Produced water – the fluid that surfaces alongside oil and gas during extraction, typically carrying high concentrations of dissolved salts and minerals – has long been the industry’s largest waste stream and one of its most persistent cost centers. That is changing. A convergence of disposal constraints, treatment technology advances, legislative reform, institutional-scale capital deployment, and the strategic importance of critical minerals is transforming produced water from a disposal liability into a managed resource. Across multiple U.S. basins, produced water is now at the center of billion-dollar infrastructure transactions, first-of-a-kind treatment and mineral extraction projects, and a rapidly evolving regulatory landscape that cuts across state, federal, and Tribal jurisdictions.
This client alert surveys the current state of the U.S. produced water value chain – spanning the Permian Basin, DJ Basin, Smackover Formation, and beyond – and identifies the legal, regulatory, commercial, and transactional issues that energy companies, investors, landowners, midstream operators, technology providers, and critical minerals developers should be watching.
I. Scale of the Problem and the Opportunity
Every barrel of oil produced in the Permian Basin brings with it roughly three to five barrels of produced water, and in parts of the Delaware Basin those ratios can reach ten to one. At current production levels, the Permian alone generates more than 20 million barrels of produced water daily. New Mexico’s oil and gas operations generate nearly two billion barrels of produced water per year. In Colorado’s DJ Basin, by contrast, water-to-oil ratios are significantly lower – roughly one barrel of water for every eight barrels of oil – but freshwater consumption for completions is substantial, with the basin consuming approximately five billion gallons of fresh water in 2022 alone.
An estimated 50% to 60% of Permian produced water is currently recycled for use in hydraulic fracturing – the simplest and cheapest form of reuse. The remainder must be disposed of by injection into deep underground formations, and decades of injection have raised formation pressures, triggered seismicity concerns, and prompted regulatory restrictions that increasingly limit disposal capacity in core producing areas.
Advanced treatment technologies capable of converting produced water to higher-value uses – agricultural irrigation, industrial supply, aquifer recharge – exist but face a persistent cost gap. Disposal currently runs roughly $0.75 to $1.25 per barrel. Treatment for frac reuse costs a similar amount, whereas treatment to agricultural quality can run $2 to $4 per barrel, and treatment to drinking water standards $4 to $7 per barrel or more. Until that gap narrows through technology maturation, regulatory incentives, new co-product revenue streams such as mineral extraction, or a supply-and-demand shift that drives prices higher for treated water and equivalent alternatives, large-scale beneficial reuse beyond the oilfield will remain in the pilot and early-commercial phase.
Induced seismicity is likely to be a primary driver in closing that gap. Decades of high-volume saltwater injection have triggered measurable seismic events across the Permian, prompting the Texas Railroad Commission to impose volume reductions and geographic restrictions on injection wells in affected areas. Similar concerns have led the New Mexico Oil Conservation Division to tighten disposal oversight. These constraints are not temporary; as formation pressures continue to rise, the physical and regulatory capacity for disposal-as-usual is narrowing, strengthening the economic case for recycling, treatment, and beneficial reuse.
II. A National Regulatory Landscape in Flux
Produced water regulation is evolving rapidly – and divergently – across multiple states and at the federal level. Oil and gas operators, investors, and technology providers in Texas, New Mexico, Colorado, or on federal lands should closely track simultaneous developments in those states and Washington, D.C.
Texas. The Texas Supreme Court, in Cactus Water Services, LLC v. COG Operating, LLC (June 2025), held that produced water is oil-and-gas waste belonging to the mineral lessee absent an express contrary conveyance – resolving a longstanding ownership ambiguity that had clouded midstream contracting, surface-use agreements, and reuse project development.
The 89th Texas Legislature also enacted a suite of changes in 2025 that collectively represent the most significant produced water legislative package in the state’s history:
- SB 1145 transferred land-application permitting authority for treated produced water from the Texas Railroad Commission to the Texas Commission on Environmental Quality (TCEQ), which is expected to propose implementing rules in April 2026.
- HB 49 limits tort liability for entities involved in the treatment, transfer, or beneficial use of treated produced water, effective September 1, 2025, with exceptions for gross negligence, regulatory noncompliance, or intentional wrongful conduct.
