NYSE: WBI

The transportation, treatment and handling of produced water is crucial to oil and natural gas production. Water naturally exists in subsurface geologic formations that contain oil and natural gas deposits and is produced alongside, and typically in higher volumes than, hydrocarbons throughout the full life cycle of oil and natural gas wells. Produced water must be reliably separated and handled in order for these wells to be brought online and remain in production. Due to the significant produced water volumes in the Delaware Basin in particular, our operations are critical to the ability of E&P companies to develop and produce oil and natural gas over the life cycle of a well.

Our Assets

Our current areas of operation include the Delaware Basin in West Texas and New Mexico, the Eagle Ford Basin in South Texas and the Arkoma Basin in Oklahoma. As of December 31, 2025, our infrastructure network included approximately 2,500 miles of pipelines and 201 produced water handling facilities with approximately 4.7 million bpd of produced water handling capacity supported by approximately 2.4 million acres dedicated to us under long-term, fixed-fee contracts with E&P companies. This network is supported by our field personnel and automated in-field equipment, including pumps, valves and cameras that are managed by our operations center on a continuous basis.

We have an established track record of developing significant produced water infrastructure to meet the operational needs of our customers. From January 1, 2018 to December 31, 2025, we constructed approximately 1,000 miles of pipelines and 76 produced water handling facilities across our areas of operation, as well as Desert Environmental’s two energy waste management facilities. In particular, during 2025, we constructed large-diameter produced water transportation pipelines and related handling facilities with an initial capacity of 450,000 bpd and the ability to increase capacity to approximately 600,000 bpd, to transport and handle produced water from bpx energy’s development locations in Reeves County, Texas. This infrastructure is underpinned by long-term transportation and disposal agreements with bpx energy that include 10-year MVCs.

In addition, we are currently constructing the Speedway Pipeline, which will extend across the northern Delaware Basin and connect Eddy and Lea Counties to out-of-basin pore space in the Central Basin Platform owned by LandBridge. The initial phase of the Speedway Pipeline, which we anticipate will be completed and in service during the third quarter of 2026, will have a throughput capacity of 500,000 bpd. On February 23, 2026, we announced the launch of an open season to support the construction of the Speedway Pipeline Phase II, which is anticipated to provide incremental throughput capacity of up to 500,000 bpd to out-of-basin pore space located in the Central Basin Platform, for a total expected throughput capacity of up to 1.0 million bpd once fully constructed. The construction and commissioning of any expansion project, including the Speedway Pipeline, is subject to numerous uncertainties, and we can provide no assurances that any such project will be executed on the terms or on the timetables estimated for such expansion project.

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We and LandBridge also entered into agreements with Texas Pacific Land Company (“TPL”), one of the largest landowners in Texas, to provide reciprocal crossing rights across an approximately 64,000 acre area of mutual interest (“AMI”) near and along the Texas-New Mexico state border that, together with our access to LandBridge’s surface acreage, provides us access to semi-contiguous, or checkerboarded, acreage necessary to develop large scale water infrastructure assets in the area. Through these agreements, we have access to TPL’s surface within the AMI for pipeline rights of way and the right to operate produced water handling facilities within the AMI as well as the exclusive right to market and sell produced water within the AMI, subject to customary royalty and revenue-sharing payments.

Note: Map as of March 2026. The open season for Phase II of the Speedway Pipeline project was announced in February of 2026 and is scheduled to end in April 2026. Development and construction of Phase II of the Speedway Pipeline is dependent on future commercialization and market viability.

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The table below includes a summary of our operating assets, produced water handling capacity, acreage dedications, AMI acres and percentage of produced water handling volumes by area of operation as of December 31, 2025.

