Skip to content
Traditional Energy News

Our Commentary on Recent Traditional Energy News

  • One Man’s Trash is Another Man’s Treasure: Ownership of Produced Water in Texas
    February 7, 2024

    Introduction

    With the rise of battery technologies in electric vehicles, electronics, utility-scale electrical energy storage and other industrial applications, there has been increased demand for lithium, cobalt, and other minerals. In response to the increased demand, sources of such minerals that have previously gone unutilized have attracted increased interest. Most notably, produced water from oil and gas wells, previously viewed as a waste product, is now attracting interest for the lithium, cobalt and other minerals contained therein.

    Given that this is a new area of production, the law surrounding the ownership of produced water remains relatively unsettled — and where there is potential money on the table, actual litigation surely follows. On July 28, 2023, in the case Cactus Water Services, LLC v. COG Operating, LLC,1 the Texas Court of Appeals in El Paso addressed the ownership of produced water. In the Cactus Water case, a majority of the court determined that the mineral interest owners had superior rights to the produced water in dispute. The dissent favored the rights of the surface owners and the case has since been appealed to the Texas Supreme Court.

    In this alert, we discuss the Cactus Water case and the legal implications of lithium extraction from produced water.

    Cactus Water Case

    COG Operating, LLC (“COG”) was the lessee of a property in west Texas. Their leases on the applicable property (the “COG Leases”) involved a grant of “oil, gas and other hydrocarbons” and similar variants. Under the COG Leases and other agreements, the landowner granted rights-of-way and easements to COG so it could transport such produced wastewater off the land. Further, COG handled and paid for the transportation and disposal of the produced water from their operations for years without landowner comment. However, under the COG Leases, COG expressly did not have the right to “use water which is on or under the described land, except it may itself drill a water well and then use the water from that well in its conduct of drilling operations that are conducted on land covered by [the lease.]”

    Several years after the landowner leased their interests to COG, the landowner also leased their interest in their water estate to Cactus Water Services, LLC (“Cactus”), including the rights to sell all water “produced from oil and gas wells and formations [on the covered properties.]”

    COG and Cactus filed declaratory suit against one another to find out who held the rights to the produced wastewater from the land (as well as the substances contained therein).

    The trial court found for COG and the appellate court in this case affirmed, primarily falling back on statutory interpretation, regulatory understanding and industry practice. In their decision, the appellate court held that produced wastewater is not groundwater (which is part of the surface estate), but instead is “oil and gas waste,” which typically under oil and gas leases belongs to and is the obligation of the mineral interest operator. As a result, produced water is within the mineral lessee’s grant of “oil, gas and other hydrocarbons” and the mineral interest lessor had the exclusive right to the produced water under its leases. The court held this (1) even though the COG Leases specified a grant of “oil, gas and other hydrocarbons” rather than the formulation of “oil, gas and minerals”; and (2) despite the limitation on COG’s use of water on the land.

    Note that this case does not expressly address lithium and that, for leases executed after June 8, 1983, the determination of “mineral” under Texas law is done on a mineral-by-mineral basis under the “ordinary and natural meaning” test (in the absence of lease language specifying one way or another). However, pending further activity on this item, it would be reasonable to assume that this case lends support to the idea that lithium contained in produced wastewater from oil and gas operations would also belong to the oil and gas operator in the absence of lease language to the contrary.

    The dissent in this case took a different view of produced water ownership. The dissent noted that “water” and “oil and gas waste” were not expressly granted under the leases, and that, without express granting language conveying the surface estate’s water rights, Texas law provides that such water remains part of the surface estate. As a result, water would not be impliedly conveyed in the grant of “oil and gas.”

    Many commentators expect that ultimately this issue will be determined by the Texas Supreme Court. An appeal has been filed to the Texas Supreme Court as of the writing of this article.