- HB 4426 establishes permit durations and renewal procedures for commercial surface disposal facilities for produced water, setting a maximum 10-year permit term.
Despite these advances, significant legal questions remain. SB 1763, which would have clarified ownership of brine minerals within the mineral estate, stalled in the Senate Natural Resources Committee during the 2025 session. The resulting ambiguity over brine mineral ownership may hamper investment in lithium and other mineral extraction from produced water until the legislature or courts resolve the issue.
New Mexico. New Mexico is taking a more cautious approach. Governor Lujan Grisham signed the Strategic Water Supply Act (HB 137) in April 2025, creating a $75 million program to fund brackish water (naturally occurring saline groundwater, as distinct from produced water) treatment projects as part of the state’s 50-Year Water Action Plan. The legislature removed all produced water reuse provisions from the bill during the committee process, however, reflecting persistent concerns about the adequacy of treatment science and the risks associated with reuse of water from hydraulically fractured wells. The enacted version imposes a three-cent-per-barrel fee on produced water disposed of in the state, with revenue directed to the Strategic Water Supply Program Fund. The New Mexico Environment Department’s Water Quality Control Commission continues to develop rules for produced water reuse outside the oilfield, but the agency has expressed skepticism about permitting surface discharges of treated produced water, noting that the scientific basis for protective permitting does not yet exist for all relevant constituents. As of March 2026, New Mexico does not permit surface discharge of treated produced water.
Colorado. Colorado has taken the most prescriptive approach to produced water recycling of any major producing state. In March 2025, Colorado’s Energy and Carbon Management Commission (ECMC) adopted first-in-the-nation rules requiring operators to use an increasing percentage of recycled produced water in oil and gas operations: approximately 4% for developments permitted after January 1, 2026, increasing to 10% after January 1, 2030, with a mandatory 2028 rulemaking to set targets for 2034 and 2038 (defaulting to 20% and 35%, respectively, if no new rules are adopted). The rules also establish a recycled produced water credit trading system to enable compliance flexibility. These rules were informed by the Colorado Produced Water Consortium – a 31-member multi-stakeholder body established by Colorado HB 23-1242 – which published nine data-driven reports to the legislature and will continue to evaluate implementation. Air emissions from produced water handling remain a subject of active rulemaking, with a reporting framework expected in 2026.
Colorado’s regulatory framework for produced water is also shaped by the state’s unique “nontributary” groundwater classification. Under C.R.S. Section 37-90-137(7) and the Produced Non-tributary Ground Water Rules (2 CCR 402-17), the vast majority of oil-and-gas-producing geologic formations in Colorado – including nearly all in the DJ Basin – have been designated as nontributary based on comprehensive geologic mapping and determinations. Produced water withdrawn from nontributary formations can be used for oil-and-gas-related purposes (broadly construed) in the same geologic basin from which it was withdrawn without a Water Court decree, overlying landowner consent, Division of Water Resources well permit, or other standard approvals. This facilitates in-field recycling and oil and gas reuse but limits beneficial reuse for non-oilfield purposes (e.g., agriculture, municipal supply, or aquifer recharge), which generally requires landowner consent, payment, or additional water rights authorization.
Other States. Produced water management challenges are not confined to western basins. In the Appalachian Basin, Pennsylvania has effectively prohibited underground injection of oil and gas wastewater since the 1990s, forcing operators to truck produced water to disposal wells in Ohio or to centralized treatment facilities – a dynamic that has driven early investment in treatment technology but at significantly higher per-barrel costs. Wyoming and North Dakota permit produced water discharges and reuse under state-administered programs, and Utah has adopted regulations expanding reuse opportunities and limiting freshwater consumption for oil and gas operations. Practitioners operating across multiple basins should expect continued divergence in state approaches.
Federal. At the federal level, EPA Administrator Lee Zeldin announced in March 2025 that the agency will revise its effluent limitation guidelines (ELGs) for oil and gas extraction, consistent with the Trump Administration’s Unleashing American Energy Executive Order. The current ELGs date to the 1970s, and their modernization could significantly alter the federal framework for produced water management. The revision could also expand federal pathways for beneficial reuse and surface discharge of treated produced water. The timeline for a proposed rule, however, remains uncertain. Separately, the EPA’s National Water Reuse Action Plan continues to study oil and gas extraction wastewater management practices – work that could inform future federal guidance on treatment standards, monitoring protocols, and discharge criteria for produced water reuse projects.