Pipeline Miles(1)(2)

Water Handling Facilities(2)(3)

Handling Capacity (Bbl/d)

Acreage Dedications (acres)

AMI Acres

Percentage of Water Handling Volumes

Delaware

Operating

1,814

171

4,103,850

827,381

3,108,551

89

%

Under development

110

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365,000

-

-

-

Total Delaware

1,924

182

4,468,850

827,381

3,108,551

89

%

Eagle Ford

Operating

457

18

412,500

874,303

880,299

9

%

Under development

-

-

-

-

-

-

Total Eagle Ford

457

18

412,500

874,303

880,299

9

%

Arkoma

Operating

270

12

195,440

733,069

2,623,209

2

%

Under development

-

-

-

-

-

-

Total Arkoma

270

12

195,440

733,069

2,623,209

2

%

Combined Total

2,651

212

5,076,790

2,434,753

6,612,059

100

%

(1)
Excludes gas transportation pipelines.

(2)
Includes assets that are expected to be placed into service in 2026.

(3)
Includes produced water disposal wells and other recycling and reuse facilities.

Our Business Model

Our business model focuses on establishing long-term operating relationships with E&P companies to develop water infrastructure solutions throughout the full life cycle of their oil and natural gas wells. These relationships are generally characterized by long-term, fixed-fee customer contracts, with 71% of our long-term contracts having an initial primary term of at least 15 years. As of December 31, 2025, our long-term, fixed-fee customer contracts had a weighted average remaining life of approximately 10.4 years and included approximately 2.4 million acres dedicated to us.

Our long-term contracts are structured similarly to traditional crude gathering contracts. Key features of our long-term contracts include:

•
Long Term – an initial term of 15 years for a majority of our long-term contracts, with a weighted-average remaining term of approximately 10.4 years as of December 31, 2025;

•
Fixed Fee – a per-barrel fixed fee charged to transport and handle produced water volumes;

•
Acreage Dedications and AMIs – dedications of large acreage positions in which, other than diverted volumes described below, all produced water is required to be handled by our integrated network and, for certain of our contracts, AMIs designating areas in which producers will dedicate subsequently acquired or leased acreage and oil and natural gas wells to us;

•
MVCs – for certain of our contracts, MVCs, which require our customers to deliver, or pay for the delivery of, certain minimum volumes of produced water over specific time periods, which often serve to underwrite return thresholds on initial capital outlays and are intended to generate predictable cash flows;

•
Fee Escalators – annual fee escalation tied to the Consumer Price Index (“CPI”) or similar inflation index for substantially all of our long-term contracts; and

•
Fees for Diverted Volumes – a per-barrel fixed fee for produced water volumes diverted by customers subject to acreage dedications prior to delivery to us, or redelivered by us, or for use in drilling and completion operations, which fees approximate or exceed the same net margin we would have received had we transported and handled the diverted or redelivered volumes. In addition, we typically receive the exclusive right to recycle produced water volumes generated by our customers from their dedicated acreage.

In addition to organic growth opportunities, we routinely evaluate opportunities to acquire produced water assets owned by E&P companies or third-party water infrastructure companies. We believe that scale is critical for operational and capital efficiency of water handling and that there will be opportunities to expand our existing network through opportunistic acquisitions. Several of our customers commenced or expanded their commercial relationship with us by selling their water assets to us and signing long-term contracts in

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connection with the sale. We expect to continue to prioritize acquisitions of producer-owned water infrastructure assets over third-party assets due, in part, to the opportunity to enter into favorable long-term contracts as part of the transaction.

Sources of Revenue

We generate revenue primarily by charging produced water handling fees for transporting produced water for disposal into our produced water handling facilities and, to a lesser extent, by providing raw or recycled produced water to customers for reuse in drilling and completion operations. By focusing on produced water handling, our revenues are tied primarily to the long-life production of oil and natural gas wells rather than drilling activity, which can be more cyclical in nature. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue” for further discussion.

Our Relationship with LandBridge

We share a financial sponsor, Five Point, and our management team with LandBridge. As of December 31, 2025, LandBridge owned or managed more than 315,000 surface acres in and around the Delaware Basin. Five Point and our management team initially formed LandBridge to acquire, manage and expand a strategic land position in the heart of the Delaware Basin to support the development of our large-scale produced water infrastructure.