    • Considerations Relating to Lithium Extraction in Produced Water

    Below are several matters for an oil and gas operator to consider in connection with the development of lithium and other minerals from produced water in connection with its oil and gas operations:

    • Granting Language
      • Regardless of the outcome of the Cactus Water case, the best practice is to explicitly state lithium, cobalt, brine, etc. in the granting language of a lease or severing instrument, and to avoid such minerals being part of the reservation language in a lease or severing instrument.
      • In some cases, depending on the lease-granting language, the rights to lithium and other minerals are more likely to be part of the mineral estate if they are produced in connection with the same operations that are being undertaken to extract oil and gas. However, if an operator were to seek to extract lithium and other minerals as part of operations that do not involve the extraction of oil and gas, then some lease language would provide that such lithium and minerals are not included as part of the lease grant. As a result, it will be important to further consider the lease-granting language if lithium and mineral production will occur separately from oil and gas operations.
    • Joint Operating Agreements — Oil and gas production is often subject to joint operating agreements (“JOAs”). An oil and gas operator should consider if the cost and revenue sharing terms under JOAs will apply to lithium and other non-oil and gas mineral extraction, including as to the development of lithium extraction facilities separate from oil and gas production and gathering facilities.
    • Produced Water Treatment and Disposal Agreements — Often produced water treatment and disposal agreements contain clauses that grant all right, title and interest in the produced water (including all minerals contained therein) to the party disposing of and treating the water. An oil and gas operator should consider the terms of these agreements and title transfer provisions.
    • Royalty Considerations — To what extent does the royalty language in the applicable lease apply to lithium extraction from produced water? Often royalty amounts are different depending on whether the royalty item is a “liquid” or a “mineral.” Given that lithium is contained in the saltwater brine of produced water, it is unclear which applies. Further, given lithium extraction from produced water requires processing, it is unclear where in the production chain the value of the lithium is determined and how the allocation of processing costs are determined. There may be some additional disputes in this area as lithium extraction operations increase.
    • Tax Considerations — The Internal Revenue Code and other federal income tax authorities contain a robust set of tax rules relating to both (i) oil and gas drilling, development, and production activities, and (ii) non-oil and gas mineral exploration, development, and operating activities. However, many of the statutory, administrative, and judicial authorities that apply to the oil and gas industry are separate and distinct from those that apply to activities involving non-oil and gas minerals, and those rules were not developed with produced water lithium extraction in mind. As a result, it will be important for taxpayers engaging in both oil and gas operations and produced water lithium extraction to work closely with their tax advisors to determine how to properly allocate and report overlapping exploration, development, and operating activities.

    Conclusion

    Given the significance of the interests, the Texas Supreme Court will likely consider the Cactus Water case or a similar case shortly and provide further clarification as to the law on its ownership. Regardless of its decision on the ownership matter, a slew of further legal questions are likely to ensue and surface owners and producers alike should keep a keen eye on legal developments in this area.

    1 Cactus Water Services., LLC v. COG Operating, LLC, 676 S.W.3d 733 (Tex. App.—El Paso July 28, 2023, pet. filed) [hereinafter “Cactus Water”].

  • Railroad Commission Proposes Overhaul of Waste Management Rules
    October 11, 2023

    On October 2, 2023, the Railroad Commission of Texas (“Commission”) announced proposed changes (“Proposed Rule”) to its rules regulating the management of oil and gas waste. Many oil and gas exploration and production wastes are exempt from federal regulation as hazardous wastes, and are instead regulated federally as non-hazardous waste and subject to extensive state regulation — in Texas, this is Statewide Rule 8. The Proposed Rule represents the first major revisions to Statewide Rule 8 in over 40 years.

    In its statement on the Proposed Rule, the Commission noted that the protection of groundwater was a key consideration in crafting the Proposed Rule. The Proposed Rule introduces a number of changes intended to reflect modern waste management practices and recent advancements in oil and natural gas production methods, such as hydraulic fracturing. Many of these changes were already reflected in the Commission’s guidance documents, which have been used for years in connection with the issuance of permits for waste pits and landfarming. Under the Proposed Rule, standards for design, construction, operation, monitoring, and closure of authorized, permitted, and commercial waste pits and landfarming would be codified, reorganized, and moved to new Chapter 4, Subchapter A. The proposal would also include codification of guidance and revisions to the rules relating to the transportation of oil and gas waste, including characterization, documentation, and recordkeeping in new Chapter 4, Subchapter B.