III. Partnerships and Infrastructure: The Midstream Water Buildout
The produced water midstream sector is undergoing a wave of consolidation and infrastructure investment that mirrors the buildout of hydrocarbon gathering and processing systems over the past two decades.
The partnership between Texas Pacific Land Corporation (TPL) and WaterBridge illustrates the emerging model. In 2022, TPL – one of the largest landowners in West Texas – and WaterBridge – the largest U.S. produced water network operator – formed a Delaware Basin water development alliance covering a 64,000-acre contiguous area of mutual interest. By combining fragmented surface rights with midstream infrastructure and operating capability, they created a single counterparty for comprehensive water management across entire development areas.
WaterBridge’s infrastructure includes approximately 2,500 miles of pipeline and over 4.5 million barrels per day of handling capacity. Its Speedway pipeline – an 80-mile system moving water out of the most pressurized core areas of the Delaware Basin into peripheral formations with better disposal capacity – reflects a broader geographic shift in disposal strategy toward lower-pressure formations in Andrews County and eastern Loving County. WaterBridge handled 2.4 MMbbl/d of produced water in 2025 (up 15% year-over-year) and expects volumes of 2.5 MMbbl/d to 2.7 MMbbl/d in 2026. Phase I of Speedway is expected online mid-2026; a February 2026 open season is underway for Phase II, which would double capacity to 1 MMbbl/d by moving volumes from Eddy and Lea counties, New Mexico, to out-of-basin pore space. Executives have signaled a potential Phase III expansion and system looping, with CFO Scott McNeely stating “the short answer is yes” given strong demand (timing subject to Phase II commercial outcomes). The company also expects to begin construction in Q4 2026 on a new produced water infrastructure project tied to Devon Energy under a ten-year agreement with a 7.5-year minimum volume commitment starting April 2027.
Two landmark 2025 capital markets transactions confirmed that institutional investors now view produced water infrastructure as a distinct, investable asset class. WaterBridge completed an upsized IPO in September 2025, raising approximately $634 million (with full exercise of the underwriters’ option) at $20 per share (top of range) on the NYSE. Western Midstream Partners completed an approximately $2 billion acquisition of Aris Water Solutions in October 2025, combining over 1,600 miles of produced water pipeline. The combined system created what Western Midstream described as a fully integrated produced water value chain – spanning gathering, disposal, recycling, desalination, mineral extraction, and long-haul transport. These transactions signal that the produced water midstream sector is transitioning from a fragmented, operator-by-operator service model to a consolidated, infrastructure-backed platform business. That shift brings attendant legal demands – long-term commercial agreements, acreage dedications, pore space rights, surface access, and regulatory compliance across multiple agencies.
WaterBridge is also at the center of a significant regulatory enforcement dispute. In September 2024, the Texas Railroad Commission spent approximately $6.95 million to plug a Ward County well that experienced a produced-water blowout. The Texas Railroad Commission canceled the permit for a nearby WaterBridge disposal well – located half a mile from the blowout site, at a 1950s-era legacy well – and initiated proceedings to recover the plugging costs. WaterBridge disputes the findings, arguing that its well was properly permitted and operating within its permit limits, that causation has not been proved, and noting three other disposal wells within a two-mile radius as potential contributors. The company has called the action “unprecedented”; as of this writing, a hearing has not yet been scheduled. The case is significant for the broader midstream sector because it raises questions about operator liability for blowouts at legacy wells compromised by cumulative injection pressure from multiple operators – a dynamic likely to recur as formation pressures rise across the Delaware Basin.
IV. Treatment Technologies: From Pilot to Near-Commercial
Multiple treatment approaches are advancing through the pilot phase in the Permian and elsewhere. WaterBridge alone reported 10 to 12 treatment technology pilots underway in the Permian in 2025, evaluating both distillation and reverse osmosis approaches.