We believe that expected future growth of produced water volumes in the Delaware Basin will require additional, underutilized pore space to allow for proper sequestration. LandBridge’s surface acreage is strategically located in proximity to significant producer activity and has access to largely underutilized pore space, offering critical capacity for produced water handling. As of December 31, 2025, we operated approximately 1.5 million bpd of produced water handling capacity on LandBridge’s surface acreage, with approximately 3.2 million bpd of additional permitted capacity available to us for future development. We have the exclusive right to construct up to 36 initial produced water handling facilities on a portion of LandBridge’s surface acreage located along the eastern portion of the Texas-New Mexico state border, with contracted access for additional facilities in excess of that amount. We believe that our relationship with LandBridge and our preferential access to largely underutilized pore space, when combined with our management team’s extensive experience in the produced water industry, are competitive strengths.

Our Relationship with Five Point

Five Point is a private equity and infrastructure investor focused on investments within the North American water management, surface management, powered land and sustainable infrastructure sectors. Five Point acquires and develops in-basin assets, provides growth capital and builds industry-leading companies with experienced management teams and large E&P partners.

Our Relationship with Devon

We entered into a long-term, strategic partnership with Devon Energy Corporation (“Devon”) in the Delaware Basin in 2023. In connection with that transaction, we and Devon entered into a long-term agreement pursuant to which Devon committed to us all of its produced water within a large AMI, including an initial dedication of approximately 52,000 acres, and contributed 18 produced water handling facilities with approximately 375,000 bpd of permitted capacity and approximately 210 miles of produced water pipelines for gathering, transportation, disposal and reuse in exchange for an equity interest in our predecessor. For the year ended December 31, 2025, Devon was one of our largest customers by volume and accounted for approximately $98 million of our water-related revenues, which represented approximately 19% of our total water-related revenues for the year.

Devon owns 17,757,225 Class B shares, representing 14.4% of our common shares, and 14.4% of the outstanding OpCo Units.

Our Operations

We operate the largest produced water infrastructure network in the United States through which our companies provide E&P companies with water management solutions, which include the gathering, transportation, treatment, recycling and handling of produced water, all under long-term contracts. Our infrastructure network includes an integrated network of pipelines that transport water to our water handling facilities where we remove solids and any residual skim oil from the water. Once the water has been processed at our water handling facilities, we either dispose of the water or recycle the water for use in future drilling operations. We also believe there will be future opportunities for beneficial reuse of the water for agricultural and industrial purposes, which could provide us with additional revenue opportunities. The integrated nature of our assets is critical to providing our customers with flow assurance and enables us to distribute large volumes of water gathered within concentrated oil and natural gas producing areas across our network. We believe that our ability to optimize our infrastructure network enables us to be more capital efficient relative to producer-owned water infrastructure or smaller-scale, third-party water infrastructure.

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Water Gathering and Transportation Pipeline Network

Our water gathering and transportation pipeline network transports water from the wellsite to our water handling facilities. As of December 31, 2025, we operated approximately 2,500 miles of water pipelines. As our E&P customers have continued to drill longer laterals with large pad developments that include more wells drilled from a single pad, the volumes of water concentrated within a single surface location has increased. There are no viable long-term alternatives to pipeline transportation of water volumes produced from new pad developments, and, unlike gas production, a producer cannot flare water if takeaway infrastructure is constrained. We believe that the necessity of transporting water away from the wellsite by pipeline makes our water gathering and transportation pipeline network critical infrastructure, as our customers would be forced to shut-in their production without reliable water handling capacity.

Water Handling Facilities

When water is transported from the wellsite or central gathering facility, it typically contains salt, chemicals and/or skim oil. At our water handling facilities, we filter and treat produced water and either inject it into underground disposal wells or recycle the treated water for further use in drilling activities. As of December 31, 2025, we operated 201 produced water handling facilities with approximately 4.7 million bpd of produced water handling capacity. In the process of treating produced water at our water handling facilities, we often recover residual skim oil that remains in the water stream. We generate revenue by selling that skim oil at prevailing market prices, less applicable discounts.