    In addition to providing a much-needed codification of existing guidance that will provide clarity to the regulated community, the Proposed rule also implements recently passed state legislation regarding the location of disposal pits (H.B. 2201, 87th Leg.), beneficial recycling of fluid oil and gas waste (H.B. 3516, 87th Leg.), and the treatment, recycling for beneficial use, and disposal of drill cuttings (S.B. 502, 88th Leg.; S.B. 1531, 85th Leg.).

    The Commission is accepting public comments on the Proposed Rule until Friday, November 3, 2023.

    Key substantive changes in the Proposed Rule include:

    1. Pit Liner Standards: Current regulations allow clay or natural liners for pits as long as the liner meets certain thickness and permeability standards. The Proposed Rule would change these standards and allow natural liners only for pits with an active life of less than one year; any pit with an active life of more than one year or that is used for waste disposal must have a synthetic liner with an impermeable geomembrane. See Proposed 16 T.A.C. § 4.114(c).
    2. Pit Location Restrictions: Under the Proposed Rule, pits may not be located on a barrier island or a beach or within 300 feet of surface water, 500 feet of any public water system well or intake, 300 feet of domestic or irrigation water wells, or within a 100-year floodplain. Proposed 16 T.A.C. § 4.114(b); 4.150(g). Commercial disposal pits are further restricted and must be sufficiently isolated to prevent surface or subsurface water pollution and the applicant must conduct a flooding history investigation of the proposed site to ensure that the facility is not located in a flood-prone area. Proposed 16 T.A.C. § 4.153(a). These updated location restrictions implement the Texas Legislature’s H.B. 2201.
    3. Reclamation Plant Permits: In addition to significant substantive revisions to Statewide Rule 8, the Proposed Rule would also modify certain permit requirements for reclamation plants under Statewide Rule 57. Currently, reclamation plant permits do not expire and cannot be transferred to another operator after issuance. Under the Proposed Rule, reclamation plant permits would have set terms of five years, after which they must be renewed. The Proposed Rule would also allow reclamation plant permits to be transferred to another operator, so long as certain timing, financial security, and real estate requirements are met. See Proposed 16 T.A.C. § 4.122.
    4. Pilot Program for Recycling Activities: The Proposed Rule encourages recycling of oil and gas waste by adding provisions whereby an operator may propose a pilot program to assess the safe use, efficiency, and effectiveness of using a recycled product in certain activities. If the Commission finds that the pilot program does not present a threat of pollution and encourages the recycling of oil and gas waste, then the pilot program may be authorized for one year and, if successful, may be continued via permitting under the Commission’s regulations. Proposed 16 T.A.C. § 4.185. For example, recycling of treated produced water could be subject to a pilot program under these provisions. These provisions implement the Texas Legislature’s instruction to encourage fluid oil and gas waste recycling in H.B. 3516.
    5. Encouragement of Commercial Fluid Recycling: To further effectuate H.B. 3516, the Proposed Rule includes provisions to expedite permitting of off-lease and stationary commercial fluid recycling. These provisions include a 90-day deadline for the Commission to act on a complete permit application. If the Commission fails to act on a permit before the 90-day deadline passes, then the application is presumed approved and the applicant may operate under it for one year. See 16 T.A.C. §§ 4.262, 4.278.
    6. Beneficial Use of Drill Cuttings: The Proposed Rule implements S.B. 1541’s requirements that the Commission adopt criteria for permitting and beneficial reuse of drill cuttings that that is as protective of public health as requirements for disposal of drill cuttings. It also implements H.B. 502’s requirements by clarifying that the tort liability shield for treatment, recycling, and disposal of waste drill cuttings extends to associated waste streams like sands, drilling fluids, and other materials cleaned out of the wellbore that compose the same waste stream as the cuttings. See 16 T.A.C. § 4.301.