The most advanced near-commercial project is TPL’s Transmissive Water Services Phase 2 system, which combines freeze distillation (leveraging temperature differentials to separate clean water from brine) with reverse osmosis to achieve approximately 75% water recovery. The system has secured a surface-discharge permit from the Texas Railroad Commission, with a separate TCEQ discharge authorization pending. Construction paused in 2025 for additional testing and equipment enhancements. If approvals and construction proceed as currently planned, the system could begin treating approximately 10,000 barrels per day by mid-2026, with potential applications in agriculture and aquifer recharge.
A potentially significant new end-use is also emerging: data-center cooling and co-located power generation. Tetra Technologies is advancing its Oasis desalination platform – pre-treatment for contaminant removal, membrane-based desalination to reduce salinity from the Permian’s typical 130,000-150,000 mg/L to below 200 mg/L, and post-treatment polishing. Tetra executives describe the opportunity as “huge,” noting that one gigawatt of data-center and power-generation capacity can require 250,000-350,000 bbl/d of treated water. Larger installations require still more – in a basin that produces over 20 MMbbl/d of produced water daily amid limited fresh-water availability. An EOG pilot has run consistently since Q3 2025 with encouraging agricultural growth study results. According to Tetra, economics are converging as disposal costs rise and treatment costs decline.
Treatment technology selection depends heavily on the source water’s total dissolved solids (TDS), constituent chemistry, and intended end use. Produced water in the Delaware Basin can be five to eight times saltier than seawater, and also contains a complex mix of hydrocarbons, heavy metals, naturally occurring radioactive materials (NORM), and chemical additives from completions. Treating to agricultural or drinking water quality requires addressing constituents – many of which lack established federal or state toxicity standards – at costs that remain significantly above disposal.
PFAS (per- and polyfluoroalkyl substances) are another emerging concern. PFAS have been detected in produced water from multiple basins, and EPA’s evolving PFAS regulatory framework (including the 2024 National Primary Drinking Water Regulation for six PFAS compounds) may impose additional treatment requirements and liability exposure for produced water reuse projects. Rice University’s WaTER Institute has established a dedicated PFAS Alternatives and Remediation Center (R-PARC) focused on destruction and removal technologies for these persistent contaminants.
Research efforts at Texas Tech University (through the Texas Produced Water Consortium), Texas A&M, and the University of Texas are evaluating advanced membranes, hybrid thermal-membrane systems, and treatment process trains targeting beneficial reuse quality. Rice University’s WaTER Institute – launched in January 2024 and building on a decade of work through the NSF-funded Nanotechnology Enabled Water Treatment (NEWT) Center – is pursuing a particularly ambitious research agenda. Its focus areas include beneficial disposition of produced waters from oil and gas fields, critical elements recovery from wastewaters, and advanced membrane and catalytic separation technologies designed to reduce the energy intensity and cost of fit-for-purpose treatment. Rice has also established the Center for Membrane Excellence (RiCeME) to advance separation technologies for energy and environmental applications, and its researchers are developing more efficient lithium extraction methods – work that sits squarely at the intersection of produced water treatment and critical mineral supply chains. The Department of Energy’s National Energy Technology Laboratory continues to fund research across multiple institutions. Colorado’s Produced Water Consortium has also separately evaluated analytical and toxicological methods for assessing treatment adequacy.
V. Lithium and Critical Mineral Extraction: A New Co-Product Revenue Stream
Strategic partnerships between landowners, midstream companies, and operators are expanding to include mineral extraction – particularly lithium, a critical input for EV batteries and energy storage listed on the USGS 2025 List of Critical Minerals – from briny waters, including produced water.
Smackover Formation (Arkansas and East Texas). The most advanced domestic lithium-from-brine plays are in the Smackover Formation, where lithium concentrations in natural brine exceed 300 ppm and have been measured above 600 ppm in some wells. ExxonMobil (through its subsidiary Saltwerx) has acquired brine rights to over 300,000 net acres, completed an eight-well appraisal drilling program, received Arkansas Oil and Gas Commission approval for a 56,245-acre brine production unit and a 2.5% lithium royalty rate, and is targeting first lithium production in 2027 under its Mobil Lithium brand. Equinor has partnered with Standard Lithium for direct lithium extraction (DLE) in the same formation. The Smackover play has also drawn entry from Chevron, TETRA Technologies, PotlatchDeltic, and Albemarle, among others.