Water Solutions

We sell brackish and produced water to our customers for use in their drilling and completion operations. We also provide produced water treatment and recycling services and sell recycled water to our customers for use in drilling and completion operations. We charge contracted fees per barrel of water sold.

Energy Waste Management Facilities

As our energy waste management business, Desert Environmental owns and operates two fluid waste reclamation facilities, one stationary treatment facility and two solid waste management facilities in the Delaware Basin, all newly constructed as of 2023. Desert Environmental’s state-of-the-art solid waste facilities have advanced processing capabilities with ample remaining solid waste facilities capacity that can handle more than 20 years of waste at current activity levels. Desert Environmental’s reclamation facilities are co-located with our solid waste facilities and use advanced separation technologies to extract hydrocarbons from solid and fluid waste products with the capacity to handle more than 200 trucks per day. Additionally, we believe that Desert Environmental is well-positioned to benefit from the ongoing shift towards closed-loop disposal systems, which would result in additional volumes available for capture in our energy waste management business.

Gas Transportation

We also own gas transportation pipelines in Oklahoma and earn fees related to that service.

Operations Management

We operate a purpose-built, centralized communication hub for our business that is staffed 24 hours per day, seven days per week for coordinating field operations and managing external stakeholder communications, leveraging over 880 live camera feeds, 50,000 direct control inputs per month and various monitoring systems to track pressures, temperatures, flow rates and equipment performance. Beyond safety and monitoring, the operations center provides field automation capabilities that remotely optimize injection processes, control pumps and valves and regulate power usage, delivering significant labor cost savings and operational efficiencies. We further enhance our data-driven operations through our proprietary WAVE software platform, a custom forecasting tool that we developed in-house that integrates field-level data with reservoir modeling to generate daily operational and planning forecasts, optimize capacity utilization and capital deployment and provide customers with insights into system capacities, hydraulics and flowback planning.

Customers and Contracts

Our customers include many of the top-tier operators in the regions in which we operate, including bpx energy, Chevron Corporation, Devon, EOG Resources, Inc. and Permian Resources Corporation. We serve our customers primarily under long term, fixed-fee contracts that contain acreage dedications or MVCs, with annual fee escalators tied to the CPI or similar inflation index. For the year ended December 31, 2025, our top five customers by revenue consisted of Devon, Permian Resources Corporation, bpx energy, Mewbourne Oil Company and EOG Resources, Inc, which collectively represented approximately 51% of our total water-related revenue for the year. We expect to continue to execute long-term contracts with existing and new customers as we continue to expand our water infrastructure network.

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Organic Growth Opportunities

We intend to continue to grow our business through organic growth and strategic acquisitions. We intend to expand by securing long-term, fee-based contracts that generate predictable cash flows by providing water management solutions to our customers in support of their increasing water management requirements. Additionally, our unique relationships with LandBridge and TPL provide us with advantaged access to pore space for incremental disposal capacity, which we view as a key competitive differentiator in pursuing new and expanded commercial agreements.

We also expect ongoing consolidation opportunities as E&P companies increasingly seek to divest their water infrastructure assets or outsource water management to third party operators due to flow assurance and operational and capital efficiency of leveraging a larger, integrated third-party network. We employ a rigorous framework when evaluating potential acquisitions, pursuing accretive opportunities involving high-quality, complementary water infrastructure assets. Any acquisition must compete favorably against alternative uses of our capital, including organic growth projects, shareholder dividends, share repurchases and debt reduction. Since 2018, we have completed more than 30 separate acquisitions and have demonstrated a track record of successfully integrating these assets into our broader network.

Competition

We primarily compete with water infrastructure assets owned by E&P companies and with other third-party water midstream companies. Our competition is primarily relevant as it relates to new commercial agreements. Due to the long-term nature of our existing acreage dedication contracts, we may be able to grow through existing contracts with our existing customers without the necessity of entering into additional commercial agreements.

We believe that many of the E&P companies that continue to own their own water infrastructure would benefit from outsourcing their water management needs and selling their assets due to the capital efficiencies that can be realized from leveraging a larger, integrated network to manage produced water volumes. Additionally, we believe that our large-scale, fully integrated network, combined with our advantaged access to pore space as a result of our partnerships with LandBridge and TPL, differentiates us from other third-party water midstream companies that lack the scale required to address the challenges faced by our customers.

