by July 1, 2026.

3. Prohibition of New Well Stimulation Permits

CalGEM’s Well Stimulation Treatment Permitting Regulation went into effect on October 1, 2024, amending 14 CCR section 1780 to state that CalGEM would not approve any application for permits to conduct well stimulation treatments, that is, any hydraulic fracturing, acid fracturing, and acid matrix stimulation.

4. Federal Funds for Abandonment of California Orphan Wells

Secretary of the Interior Deb Haaland announced on May 17, 2024, a $35.2 million grant to California to continue reclaiming and restoring orphaned oil and gas wells in that state. With this new funding, CalGEM expects to plug and remediate 206 high-risk orphaned oil and gas wells and decommission 47 attendant production facilities. On August 14, 2024, the Department of Interior announced California’s eligibility for additional $52,826,441 in orphan well abandonment funding.

5. State Lands Commission Memorandum of Understanding with BSEE

On August 29, 2024, the California State Lands Commission authorized the Executive Officer to enter into a Memorandum of Understanding with the federal Bureau of Safety and Environmental Enforcement to coordinate offshore oil and gas pipeline inspections, establish inspection standards, and share information to ensure regulatory compliance and protect public health, safety, and the environment.

IV. Colorado

A. Legislative Developments

1. Targeting Reductions in NOx Emissions from Upstream Oil and Gas Operations

On May 16, 2024, Governor Jared Polis signed SB 24-229 into law, which enacts a series of measures to improve air quality by reducing emissions of ozone precursors by the oil and gas industry. The bill directs the Colorado Department of Public Health and Environment to promulgate rules to reduce oxides of nitrogen (NOx) emissions from upstream operations by 50% from 2017 levels by 2030. Further, SB 24-299 expands the Colorado Energy and Carbon Management Commission’s (ECMC) enforcement authority to include the ability to revoke an operator’s license to conduct oil and gas operations for certain violations, and it broadens the types of violations that could result in suspension of all of the operator’s permits. The bill brings marginal wells, which are those wells deemed at the highest risk of becoming orphaned, into the Orphaned Wells Mitigation Enterprise and provides funding for the plugging, reclamation, and remediation of such marginal wells. Finally, SB 24-229 mandates that ECMC minimize adverse impacts on disparately impacted communities.

2. Levying Additional Fees on Oil and Gas Production

Governor Jared Polis signed SB 24-230 into law on May 16, 2024, implementing new enterprise fees that will provide funding for clean transit and wildlife and land remediation programs within Colorado. The fees will fund the Clean Transit Enterprise within the Department of Transportation and the Wildlife and Land Remediation Enterprise within the Division of Parks and Wildlife. Beginning July 1, 2025, quarterly fees will be imposed upon all oil and gas production by those enterprises through the Department of Revenue. The enterprises shall determine the fees in consultation with the ECMC. The fees are dependent upon the average spot prices for oil and gas during the applicable quarter, which will be published on the ECMC website.

3. Protecting Unleased Mineral Owners in Statutory Pooling Applications

On May 22, 2024, Governor Jared Polis signed SB 24-185 into law, which adds requirements in applications for a statutory pooling order submitted to the ECMC. Pooling applicants must now submit an affidavit with their application indicating they have secured the requisite consent of 45% of the mineral interests to be pooled. The affidavit must identify recorded leases or agreements that convey rights to the mineral interests or contain consent of the mineral interest owners to be pooled, along with any assigned American Petroleum Institute well number(s) holding recorded leases or agreements. The applicant must also disclose if it is relying on unrecorded conveyances. Affected unleased mineral interest owners may file a protest disputing the applicant’s declaration in the affidavit. The ECMC must resolve bona fide protests prior to entering a pooling order. SB 24-185 also prevents the ECMC from issuing an order that pools unleased mineral interests owned by a local government that has rejected an offer to lease minerals if the unleased minerals are located within the local government’s geographic boundaries. In such circumstances, the ECMC must deny the pooling request unless the applicant amends the application to no longer pool the local government unleased interest.

B. Administrative Developments

1. ECMC Finalizes Cumulative Impacts Rulemaking

On October 15, 2024, the ECMC adopted final rules in response to HB 23-1294 which required that ECMC evaluate and address cumulative impacts of oil and gas operations. The new rules define “Cumulative Impacts” and require operators submitting an Oil and Gas Development Plan to propose operations in a Form 2 that are not subject to an Oil and Gas Development Plan, or propose operations in a Comprehensive Area Plan to submit Form 2B. Form 2B provides quantitative and qualitative data to analyze Cumulative Impacts, along with proposed mitigation measures. The new rules also require operators to submit a Cumulative Impacts analysis for proposed oil and gas locations and subsequent operations on existing wells that evaluates the impacts to the environment within a one-mile radius and impacts to water within a 2.5 mile radius around a well pad surface. Finally, the new rules create two community liaison positions to improve relationships between ECMC and Disproportionately Impacted Communities and to serve as advocates for such communities.

C. Judicial Developments

1. Colorado Supreme Court Determines Weld County Lacks Standing to Challenge Air Quality Control Commission Rule Revisions

In Weld County Colorado Board of County Commissioners v. Ryan, the Colorado Supreme Court held that the Weld County Board of County Commissioners (Weld County) lacked standing to challenge revisions to rules adopted by the Air Quality Control Commission (CAQCC). Weld County participated in rulemaking proceedings for changes to Regulation 7, requiring more frequent leak detection and repair tests at facilities, but CAQCC approved rule revisions that rejected Weld County’s concerns. Weld County filed a lawsuit arguing CAQCC violated the Colorado Air Pollution Prevention and Control Act by failing to prioritize Weld County’s concerns regarding the economic impacts of the changes by allotting it only ten minutes of testimony and violated the Colorado Administrative Procedure Act by relying on flawed economic analyses and accepting and adopting a late-filed proposal.

In determining that Weld County lacked standing to bring its claims, the Colorado Supreme Court explained that the political subdivision test has been abandoned and that a political subdivision must instead satisfy the general standing test developed in Wimberly v. Ettenberg. The Wimberly test requires “(1) an injury in fact (2) to a legally protected interest.” The Court determined that while Weld County held a legally protected interest, it did not demonstrate an injury to that interest. Although Weld County alleged injury to its tax base, its procedural rights in the rule-making process, and to its land use authority, the Court determined these injuries to be speculative and not injuries in fact.

2. Colorado Supreme Court Clarifies Centerline Presumption in Determining Mineral Ownership under Rights-of-Way

In Great Northern Properties, LLLP v. Extraction Oil & Gas, Inc., the Colorado Supreme Court addressed application of the long-established centerline presumption to ownership of mineral rights under a road. In 1975, a real estate developer dedicated a street to the City of Greeley and sold off the adjoining parcels without reserving mineral rights. In 2019, the developer sold the mineral estate beneath the street to Great Northern Properties, LLLP (GNP), who subsequently filed an action to quiet title as to the mineral rights under the street against the adjacent parcel owners and the oil and gas leaseholder, Extraction Oil & Gas, Inc. (Extraction). The trial court entered judgment against GNP, holding that the centerline presumption applied such that the developer conveyed the mineral rights under the street when it sold the adjacent parcels. The court of appeals affirmed. The Colorado Supreme Court determined that when the centerline presumption applies, a conveyance is presumed to include the mineral estate to the centerline, as well. The Court rejected the limitation of complete divestiture by the grantor, holding that the centerline presumption applies when: “(1) the grantor conveyed ownership of land abutting a right-of-way; (2) the grantor owned the fee – to both the surface estate and the mineral rights – underlying the right-of-way at the time of conveyance; and (3) no contrary intent appears on the face of the conveyance document.”

V. Kansas

Kansas had an active year in the judiciary for oil and gas matters. Three decisions were issued of interest to practitioners and the Legislature passed an amendment to increase pipeline enforcement penalties.

A. Judicial Developments

1. Lost Profits

The Kansas Court of Appeals issued a decision in Strategic Energy Income Fund III, L.P. v. Stephens Energy Group, LLC. This case involved a dispute over a failed pipeline sale and allegations of wrongdoing that impaired a planned, subsequent business transaction. Strategic Energy Income Fund III (SEIF) attempted to purchase interests in the Nemaha Gas Pipeline, intending to resell it for a profit. However, SEIF alleged that the defendants took actions that devalued the pipeline and disrupted SEIF's efforts to complete its planned "flip sale."

SEIF sought damages based on the profits it claimed it could have earned from selling the pipeline. However, the Kansas Court of Appeals upheld the district court's ruling that SEIF's damages theory was speculative. SEIF's valuation of the pipeline ignored the well operators actual drilling plan, relied on unrealistic well drilling projections, and lacked evidence that buyers would pay the proposed price. No certain offer was ever presented by a willing Buyer for a price even close to plaintiffs claimed valuation. The decision underscores the importance of reliable damages calculations in oil and gas merger and acquisition disputes. Courts are unlikely to accept claims based on speculative profits, especially when the valuation ignores existing market realities.

1. Royalty Deductions

In the Federal District of Kansas, Judge Vratil declined to grant motions to dismiss plaintiffs’ class action complaint in Rider v. OXY USA, Inc. Plaintiffs are trustees of mineral and royalty interests in the Kansas Hugoton Gas Field. In 1998, a class action was filed alleging improper royalty payment calculations. A settlement was reached with Oxy in 2007, with specific limitations on deductions from royalty payments. In 2014, Merit acquired Oxy's assets in the gas field. Plaintiffs alleged that Merit took improper deductions from royalty payments in violation of the settlement.

The Court examined plaintiffs’ allegation of whether Merit was a successor or assignee bound by the original settlement and whether Oxy remains liable for royalty payment deductions after selling its assets. The Court found that Plaintiffs' interpretation of the settlement terms was reasonable at the motion to dismiss stage and that the settlement language suggested Oxy's obligations continued even after the asset transfer.

2. Marketable Product Doctrine

Judge Vratil also issued a decision in Cooper-Clark Found. v. Scout Energy Management, LLC. Cooper Clark is part of a series of long-running Kansas Marketable Product Doctrine cases. Under the marketable product doctrine, “once gas is in marketable condition, the lessee can charge the lessor . . . a proportionate share of (1) ‘the cost to transport the gas to a market’ and (2) ‘the cost to enhance the value of the gas stream.” Previously, in Fawcett v. Oil Producers, Inc. (Fawcett I), the Kansas Supreme Court found that if gas is sold at the well, the gas is marketable at that location.

In this round of Cooper Clark, the question was what costs operators could deduct for gas sold at the tailgate of the processing plant. In a previous iteration of Cooper Clark, a panel of the Kansas Court of Appeals determined that under Fawcett I, “when parties define a market for gas through their conduct, that gas is marketable when it is in a condition acceptable for that intended market.” However, the federal district court noted that the Kansas Supreme Court referred to this intended market argument as “novel” in dicta in Fawcett II and declined to apply that rule in its decision. Judge Vratil found that the Kansas Supreme Court has never addressed the precise quality or condition at which gas becomes marketable. The court then certified a question to the Kansas Supreme Court to ask if a lessee’s duty to make gas marketable at its own expense ends when the gas would be sold in a market or at the point it reaches its intended market. The Kansas Supreme Court has accepted the certified question, and the matter is currently pending.

