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On June 27, 2025, the Texas Supreme Court issued yet another landmark decision: Cactus Water Services, LLC v. COG Operating, LLC. Justice Devine delivered the opinion of the Court, holding that produced water is oil-and-gas waste, and, therefore, it belongs to the hydrocarbon lessee (i.e., the operator who is legally obligated to dispose of waste). Justice Busby filed a concurring opinion, in which Justice Lehrmann and Justice Sullivan joined, outlining what the Court’s holding did not say and what issues related to ownership of produced water remain unresolved.

Oil and gas production in areas of Texas containing dense shale formation with poor permeability necessitates hydraulic fracturing—or “fracing”—to extract minerals. Fracing involves the injection of pressurized fluid (the most common being water), proppants (such as sand, ceramic beads, or bauxite), and chemicals into the formation to fracture the rock and release the trapped hydrocarbons through the wellbore. The majority of the injected fluid remains underground, but about 15 to 20% of it returns to the surface and is called “flowback,” bringing with it a mix of hydrocarbons, brine, and other substances. Oil and gas can be separated from this mix, and the remaining brackish mixture of drilling, fracing, and formation fluids is known as produced water. Hydrocarbons cannot be produced in these areas of Texas without simultaneously producing produced water, and vice versa. As such, operators have historically, and are, legally obligated to handle and dispose of produced water—which is hazardous to human health—and if operators fail to do so, they are subject to penalties and other liabilities. Given this background, produced water historically has been considered a costly byproduct of oil-and-gas production, and it has been treated as oil-and-gas waste, with the burden of handling and disposal being placed on the operator. In recent years however, technical advancements offering the potential for recycling and reuse of this product, water scarcity, and lithium extraction, among other things, have resulted in produced water being viewed as having increased utility.

The dispute raised in Cactus Water Services, LLC v. COG Operating, LLC is a “first-of-its-kind” dispute, pitting an oil and gas lessee/operator of producing wells (COG) against a surface-estate lessee asserting claims to the produced water collected at or near the wellhead (Cactus). On one hand, COG argued that conveyance of the right to produce oil and gas (by lease or deed) necessarily includes the liquid-waste byproducts entrained with hydrocarbons absent an express reservation or exception. On the other hand, Cactus argued that once the hydrocarbons have been separated after production at the well, the remaining mixture, which is neither oil nor gas, is considered water owned by the surface estate absent an express conveyance of water rights. Ultimately, the lower courts and the Texas Supreme Court found COG’s argument more persuasive.

Between 2005 and 2014, COG acquired four hydrocarbon leases covering approximately 37,000 acres in Reeves County, Texas. COG’s leases granted it the exclusive right to explore for, produce, and keep “oil and gas” or “oil, gas, and other hydrocarbons”—note, not “other minerals.” The leases were silent about ownership of waste byproducts. Regarding water, three of the leases expressly prohibited the use of water except in limited circumstances, and the fourth lease was silent about water use. The leased acreage was concentrated in the Delaware Basin—a dense formation underlying the Permian Basin that is characterized by low permeability. As such, fracing was the principal method of production employed there by COG. At the surface, COG separated the oil and gas, leaving produced water. 

Between 2013 and 2016, to facilitate waste handling, COG entered into a surface use-compensation agreement and multiple right-of-way agreements with the landowner for three of the leases. These agreements allowed COG to construct tank battery sites to gather, separate, and store the produced water. Disposing of produced water was costly. COG drilled 72 horizontal oil wells that had generated nearly 52 million barrels of produced water. COG disposed of the produced water independently and through third parties. Between December 2018 and March 2021, COG paid roughly $21 million in disposal fees to a third-party contractor—these disposal expenses were borne exclusively by COG. While disposal was expensive, treating and recycling of produced water was much more costly. Therefore, COG did not reuse produced water. If COG failed to timely dispose of the produced water offsite, it would have been required to cease its production efforts.