    If the Proposed Rule is promulgated, any existing pits that are compliant with current Statewide Rule 8, but not the Proposed Rule, must be brought into compliance or closed. While the Proposed Rule does not include a timeline for permitted or commercial pits, existing authorized pits must be registered or closed within one year.

    Follow our Shale and Fracking tracker for further information as we cover the overhaul of Statewide Rule 8 and other unconventional oil, gas, and energy-related developments.

  • California Suspends Senate Bill 1137 Pending Referendum Vote
    February 9, 2023
    California

    On February 3, 2023, the California Secretary of State certified a referendum challenging Senate Bill 1137 (“SB 1137”), which institutes a 3,200-foot setback for new oil and gas operations and includes new requirements for operators of existing oil and gas production facilities. SB 1137 took effect on January 1, 2023, and the California Geologic Energy Management Division’s (“CalGEM”) regulations implementing the law (“Implementation Regulations”) went into effect on January 6, 2023. The certification, by operation of law, suspends SB 1137’s provisions and CalGEM’s associated regulations pending the results of the referendum vote during the 2024 general election.

    CalGEM notified operators of the suspension on the same day the suspension was certified. Per CalGEM’s notification, operators who have received notices of intention to commence drilling (“NOIs”), or who have pending NOI applications before CalGEM, no longer need to take the additional actions required to comply with the provisions of SB 1137 or CalGEM’s Implementation Regulations.

    SB 1137 and the Referendum

    SB 1137’s setback provision prohibits CalGEM from approving NOIs within health protection zones, except in a handful of specified circumstances. “Health protection zones” are defined as areas within 3,200 feet of a “sensitive receptor,” meaning residences, education resources (e.g., schools, daycare centers, parks), community resources (e.g., youth centers), health care facilities, dormitories, or any building open to the public. SB 1137 also requires operators submitting NOIs to submit a sensitive receptor inventory and map for the area within a 3,200-foot radius of the proposed wellhead location. The law would also impose more stringent obligations on operators over the course of the coming years, including new water quality sampling requirements, additional annual reporting, and implementation of leak detection and response (“LDAR”) plans.

    The referendum to reverse SB 1137 was organized by the California Independent Petroleum Association in October 2022. After receiving the necessary signatures, the referendum was certified on February 3, 2023, and will be placed on the November 5, 2024, general election ballot.

    Effect of the Suspension

    The certification has suspended both the statutory provisions established by SB 1137 and CalGEM’s Implementation Regulations, pending resolution of the referendum. As explained by CalGEM, the suspension has several implications for operators:

    • Previously Approved NOIs: For NOIs approved prior to February 3, 2023, operators will not need to take additional action in connection with the NOI in order to comply with the provisions of SB 1137.
    • NOIs Pending Review by CalGEM: NOIs submitted to CalGEM that have not yet received approval are no longer subject to the requirements of SB 1137. CalGEM will continue its review without requiring compliance with SB 1137. For NOIs that were returned for operators to update with additional information to evaluate for compliance with SB 1137, those NOIs may be resubmitted for review without the need for the additional information.
    • Operators Constructing or Operating New Production Facilities: A Notice of New Production Facility is no longer required before constructing or operating a new production facility.

    Follow our Shale and Fracking tracker for further information as we monitor developments related to SB 1137.

  • Los Angeles City Council Votes Unanimously to Ban Oil and Gas Extraction
    December 9, 2022
    California

    On Friday, December 2, 2022, the Los Angeles City Council voted unanimously to ban all oil and gas drilling within the city and to phase out existing extraction over the next 20 years.

    The Ordinance

    The ordinance approved by the City Council amends the municipal (zoning) code to prohibit new oil and gas extraction within the city and to make all existing extraction activities a nonconforming use, regardless of the zone. The nonconforming use designation enables the city to force producers to wind down their existing operations over a period of 20 years. The city has also been studying the economics of the oil and gas properties within its jurisdiction. When completed, the studies may be used to shorten the wind down period if the city can demonstrate that the property owners have adequately recouped their investments in the now-nonconforming use.