B. Administrative and Legislative Developments

There were no state regulatory changes related to oil, gas, and mineral law in 2024. In the Legislature, HB 2590 was signed into law. The statute increased the maximum penalties that may be imposed by the Kansas Corporation Commission for pipeline safety violations to $200,000 for each violation for each day that the violation persists and increased the penalty cap to $2,000,000 for a series of violations.

VI. Louisiana

A. Legislative Developments

Act No. 126 of the 2024 Regular Session expanded the scope of Louisiana’s Conservation Law (i.e., Title 30) and Louisiana’s Mineral Code (i.e., Title 31) to specifically address brine extraction. The legislation expands both the terminology of Title 30 to specifically define terms relating to brine extraction and the jurisdiction granted to the Commissioner of Conservation to include brine production in the State of Louisiana. Act No. 126 also enacted La. R.S. 30:2.1 to provide the default rule of Louisiana that produced brine belongs to the party with the right to drill and produce the oil and gas in the absence of any agreement to the contrary. This Act further amends La. R.S. 30:5 to empower the Commissioner of Conservation to create field-wide units for the extraction of brine, just as the Commissioner is empowered to do with respect to oil and gas units. That authority for brine units is conditioned upon the consent of three-fourths of the interest owners, but there is no consent requirement from royalty owners.

The Act also amends La. R.S. 30:9 and 30:10, authorizing the Commissioner of Conservation to create drilling units for brine extraction and pool separately owned interests within a drilling unit. Moreover, the well cost reporting scheme for oil and gas wells under La. R.S. 30:103.1 and 30:103.2 has been expanded to apply in the context of drilling units formed by the Commissioner of Conservation for brine recovery. Finally, La. R.S. 31:4 was amended to expressly confirm that the application of the Mineral Code to “subterranean water” includes brine.

In the area of carbon capture, the EPA signed a rule giving the State of Louisiana primacy over the EPA in the permitting, compliance, and enforcement of Class VI injection wells under the Underground Injection Control Program. As a result, Louisiana carbon capture industry participants can expect a shorter and more efficient permitting process, as in states such as North Dakota that have experienced a dramatic increase in permits granted since obtaining primacy over Class VI wells.

B. Judicial Developments

Significant litigation related to unleased mineral owners (i.e., owners whose land is not subject to any oil, gas, and mineral lease) remains ongoing in both federal and state courts in Louisiana. On the federal court front, the current issue is whether these unleased mineral owners must bear their pro rata share of post-production costs when the unit operator markets and sells their share of production from the unit under La. R.S. 30:10(A)(3). 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 Company and Johnson v. Chesapeake La., LP for interlocutory appeal pursuant to 28. U.S.C. § 1292(b). On appeal, the majority certified the following narrow question to the Louisiana Supreme Court: “[d]oes La. Civ. Code art. 2292 apply to unit operators selling production in accordance with La. R.S. 30:10(A)(3)?” In Self v. BPX Operating Company, the Louisiana Supreme Court granted certification in Self and answered the certified question in the negative. The Louisiana Supreme Court found that La. R.S. 30:10(A)(3) “cannot be applied consistently with the doctrine of negotiorum gestio.” Namely, the Louisiana Supreme Court recognized that “[a] party is only a gestor if his action is taken ‘without authority.’” In contrast, the unit operator is statutorily authorized to sell an unleased owner’s share of unit production under La. R.S. 30:10(A)(3). Thus, “[a] unit operator who sells an owner’s production under the statutory authority of La. R.S. 30:10(A)(3) cannot, therefore, be a gestor under La. C.C. art. 2292 as a gestor is one who acts ‘without authority.’” However, the underlying question of the legal deductibility of post-production costs remains disputed in both matters upon remand to the district court.

A slightly different issue regarding unleased mineral owners was addressed this year by the Louisiana state courts. Mistretta v. Hilcorp Energy Company is an important case addressing the reporting obligations of oil and gas operators to unleased mineral owners with interests in a drilling and production unit. La. R.S. 30:103.1 allows unleased mineral owners to request a report of well costs and production information from the unit operator and gives the operator an initial deadline by which it must respond. If the report is insufficient or untimely, La. R.S. 30:103.2 provides for a penalty in favor of unleased mineral owners if the operator again fails to sufficiently respond after receiving a notice of their failure to respond to the interest owner’s initial request.

In Mistretta, the Plaintiffs sent Defendant an initial request for an accounting of the costs and production of the producing well they were operating on the unit on December 7, 2022. Defendant responded with an accounting via certified letter 70 days later. Plaintiffs then filed suit and moved for summary judgment, entitling them to the penalty provided in La. R.S. 30:103.2 due to Defendant’s alleged noncompliance with their demand under La. R.S. 30.103. Based on persuasive authority and the plain wording of the statutes, Defendants argued that La. R.S. 30:103.1 and La. R.S. 30:103.2 required two notices before the penalty provisions could be applicable, and Plaintiffs failed to comply with their obligations to trigger that penalty. The Third Circuit ultimately agreed with the Defendant, finding that La. R.S. 30:103.1 and 103.2 require “dual notices” prior to being entitled to the penalties of La. R.S. 30:103.2 if the operator again fails to timely respond to their request.

ETC Tiger Pipeline, LLC v. DT Midstream, Inc. was a pipeline dispute wherein ETC Tiger Pipeline, LLC (ETC) was granted a Servitude of Use for Pipeline (the ETC Servitude). After an ETC pipeline was installed pursuant to the ETC Servitude, ETC was contacted by DT Midstream, Inc. and DTM Louisiana Gathering, LLC (collectively, DTM) about constructing a perpendicular pipeline under ETC’s existing pipeline. ETC argued that such installation was unlawful insofar as ETC claimed the ETC Servitude provided “exclusive” servitude rights over the property at issue and filed a lawsuit seeking a TRO, preliminary injunction, and permanent injunction prohibiting the installation of DTM’s pipeline. ETC’s preliminary injunction was granted by the district court.

On appeal, the Louisiana Second Circuit Court of Appeal confirmed as an initial matter that the ETC Servitude was a right of use, as opposed to predial servitude. Thereafter, the court rejected ETC’s argument that the term “exclusive” meant the ETC Servitude “includes all depths and [ETC] can subjectively block the crossing of another pipeline.” The court found that the ETC Servitude contemplated only one pipeline and did not authorize ETC to install a second pipeline below the first pipeline. Moreover, the ETC Servitude expressly contemplated crossings insofar as it included depth separation limits in such circumstances. Accordingly, the district court’s decision was reversed.

Finally, the Louisiana First Circuit Court of Appeal provided further insight into the application of Act 312 in awarding remediation damages for Louisiana legacy lawsuits. In Louisiana Wetlands, LLC v. Energen Resources Corporation, the court considered whether the Plaintiff could maintain a claim against BP America for “unreasonable and excessive operations” on their land pursuant to Act 312 under a lease which BP America never drilled or operated wells on their property. Plaintiffs argued that BP breached “implied obligations” under the Louisiana Civil and Mineral Code against unreasonable and excessive activities by oil and gas operators pursuant to Act 312(M)(c) because the mineral lease at issue contained no express provision for additional remediation. However, the First Circuit disagreed because the 1948 lease connecting BP America to the Plaintiff’s land “does not contain any express provision for additional remediation or a requirement that the Bailey family’s property be restored to its original condition.”

VII. New Mexico

A. Judicial Developments

New Mexico state courts now face a new wave of litigation under the relatively untested state constitutionalism theory and the 2021 New Mexico Civil Rights Act, to include actions affecting the oil and gas industry. In Atencio v. State of New Mexico, 15 plaintiffs comprised of “frontline community members [], Indigenous peoples, youth, and environmental organizations” filed for relief against eight government defendants, including the State Legislature, the Governor, the Energy, Minerals and Natural Resources Department and its Secretary, and the Oil Conservation Commission under the New Mexico State Constitution’s Pollution Control Clause and the Inherent Rights, Due Process, and Equal Protection Clauses. Specifically, the Atencio plaintiffs allege that the current state framework promoting oil and gas development lacks adequate environmental protections, which violates certain enumerated personal rights. The Atencio plaintiffs sought injunctive relief in the form of blanket suspension of state oil and gas permitting.

On early motions to dismiss, the Executive Defendants argued that judicial action would violate separation of powers and that plaintiffs’ requested relief was improper and unavailable. The Legislature moved on similar grounds and also asserted legislative immunity. The district court denied the Executive Defendant’s motion, but partially granted dismissal of the plaintiffs’ Civil Rights Act claims against the Legislature. The district court hinted that it might take up prudential concerns related to the political question doctrine at a later date, but ultimately resolved that plaintiffs’ claims concerning constitutional guarantees and fundamental rights are “ill-suited” to early decision. Nevertheless, the district court acknowledged that its decision qualified under NMSA 1978, § 39-3-4(A), which provides for immediate appeal of lower court decisions. Intervenor-Defendant New Mexico Chamber of Commerce, Defendant New Mexico Legislature, and the Executive Defendants all applied for appeal, consolidated and granted by the New Mexico Court of Appeals on August 14, 2024. The questions on appeal raise the same issues as the earlier motions: whether the New Mexico Pollution Control Clause provides a private right of action in the form of a guarantee to a specific level of protection, whether such claim is justiciable, and if so, what standard a court should apply.

In an unreported, but clarifying opinion, Koch v. David Family Oil and Gas Partnership, the New Mexico Court of Appeals expanded upon the ability of foreign personal representatives to convey color of title to oil and gas mineral interests and the void/voidable distinction as it relates to assertion of the bona fide purchaser defense. The parties disputed ownership of a 3.375% overriding royalty interest (ORI) in a long-suspended federal oil and gas lease located in the Designated Potash Area (DPA). In Koch, husband Robert and his wife Anne initially reserved the ORI under two 1962 assignments. The couple divorced, and the entire Colorado divorce proceeding was sealed, including a 1970 separate property agreement. Days later, in an assignment filed only in the BLM state lease file, Robert assigned “5/8ths of 3.0% overriding royalty interest” to Anne. Robert died testate in 1975, and his nearly insolvent estate was administered in Colorado. Robert’s personal representative, appointed in Colorado, sold and assigned a 3.125% ORI in the subject lease to David under a 1977 assignment (1977 PR Deed) and distributed proceeds from that sale and others under Robert’s will to the Koch plaintiffs. Thus, plaintiffs, being heirs and successors to Anne, claimed to own the entirety of the 3.375% ORI and defendants, successors to David under the 1977 PR Deed, asserted the opposite. Due the lease’s suspended nature, however, no party had questioned ownership of the ORI for almost 50 years. Cross-motions for summary judgment raised questions of community property, the authority of a foreign personal representative in the absence of a local ancillary probate, and whether David established himself as a bona fide purchaser (BFP) against Anne’s heirs and devisees, especially when Anne never recorded the 1970 BLM assignment in the local county records.

The New Mexico Court of Appeals reversed the district court and remanded the matter for trial on the BFP and notice issues. The opinion addresses the void/voidable distinction as it affects the BFP analysis, chipping away at the blanket “void” language used by the court in Allen v. Amoco Production Company. The opinion highlights the conduct of Allen’s self-dealing executor and limits Allen’s holding to those facts. In contrast to Allen, where the Colorado-appointed personal representative sold himself an interest to the exclusion of other family members and then his wife sought to quiet title relying only on the power to sell in decedent’s will, the David defendants argued that David, as a third-party purchaser, was a BFP in conjunction with New Mexico precedent that void deeds convey and establish color of title in competing claims of ownership. The court of appeals determined that the record failed to establish as a matter of law that David possessed actual notice and was conclusively not a BFP.