Seasonality

Our operations are not subject to significant seasonal variation in demand or supply.

Insurance

Our business is subject to all of the inherent and unplanned operating risks normally associated with the transportation, treating and handling of produced water. Such risks include weather, fire, explosion, pipeline disruptions and mishandling of fluids, any of which could result in damage to, or destruction of, gathering and storage facilities and other property, environmental pollution, injury to persons or loss of life. As protection against financial loss resulting from many, but not all, of these operating hazards inherent to our business, our insurance coverage includes commercial general liability, employer’s liability, directors and officers’ liability, environmental and pollution liability and other coverage. While we cannot guarantee that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage, or that these levels of insurance will be available in the future at economical prices, we believe that this insurance coverage is appropriate and consistent with industry practice. We will continue to evaluate our policy limits and deductibles as they relate to the overall cost and scope of our insurance program.

Environmental and Occupational Health and Safety Matters

Our operations and the operations of our customers are subject to numerous federal, state and local environmental laws and regulations relating to pollution, worker health and safety, the discharge of hazardous and non-hazardous materials and environmental protection. These laws and regulations may, among other things: require the acquisition of permits for regulated activities; govern the amounts and types of substances that may be released into the environment in connection with our operations; restrict the way we handle or dispose of wastes; limit or prohibit our or our customers’ activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions that may be caused by our operations or attributable to our former operations; and impose specific standards addressing worker protections. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial, cancellation, suspension, or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties and even criminal prosecution.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations to which our business operations and the operations of our customers are subject.

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Hazardous Substances and Hydrocarbon Wastes

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, non-hazardous wastes, hazardous wastes and petroleum hydrocarbons. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of non-hazardous and hazardous waste and may impose strict liability and joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owners and operators of the site where the release occurred and the transporters and generators of hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability and strict liability for the costs of investigating and remediating the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We handle materials that may be regulated as hazardous substances as defined under CERCLA, or similar state statutes, in the course of our ordinary operations, but we are unaware of any liabilities for which we may be held responsible that would have a material adverse effect on us.

We also generate and accept for disposal from our customers wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA regulates the generation, storage, treatment, transportation and disposal of both non-hazardous and hazardous wastes, but it imposes more stringent requirements on the management of hazardous wastes. In the course of our or our customers’ operations, some amounts of ordinary industrial wastes are generated that may be regulated as hazardous wastes. Most E&P waste, if properly handled, is exempt from regulation as a hazardous waste under RCRA. However, it is possible that certain E&P waste now classified as non-hazardous waste and exempt from regulation as hazardous wastes may in the future be designated and regulated as “hazardous wastes” under RCRA or other applicable statutes. Any revision to the RCRA exclusion for drilling fluids, produced water and related wastes could result in an increase in the costs to manage and dispose of generated wastes and could have a material adverse effect on our operations.

In the course of our operations, some of our storage and process vessels, piping work areas and other equipment may be exposed to naturally occurring radioactive material (“NORM”) associated with oil and gas production. NORM-contaminated scale deposits and other accumulations exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage and process vessels, piping and work areas affected by NORM may be subject to remediation or restoration requirements. It is possible that we may incur costs or liabilities associated with elevated levels of NORM.

Subsurface Injections

Our underground injection operations are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, U.S. Environmental Protection Agency (the “EPA”) established the Underground Injection Control (“UIC”) program, which sets minimum requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require us to obtain a permit from the applicable regulatory agencies to operate our produced water handling facilities. We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in substantial compliance with permit conditions and state rules.

Although we monitor the disposal process of produced water, any potential leakage from the subsurface portions of our produced water handling facilities could cause degradation of fresh groundwater resources, potentially resulting in suspension, adverse modification, or revocation of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties for contamination, natural resource damage, property damages and personal injuries. Also, some states have considered laws mandating the recycling of produced water. Our business is designed to take advantage of the increased use of recycling and reuse trends that may change existing industry dynamics, providing our business with increased flexibility and strengthening our competitive position.