    In addition to the prohibition on new wells and forced wind down, the city has bolstered its rules regarding when a well is deemed to have been abandoned, which triggers an operator’s well plugging and abandonment obligations. For example, if a well is idle for more than six months, the nonconforming use designation expires and the well is no longer permitted to operate.

    The Effect

    The City reported 5,273 total wells within the city limits in August 2022, with 641 of those still active and another 1,350 idle. There was little doubt that the ordinance would pass when we first covered, in January 2022, the City Council’s decision to have the Planning Department draft the ordinance. Although the short term effect will be a cessation of permitting and new drilling, sizable oil and gas interests will still be in play for many years to come.

  • Los Angeles City Council Moves to Ban New Oil and Gas Drilling
    January 31, 2022
    California

    On Wednesday, January 26, 2022, the Los Angeles City Council took a significant step towards banning new oil and gas extraction in Los Angeles, and phasing out production from existing wells. By unanimously voting to adopt a series of recommendations contained in a Budget and Finance Committee Report, the City Council has initiated a process that will likely culminate in the decommissioning of over 5,200 wells.

    Ordinance Banning New Oil and Gas Extraction

    The City Council instructed the Los Angeles Department of City Planning to prepare and present an ordinance prohibiting all new oil and gas extraction within the city limits (new oil and gas wells were banned in surrounding unincorporated areas in 2021). Furthermore, the ordinance will make extraction activities a nonconforming use in all areas of the city.

    While there is little doubt that the ordinance will pass, another City Council vote will be necessary before the ban is formally adopted.

    Phasing Out Existing Wells

    While stopping short of an outright moratorium on current oil and gas extraction, the City Council adopted several measures that initiate the process of phasing out existing wells. First, the City Council commissioned an amortization study to determine how oil and gas companies can recoup their investments in existing well infrastructure, a prerequisite to decommissioning oil and gas operations.

    Second, the Los Angeles Office of Petroleum and Natural Gas Administration and Safety was instructed to develop a new city policy to ensure that wells are properly plugged and abandoned. The new policy will also require site remediation to be completed within 3 to 5 years of the cessation of active oil production, with the intention of ensuring oil companies bear the full responsibility for abandonment and remediation.

    Los Angeles currently supports a substantial amount of oil and gas extraction within its city limits, with around 5,229 known wells, 704 of which are considered active. Interested parties should stay alert for updates on whether and when these preliminary measures mature into a permanent ban by the City Council.

  • Colorado Promulgates Groundbreaking Rules to Curb Methane Emissions
    December 21, 2021
    Colorado

    On Friday, December 17, 2021, the members of the Colorado Air Quality Control Commission (AQCC) voted unanimously to adopt a set of regulations aimed at curbing methane emissions from oil and gas operations. These ambitious regulations are supposedly designed to help Colorado meet its statewide greenhouse gas emissions targets. Notably, the new methane rules give industry some flexibility in how to reduce methane emissions while strengthening the state’s mandatory inspection and repair program. Highlights include:

    • Aggressive intensity program with some flexibility for industry. The AQCC will set methane emissions limits per 1,000 barrels of oil equivalent produced, but the target limits will be based on the size and impact (“intensity”) of production. In other words, larger wells, new wells, and wells operating near “overburdened communities” will have to comply with stricter emissions reduction targets. That being said, operators will create their own “intensity plans” to specify how they will meet their targets, meaning that the operators get to choose where their reductions in methane emissions will come from.
    • More frequent inspections. Larger sites – wells producing more than 20 tons of oil equivalent a year – must conduct monthly inspections and report the resulting instrument monitoring data to the Colorado Air Pollution Control Division. Sites near environmental justice communities and sites within 1,000 feet of occupied areas have similar obligations, with the frequency of the inspections varying based on the size of the well.
    • Limits on emissions during maintenance. Under the final rules, both wells and pipelines will be subject to greater controls on methane emissions during maintenance, including a prohibition on venting during certain maintenance activities.