B. Regulatory Developments

U.S. Fish and Wildlife Service (USFWS) published its final rule listing the Dunes Sagebrush Lizard as endangered effective June 19, 2024 under the Endangered Species Act, with one year to propose a designated critical habitat. The Dunes Sagebrush Lizard is endemic to western Texas and southeastern New Mexico. Now, pursuant to 50 C.F.R. § 17.21, any conduct that harms or harasses a lizard without either an initial take permit or prior enrollment in voluntary Candidate Conservation Agreements (CCAs) or Candidate Conservation Agreements with Assurances (CCAAs) will subject operators and landowners to a wide range of civil and potential criminal penalties. Further, after June 19, 2024, voluntary enrollment in CCAs and CCAAs is no longer an option. Thus, developers affected by the presence of the lizard must now prepare and submit the more costly, complex and time-consuming habitat conservation plan prior to USFWS approving an initial take permit. Texas filed suit through its Attorney General to challenge the Dunes Sagebrush Lizard listing in the U.S. District Court for the Western District of Texas. There is no ruling to date and dispositive motions are anticipated in late summer 2025.

VIII. Ohio

A. Judicial Developments

1. Lease and Royalty Disputes

In Gateway Royalty II, LLC, v. Gulfport Energy Corp., Ohio’s Seventh District Court of Appeals affirmed a trial court decision granting summary judgment to payees of overriding royalty interests (ORRIs) on their claim that the producer breached the ORRIs by deducting post-production costs. The parties’ contract granted an “an overriding royalty, free and clear of all cost and expense of development and operation.” Additionally, the contract provided that “[t]he overriding royalty interest conveyed shall be free and clear of all drilling, development, and operating expenses,” but would bear its share of certain other expenses, including severance taxes, fuel, and oil and gas used for treating production to make it merchantable. Over the producer’s objections that it was relying on erroneous dicta, the appeals court applied a definition of “overriding royalty interest” cited by earlier Ohio decisions to mean

[A] fractional interest in the gross production of oil and gas under a lease in addition to usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing, and other costs incident to the production and sale of oil and gas produced from the lease.

The appeals court held that “this definition excludes deductions for all expenses for the entire process of extracting, processing, and selling the oil and gas.” Nonetheless, the court held that “though overriding royalties are generally cost-free, parties to an overriding royalty contract ‘can agree to any manner of cost sharing they choose.’” Here, however, the court found that the parties did not contract around the cost-free definition of an ORRI. Namely, the contract provided that the ORRI would be expressly free of “operating expenses,” which the court defined to mean “expenses required to keep the business running, e.g., rent, electricity, heat. Expenses incurred in the course of ordinary activities of an entity.” “It is apparent that [the producer’s] claimed post-production costs are operating expenses,” the court found. The court also accepted the ORRI payees’ claim that parol evidence supported applying that definition to the disputed ORRIs.

In Kirkbride v. Antero Resources Corp., the lessor filed a class action complaint alleging that the lessee breached an oil and gas lease by improperly calculating royalty payments. The lessee moved to dismiss, contending that the lessor did not satisfy the lease’s pre-suit notice provision, which provided that service of such notice “shall be a condition precedent to the commencement” of an action for breach of the lease. Finding that the lessor failed to comply with the provision before suing, the trial court dismissed the complaint. On further appeal, the Sixth Circuit affirmed. The appeals court rejected the landowner’s argument that service of her complaint constituted sufficient notice. Rather, “the Lease expressly required pre-suit notice” that service of the complaint occurred after the lessor filed her suit, and thus “by definition, it cannot be pre-suit notice.”

In Hogue v. PP&G Oil Company, LLC, Ohio’s Seventh District Court of Appeals considered whether an “assignment of working interest” applied to the deep rights leased under an oil and gas lease. That assignment stated:

That the undersigned, [PP&G], … does hereby assign, transfer, sell and convey unto [the appellees] an undivided 2.5% working interest in and to [certain wells drilled to approximately 2,500 feet in depth] and the related 20 acre drill site unit, together with the rights incident thereto and the personal property therein.

The appeals court held the deep rights did not transfer to the appellees:

There is no dispute that the Ohio Administrative Code section in effect when the Assignment was executed limited 20-acre drilling units to depths of 4,000 feet. Insofar as [a]ppellees do not dispute the deep rights at issue in this case are below 4,000 feet, … we find the Assignment is unambiguous and … limited [a]ppellee’s working interest in the oil and gas to a maximum depth of 4,000 feet.

2. Trespass

In Tera, L.L.C. v. Rice Drilling D, L.L.C., the Supreme Court of Ohio addressed whether a lessee had the right to drill in the Point Pleasant formation. The lease granted the lessee the right to drill “in the formations commonly known as the Marcellus Shale and the Utica Shale.” The lessor expressly reserved all rights “in all formations below the base of the Utica Shale.” The lessor argued that the lessee committed a trespass by drilling in the Point Pleasant formation because it reserved the rights in that formation. The trial court granted summary judgment in favor of the lessor on the issue of liability and the Seventh District Court of Appeals affirmed. The Seventh District Court of Appeals also affirmed the trial court’s finding that the lessee committed a “bad faith trespass,” and held that the lessors were entitled to the full market value of the extracted gas without deduction for the cost of labor and other expenses incurred in producing and transporting gas to the point of sale. The Ohio Supreme Court reversed. It reasoned that the lease was ambiguous and that the extrinsic evidence submitted to the trial court demonstrated a triable issue of fact regarding whether the parties intended for Point Pleasant to be considered part of the Utica Shale.

In Honey Crest Acres, LLC v. Rice Drilling D, LLC, the Southern District of Ohio denied the defendant’s motion to dismiss the plaintiff’s declaratory judgment, trespass, conversion, and unjust enrichment claims. The plaintiff alleged that the producer obtained the rights to drill in the Marcellus Shale and the Utica Shale, but it did not have the right to drill into the Point Pleasant. The court determined that the complaint stated a plausible trespass claim because it alleged that Rice Drilling’s completion operations indirectly interfered with the plaintiff’s rights in the Point Pleasant formation. The district court also rejected the defendant’s argument that the “rule of capture” barred the plaintiff’s conversion claim because courts have recognized conversion claims based upon hydraulic fracturing. While the rule of capture generally protects a landowner who extracts oil from her property that migrated from a neighboring property, the district court recognized that the rule of capture is “an inefficient approach” and found that “the sparse case law on this topic recognizes a conversion claim predicated on natural resources that have been acquired by hydraulic fracturing that invades the plaintiff’s property.” Last, the district court held that an unjust enrichment claim could proceed because the landowner conferred a benefit by leasing its subsurface mineral rights to the lessee, and it would be unjust for the lessee to extract the minerals without compensating the landowner.

3. Ohio’s Marketable Title Act

In RL Clark, LLC v. Hammond, Ohio’s Seventh District Court of Appeals considered whether two statutory exceptions operated to prevent the extinguishment of a severed oil and gas royalty interest under the Ohio Marketable Title Act (MTA). In 1902, the then-owners sold the property, “excepting the one-half (1/2) of the oil and gas royalty.” While a subsequent 1908 deed excepted one-half of the royalty, the 1956 root of title deed conveyed the property “subject also to such interest in the oil and gas royalties as have heretofore been reserved by former grantors.” Under the MTA, an interest can be saved from extinguishment if there is a specific reference to the interest in the claimant’s 40-year chain of record title. The court undertook the three-part test established by the Supreme Court of Ohio in Blackstone v. Moore to determine whether the reference in the 1956 deed was specific or general. The court determined that the reference in the 1956 deed was general, as it did not identify who the “former grantors” were or even clarify what the actual royalty interest was (e.g., one-fourth, one-half, entire). Instead, the language in the 1956 deed (and later deeds) was “[b]oilerplate, generic, vague, and different than the original description of the property interest.” And because the general reference in the 1956 deed clearly did not identify any other recorded title transaction, the specific reference exception under the MTA could not prevent the extinguishment of the severed royalty interest.

The court also faced the question of whether certain oil and gas leases recorded within the 40-year period after the 1956 root of title saved the royalty interest from extinguishment. Under the MTA, any interest arising out of a title transaction that was recorded within the 40-year period following the effective date of the root of title will not be extinguished. There were several oil and gas leases covering the subject property recorded during that period. However, while oil and gas leases may be title transactions under the MTA, these leases were not entered into by the severed royalty owners, nor did the leases mention the severed royalty interest. The court noted that there “[i]s no connection between the recorded leases … and the [severed royalty interest]” and “[a]n interest does not arise from a title transaction simply by virtue of some amorphous connection to the title transaction.” As a result, the court held that the severed royalty interest was extinguished under the MTA.

In Wolfe v. Bounty Mins LLC, Ohio’s Seventh District Court of Appeals addressed whether the incorporation by reference doctrine could be used to preserve a severed oil and gas interest from extinguishment under the MTA. In this case, the oil and gas underlying the subject property was severed from the surface in a 1921 deed. The subsequent deeds in the chain of title up through and including a 1950 deed contained a verbatim repetition of the severance language; however, the 1966 deed that followed did not repeat the severance language, nor did it even include a legal description of the property. Rather, it referenced title instruments identified on an attached Exhibit A for a description of the properties, while also expressly incorporating the terms and conditions of said instruments. Exhibit A identified the prior 1950 deed by reference to its date, volume, page numbers, and names of the grantor and grantee. Affirming the trial court’s decision, the court found that (1) the inclusion of the 1950 deed on Exhibit A was sufficient for the 1966 deed to qualify as the root of title, and (2) the 1950 deed’s verbatim repetition of the oil and gas severance was properly incorporated into the 1966 deed. As a result, the court held that the severed oil and gas interest was not extinguished under the MTA.

4. Ohio’s Dormant Mineral Act

In Henderson v. Stalder, Ohio’s Seventh District Court of Appeals was once again faced with the question of whether a surface owner properly complied with the mandates of the Ohio Dormant Mineral Act (DMA) when serving a notice of abandonment by newspaper publication. In this case, an oil and gas interest was severed in the early 1900s by the Eggers. In 2014, on behalf of the surface owners, a research company searched the public records of the county where the property is located but was unable to identify any heirs of the Eggers. The company conducted additional internet research and identified Vivian Egger Henderson as an heir of the Eggers; pursuant to this information, the surface owners attempted, albeit unsuccessfully, to serve Vivian via certified mail. Subsequently, the surface owners published a notice of abandonment that identified the Eggers as the holders but failed to name Vivian. The issues before the court were whether the surface owners exercised reasonable diligence in attempting to identify and locate heirs of the Eggers and whether the notice by publication was ineffective because it failed to specifically identify Vivian. The court found that the surface owners “[w]ere reasonably diligent in their search before resorting to notice by publication.” Specifically, the surface owners’ search of the public records complied with the Supreme Court of Ohio’s Gerrity v. Chervenak. The court held that the surface owners failed to comply with the requirements of the DMA by failing to name Vivian in the published notice. The DMA requires the notice of abandonment to contain “the name of each holder and the holder’s successors and assignees, as applicable.” Therefore, the court held that the DMA abandonment was not completed.