Some experts have concluded that the injection of produced water into certain underground formations may trigger seismic activity. In March 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. In response to these concerns, some federal and state agencies are investigating whether disposal wells have caused increased seismic activity. Also, regulators in some states, including Texas and Oklahoma, have adopted, and other states are considering adopting, additional requirements related to seismic safety, including imposing certain restrictions on the permitting of disposal wells or otherwise to assess any relationship between seismicity and the use of disposal wells, which has resulted in some states restricting, suspending or shutting down the use of such injection wells temporarily or permanently. We continue to pursue alternative technologies to disposal, including desalination and recycling technologies, which we

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believe will be a critical part of the future of produced water handling, particularly in regions that are likely to experience increased regulation of water use and produced water handling activities.

Water Discharges

The Clean Water Act (“CWA”), Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other oil and gas wastes, into regulated waters and impose requirements affecting our ability to conduct activities in waters and wetlands. Pursuant to the CWA and analogous state laws and regulations, permits must be obtained to discharge pollutants into regulated waters, including discharge of stormwater or discharge into ground water. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The scope of these regulated waters has been subject to controversy and revisions in recent years. To the extent any rule or regulation expands the scope of the CWA’s jurisdiction, we and our customers could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Additionally, many states have similar requirements that apply to state waters where federal jurisdiction ends, and as a result, under most circumstances, discharges of pollutants reaching any permanent waterbodies will likely be regulated. If our operations cause a release of oil or other wastes into regulated waters, we could also become liable for clean-up costs and various damages under the OPA. Notably, the scope of the OPA includes certain hazardous wastes that are exempt from regulation under CERCLA and RCRA, such as wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a spill, rupture or leak of hydrocarbons, including in produced water, from a well, storage tank, or container. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA, OPA, and analogous state laws and regulations. To the extent the scope of the CWA’s or the OPA’s jurisdiction is expanded in areas where we or our customers operate, it could impose additional permitting and other obligations on us and our customers, and we could face increased costs and delays with respect to obtaining permits. Such developments could also increase compliance expenditures or mitigation costs, contribute to delays, restrictions, or cessation of the development of projects, and also reduce the rate of production of oil and natural gas from producers with whom we have a business relationship and, in turn, could have a material adverse effect on our results of operations, cash flows and financial position.

Air Emissions & Climate Change

The federal Clean Air Act (the “CAA”) and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us or our customers to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain or renew permits has the potential to delay our customers’ development of oil and gas projects. Failure to obtain, maintain, or comply with a permit could result in the imposition of administrative, civil and criminal penalties.

In addition, in recent years concerns over the risk of climate change have generally increased the focus by global, regional, national, state and local regulators to reduce emissions of greenhouse gases (“GHGs”); however, presently, no comprehensive climate change legislation has been implemented at the federal level in United States. Nevertheless, several states and geographic regions in the United States have adopted legislation and regulations to address GHG emissions, primarily through the development of emission inventories or regional GHG cap-and-trade programs. Independent of the U.S. Congress, the EPA has adopted regulations controlling GHG emissions under its existing authority under the CAA. Our customers’ operations are subject to such GHG emissions regulations. For example, the EPA previously finalized New Source Performance Standards, known as Subpart OOOO, that require certain new, modified or reconstructed facilities in the oil and gas sector to reduce methane gas and volatile organic compound emissions by using certain equipment-specific emissions control practices. However, in March 2025, the EPA announced plans to reconsider its methane regulations and issued an interim final rule delaying implementation of its most recent methane standards, and has separately proposed to repeal or otherwise modify multiple other rules relating to GHG emissions in line with the Trump Administration’s deregulatory agenda. Litigation challenging the EPA’s interim final rule extending such compliance deadlines for new and existing oil and gas sources remains pending, and we cannot predict whether or not the current Administration’s deregulatory efforts will ultimately be successful.