In 2019 and 2020, the surface owners and Cactus executed produced water lease agreements (“PWLAs”). The PWLAs purportedly conveyed all right, title, and interest in and to the produced water on the lands covered by COG’s leases. The PWLAs expressly excluded water unrelated to oil-and-gas production. In March 2020, Cactus, which did not possess permits, infrastructure, or the ability to handle, transport, or dispose of produced water, informed COG of its claimed rights under PWLAs and stated that it was entitled to produced water from COG’s wells. COG then sued for declaratory relief, seeking a judgment declaring that COG, not Cactus, owned and had the exclusive right to the produced water from COG’s wells. Cactus responded by seeking a judgment declaring that it alone owned and had the exclusive right to the produced water from COG’s wells. Both parties moved for summary judgment on their declaratory judgment claims. These claims centered on whether COG’s claimed rights were “baked into” the express conveyance of oil-and-gas rights (by deed or lease) or whether produced water was part of the surface estate as no water rights were expressly and separately conveyed to COG. The trial court ruled in COG’s favor. Cactus appealed, and the court of appeals affirmed, holding that produced water constitutes oil-and-gas waste belonging to the mineral lessee, not groundwater belonging to the surface estate. The Texas Supreme Court granted Cactus’s petition for review.

Beginning with an overview of the historical and regulatory practices that task the operator with the handling and disposal of waste, Justice Devine, writing for the Court, stated that “produced water is not water,” explaining that “[w]ater is something that must be protected from oil-and-gas waste; the two are not interchangeable.” The Court reasoned that if Cactus’s argument—that produced water is water—were to be deemed correct, the leases’ express water-use constraints would functionally prevent the production of oil and gas and thus frustrate, not facilitate, the purpose of the lease. Further, the authorities Cactus relied on involved ground water, not produced water. Finding all of Cactus’s arguments and authorities unpersuasive, the Court held that deeds or leases that use the “typical language” to convey oil-and-gas rights, even when they do not expressly address produced water, include produced water as part of the conveyance. If a surface owner seeks to retain ownership of produced water, it may include an express reservation or exception from the mineral conveyance—said reservation or exception may not be implied. Because the conveyances at issue here did not include an express reservation or exception of produced water, COG, not Cactus, had the right to possess, control, and dispose of produced water. This holding is a narrow one. As such, Justice Busby issued a concurring opinion outlining all the things the Court’s opinion does not hold.

Justice Busby opened his concurrence by stating that it is not helpful to focus on whether produced water is “water” or “waste,” as the answer is both. Rather, Justice Busby instructed that the Court must instead focus on whether the landowners leased produced water to the lessee. He agreed that the “incidentally produced” subsurface water was included the hydrocarbon conveyances, but wrote separately to make clear what the Court did not decide. First, the Court’s holding is simply a default rule; it does not prevent parties from striking a different deal regarding produced water ownership. Second, the COG leases at issue only concerned “oil and gas,” or “oil, gas, and other hydrocarbons;” thus, the Court’s opinion does not “break new ground” concerning unleased minerals or other substances that may be produced with leased minerals. Third, and finally, because no claims between the landowners and COG were before the Court, its opinion does not address or concern mineral lessees’ obligations to the landowners with respect to produced water. The concurrence concludes by posing several outstanding questions, including:

1) Does the lessee owe royalties to the lessor on produced groundwater it leased?

2) If not, how should parties account for profit or loss realized from beneficial reuse or disposal of the produced water?

3) Does the lessee owe any implied covenants with respect to management of produced water when a lease does not expressly address the issue?

Additional questions will surely arise, particularly in the context of the lithium boom in northeast Texas. Currently, companies are targeting the Smackover Formation, a large formation of rock extending from East Texas to Florida, as the brines contained therein are rich with lithium and other minerals. Would a Texas court view lithium and other minerals contained in the brine as “other minerals” under Texas law? Further, if a brine mining well is drilled for the purpose of extracting lithium and other minerals, which party owns those constituents? While these questions may well be the subject of a future lawsuit, for now, this case establishes, at least for instruments executed prior to September 1, 2019, that produced water is owned by mineral owners when those instruments convey “oil and gas” or “oil, gas and other hydrocarbons” without specifically reserving produced water or oil and waste.