In Cardinal Minerals LLC v. Miller, Ohio’s Seventh District Court of Appeals addressed a mineral buyer’s attempt to invalidate the abandonment of a severed mineral interest under the DMA. After signing an oil and gas lease, the surface owners sought to abandon the severed mineral interest under the DMA, resorting to serving the notice of abandonment by newspaper publication. Almost a decade after the abandonment proceedings were completed and accounted for in the public records, Cardinal Minerals sought out the heirs of the original reserving parties and purchased any remaining mineral interests they may have held, along with an assignment of claims. Cardinal subsequently filed suit against the surface owners, challenging the validity of the earlier abandonment due to the use of newspaper publication. While the DMA abandonment was the focal point of the suit, the issue of standing was ultimately dispositive. Here, affirming the lower court’s decision, the court held that Cardinal could not “step in the shoes” of the mineral reserver’s heirs. Because the abandonment process had concluded years prior, the mineral reserver’s heirs could not sell—nor could Cardinal buy—an interest that no longer existed in the public record. Instead, because the heirs did not successfully challenge the abandonment, the severed mineral interest ceased to exist and could no longer be transferred. The court reasoned that their interests had already been deemed abandoned of record and vested in the surface owners for almost a decade. Further, the court noted that Cardinal “[i]s in the business of buying lawsuits” and its purchase of rights from the heirs, for the sole purpose of filing suit to undo the DMA abandonment, was barred under the doctrines of champerty and maintenance.

5. Development Disputes

In EOG Resources, Inc. v. Lucky Land Management., LLC, Lucky Land Management acquired the surface of the disputed property. EOG, which owned an oil and gas lease covering the property’s subsurface minerals, sought to use the surface to construct two horizontal well pads to produce oil and gas from underneath the property and other nearby properties. Lucky objected to EOG’s plans as an unreasonable use of its surface that would impede Lucky’s enjoyment of the property as a hunting ground. EOG sued and moved for a preliminary injunction to prohibit Lucky from interfering with EOG’s development activities. The district court granted the injunction, finding that under “[w]ell-settled law in Ohio [] the owner of a mineral interest has the right to use the surface to develop and produce minerals, while exercising due regard for the owner of the surface.” Here, the amount of surface EOG proposed to use was not more than is reasonably necessary and showed due regard for Lucky as the surface owner.

Lucky appealed to the Sixth Circuit, which stayed the injunction. The Ohio law that the district court relied on was “[s]ilent as to whether the mineral owner can use the surface of one property to mine minerals from adjacent properties. . . .” However, “there is a wealth of persuasive authority addressing that very issue,” holding that “[i]n the absence of an express agreement, the mineral owners or lessees cannot use the surface for the production of minerals from other lands.” Lucky had, therefore, shown “a likelihood of success on appeal,” which warranted staying the injunction.

6. Regulatory Disputes

In State ex rel. AWMS Water Solutions, LLC v. Mertz, the Eleventh District Court of Appeals addressed whether a 2014 shutdown order issued by the Ohio Department of Natural Resources caused the plaintiff to suffer partial or a categorical taking. In 2014, the plaintiff began injecting wastewater brine on the property at issue through two separate wells. After an induced seismic event was traced to the plaintiff’s primary injection well, ODNR issued the shutdown order enjoining the plaintiff’s use of the primary well, which was not lifted until May 2021. The court determined that a categorical taking did not occur because the plaintiff could have applied for a permit to drill with a different well on the property, could have sought a modification order for the enjoined well, and could have applied to drill a third well on the property. In other words, the shutdown order did not fundamentally deprive the plaintiff of all economically viable use of the property. However, ODNR did effect a partial taking because the plaintiff suffered an economic impact based on the shutdown order, and the shutdown order interfered with the plaintiff’s reasonable and distinct investment-back expectations.

IX. Oklahoma

A. Legislative Developments

During the 2024 legislative session, the Oklahoma legislature adopted House Bill 2197 to amend existing statutes to authorize the Executive Director of the Oklahoma Water Resources Board to issue 90-day permits for stream water and groundwater use for oil and gas drilling and completion operations. As amended, these permits may be renewed up to three times (in most cases) but are conditional on the permittee’s filing an annual report with the Water Resources Board. By Senate Bill 1514, the legislature also amended the Production Revenue Standards Act (PRSA) to extend its five-year statute of limitations to apply to claims brought under the act by the Commissioners of the Land Office. Finally, through passage of Senate Bill 1505, the legislature extended the Oklahoma Emissions Reduction Technology Incentive Act to provide rebates for the costs of implementing emissions reduction projects on downstream oil and gas operations and refining and distribution activities, in addition to upstream and midstream operations.

B. Judicial Developments

The Oklahoma Supreme Court decided whether and when quiet title suits are subject to a statute of limitations in Base v. Devon Energy Production In 1973, the plaintiff’s predecessors in interest executed an oil and gas lease in favor of the Rodman Corporation. The 1973 lease provided for a five-year primary term ending on December 4, 1978, and a 1/8 lessor’s royalty on oil and gas production. Within the lease’s primary term, Rodman Corporation assigned the 1973 lease to Partnership Properties Co. and on July 24, 1978, the plaintiff’s predecessors executed a lease in favor of Petro-Lewis Funds, Inc. This lease was to commence a three-year primary term on December 4, 1978, the date when the 1973 lease was to expire. The 1978 lease provided for a lessor’s royalty of 3/16. Petro-Lewis Funds, Inc. then filed a pooling application with the Oklahoma Corporation Commission for the drilling of a well on the premises covered by both leases and completed a producing well. Production was achieved in November 1978, before the expiration of the 1973 lease. The plaintiff’s predecessors subsequently signed division orders certifying their right to a 1/8 royalty under the 1973 lease. Shortly thereafter, the owner of the 1973 lease, Partnership Properties Co., also acquired the 1978 lease. While the 1973 lease would be assigned many times over the intervening years, no evidence indicated that Partnership Properties Co. ever assigned the 1978 lease.

In 2008 Chesapeake Operating, Inc. apparently acquired the 1973 lease, drilled a second well, and began paying a 3/16 royalty “[a]s if the 1978 [l]ease had superseded or amended the terms of the 1973 [l]ease.” Ten years later, Devon Energy Production Company acquired the 1973 lease, drilled eight multi-unit horizontal wells, and began paying a 1/8 royalty, “[a]s if the 1973 [l]ease controlled over the 1978 [l]ease.” The plaintiff filed suit against Devon Energy in 2019 after refusing to sign division orders certifying the plaintiff enjoyed only a 1/8 royalty interest. The suit brought claims for quiet title and declaratory judgment as well as for accounting and payment under the Production Revenue Standards Act (PRSA). The plaintiff’s underlying theory was that the terms of the 1978 lease “[s]upplanted or amended by the terms of the. . .” 1973 lease.

In a 2-1 decision, the court of appeals affirmed the district court’s grant of summary judgement, holding that the plaintiff’s quiet title claim accrued in 1978 when the 1978 lease resulted in a cloud on title to the plaintiff’s interest under the 1973 lease, and that the claim was barred by the 15-year statute of limitations for the recovery of real property contained in 12 O.S. § 93(4).

The Oklahoma Supreme Court affirmed the court of appeals on three issues relating to Devon Energy’s limitations defense: (1) whether the plaintiff’s quiet title claim is subject to a statute of limitations at all, (2) if so, whether the 15-year statute governing actions to recover real property is applicable, and (3) if so, whether the claim only accrued when the plaintiff made a demand under Claude C. Arnold Non-Operated Royalty Interest Properties, L.L.C. v. Cabot Oil and Gas Corp.

Beginning with the threshold issue of whether any statute of limitations applies to the plaintiff’s quiet title claim, the Oklahoma Supreme Court held that a limitations period does apply. The general rule is that “[t]he statute of limitations never runs against the plaintiff in a quiet title action who is in possession of the property at issue” but when the plaintiff has not been in continuous possession, “[h]is equitable claim to quiet title will be viewed as a legal claim to recover the property, which is subject to a statute of limitation.” Thus, the question in the case boils down to whether the plaintiff was in or out of possession of the subject mineral interest; if the former, her quiet title would be equitable and thus not barred by a statute of limitations, but if the latter, the claim for recovering possession of the property would be time limited.

The court made what is probably the opinion’s most significant pronouncement of law in response to this question. In holding that the plaintiff was out of possession of her mineral interest, the court explained that one method for demonstrating possession of mineral interests is by holding unencumbered record title. Another method, “[t]ypically used by parties asserting adverse possession,” is “show[ing] that they have taken steps toward reducing the minerals to possession through drilling operations. Interpreting the court’s meaning here, Oklahoma law requires mineral owners to timely sue (a) persons in actual possession of the minerals to avoid adverse possession of the mineral interest, as well as against (b) persons whose claims cloud record title to the mineral interest despite not being in actual possession of the minerals. Thus, a mineral owner’s failure to timely assert a claim to quiet title against a mere cloud on title results in the de facto perfection of the defendant’s adverse claim in the minerals, without any requirement that the defendant be in possession of the minerals. In the case at bar, the court concluded that the plaintiff fell into the second category and were time-limited in bringing their claims: Plaintiff “[s]hould have seen that her possession of the mineral interests was encumbered by the existence of two leases and should have been on notice that she needed to quiet title in favor of her preferred lease through cancellation of the opposing lease .”

Having concluded that the plaintiff’s claim was subject to a statute of limitations, the court next considered which statute was applicable—the 15-year statute for actions to recover real property or the five-year statute for actions brought under the PRSA. Finding that the action was to resolve a cloud on title and that the PRSA claims were merely derivative of that resolution, the court affirmed the court of appeals’ application of the catchall 15-year period of 12 O.S. § 93(4).

The third limitations issue is more difficult: when did the plaintiff’s quiet title claim accrue? Devon Energy argued that the claim accrued in 1978 or 1979, when the plaintiff’s predecessor executed the 1978 lease and signed a division order reflecting the 1/8 royalty under the 1973 lease. The plaintiff argued that under Claude C. Arnold, her claim accrued only after she demanded payment of the higher royalty percentage under the 1978 lease.

Distinguishing Claude C. Arnold, the Base court held that the plaintiff’s predecessor was first on notice of the potential cloud on her mineral interest when she executed the 1978 lease or when she signed the 1979 division order reflecting the lower royalty percentage. Unlike the plaintiff in Claude C. Arnold, who had no role in drafting or recording the subsequently recorded leases that clouded title to her interest and no notice of them until she demanded payment of the higher royalty percentage, the predecessor of the plaintiff at bar was herself a party to the very transaction that she claimed to cloud her title. The court thus affirmed dismissal of the plaintiff’s claims.

The Oklahoma Supreme Court also decided Latigo Oil & Gas v. BP America Production Co., involving the construction of a preferential right to purchase in a joint operating agreement (JOA). Latigo sought a preliminary injunction against BP from selling certain assets subject to Latigo’s preferential right to purchase under the parties’ JOA. BP had entered an agreement with a third party to sell a package of oil and gas interests nationwide, which included a few interests that were subject to the parties’ JOA. As required by the preferential right to purchase, BP offered the burdened interests to Latigo, attaching a copy of the purchase price allocation contained in BP’s purchase and sale agreement with the third party. The purchase and sale agreement allocated a uniform value of $60,000 to every interest that was burdened by a preferential right. Latigo rejected the offers, arguing that the allocated price exceeded the interests’ market value and that the price allocation was made in bad faith to discourage Latigo from exercising the preferential right to purchase.