Separately, the federal Bureau of Land Management (“BLM”) previously finalized a rule that established, among other things, requirements to reduce methane emissions arising from venting, flaring and leakage from oil and gas production activities on onshore federal and American Indian lands. Litigation challenging the rule was held in abeyance in March 2025, pending review of the rule by the Trump Administration. Additionally, in November 2025, the BLM announced it would delay enforcement of two provisions of the rule while underlying review and revisions are considered. Uncertainty exists with respect to future implementation of the rule. However, given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility.

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At an international level, the United States has historically participated in the Conferences of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”), and agreed to commitments from the Paris Agreement, requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020, and the Global Methane Pledge. More recently, however, on January 20, 2025, President Trump issued an executive order that initiated the process to withdraw the United States from the Paris Agreement, mandating the end of the United States’ financial commitments under the UNFCCC. While it is not possible at this time to predict how any such actions may impact our business, the withdrawal of the United States from the Paris Agreement may animate stronger actions by various other policymakers at the local, state, or regional levels, including making commitments to contribute to meeting the goals of the Paris Agreement.

Various policymakers have also adopted, or are considering adopting, laws regarding GHG emissions or other climate matters. For more information, see our risk factor titled “The results of operations of our customers may be materially impacted by efforts to transition to a lower-carbon economy, which could have a material adverse effect on our business, results of operation, cash flows and financial position.” Any future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers’ equipment and operations could require us or our customers to incur compliance costs or experience delays or restrictions in permitting new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil that is produced by our customers and could reduce the demand for our services.

Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere are expected to produce significant physical effects as a result of climate change, such as increased frequency and severity of storms, floods and other climatic events, as well as contribute to various chronic changes to meteorological and hydrological patterns. If any such effects were to occur, or if additional regulations were adopted in response to or anticipation of such effects, they could have an adverse effect on our and our customers’ operations, and could reduce demand for our services, which could have a significant adverse effect on us.

Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, including oil and gas, from low permeability formations, including shales. The process involves the injection of water, sand and chemicals under pressure into targeted formations to fracture the surrounding rock and stimulate production. Our customers regularly use hydraulic fracturing as part of their operations. Hydraulic fracturing is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and gas commissions and similar agencies. However, several federal agencies, such as the EPA and the BLM, have conducted investigations or asserted regulatory authority over certain aspects of the process. Also, from time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing, including the underground disposal of fluids or propping agents associated with such fracturing activities and the disclosure of the chemicals used in the fracturing process.

A number of states have adopted, and other states are considering adopting, regulations imposing new permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could impose moratoriums or elect to prohibit high-volume hydraulic fracturing altogether. Also, local governments could seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

If new or more stringent laws or regulations relating to hydraulic fracturing are adopted at the federal, state or local levels, our customers’ fracturing activities could become subject to additional permit requirements, reporting requirements, operational restrictions, permitting delays or additional costs. Any such laws or regulations could adversely affect the determination of whether a well is commercially viable and reduce the amount of oil and gas that our customers are ultimately able to produce in commercial quantities, and thus significantly affect our business. Such laws and regulations could also materially increase our cost of business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Protected Species

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”). Many states also have analogous laws designed to protect endangered or threatened species and migratory birds. The designation of previously unlisted species as endangered or threatened could cause us to incur additional costs or cause our or our customers’ operations to become subject to operating restrictions or bans or limit future development activity in affected areas. For instance, in May 2024, the United States Fish and Wildlife Service (“FWS”) designated the dunes sagebrush lizard (“DSL”), found in certain areas of southeastern New Mexico and adjacent portions of Texas, as endangered under the ESA. If additional restrictions are imposed on oil and gas operations in the Permian Basin, pursuant to, for example, new or expanded habitat designations, it could cause us or our customers to incur additional costs or become subject to operating restrictions or bans in the affected areas. Such new operating restrictions or bans affecting our customers’ operations could indirectly affect our financial performance and results of operations by potentially decreasing demand for our services. However, as part of a series of executive orders and other actions, President Trump declared a “national energy emergency” directing all federal agencies