Permian Basin. In the Permian, the massive aggregate volumes of produced water create a significant brine resource, but lithium concentrations are far lower (15-40 ppm). Element3, a Fort Worth-based extraction company, is commissioning the first commercial-scale DLE unit at Double Eagle Energy’s recycling facility, with first customer deliveries targeted for the first half of 2026. This is expected to be the first commercial lithium extraction from Permian produced water. The economic thesis is integration: where water is already being handled as part of oil operations, lithium extraction becomes an incremental co-product rather than a standalone venture, potentially improving the economics of both water handling and mineral supply.
Broader U.S. DLE Activity. California’s Salton Sea natural geothermal brine has attracted DLE investment from Occidental Petroleum (through a joint venture with All-American Lithium) and others, supported by DOE research. Nevada has seen DLE pilot activity by oilfield services firms including SLB (formerly Schlumberger).
Practitioners should note that lithium extraction from brine implicates a complex and still-developing web of legal issues. These include ownership of brine minerals (unsettled in Texas), unitization and royalty frameworks (newly established in Arkansas), federal land and Tribal consultation requirements where applicable, water rights and return-flow obligations, and environmental permitting for brine production and reinjection. Federal incentives add a further dimension: the Inflation Reduction Act’s Section 45X Advanced Manufacturing Production Credit applies to domestically produced critical minerals, and the Section 30D clean vehicle credit sourcing requirements incentivize U.S.-origin lithium – both of which may materially affect project economics and offtake structuring for DLE ventures.
VI. Legal and Transactional Issues for Practitioners
The produced water value chain implicates a wide range of practice areas. We highlight several that are particularly active.
Ownership and Property Rights. The Texas Supreme Court’s Cactus Water decision clarified that produced water belongs to the mineral estate absent express contrary language, but it did not resolve ownership of brine minerals, leaving ambiguity that affects commercial agreements for mineral extraction. Practitioners should review existing mineral leases, surface use agreements, and water handling contracts for produced water and brine mineral allocation language. In prior appropriation states such as Colorado and New Mexico, the interaction between produced water reuse and state water rights law raises additional questions – including whether treated produced water discharged to surface waters or applied to land creates new appropriation obligations, triggers return-flow requirements, or implicates existing senior water rights. In Colorado, the nontributary produced water framework adds a further layer of complexity, as reuse of nontributary produced water is generally restricted to oil-and-gas-related purposes absent landowner consent or other authorization. These issues are particularly acute where beneficial reuse projects propose to introduce treated produced water into watersheds or aquifers that are already over-appropriated.
Commercial Agreements. Produced water midstream agreements – water gathering, disposal, and recycling agreements with acreage dedications and volume commitments – are becoming increasingly complex, approaching the commercial sophistication of hydrocarbon midstream contracts. Pore space access and disposal rights, take-or-pay structures, treatment specifications, regulatory risk allocation, and mineral extraction rights are all subjects of active negotiation.
Regulatory Compliance. The multi-agency regulatory landscape – spanning the Texas Railroad Commission, TCEQ, the New Mexico Environment Department, the Colorado ECMC, EPA, state water agencies, and (where applicable) the Bureau of Indian Affairs and Tribal regulatory bodies – requires careful navigation. Permits for surface discharge, land application, subsurface injection, and beneficial reuse are governed by overlapping and sometimes conflicting state and federal requirements. The pending WaterBridge/Ward County enforcement proceeding (discussed in Section III) highlights emerging liability exposure for permitted disposal operations that may contribute to subsurface pressure buildup affecting nearby legacy wells. Practitioners should address this risk in disposal agreements and infrastructure transaction diligence.
Capital Markets and M&A. The WaterBridge IPO and Western Midstream/Aris acquisition establish produced water infrastructure as an institutional asset class. Expect continued M&A activity as operators pursue scale, integration, and pore space access across the full value chain. The Devon-Coterra all-stock merger, announced in February 2026 with a combined enterprise value of approximately $58 billion, is expected to close in Q2 2026, subject to regulatory approvals and shareholder votes, and could further reshape produced water contracting in the Delaware Basin, where, as analysts have noted, Coterra’s Franklin Mountain acreage overlaps WaterBridge’s Speedway system. Diligence for these transactions requires careful evaluation of disposal well capacity and induced seismicity risk, regulatory compliance posture, surface and pore space rights, and the adequacy of environmental and water rights arrangements.