    Oil and gas producers in Colorado should prepare for the increased costs of inspection and start planning on how to comply with the new intensity program. Companies should also stay tuned for more updates as the Environmental Protection Agency is expected to move forward with its proposed rulemaking at the federal level to reduce methane emissions and air pollution nationwide.

  • California Publishes Draft Rule Imposing Well Setbacks
    October 25, 2021

    On October 21, 2021, the California Geologic Energy Management Division (“CalGEM”) published its long-awaited Draft Rule for Protection of Communities and Workers from Health and Safety Impacts from Oil and Gas Production Operations (“Draft Rule”). The Draft Rule includes numerous requirements for new and existing oil and gas facilities, the most notable being establishment of a setback exclusion and mitigation area (“Setback Area”) of 3,200 feet from “sensitive receptors” consisting of man-made structures, such as homes, residential complexes or housing facilities, schools and daycare centers, businesses open to the public, healthcare facilities, and prisons. New production facilities would be prohibited in the Setback Area and existing production facilities in the Setback Area would be subject to new and more stringent requirements.

    “Production facilities” to which the Draft Rule applies include “any equipment attendant to oil and gas production or injection operations including, but not limited to, tanks, flowlines, headers, gathering lines, wellheads, heater treaters, pumps, valves, compressors, injection equipment, production safety systems, separators, manifolds, and pipelines that are not under the jurisdiction of the State Fire Marshal.”

    Similar, but less stringent proposals that would have instituted a 2,500-foot setback have historically failed to pass the California Legislature when they were proposed in 2019 and early 2021. The Draft Rule comes in response to Governor Newsom’s 2019 oil and gas initiatives, which included a call for CalGEM to update and strengthen its rules for public health and safety protections near oil and gas production facilities. CalGEM was originally expected to conduct pre-rulemaking in 2020 and issue its draft rule by December 31, 2020.

    The Draft Rule includes several exceptions to its prohibition on new production facilities in the Setback Area:

    • intercept or pressure relief wells that must be drilled to alleviate an immediate threat to public health and safety or the environment;
    • production facilities that are necessary for safe and effective operation of a well approved by CalGEM;
    • production facilities that are necessary for compliance with local, state, or federal requirements;
    • production facilities that are necessary to public health and safety or the environment; and
    • production facilities that are replacing an existing facility of the same type with no resulting expansion of the geographic footprint.

    New production facilities are also subject to additional notice requirements for surrounding landowners and tenants, baseline water sampling and testing, and tank construction and leak detection requirements.

    The Draft Rule would also impose new and more stringent requirements on existing production facilities in the Setback Area, regardless of whether such facilities pre-dated the establishment of the sensitive receptors. These requirements include: leak detection systems and response plans; vapor venting prevention systems; sound, lighting, and dust controls; produced water sampling and analysis; non-emergency spill reporting; secondary containment for wellheads prior to drilling, workover, or abandonment; additional pipeline repair and recordkeeping; daily maintenance inspections, additional cementing and casing reporting and recordkeeping; and restrictions on use of oil-based drilling muds.

    Under the Draft Rule, all production facilities, new or existing, will be subject to new or more stringent requirements regarding secondary containment of processing fluid storage, tank testing and wall thickness, shut down and removal of out-of-service facilities, and lease restoration and abandonment.

    The public comment period on the Draft Rule ends on December 21, 2021. In addition to written comments submitted by email, CalGEM will accept oral comments during its public workshop on December 1, 2021.

  • RRC Requests Voluntary Reduction of SWD Injection Activity in West Texas
    October 1, 2021

    On September 23, 2021, the Texas Railroad Commission (“RRC”) issued letters to multiple operators requesting voluntary operational curtailment and data collection to saltwater disposal (“SWD”) well operators in the Gardendale Seismic Response Area (“SRA”). The Gardendale SRA covers areas of northeast Ector County to southwest Martin County, between Odessa and Midland, and has 76 permitted SWD wells.