The district court preliminarily enjoined BP’s sale and the court of appeals reversed, citing that Latigo failed to establish a likelihood of success on the merits of its breach of contract claim. The Oklahoma Supreme Court reversed the court of appeals and affirmed the preliminary injunction, holding that the district court did not abuse its discretion in finding that BP may owe a duty to allocate the value of the burdened interests in good faith. The court relied on Ollie v. Rainbolt, whereby the court held that a seller in such a situation breaches the essence, if not the express requirements, of a preferential right by offering the burdened property as an all-or-nothing package with other property that is not burdened by the preferential right. Citing opinions from courts in Iowa, Georgia, and Idaho, the court concluded that authority exists in other jurisdictions to support a theory that package-deal sellers have a duty to allocate the purchase price or value of interests burdened by a preferential right in good faith.

In In re Chisolm Oil and Gas Nominee, the operator under a JOA declared Chapter 11 bankruptcy against nonoperator parties to the JOA. Before the bankruptcy, the nonoperator parties elected not to participate in subsequent drilling operations, subjecting their interests to risk penalties under the JOA’s non-consent provisions. Under the JOA, the nonoperators’ shares of production were directed to the consenting parties until such time as production from the drilling operations repaid expenses and fully satisfied the risk penalties.

In the bankruptcy proceeding, the debtor operator rejected the JOA as executory contracts pursuant to section 365 of the Bankruptcy Code. In response, the nonoperators asserted that rejection of the JOA restored the parties a common law co-tenancy relationship. Under common law principles, cotenants that elect not to consent to drilling operations owe no risk penalty and retain their interests. Therefore, the nonoperators argued their working interests reverted to them as of the date of the bankruptcy petition. The court rejected this theory, citing United States Supreme Court authority that rejection of an executory contract under section 365 merely breaches the contract but does not rescind it. Thus, the operator’s rejection of the JOA did not unwind the nonoperators’ elections under the JOA’s nonconsent provisions and the nonoperators were not entitled to immediate payment of their proportionate shares of production.

In Lazy S Ranch Properties v. Valero Terminaling & Distribution Co., the owner of a ranch brought claims of public and private nuisance and negligence per se under various Oklahoma statutes, alleging that leaks from defendant’s refined products pipeline contaminated the ranch. The district court found that no reasonable trier of fact could have found the trace amounts of petroleum products detected on plaintiff’s property constituted a nuisance or rendered the environment harmful, detrimental, or injurious as required by Oklahoma law. Additionally, the court found that even if legal injury occurred, the plaintiff failed to introduce sufficient evidence of causation and failed to rule out other potential sources of contamination.

The Tenth Circuit held the plaintiff’s evidence created a triable issue of whether the defendant’s pipeline created a nuisance under this definition. In particular, the plaintiff showed that caves on the ranch smelled of hydrocarbons, which caused headaches, prevented the mapping of caves, and made a geologist hesitate about using a lighter to ignite a cigarette on the ranch. The court held further that because 27A O.S. § 2-6-105(A) mandates that “pollution of any waters of the state is a public nuisance,” the plaintiff’s claim of private nuisance based on hydrocarbon pollution logically also establishes a claim for public nuisance. Based on the same evidence of harm, the court held that the plaintiff established triable claims for negligence per se for breach of statutes and regulations prohibiting pollution of soil and water resources. On the issue of plaintiff’s evidence of causation, the Tenth Circuit again reversed the district court, finding enough evidence that the defendant’s pipeline was to blame that a reasonable jury could decide either way.

X. Pennsylvania

A. Legislative Developments

On July 11, 2024, Governor Shapiro approved Pennsylvania Senate Bill 654 which permits taxpayers to claim a deduction for the percentage depletion of certain natural resources, including oil and gas wells. The percentage depletion rate is based on revenue and is set at 15% for oil and natural gas. This Bill brings Pennsylvania into conformity with federal regulations that allow a tax deduction for percentage depletion. Previously, Pennsylvania taxpayers seeking to claim a deduction for natural resources could do so only for cost depletion, which required a more complex calculation involving the resource’s exhaustion rate.

B. Judicial Developments

In KEM Resources, LP v. Deer Park Lumber, Inc., the Pennsylvania Supreme Court considered which statute of limitations period applies to a co-tenant’s accounting claim against a fellow co-tenant. The co-tenants each owned a 50% interest in the oil and gas underlying the property. In 2008, the defendant co-tenant entered a lease for the entirety of the oil and gas estate and received a bonus payment. In July 2014, the plaintiff co-tenant filed suit, arguing, among other things, that it was entitled to an accounting for the money the defendant received from leasing the oil and gas attributable to the plaintiff co-tenant’s interest. The defendant argued that the accounting claim was barred by the statute of limitations because the claim “at its core” was either a breach of fiduciary duty claim subject to a two-year statute of limitations or an unjust enrichment claim subject to a four-year statute of limitations. The superior court rejected that argument, concluding that the plaintiff’s accounting claim constituted a statutory claim under 68 Pennsylvania Statute section 101 which permits “tenants in common, not in possession, to sue for and recover from such tenants in possession his or their proportionate part of the rental value of said real estate.” Because no statute of limitations is specified for this type of action, the superior court concluded that Pennsylvania’s catch-all six-year statute of limitations applied. The Pennsylvania Supreme Court affirmed, reasoning that, although the plaintiff had not explicitly pleaded section 101 in its complaint, it had alleged all of the facts necessary for section 101 to apply. The court further agreed that, because neither section 101 nor any other statutory section specified the statute of limitations applicable to an accounting claim between co-tenants, the catch-all, six-year statute of limitations applied. Because the action was filed within six years after the defendant co-tenant received the lease bonus, the court concluded it was timely filed.

In Frye v. Penn View Exploration, Inc., the Pennsylvania Superior Court concluded that a lease remained in effect despite the lessee’s failure to timely pay shut-in royalties because the lease’s shut-in royalty provision did not state that non-compliance would result in lease termination. The plaintiffs entered a lease providing that it would remain in effect for as long after the primary term as “[o]il or gas or their constituents are produced or are capable of being produced on the premises in paying quantities, in the judgment of Lessee.” The lease further provided that, if the lessee was unable to market the production from a well it drilled or shut-in a producing well, the lessee would pay an advanced royalty to the lessor within one year of the date the well stopped producing or was shut-in. After a connecting pipeline was abandoned, the defendant shut-in wells drilled beneath the plaintiffs’ property but did not issue a shut-in royalty payment to the plaintiffs. Three years after the wells were shut-in, the plaintiffs notified the defendant they intended to terminate the lease and subsequently initiated suit arguing that the lease had become void when the defendant failed to timely pay shut-in royalties. The defendant counterclaimed arguing that the plaintiffs breached the lease by failing to provide notice and an opportunity to cure as the lease required. The defendant further argued that because the lease was capable of producing in paying quantities the lease remained in effect.

After both parties filed motions for summary judgment, the trial court denied the plaintiffs’ motion and granted the defendant’s motion. Regarding lease termination, the trial court reasoned that the plaintiffs failed to satisfy their burden to prove termination when the evidence showed that the defendant made “[s]ignificant efforts to get the well back into productive status” which “at a minimum” created issues of fact as to whether it had “[a]cted in good faith in continuing to attempt to operate the well as required” by Pennsylvania case law. With respect to notice and cure, the trial court found that by filing suit 20 days after they informed the defendant of the lease’s termination, the plaintiffs failed to provide the defendant with the requisite 30-day period to cure. The superior court affirmed the denial of the plaintiff’s summary judgment motion, noting that the shut-in royalty provision did not state that the lease would become void if such payments were not timely made. However, the superior court disagreed with the trial court’s ruling on the plaintiffs’ failure to satisfy the notice-and-cure provision of the lease. According to the superior court, regardless of when they filed the original complaint, the plaintiffs’ filing of an amended complaint rendered their original complaint a nullity. Because the amended complaint was filed beyond the 30-day cure period, the court concluded the plaintiffs had satisfied the lease’s notice-and-cure provision.

In A&B Campbell Family LLC v. Chesapeake Energy Corp., the Middle District of Pennsylvania concluded that allegations regarding the defendants’ engagement in related schemes to underpay royalties based on “unauthorized or artificially inflated deductions” failed to state a claim under the Sherman Act or RICO. The court first concluded that the plaintiffs lacked standing to assert a claim under the Sherman Act because they alleged no facts showing “[a] reduction in competition stemming from their alleged injury,” as required for an antitrust claim, instead “[o]nly alleg[ing] harm to themselves through the underpayment of royalties.” Further, because the plaintiffs were royalty interest owners and “neither consumers nor competitors in the alleged relevant markets,” they were not permitted to bring an antitrust action. Even if the plaintiffs had standing, the court concluded they failed to state a claim under the Sherman Act because “[a]t most Plaintiffs have alleged parallel conduct ‘entirely consistent’ with each Defendant pursuing its own interests by underpaying Plaintiffs’ royalties by deducting post-production costs,” which was insufficient to establish that they had acted in concert to restrain trade.

With respect to the RICO claim, the court granted the motion to dismiss based on the lack of factual allegations establishing the defendants “[k]nowingly agreed to participate in an enterprise intended to defraud Plaintiffs” or engaged in “global, coordinate, and unified activity” rather than “independent and varied conduct” insufficient to establish a RICO enterprise. The court also dismissed the plaintiffs’ state law claims for breach of contract, conversion, civil conspiracy, and accounting, all of which were based on their allegations regarding the impermissible deduction of post-production costs. In doing so, the court pointed out that the lease’s royalty clause providing that the “[m]arket value at the well shall not exceed the amount realized by lessee for such production computed at the well” had been interpreted by other courts as requiring calculation of royalties “at the wellhead” which permitted the deduction of post-production costs.

In Chambers v. Equinor USA Onshore Properties Inc., the Middle District of Pennsylvania considered whether a lease requiring royalties to be paid for the oil and gas “marketed and used off the premises” created “[a]n implied duty to market gas produced under the Leases to downstream third parties.” While the defendant argued that it complied with the lease by paying royalties based on the price it sold gas at the wellhead to an affiliated entity, the plaintiffs argued that royalties should be calculated based on downstream sales to third parties. The court concluded that the phrase “marketed and used off the premises” was ambiguous, acknowledging merit in both the defendant’s argument that this phrase historically was understood “[t]o delineate merely whether any royalty was owed at all” and the plaintiffs’ argument that the oil and gas industry has evolved such that oil and gas is no longer sold at the wellhead. Although the court noted that the leases were proceeds leases and the defendant’s interpretation of the royalty provision did not treat them as such, the court recognized that other courts have “[i]nterpreted the term ‘marketing’ to mean sold in this context.” The court further noted that, here, “market” could mean “[t]o incur post-production costs to prepare the gas for sale” because the parties had crossed out language permitting the deduction of post-production costs but kept the marketing language. Without expert testimony regarding the language of this particular type of lease, the court concluded the phrase “marked and used off the premises” was reasonably susceptible to multiple interpretations that must be resolved by the finder of fact. Additionally, the court reiterated well-established law that the plaintiffs’ breach of contract claim subsumed their breach of the implied duty of good faith and fair dealing claim.