Tort and Environmental Liability. Texas HB 49 limits tort liability for treated produced water beneficial use, but its exceptions (gross negligence, regulatory noncompliance, intentional misconduct) and effective-date limitations mean that liability risk has been reduced, not eliminated. Operators, landowners, and technology providers should assess the scope of these protections in the context of their specific operations and contractual risk allocation.
Financial Assurance and Insurance. Regulators are increasingly requiring financial assurance for produced water operations. New Mexico’s Strategic Water Supply Act mandates financial assurance for the life of any project receiving a program contract, and the Texas Railroad Commission’s bonding requirements for disposal wells remain under periodic review. Investors and lenders should evaluate the adequacy of existing bonding, insurance, and indemnification structures – particularly for long-lived disposal and treatment assets where decommissioning and remediation obligations may extend well beyond the operational period.
Tribal Consultation and Federal Lands. Where produced water operations, mineral extraction, or treatment projects involve federal lands or Tribal resources, consultation and compliance obligations under NEPA, the National Historic Preservation Act, the Endangered Species Act, and applicable Tribal regulatory frameworks add an additional layer of complexity. This is particularly relevant for DLE projects in formations that cross jurisdictional boundaries or involve split estates.
VII. What to Watch
- TPL Transmissive Phase 2B completion: mid-2026 target (following 2025 construction pause); the first near-commercial beneficial reuse project in the Permian.
- Element3 commercial lithium deliveries: targeted for first half of 2026; expected to be the first commercial lithium extraction from Permian produced water.
- TCEQ land-application rulemaking: rules expected April 2026; the most consequential near-term regulatory milestone for Texas beneficial reuse.
- EPA ELG revision: timeline uncertain; could reshape the federal framework for produced water discharge and reuse nationally.
- Colorado ECMC recycling mandate implementation: approximately 4% recycling requirement phases in for developments permitted after January 1, 2026, with air quality rulemaking to follow.
- New Mexico WQCC produced water rulemaking: continued development of rules governing reuse outside the oilfield; a key indicator of the state’s long-term position on beneficial reuse.
- ExxonMobil/Saltwerx first lithium production in Arkansas: targeted for 2027; the largest DLE project under development in the U.S.
- Continued M&A and infrastructure investment: midstream operators pursuing scale, integration, and pore space access across the full produced water value chain, with particular activity expected around disposal-constrained basins and integrated treatment/mineral extraction platforms.
- Brine mineral ownership legislation: whether Texas, Arkansas, or other states act to clarify ownership of minerals dissolved in produced water.
- Colorado nontributary produced water framework: potential evolution of limits on reuse beyond oil-and-gas purposes amid rising recycling requirements and beneficial reuse pilots.
- WaterBridge/Texas Railroad Commission Ward County enforcement proceeding: outcome of the still-unscheduled hearing and potential precedent on operator liability for cumulative injection pressure effects on legacy wells.
- WaterBridge Speedway Phase II/III and Devon project: sanctioning and mid-2026 ramp-up amid continued northern Delaware Basin takeaway demand.
- Data-center cooling demand: commercial progress on treated produced water desalination for cooling and power generation, including Tetra’s Oasis platform.
VIII. How We Can Help
Davis Graham’s Energy & Mining, Environmental, and Water Law groups advise clients across the full produced water value chain – from upstream operators and midstream infrastructure developers to landowners, technology providers, investors, and critical minerals companies. Our team brings particular depth to this space: decades of experience in western water rights and environmental permitting; hands-on transactional work in midstream energy, critical minerals, and carbon management; and recognized capabilities in Tribal engagement and consultation, federal lands, and NEPA and NHPA compliance for resource extraction projects. We counsel on transactions, regulatory compliance and permitting, water rights, commercial agreements, environmental and water rights litigation and enforcement, and Tribal and public lands matters related to produced water, brine mineral development, and beneficial reuse projects.
For more information or if we can be of assistance, please contact a member of the Clean Energy & Sustainability Group.
This alert is intended to provide a general overview of the legal, regulatory, commercial, and transactional considerations relevant to produced water management, beneficial reuse, and critical mineral extraction across the United States. It does not constitute legal, financial, or investment advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.