For further questions about about how this ruling may affect your operations, contact Liskow attorneys Jana Grauberger, James Kittrell, Sam Allen, and Margaret Chavez, and visit our Energy – Litigation practice page.

On May 9, 2025, the Trump Administration published an executive order (“EO”), titled “Fighting Overcriminalization in Federal Regulations,” that targets criminal regulatory offenses subject to strict liability, or liability that attaches without a required criminal mindset. The EO states that strict liability offenses are “generally disfavored,” and encourages agencies to consider civil or administrative, rather than criminal, enforcement of strict liability offenses. The EO further explains that prosecution of criminal regulatory offenses is “most appropriate” when “a putative defendant is alleged to have known his conduct was unlawful.”

Typically, criminal conduct is accompanied by some sort of culpable mindset—the conduct needs to be intentional, willful, reckless, or knowing to be criminal conduct. But, certain federal statutes, notably in the environmental context, can be interpreted to make some actions criminal even where they lack a traditional criminal mental state, imposing “strict” criminal liability or criminal liability for simple negligence. Strict liability environmental crimes, coupled with the explosion of environmental criminal investigators mandated by the Pollution Prosecution Act of 1990, resulted in a striking increase in environmental criminal prosecutions under certain administrations. The absence of a required mental state for certain violations to be pursued criminally left prosecutorial discretion as the primary determinant of which violations were serious enough to investigate criminally and that discretion has varied across administrations and even individual prosecutors over time.

The EO seeks to both clarify the standard by which this administration chooses to evaluate potentially criminal conduct and to homogenize the prosecutorial decisions. 

Agencies Must Be Clear About Required Criminal Intent in New Regulations and Must Designate the Required Mental State for Existing Criminal Offenses

The EO notes that, going forward, agencies promulgating regulations subject to criminal enforcement should describe the exact conduct susceptible to criminal enforcement, the authorizing statutes, and the requisite knowledge or intent applicable to those offenses. That is, any new rule established by an agency that may be criminally enforced requires the agency to expressly disclose that a violation of the rule may constitute a criminal regulatory offense and should state the requisite mindset for each element of the offense.

Within a year from May 9, 2025, agencies must issue a report to the Office of Management and Budget (“OMB”) containing a list of existing enforceable criminal regulatory offenses that explains the possible penalties for said offenses as well as the applicable mindset or knowledge needed to commit them. This report will be posted to the agency’s webpage and updated at least once a year. If an offense is not mentioned in the report, the agency is “strongly discouraged” from imposing criminal penalties. The agency must consider if an offense is in its report before making a criminal referral, and the attorney general must consider this before initiating a criminal investigation or criminal proceedings. Also, the EO requires agencies to review their existing regulations to assess whether the applicable mental state requirements for criminal regulatory offenses are appropriate, which must be done by report within 30 days after submitting the original OMB report. This second report should present a plan, if consistent with the agency’s statutory authority, to adopt a “generally applicable” mental state requirement that applies unless a specific regulation states an alternative requirement.