The court in Gerfin v. Southwestern Energy Production Co. considered whether a lease requiring the lessee to obtain the lessor’s written consent for “additional pooling/unitization or other forms of pooling/unitization” with properties other than those identified in the lease prohibited cross-unit drilling without the plaintiffs’ written consent. The defendant filed a motion to dismiss the plaintiff’s breach of contract claim, arguing that it was only obligated to obtain the plaintiffs’ written consent for pooling and unitization, which are distinct from cross-unit drilling. The defendant further argued that Pennsylvania statutory law permits cross-unit drilling in the absence of an express prohibition in the lease which the plaintiffs’ lease lacked. The court rejected the plaintiffs’ argument that pooling, unitization, and cross-unit drilling were interchangeable terms all of which required the plaintiffs’ written consent. The court concluded that the inclusion of the language “other forms of pooling/unitization” in addition to “pooling/unitization” suggested the parties intended this language to mean something different than mere pooling and unitization and the phrase was “[i]f not an ambiguity in and of itself, the ‘contractual hook’ upon which a latent ambiguity may rest.” Based on this and the parties’ failure to address the impact of Pennsylvania’s requirement that a lease contain an “express prohibition” in order for cross-unit drilling to be prohibited, the court denied the motion to dismiss.

XI. Texas

A. Judicial Developments

In the wake of Van Dyke v. Navigator Group, Texas courts are still being called upon to address the interpretation of the historical 1/8 landowner’s royalty in conveyances and leases. The rebuttable presumption that 1/8 represents the entire leasehold estate has largely helped Texas courts clarify conflicting interpretations of double fractions. In Powder River Mineral Partners, LLC v. Cimarex Energy Co., the issue was whether a deed conveyed a fixed 3/128 royalty interest or a floating 3/16th interest. In the deed, the grantors conveyed “[a]n undivided three sixteenths (3/16ths) interest in and to all the oil, gas and other minerals in and under that may be produced from the ... described land.” The deed went on to say:

In the event the above land should be loaned for the mining of oil and gas or other minerals, then Grantees shall be entitled to receive under this conveyance free of cost in the pipe line to which any well or wells on said land may be connected, 3/16ths of one-eighth of all the oil and/or gas or other minerals produced therefrom under such lease.

The double fraction nature of the deed required the court to determine the parties' intent by looking at the document in its entirety. The court noted a rebuttable presumption that 1/8 was historically used as a “placeholder for future royalties generally,” and not as a mathematical value, so the court presumed that the parties intended for the 1/8 to be used in its historical standard, thus intending a 3/16 floating royalty. The grantors’ successors argued that the royalty conveyance only applies if the subject property was leased for minerals, and that the double fraction language rebuts the presumption. The court disagreed with these arguments because of the deed’s language and the necessity of double fraction presumption. The court did not identify language in the deed to rebut the presumption and held that the deed conveyed a floating 3/16 royalty.

In Montgomery, Trustee of Tri-Mont Irrevocable Trusts v. ES3 Minerals, the court addressed the question of a double fraction in a conveyance of a non-participating royalty and whether it created a fixed or floating royalty. Following the precedent set by Van Dyke v. Navigator Group, the court found that 1/4 of 1/8, in the context of the conveyance language, did not mean 1/32. Rather, the rebuttable presumption that “1/8” in a conveyance represents the grantor’s entire leasehold interest was not overcome. Additionally, the inclusion of the language “of the landowner’s usual one-eighth royalty” further demonstrated that the original parties meant for 1/8 to symbolize the entire estate rather than as a fixed limitation on the ¼ non-participating royalty interest.

Texas courts also received a fair amount of litigation regarding interpretation of deeds. In Liska v. Dworaczyk, the court was tasked with taking contested language in a will and determining both whether the testator bequeathed an interest in an entire tract of land or just a specific unit and whether the inclusion of two fractions resulted in the beneficiaries receiving a reduced amount. The will stated that the testator would bequeath to the ten named individuals “[a] ONE-TENTH (1/10) interest in the Mineral Interest I own in 118.4 acres near Gillet, Karnes County, Texas, known as the Dragon Unit…” followed by the name of each beneficiary with the words “A ONE-TENTH (1/10).” The court found that the mineral interests included just the Dragon Unit and not the entire 118.4 acres. The 118.4 acres were split into “the Dragon Unit” and “the Bowers Unit,” thus, an interpretation that the beneficiaries were given all 118.4 acres would have erroneously rendered the chosen language “known as the Dragon Unit” pointless. Additionally, each restatement of “A ONE-TENTH (1/10)” meant that each beneficiary was to receive an undivided one-tenth interest in the property, not that each beneficiary’s interest is further divided into a one-hundredth interest, which would have resulted in less than all of the testator’s interest being disposed of by the will.

In Gardner Energy Corp. v. McNeil, McNeil, & Holt the court determined whether the grantors of a fee mineral interest intended to convey the proportionate burden of a third party’s non-participating royalty interest (NPRI) to the grantees, or on the other hand, whether the grantors intended the entire burden to be allocated to their reserved ½ interest. “In 1951, the State of Texas conveyed the subject property” while reserving a 1/16 NPRI. The grantors became successors-in-interest and in 1976, conveyed by mineral deed an undivided ½ mineral interest in the property to the grantees. The successors-in-interest for the grantors eventually sought a declaratory judgment that the burden of the State’s NPRI should be borne by both parties in proportion to their respective interests. The successors-in-interest for the grantees argued that the failure to mention the State’s NPRI in the mineral deed reflects the grantors’ intent to convey an undivided ½ mineral interest in fee simple in the subject property, unburdened by the NRPI. Interpreting the parties’ intent as expressed in the mineral deed, the court held that the grantors intended to convey the proportionate burden of the State’s NPRI to the grantees based on the subject-to clause. Though the mineral deed did not explicitly mention the State’s NPRI, the court reasoned that the subject-to clause confirms that the grantees were subject to “any rights now existing to any lessee or assigns under any valid and subsisting oil and gas lease,” entitling them only to the royalty interest to which the grantors were entitled. Therefore, the subject-to clause’s reference to the grantors’ right to receive royalties under the existing leases put the grantees on notice that their rights were being limited at which point the grantee’s could have made inquiries and discovered the burden of the State’s NPRI.

Courts also issued a couple of opinions dealing with depth limitations in conveyances (or the lack thereof). In Rock River Minerals, LP v. Pioneer Natural Resources USA, Inc., the court analyzed whether an overriding royalty interest (ORRI) conveyance included a depth limitation. The grantor owned an ORRI in all depths of various leases in a unit. At the time of the conveyance, the leases were subject to a unit agreement as to the Spraberry formation. However, the exhibits to the conveyance referenced that the conveyance was as to “all depths located within the geographic boundaries” of the unit. Eventually, Wolfcamp formation wells were drilled (which is below the Spraberry). The grantor’s successors argued that the Spraberry unit agreement operated as a depth limitation on the conveyance, such that the overriding royalty interest remained with them for the deeper Wolfcamp depths. The court reasoned that geography is a science of the surface, and the reference to the unit was merely a reference to the horizontal limitations of the land description. Thus, confining the land description to the unit was not express or sufficient enough language to create a depth limitation in the conveyance of an overriding royalty.

Occidental Permian, Ltd. v. Citation 2002 Investment LLC also involved alleged depth limitations in a conveyance. The Texas Supreme Court held that an assignment of mineral interests listing certain depth descriptions could not be read to reserve “deep-rights” interests to the assignor. In 1987, Shell Western E&P, Inc. (Shell) sold oil-and-gas properties to Citation 2002 Investment LLC (Citation) in an assignment of mineral interests (1987 Assignment). A decade later, Shell purported to assign some of the same interests to Occidental Permian. Exhibit A of the 1987 Assignment described the conveyed interests in a table of leases with depth references. The parties disputed whether the 1987 Assignment was depth-limited, with Occidental Permian arguing that Shell had reserved interests beyond the depth specifications indicated in Exhibit A. The court relied on Piranha Partners v. Neuhoff to find that Exhibit A presented an ambiguity because it contained no language directing the proper method for reading its tables. The court turned to the 1987 Assignment’s other terms, which provided that Shell assigned “all rights and interests now owned by Shell . . . in the leases and other rights described herein . . . .” The court concluded that by specifying the “leases” as “described herein,” Shell intended to convey its rights to Citation in such leases without any depth limitation.

In Unitex WI, LLC v. CT Land & Cattle Company, LLC, the court determined that a surface owner, who was not a party to an oil and gas lease, lacked the ability to enforce a pipeline burial covenant that was reserved to the lessor of a mineral lease. CT Land & Cattle acquired the surface rights to property subject to an existing mineral lease. It sought to enforce a pipeline burial provision in the original lease. The court noted that while burial provisions generally run with the land, the provision did not do so in this case because of the precise wording of the lease and other instruments in the surface owner’s chain of title. Effectively, the court found no authority on behalf of CT Land & Cattle to enforce the pipeline burial provision.

Lee v. Memorial Production Operating arose from an improperly installed additional packer on a saltwater-disposal well that resulted in toxic saltwater breaking through the surface on the plaintiff landowners’ property. Seeking recovery for the damage to their cattle operation and enjoyment of the land, the landowners sued the current and previous well operators. One claim by the landowners was for the operators’ breach of the oil and gas lease, which required the landowners to prove that they were the mineral owners (thus parties to the oil and gas lease). The court of appeals affirmed the district court’s grant of summary judgment on the grounds that the landowners only produced evidence of owning the surface estate, not the mineral estate, thus failing to prove a contract between the parties.

The court in Darkhorse Water, LP v. Birch Operations, Inc. focused on whether a surface lease for saltwater disposal was more similar to a traditional occupancy lease (which conveys no right to ownership and title), or a “typical oil and gas lease…[that] conveys the mineral estate as a determinable fee,” and therefore a right to ownership which would be necessary for claims to quiet title and for an accounting. Though Darkhorse’s alleged ownership interest related to the subsurface reservoir storage space—not minerals—the court found that “reservoir storage space is an attribute of the surface estate” and can be depleted in the same way minerals can be extracted. Further, the language in Darkhorse’s lease pertaining to the term of operation mirrors the language in typical oil and gas leases; it provides for an initial five-year term that continues indefinitely as long as operations are actually conducted. Thus, the court held that the reservoir storage space was conveyable as a determinable fee interest and that the lease provided a right to ownership and title.

In Samson Exploration, LLC v. Bordages, the court determined that, without express language demonstrating an intent to the contrary, there is a presumption in Texas against compound interest calculations. The Bordages, royalty owners in mineral leases held by Samson Exploration, sued for unpaid royalties on those leases. The Bordages interpreted the late-payment provision in the leases to require compounding interest on the resulting late charges from late royalty payments at the end of each month. The court noted that Texas law favors simple interest unless there is a clear, express provision in the instrument indicating the parties explicitly contemplated compound interest. Because the court found no language in the Bordages’ leases to satisfy this requirement, the court held that the late charges were subject to simple interest.