    The letters were issued in response to a series of earthquakes that have occurred in the Gardendale SRA since February 2020, including six felt earthquakes with magnitude of 3.5 or greater. In these letters, the RRC asserts that SWD well injection is “likely contributing” to seismic activity in the region. In addition to the requested reduction for existing in-use wells, RRC has asked that existing permitted wells that have not yet been completed, commenced operations, or that are currently out of service to refrain from any injection activities. The letters further state that the RRC will no longer be administratively approving new permits for SWD wells in this SRA.

    The requested operator actions are:

    1. Reduce the permitted maximum daily injection rate to 10,000 barrels per day per well.
    2. Measure daily injection volume, average pressure, and maximum pressure, and report this information to RRC monthly.
    3. Submit historical daily injection volume and pressures to RRC from November 1, 2019.
    4. For SWD wells that are not currently in service, do not begin or return to fluid injection.

    The letters request notification from operators on whether they intend to comply with these actions within 30 days of receipt, and if they have chosen to comply, requires compliance within 90 days. While compliance with the request is voluntary, the letters state that the RRC may take action with respect to the injection permits held by operators that do not agree to comply or do not provide a response, including modification, suspension, or termination of the the permit. If the RRC takes such actions on a permit, under 16 Texas Admin. Code §3.9 and 3.46, the operator may request a hearing to review.

    The letters state that these changes will remain in effect “until further notice,” but estimate that the request for curtailment will last at least 9-12 months. The RRC asserts that it will continue to monitor seismic activity in the area and may communicate with affected operators in the future, either individually or as a group.

    Our Shale and Fracking practice group is monitoring developments related to seismic activity and continues to advise clients on navigating notices and other requests from regulators.

  • Judge Blocks Moratorium on New Federal Oil and Gas Leases
    June 17, 2021

    On June 16, 2021, the U.S. District Court for the Western District of Louisiana (“Court”) granted a preliminary injunction halting the Biden Administration’s moratorium (or “pause”) on new oil and gas leasing on Federal public lands and offshore waters. The decision will allow leasing to restart on Federal public lands and offshore waters nationwide and continue until the Court rules on the substance of the case or until the Court or an appeals court issues additional orders.

    The Moratorium on Federal Oil and Gas Leasing

    Earlier this year, President Biden issued an executive order directing the Secretary of the Department of the Interior (“DOI”) to pause new oil and natural gas leases on federal public lands or offshore waters to the extent consistent with applicable law, until the completion of a comprehensive review and reconsideration of Federal oil and gas permitting and leasing practices, and to identify steps that can be taken to double renewable energy production from offshore wind by 2030. The Secretary immediately issued the suspension order, which put an indefinite moratorium on new leases on federal public land and offshore waters. The suspension order did not impact existing leases in federal public land and offshore water, leases on state land, leases on private land, or leases on Indian lands or lands held in trust for Tribes.

    Legal Challenges to the Moratorium

    DOI’s suspension order was immediately challenged by several states and industry groups claiming that the DOI had exceeded its authority by indefinitely pausing lease sales on eligible land. The instant case was brought by the States of Alabama, Alaska, Arkansas, Georgia, Louisiana, Mississippi, Missouri, Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia. These states asked the Court to enjoin, or stop, the pause on new leasing while the Court further considers whether the pause is lawful.

    The Court determined that the states had met their burden in showing that the pause on new leasing should be immediately stopped nationwide.  Specifically, the Court determined that the states were likely to succeed in their claims, showed that they would be “irreparably harmed” by loss of revenues linked to the sales, and that it was in the public interest to resume the lease sales.  This strongly signals that the Court will ultimately put a permanent stop to the moratorium as the litigation progresses.  That decision, however, will still be subject to further review by appellate courts.