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with energy projects to use emergency consultation rules to resolve ESA-related issues. Furthermore, with respect to the DSL, a bill was introduced into the U.S. Congress to permanently delist the species and prevent it from ever being listed as threatened or endangered again. Additionally, in April 2025, the FWS issued a proposed rule proposing to revoke the USFWS regulations that include within the definition of “harm” under the ESA certain habitat modifications (a “significant habitat modification or degradation where it actually kills or injures wildlife by significantly impairing essential behavioral patterns, including breeding, feeding or sheltering”). While it is not yet possible to determine how such actions may impact our and our customers’ businesses, such federal actions may prompt more protective laws and regulations to be advanced at the state and local level.

National Environmental Policy Act

Major federal actions, such as the issuance of permits associated with construction, can require the completion of certain reviews under the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Army Corps of Engineers, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delays in the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the abandonment of proposed projects, which could directly and indirectly affect our financial performance and results of our operations.

Following an Executive Order from President Trump, on February 25, 2025, Council on Environmental Quality (“CEQ”) published an interim final rule, effective April 11, 2025, removing CEQ’s NEPA implementing regulations. Since that time, many federal agencies have updated or begun the process of preparing their own new or updated NEPA-implementing rules and procedures. In May 2025, CEQ withdrew its interim guidance on considering GHG emissions and climate change under NEPA. And, in September 2025, CEQ issued guidance and an updated template for NEPA implementation procedures to provide clarity to federal agencies and promote consistency in NEPA implementation.

Future development and production activities and plans on federal lands may require governmental approvals that could be subject to the requirements of NEPA in the future. There has been litigation regarding the environmental review requirements of NEPA. On May 29, 2025, the U.S. Supreme Court unanimously decided to limit environmental reviews for major infrastructure projects. In particular, the U.S. Supreme Court’s decision reduces the scope of reviews under NEPA only to the immediate impacts of a proposed project. The impact of this decision or any future litigation regarding NEPA is unknown at this time and, accordingly, there may be uncertainty as to the NEPA requirements applicable to future development and production activities that require NEPA review, which could directly and indirectly affect our financial performance and results of our operations.

Occupational Safety Health Act

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Employees

As of December 31, 2025, we had approximately 540 employees providing full-time, direct support to our operations. We believe we have a satisfactory relationship with our employees.

Organizational Structure; Availability of Information

WaterBridge was formed on April 11, 2025 as a Delaware limited liability company. We are a holding company whose principal asset is membership interests in OpCo. We are also the sole managing member of OpCo. Our principal executive office is located at 5555 San Felipe Street, Suite 1200, Houston, Texas 77056.

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The following diagram reflects our current simplified organizational structure as of December 31, 2025.

*This diagram is provided for illustrative purposes only and has been simplified by not depicting each individual operating subsidiary.

Our website is located at www.wbinfra.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and filings and amendments thereto filed or furnished with the SEC are available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are filed with or furnished to the SEC. Information contained on our website is not incorporated into this Annual Report or on our other filings with the SEC. Our filings are available in hard copy, free of charge, by contacting us at 5555 San Felipe Street, Suite 1200, Houston, Texas 77056, Attention: Investor Relations, telephone: (713) 230-8864. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Also posted on our website under “Investor Relations—Governance—Governance Documents,” and available in print upon request made by any shareholder to the Investor Relations Department, are our Code of Business Conduct and Ethics and Whistleblower Policy and Corporate Governance Guidelines, as well as our charter for our Audit Committee. Within the time period required by the SEC, the New York Stock Exchange (the “NYSE”), NYSE Texas, Inc. (“NYSE Texas”), as applicable, we will post on our website any modifications to the foregoing governance documents and any waivers applicable to senior officers as defined in the applicable governance document, as required by the Sarbanes-Oxley Act.

We webcast our earnings calls and certain events we participate in or host with members of the investment community on our investor relations website. Additionally, we provide notifications of news or announcements regarding our financial performance, including SEC filings, investor events and presentations and press and earnings releases, as part of our investor relations website. We intend for our website to be a forum of public dissemination for purposes of Regulation FD.