In Nortex Minerals, L.P. v. Blackbeard Operating, LLC, the court was tasked with determining whether a sale of equity interests in a lessee constitutes a transfer of the lease, thus triggering the lessor’s consent right pursuant to the limited assignment provision. The limited assignment provision of the lease stated: “Except as provided herein, Lessee may not assign or otherwise transfer an interest in this Lease without prior written consent of Lessor.” The court approached the issue with a three-step framework: (1) whether a transfer occurred; (2) if a transfer occurred, whether it was a permitted transfer; and (3) if the transfer was not permitted and consent was required, whether the provision is an unenforceable restraint on alienation. The court determined that since the sale of the lessee’s equity occurred through a merger, which is not a transfer in the interest of the leases, it need not continue through steps (2) and (3) of the analysis. Texas Business Organizations Code section 10.008(a)(2)(C) dictates that a merger is not a transfer. Here, the limited assignment provision required a transfer of interest in the lease, and since there was no change-of-control provision, only a transfer of interest could have triggered the consent right. Since the equity sale was not a transfer of the lease rights, the lessor’s consent rights were not triggered pursuant to the limited assignment provision.

Hamilton v. ConocoPhillips Co. involved the interpretation of surface use provisions of a production-sharing agreement. After leasing their minerals to Burlington, the Hamilton family partitioned the land, and Lloyd Hamilton received a separate surface tract subject to an oil and gas lease. The family then signed a production sharing agreement (PSA) pursuant to which Burlington began constructing a well pad. Mr. Hamilton argued Burlington breached the lease and the PSA for failing to obtain his consent before constructing the pad site, arguing that although the PSA provided an easement for drilling a horizontal well, the PSA and the lease nevertheless required Burlington to seek a separate surface use agreement to receive the exact easements otherwise granted by the PSA. The court found that such a reading would render the entire purpose of the PSA meaningless as, under a plain meaning, it was entered into to grant an easement and right of way to conduct operations for a sharing well.

Repsol Oil & Gas USA, LLC v. Matrix Petroleum, LLC involved a complex dispute amongst non-operators and an operator. Among other claims related to the validity of participation elections, unilateral expenses incurred by the operator, and take-in-kind rights of non-operators, the non-operators asserted claims about missing volumes due to commingling under a joint operating agreement. The non-operators argued that the operator’s method of allocating hydrocarbons resulted in underreporting and underpayment for the hydrocarbons produced from their leases, which led to financial discrepancies. The court found that the non-operators did not adequately plead their “missing volumes” claim because allegations regarding “improper commingling” and “unreliable allocation methodology” do not give notice of a “missing volumes” claim.

In Carl v. Hilcorp Energy Company, the plaintiffs, Carl and White, filed a class action on behalf of royalty owners in leases operated by defendant Hilcorp. The leases stated that Hilcorp must pay royalties “on gas . . . produced from said land and sold or used off the premises . . . the market value at the well of one-eighth of the gas so sold or used.” The leases provided that Hilcorp also “shall have free use of . . . gas . . . for all operations hereunder.” The parties disputed whether Hilcorp owed royalties on gas used off-lease for post-production activities. The Fifth Circuit certified two questions to the Texas Supreme Court, given that court’s decision in BlueStone Natural Resources, II, LLC v. Randle,: “(1) [a]fter Randle, can a market-value-at-the well lease containing an off-lease-use-of-gas clause and free-on-lease-use clause be interpreted to allow for the deduction of gas used off lease in the post-production process?” and “(2) If such gas can be deducted, does the deduction influence the value per unit of gas, the units of gas on which royalties must be paid, or both?” The Texas Supreme Court answered the first question yes. It reasoned that under longstanding caselaw, gas used for post-production activities should be treated like other post-production costs where the royalty is based on the market value at the well. Randle involved a gross-proceeds royalty and its discussion of a free-use clause had no bearing on the outcome of this dispute. As to the second question, the court noted that the parties did not fully engage on this issue, but the court’s rough mathematical calculations indicated that either of the accounting methods referenced in the second question would yield the same royalty payment. The court did not state a preference for any particular method of royalty accounting.

Rights of way and easements are extremely important to the successful operation of mineral leases and production of oil and gas. As with other contract provisions, Texas courts try to discern what each party expressly intended with the chosen easement language. However, the courts’ job gets much more difficult when such language never existed. The court in Premcor Pipeline Company v. Wingate analyzed whether a trial court could rewrite a general pipeline easement to include a fixed permanent width for a pipeline right of way. When the pipeline easement was originally created, it gave the grantee “the right to do whatever may be requisite for enjoying the rights herein granted,” but did not specify a width for the pipeline. After a dispute developed between respective successors to the grantor and grantee, the grantor’s successor sought to have the trial court determine a fixed boundary based on previously laid pipelines. The trial court concluded that the pipeline’s dimensions became fixed and certain based on sixty-seven years of operation and maintenance. The appellate court overruled this and highlighted the Supreme Court of Texas’s reluctance to write fixed widths into easements when the parties did not agree to such easements. Therefore, the appellate court held that “the use of a general easement without a fixed width is a strategic decision that does not render an easement ambiguous or require a court to supply the missing term.”

In Iskandia Energy Operating, Inc. v. SWEPI LP, the court evaluated the nature of trespass claims in the context of deep subsurface wastewater migration. There, an oil and gas operator brought a trespass claim against a neighboring operator, alleging that the defendant operator injected waste saltwater into the plaintiff’s producing zones. The court held that a trespass claim based on an unauthorized interference with a lessee’s development right is recognized by recent Supreme Court jurisprudence as long as the injury is not outweighed by competing interests in the oil and gas context.

ETC Texas Pipeline, Ltd. v. Ageron Energy, LLC also involved a dispute between two neighboring well operators. The court dismissed negligence and trespass claims against ETC arising from poisonous and corrosive hydrogen sulfide gas from an ETC well that damaged Ageron’s wells. The court held that any injury to Ageron’s leasehold occurred before Ageron acquired its working interest. Because Ageron’s predecessor did not assign its causes of action related to the leases and wells, Ageron lacked standing to sue. The court noted: “[t]he right to sue belongs to the person who owns the land when the injury occurs and does not pass to a subsequent owner without an express assignment.” The court observed that Ageron could only have standing if: (1) it holds assigned claims (which it did not); or (2) the mineral interests it asserts were first injured after it acquired its leases in January 2020. The court found that the claims accrued to members of the Dickinson family—who owned the surface estate and mineral estate in common when the land was first injured in November 2012 by hydrogen sulfide that migrated to the surface, killing a few of the Dickinsons cows, giving “rise to a single, indivisible action in which the claimant might pursue all claims for all damages resulting from all injuries that arise from the wrongful conduct.”

In Ammonite Oil & Gas Corp. v. R.R. Commission of Texas, the Texas Supreme Court analyzed the voluntary pooling requirements that must be met before the occurrence of forced pooling under the Texas Mineral Interest Pooling Act (MIPA). Ammonite, the lessee of State-owned minerals in a riverbed, sought to force pool those minerals, under MIPA, with minerals being produced by EOG on either side of the riverbed. EOG’s wells did not extend to the riverbed; thus, their position was that Ammonite was trying to receive revenue through pooling without actually contributing to production. The court ultimately held that, due to the requirement for a fair and reasonable offer to voluntarily pool before a MIPA application can be successful, the Railroad Commission’s denial of Ammonite’s applications was sound. Ammonite’s initial offer to EOG did not contemplate extending the wells to reach Ammonite’s minerals, so the offer did not satisfy MIPA’s fair and reasonable effort requirement. Additionally, because EOG’s wells were already drilled, force-pooling them now would not do anything to prevent waste.

In ETC Texas Pipeline, Ltd. v. XTO Energy Inc., the court analyzed whether a dedicated acreage map relating to a gas gathering and processing agreement (the GPA) contained enough information to satisfy the land description requirement of the statute of frauds. The GPA was between XTO, as the producer, and ETC, as the gas gatherer. The GPA included a map that purported to delineate a specific geographic area. For any XTO leases within that area, ETC had the right to provide gathering and processing services (and be paid therefor). XTO argued that the dotted boundary on the map was made up of circles that, when considered to scale on a map, had a width of approximately 4,000 feet. XTO argued this made the map void under the statute of frauds for insufficient land description. The court disagreed, finding that the acreage map merely provided the general area that was to be further defined by XTO. The court also found that the parties had amended the gas purchase agreement several times with references to the latitude and longitude of receipt points subject to the agreement. This, coupled with XTO’s agreement to provide further specific lease information, constituted additional written information to aid in determining the area described by the dedicated acreage map.

While not involving oil and gas matters as such, Donnan v. RTJ Capital Group, LLC is pertinent to how a Texas court might approach a dispute involving preferential purchase rights, which are commonly found in joint operating agreements. The Donnans acquired a preferential purchase right for a tract of land. RTJ later acquired the property that was subject to the Donnans’ preferential purchase right. When RTJ realized that the Donnans claimed a preferential purchase right, RTJ’s counsel emailed the Donnans’ counsel with information about the purchase. Two months later, RTJ notified the Donnans that the tract was not subject to their preferential purchase right because the Donnans had not notified RTJ that they would purchase the tract. The court ultimately found in favor of RTJ and reasoned that RTJ, through the email correspondence, had satisfied their “offer” obligation to inform the Donnans of the sale. The court noted that the preferential provision did not require RTJ to offer to sell the entire tract to the Donnans, and when the holder of a preferential right learns of a sale in violation of that right, the preferential right is triggered. Additionally, the preferential purchase right expired thirty days after receiving an offer, and the Donnans’ lack of action following receipt of the email constituted a waiver of the preferential right.

In Pruett v. River Land Holdings, LLC, the court reversed summary judgment, holding that genuine issues of material fact existed as to whether a lease terminated due to either (1) total cessation of physical production or (2) cessation of production in paying quantities. The lease provided that following its primary term of three years, if “oil, gas, and mineral is not being produced, . . . the lease shall remain in force so long as operations are prosecuted with no cessation of more than sixty (60) consecutive days.” To support its total-cessation-of-production claim, River Land Holdings presented evidence of Texas Railroad Commission records showing that no production on the property had been reported by any operator for more than five years between 2006 and 2012. In response, Pruett asserted that he would routinely pump oil from a handful of wells on the property. River Land Holdings responded that since he was not the operator of record this self-production was irrelevant to the cessation-of-production issue, but the court disagreed. In the alternative, River Land Holdings asserted that the Texas Railroad Commission records established that the lease had terminated due to a failure to produce in paying quantities. However, River Land Holdings did not provide evidence of profitability, nor of any timeframe within which to measure profitability, as required under relevant authorities. Neither did it establish that a reasonably prudent operator would not have continued to operate the wells in the manner in which Pruett was operating them. Thus, the court concluded that summary judgment for River Land Holdings was improper.

In Elmen Holdings, L.L.C. v. Martin Marietta Materials, Inc., the Fifth Circuit assessed whether a sand and gravel mining lease terminated. The lease was between Elmen Holdings, L.L.C., the successor to the original lessor, and Martin Marietta Materials, Inc., the successor to the original lessee. Martin Marietta inadvertently made royalty payments to the incorrect person for a period of time. Based on the court’s interpretation of the lease, the court held that Martin Marietta’s failure to pay royalties to the correct people was appropriate grounds for Elmen to terminate the lease. The court interpreted paragraph two of the lease to create a special limitation on Martin Marietta’s leasehold interest, but when viewed in conjunction with the notice-and-cure provision of paragraph six, the court reasoned that a missed royalty payment would not automatically terminate the lease until Martin Marietta was notified and subsequently failed to cure the payment. The court’s rationale was that because Martin Marietta (1) failed to pay the royalties to the proper party, (2) received adequate notice of non-payment via email from the proper party on the basis of the substantial compliance standard, and (3) still did not cure within ten days of said notice, the sand and gravel mining lease terminated.