    The decision focuses on the fact that neither the President nor DOI have the discretion under the Mineral Leasing Act (“MLA”) or Outer Continental Shelf Lands Act (“OCSLA”) to decide whether to offer areas for oil and gas development because both the MLA and OCSLA set forth requirements to hold lease sales of eligible land and requirements for how those sales should be conducted. DOI is required to designate land that will be available for development, but the opinion underscores that, once areas are designated, DOI does not have the power to pause the ongoing program unless the land has become ineligible or some other legal deficiency is present. The Court stated that an executive order is not sufficient reason under the statutes, as the executive order gave no reason for the pause other than a “pretextual” need for further environmental analysis. The decision did not address the Biden Administration’s argument that the moratorium was due to violations of the National Environmental Policy Act. While the government defendants argued to the Court that there has not been an actual moratorium on new leasing, the Court noted that there has not been a single new lease sale since the executive order was issued. The Court pointed out that a number of lease sales have been postponed, and DOI has either provided no reason for the delay, or gave reasons that the states described as “pre-textual.”

    The decision also notes DOI’s failure to provide notice and comment on the moratorium as further indication of likelihood of success on the merits, as the moratorium is a substantive rule and the Administrative Procedure Act requires notice and comment for all substantive rules.

    Finally, the Court found that there was a risk of substantial monetary losses from the leasing pause and that the balance of equities was in the plaintiffs’ favor, as an injunction would not harm the public interest. Therefore, it granted the preliminary injunction.

    What Comes Next?

    Leasing on Federal public lands and offshore waters may immediately restart nationwide. The Biden Administration may choose to appeal the preliminary injunction to the Fifth Circuit and request a stay of the Court’s order pending appeal.

    As directed in President Biden’s initial executive order, DOI is currently preparing an interim report that includes a comprehensive review of Federal oil and gas permitting and leasing practices. The interim report is expected to be published in the coming weeks.

    Stay tuned to our fracking tracker for any updates to the status of oil and gas leasing on federal lands.

  • Biden Administration to Suspend Future Oil Leases in Arctic Refuge
    June 3, 2021

    On June 1, 2021, the U.S. Department of the Interior (“DOI”) issued Secretarial Order 3401 (“Order”), temporarily suspending all activities related to the Coastal Plain Oil and Gas Leasing Program (“Program”) in the Arctic National Wildlife Refuge pending completion of a comprehensive environmental analysis under the National Environmental Policy Act (“NEPA”). This Order follows through on President Biden’s day-one Executive Order on environmental and climate change issues, which ordered a review of all oil and gas activity in the Arctic Refuge.

    The Program was established by DOI’s Bureau of Land Management (“BLM”) in 2019 during the Trump administration. BLM Prepared an environmental impact statement for the Program under NEPA and held its first lease sale under the program on January 6, 2021. The lease sale resulted in issuance of multiple ten-year leases that cover more than 430,000 acres in the Arctic Refuge. These leases were signed and finalized on January 19, 2021, President Trump’s last full day in office. President Biden’s Executive Order calling for a review of all oil and gas activity in the Arctic Refuge was issued the next day.

    In the Order, DOI Secretary Deb Haaland states that her review of the Program identified multiple legal deficiencies in the Program’s NEPA analysis and Record of Decision, including failure to adequately analyze a reasonable range of alternatives. Sec. Haaland ordered DOI to temporarily halt all department activities, including leasing, exploration, development, production, transportation, and processing of any pending or future applications for such activities, related to the Program and conduct a new environmental analysis. It is important to note that the Order only suspends new leasing and has no impact on existing leases in the Arctic Refuge.

    The Order is effective immediately and gives DOI 60 days to publish its notice of intent to initiate its NEPA review of the Program. The review process will include a comprehensive environmental analysis of the potential impacts of the Program, consultation with other federal agencies, and a public notice and comment period on DOI’s draft environmental analysis. Environmental reviews under NEPA can easily extend for many months, and unless a court imposes a deadline, there is no limit to the amount of time DOI can spend on the analysis. As a result, we cannot predict how long the suspension will last.