Lastly, after consulting with the attorney general, agencies must publish guidance in the Federal Register expressing their plan to address criminally enforceable offenses. The EO requires each agency publishing guidance to make clear that it will consider the following when deciding whether to refer alleged violations of criminal regulatory offenses to the Department of Justice: the risk of harm caused by the offense; the potential gain for the person committing the offense; whether the person committing the offense had knowledge or expertise of the regulation at issue; and any evidence of the alleged perpetrator’s general awareness of the unlawfulness of his conduct and if he had knowledge of the regulation itself.   The EO criticizes the large number of regulatory crimes that are strict liability offenses, noting that likely not even “those charged with enforcing our criminal laws at the Department of Justice … know[] how many separate criminal offenses are contained in the Code of Federal Regulations[.]” The EO then presents the issue with this framework by explaining that it is an “absurd and unjust” concept that permits the “weaponization” of these regulatory offenses by government officials. Accordingly, the EO establishes a clear directive in response: “Criminal enforcement of criminal regulatory offenses is disfavored” and “is most appropriate for persons who know or can be presumed to know what is prohibited or required by the regulation and willingly choose not to comply.” This directive demonstrates a notable change in direction that the current administration is taking with respect to criminal enforcement of regulatory offenses, and the regulated community should stay tuned for further updates on this topic.

For further questions regarding this topic, contact Liskow attorneys Greg Johnson, Clare Bienvenu, Sean Toomey, and Colin North, and visit the Louisiana Industrial Insights Hub for further updates.

Louisiana has a new renewable energy law on the books, Act No. 279, set to take effect on August 1, 2025. It provides for the regulation of solar facilities, renewable energy batteries, and onshore wind projects, all under the permitting authority of the Louisiana Department of Energy and Natural Resources (LDENR). The solar facility piece of the legislation comes in response to several parishes grappling with recent divisions over large-scale solar project proposals. Act No. 279 is notable in that it grants the state permitting authority and mandates solar project siting requirements, yet it carves out an exception whereby parish governments may elect to impose their own, potentially more restrictive, siting requirements. A summary of the new requirements for each renewable energy category is as follows.

Solar Facilities

Any solar power generation project with a footprint of 75 acres or more must obtain a permit from LDENR. In addition, the Department of Agriculture and Forestry and the Department of Wildlife and Fisheries may weigh in and comment on the project permit.

The new law also contains siting requirements related to setbacks and noise levels that apply to solar facilities with a footprint of 75 acres or more and that begin construction after January 1, 2026. However, there are notable exceptions to these siting requirements:

• Parish governments that create their own siting requirements can opt out of the state siting requirements.
• Facilities located completely within an industrial-zoned area or a Louisiana Economic Development-certified site are excepted from the siting requirements.
• Residential property owners may opt out of certain siting requirements under a written agreement with the solar project’s operator.

The new law’s setback requirements are generally 300-feet from adjacent residential property lines; 100-feet from the ordinary low watermark of natural and navigable waterways; and 50-feet from the edge of public roads. Additional vegetative barrier requirements were also adopted. In addition, the act prohibits noise levels greater than 10 A-weighted decibels (dbA) above the pre-project operation ambient noise level at the project’s property line.

Renewable Energy Batteries

The new law requires that any renewable energy storage facility obtain a permit from LDENR prior to battery installation. Proof of financial security and a decommissioning plan are also required. LDENR has been directed to promulgate rules to implement these requirements by August 31, 2026.

Onshore Wind Energy

The new law prohibits the construction or completion of any onshore wind project without a permit from LDENR. Proof of financial security and a decommissioning plan are required as part of the permitting process. LDENR has been directed to promulgate rules to implement these requirements by August 31, 2026. The law applies to wind turbines that are land-based and that are located in inland water bodies.

Act No. 279 sets into motion new permitting requirements for renewable energy in Louisiana, granting LDENR the state permitting authority. With respect to solar, the act paves the way for parish governments to exercise control over project siting by opting out of the state requirements. The act does not speak to the nature of parish requirements, and parish governments therefore have leeway to craft their siting requirements to be more restrictive. As a result, it will be important to monitor the extent to which new parish-level ordinances are enacted as a counter to Act No. 279, as well as how previously adopted parish ordinances interact with Act No. 279. For more information on renewable energy transactions and approvals at both the state and local levels, please contact Liskow attorneys Neil Abramson, Paul Kitziger, and Clare Bienvenu and visit our Environmental Regulatory practice page.