XII. West Virginia

B. Legislative Developments

H.B. 5268 amended three sections of the West Virginia Natural Gas Horizontal Well Control Act at §§ 22-6A-4, 22-6A-5, and 22-6A-6 to permit enhanced oil and gas recovery techniques in horizontal wells and horizontal drilling. The amendments to the Act expanded the definition of horizontal drilling and horizontal wells to explicitly include enhanced recovery methods for oil and natural gas using fluid or gas injection as long as those methods are not otherwise prohibited by law. Next, the amendments added new provisions under § 22-6A-5 that expanded regulations to allow both fluids and gas injection, particularly carbon dioxide, for enhanced recovery of both oil and natural gas, while maintaining the existing regulatory framework and permitting processes for these expanded activities. Finally, the amendments added “enhanced recovery” as an aspect of oil and gas operations in West Virginia over which the Secretary of the Department of Environmental Protection exercises exclusive authority.

H.B. 4850 amended § 11-1C-10 of the West Virginia Fair and Equitable Property Valuation statute by removing a sunset provision due to take effect July 1, 2025, thus permitting the use of the current valuation procedure for determining the value of personal property that produces oil, natural gas, and natural gas liquids for use by the West Virginia State Tax Division going forward. Under this formula, the Tax Division appraises the value of property producing oil, natural gas, and natural gas liquids by applying a yield capitalization model that combines both a working interest component and a royalty interest component. The working interest component is based on net proceeds after costs while the royalty interest component reflects the mineral owner’s share of production, with both components adjusted by capitalization and decline rates to account for future value. The current procedure was established during the State’s 2022 Legislative Session through H.B. 4336, which based the oil and gas well tax valuation formula on actual prices from only the prior tax year instead of the weighted three-year average price previously used for assessment.

H.B. 5045 amended multiple sections of the West Virginia Code, all related to the administration of the West Virginia Water Pollution Control Act and Underground Carbon Dioxide Sequestration and Storage statute, to provide assurances to the EPA regarding West Virginia’s application for primary enforcement authority, or primacy, over the federal Class VI injection well program. The EPA opened a 45-day comment period on the proposal after determining, subject to public comment, that the State’s application meets all applicable requirements for approval.

Cross-references between the West Virginia Water Pollution Control Act and Underground Carbon Dioxide Sequestration and Storage statute were inserted to safeguard water resources, and the amendments established more stringent requirements for obtaining a certificate of completion for carbon storage projects. Most notably, the amendments extended the minimum post-injection monitoring period from 10 to 50 years between the end of injections and the issuance of the certificate of completion, though it maintains flexibility by allowing for site-specific timeframes as determined by Department of Environmental Protection rules.

Per the amended Code sections, the requirements for a certificate of completion of injection operations include post-injection site care and closure requirements as well as providing for liability when fluid migration has occurred that causes or threatens water resources.The amendments clarified liability provisions, maintaining operator responsibility in cases where fluid migration threatens underground sources of drinking water. Further, under the amendments, a release from liability does not apply to current or former owners or operators of a storage facility whose liability arises from noncompliance with applicable law, permits, or regulations prior to issuance of the certificate of completion.

C. Judicial Developments

On November 1, 2024, the Supreme Court of Appeals of West Virginia published two interdependent opinions relating to royalty provisions in oil and gas leases. First, in Romeo v. Antero Resources Corp., the court held that when an oil and gas lease expressly or impliedly contains a duty to market, operators must bear the costs associated with the exploration, production, transportation, and sale of the oil and gas to the point of sale. By applying the “point of sale” approach, the court places West Virginia in the minority of oil and gas producing states, which generally apply the “first marketable product rule,” which allows operators to deduct from royalties any postproduction expenses incurred before the oil and gas becomes marketable.

Furthermore, the court in Romeo held that, unless a lease provides otherwise, any royalties payable to the lessor must include not only profits from the lessee’s sale of wet gas and residue gas, but also any profits from the lessee’s sale of any byproducts of the natural gas, including natural gas liquids (NGLs).

Next, the court ruled on Kaess v. BB Land, LLC, determining that when oil and gas leases contain an in-kind royalty provision, there is an implied duty to market the minerals. When a lease grants a lessee the right to drill and extract oil and gas, the royalty payments are “in-kind” and the lessee elects to sell the lessor’s share on their behalf, then the lessee is required pay the lessor a royalty payment equal to the lessor’s share of the gross proceeds. Furthermore, the lessor is not permitted to deduct any postproduction expenses “received at the first point of sale to an unaffiliated third-party purchaser in an arm’s length transaction for the oil or gas so extracted, produced or marketed.”

The Intermediate Court of Appeals of West Virginia (ICA) has also ruled on two cases that carry significant weight for oil and gas jurisprudence in West Virginia. First, in Venable Royalty, Ltd. v. EQT Production Co. the ICA held that unaccrued non-participating royalty interests (NPRIs) are a vested real property interest that converts to a personal property interest upon production. Additionally, the ICA ruled in Nicholson v. Severin POA Group, LLC that when a deed clearly and unambiguously reserves a one-sixteenth oil and gas interest, it is not conveying a one-half interest in oil and gas, despite “the commonly accepted practices and customs used” throughout the industry which understood that a “reservation of one-sixteenth of an oil and gas mineral interest was actually a reservation of one-half of that interest.” The ICA’s rulings are contingent upon any upcoming contrary appellate decisions.

D. Administrative Developments

The legislature enacted rules in section 53-5-1 of the West Virginia Code of State Rules setting forth requirements and administrative procedures for decommissioning of, or deconstruction activities for, coal, oil, or natural gas-fueled power plants.

The Rules, codified in W. Va. Code sections 53-5-3 and 53-5-4, establish requirements that must be met for a facility to be eligible for consideration of decommissioning or deconstruction activities. A petition for decommissioning or deconstruction activities must be accompanied by analysis performed by a third-party evaluator on the social, environmental, and economic “impact[s] the decommissioning or deconstruction activities will have at a local and statewide level . . . .”

Under these Rules, Notices and Petitions must be filed with the West Virginia Public Energy Authority, with copies sent to local authorities and various government agencies. The petition process must include a period for public comment. A party seeking judicial review of the Public Energy Authority’s actions concerning a Petition must follow the process outlined in the State Administrative Procedures Act, codified in W. Va. Code section 53-5-10. The State Administrative Procedures Act requires a party seeking judicial review to file an appeal to the intermediate court of appeals. The Rules went into effect on June 17, 2024, and will remain in force until August 1, 2029.

XIII. Wyoming

A. Legislative Developments

The Wyoming legislature has amended several aspects of the law on carbon sequestration. The law has and continues to allow the Wyoming Oil and Gas Conservation Commission to issue unitization orders. The orders enable the injection of carbon dioxide into pour space below the surface and bounded within the ordered units. Two changes most directly affect traditional oil and gas exploration and production. First, the changes made clear that unitization orders cannot prohibit the owner of a mineral estate from development of its minerals. Second, the legislature expanded the notification requirement for any person who desires a sequestration unitization order. It must now notify those with property interests within a half mile of the proposed pore space.

The legislature also made a substantial change to the Board of Land Commissioners’ authority over state land leases for oil and gas development. The Director of the Board must now review the highest bid offered for an oil and gas lease on state lands to ensure the bidder is “qualified.” The law also requires the Board to define “qualified” by regulation. If the bidder is determined to be unqualified, the bidder is subject to a civil penalty in the amount of the unqualified bidder’s highest bid.

B. Judicial Developments

In Phoenix Capital Group Holdings, LLC v. Woods, the Wyoming Supreme Court addressed whether the phrase “in and under and that may be produced” was sufficient to show that the holder of a life estate retained the right to produce the minerals from its property and the ancillary right to receive royalties from that production. The deed contained a qualification, conveying the right “for the remainder of their life.”

The holder of the life estate had entered into oil and gas lease agreements, but the remainderman of the estate sought to receive the royalties from the lease. The court reiterated the Wyoming rule that a life estate’s right to a mineral interest requires “express deed language that indicates the parties’ intent to defeat the general rule” against waste in which “a life estate owner has no unilateral right to develop minerals and no right to receive royalties.” The court held that an interest “in and under and that may be produced” from a parcel was not enough to defeat the general rule against waste when a life estate qualifies the right. The remainderman of the life estate was then entitled to any royalty payments associated with the mineral interest.

In Chipcore, LLC v. Leadership Circle Energy LLC, the Wyoming Chancery Court concluded that certain terms of an oil and gas contract—“capable of producing,” “equipped for production,” and “production”—were ambiguous. The contract was silent as to their meanings. These terms identified three phases of incurred costs, each of which allocated costs differently. The second phase covered the costs to “drill, complete, and equip wells for production.” The working interest owners (WIOs) were to pay all phase two costs. Phase three included all costs after production commenced, which were to be split between the WIOs and the operator.

The question was whether any production—though not in paying quantities—was enough to initiate phase three and the associated cost sharing. The operator contended that without paying quantities, it was not obligated to pay any costs including those associated with plugging and reclaiming the wells. After concluding that the text alone was ambiguous, the court permitted extrinsic evidence to resolve the matter. However, the movants submitted only unsigned affidavits from non-expert witnesses and Wyoming Oil and Gas Conservation Commission reports. Neither were adequate to remove all doubt as to the meaning of the agreements and the court denied summary judgment.

C. Administrative Developments

The Board of Land Commissioners promulgated rules for 2024 Wyoming Session Law 64, which relates to the Director’s responsibility to ensure the qualifications of a bidder for an oil and gas lease. The Board defined a “qualified bidder” to mean a “person, entity, or agent thereof, engaged in any phase of exploration for, or production of Oil and Gas as a primary component of their business.”

In In the Matter of the Appeal of Pacificorp, the State Board of Equalization overturned a 2023 determination of the Department of Revenue, finding that electricity used to power horizontal, submersible pumps fit the meaning of “the transportation business” for purposes of taxation under Wyo. Stat. Ann. § 39-15-105(a)(iii)(E). This order follows a 2023 Board order, which had already interpreted § 39-15-105(a)(iii)(E) to include such use. The Department subsequently disregarded the 2023 interpretation and denied the refund associated with this use of electricity.

Wyoming law imposes a sales tax on “the sales price paid for all services and tangible personal property used in rendering services to real or tangible personal property within an oil or gas well site.” The Board considered electricity to be personal property. Property is, however, exempt from this tax when it is involved in the “[s]ales of power or fuel to a person engaged in the transportation business.”

The Board looked to the Wyoming Supreme Court’s definition of “engaged in a trade of business” to interpret § 39-15-105(a)(iii)(E). The phrase requires only that 1) “the taxpayer must be involved in the activity with continuity and regularity;” and 2) “the taxpayer’s primary purpose for engaging in the activity must be for income or profit.” The Board concluded that the petitioner’s use of the electricity met these two requirements. The Board denied the Department’s attempt to add a third requirement—that “the transportation business must be an entity’s ‘predominant activity”—as unsupported by the plain statutory language and ordered the Department to issue the refund.

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