An Overview of Salt Water Disposal

Over the last 12 years the oilfield waste water disposal industry has grown exponentially, both on an absolute basis, and by rank of its importance/size among the oilfield services. This growth has been largely driven by the increased volumes of waste water generated in the production of oil from shale plays. This post discusses the basics of salt water disposal which has become so important given the rise of hydraulic fracturing.

The Impact of the Shale Boom

The shale revolution, starting in the Bakken formation in 2007 and ramping-up in the Eagle Ford and Permian basins beginning in 2011, was largely propelled by the combination of horizontal drilling and hydraulic fracturing (commonly, “fracking”).

Over the last 12 years the oilfield waste water disposal industry has grown exponentially

Because shale hydrocarbon deposits are located in tight-rock formations, the naturally occurring produced water (water that is naturally present in oil and gas formations, referred to as “formation water”) to oil ratio is lower than in conventional reservoirs that have increased pore space and connectivity. To economically produce oil/gas from unconventional reservoirs composed of shale or tight (low permeability) rock, the reservoir must be stimulated by a process such as fracking.

Fracking increases the hydrocarbon flow capacity by creating cracks (fractures) that are then filled with a permeable media (proppant) that allows oil/gas to move out of the rock formation and into the wellbore. Fracking requires very large volumes of water to be pumped into the reservoir to carry proppant and other fluids into the fractures. That water flows back after the frack is complete. When added to naturally occurring produced water, and produced water resulting from other stimulation operations (water flooding and/or steam flooding), fracking results in water/oil production ratios that can exceed 10:1. This results in enormous volumes of produced water (tens of billions of gallons each year), some of which is utilized in additional stimulation activities, but much of which must be disposed of.

The Need for Disposal and Means

Produced water (also referred to as “brine”) contains a number of contaminants, both naturally occurring (salt, oils/grease, and organic/inorganic chemicals) and chemical additives utilized in the drilling and operation of the well. Even after treatment to extract some of the impurities, the resulting water (referred to as “salt water”) contains significant contaminants and must be handled carefully and disposed of properly.

The method of salt water disposal depends on a number of factors: geology, technology, area infrastructure, and the prevailing climate in the area

The method of salt water disposal depends on a number of factors, notably the geology of the formation from which the water is produced, as well as the technology and infrastructure available in the area and the prevailing climate in the area. While some particularly arid regions allow for disposal via evaporation from large holding pits, most salt water is disposed of at specialty disposal sites where the salt water is injected by way of a disposal well (salt water disposal, or SWD wells) into natural underground formations.

Geographic Distribution

A large portion of the U.S. SWD facilities are located in Texas due to the disproportionate amount of shale acreage in the state and the SWD conducive geology in Texas. Far fewer SWD facilities are located in other shale areas, such as the Marcellus and the Bakken, due to less favorable geological formations in those areas. The Marcellus in particular lacks favorable formations for disposal purposes with the number of recent operating SWD wells in Pennsylvania at less than 100, compared to more than 12,000 SWD wells in Texas.

Location Selection

When siting a SWD facility, a number of factors come into play, including demand, proximity, and geology.

Demand

Demand might seem to be an easy consideration – just locate the facility in an area where oil and gas operators are generating large volumes of waste water. However, oil production and, therefore, waste water production, in particular areas can vary widely over both short and long periods of time.

When siting a salt water disposal facility, a number of factors come into play, including demand, proximity, and geology

Production in a particular field naturally declines over time as reserves are depleted, but can increase again with technology advances. Oil prices dictate if it’s economically viable for continued production in a particular field, with oil prices being notoriously unstable compared to many commodities due to supply and demand, country-specific political forces and even geopolitical forces.

Proximity

Proximity to the area of waste water disposal demand is important. Proximity can be viewed both as distance and as the availability of the appropriate infrastructure (roads) to efficiently transport the waste water from the production site to the disposal site. Transporting oilfield waste water is a significant expense and for obvious reasons is tied directly to the transport distance. Many oil and gas wells are located in remote areas where the existence of roads, or lack thereof, plays into the SWD location decision.

Geology

Surface location isn’t the only consideration when choosing a SWD facility site. The location’s geology is just as important.

A porous and permeable, non-hydrocarbon bearing zone that is not considered an aquifer under the UIC program is one possible geological formation appropriate for salt water disposal. A second possibility would be a previously depleted oil and gas zone, that is both porous and permeable.

For either option, a clear barrier must exist between the target zone and all underground sources of drinking water ("USDWs"), and the drill area needs to be generally clear of any significant geologic faults.

Construction

Salt water disposal wells have very specific construction requirements in order to ensure that there will be no contamination of the area USDW or the environment in general. For example, in Texas, salt water disposal wells are constructed with three layers of casing to ensure that groundwaters are not impacted. The surface casing (the first layer) is a cement encased steel pipe that extends from ground level to a specific minimum distance below the deepest USDW level. The production casing, a pipe that is permanently cemented in the wellbore, is the second casing layer and runs the length of the well. The third protection layer contains the injection tubing string that guides the injected water to the bottom of the well for discharge into the target formation. This construction provides the most secure means of disposing of salt water developed to date in that all three pipes would have to fail at the same time for surrounding groundwater to be contaminated.

Regulation

Regulation of SWD facilities is significant and thorough. The 1974 Safe Drinking Water Act required the U.S. Environmental Protection Agency ("EPA") to set minimum requirements for salt water injection wells, along with many other wells utilized in disposing of various hazardous and nonhazardous wastes. These EPA established requirements are generally referred to as the Underground Injection Control ("UIC") program. Since the inception of the UIC program, wells classified for injection of oilfield waste liquids have been used to inject over 30 trillion gallons of oilfield salt water without endangering USDWs.

Regulation of salt water disposal facilities is significant and thorough

The UIC program established the necessary requirements for a state to enforce the program within their jurisdiction. In order to assume primacy, the states must demonstrate that their program for UIC enforcement meets the minimum requirements established by the UIC program. At the current time, 33 states and three U.S. territories have primacy for the UIC wells in their jurisdiction. Seven states share primacy with the EPA with the state typically handling one or more classifications of wells and the EPA overseeing the remaining classifications. The EPA maintains primary enforcement of the UIC programs in the remaining ten states and three U.S. Territories.

Economics

A commercial SWD well operator will typically charge between $0.50 and $2.50 per barrel of salt water. The wide range is a simple result of supply and demand. In areas where disposal demand is low, where SWD wells are abundant and have significant capacity availability, the per barrel rate trends towards the lower end of the range. That contrasted with areas where demand for salt water disposal is strong, but the disposal infrastructure, or capacity, is lacking, or the geology places limits on the injection of oilfield waste water, the commercial SWD operators are able to charge fees in the upper end of the range.

A commercial salt water disposal well operator will typically charge between $0.50 and $2.50 per barrel of salt water

Another consideration associated with disposal of oilfield waste water is the cost of transporting the salt water from the well site to the disposal site. Typically the transportation of waste liquids will cost the operator $1.00 per barrel per hour of transport time. In an area of SWD facility abundance, such as the Barnett shale, transport expense might only add $0.50 per barrel to salt water disposal expenses. However, in areas with few SWD facilities, such as some Pennsylvania locations, oilfield waste fluids have to be trucked to disposal facilities in Ohio or West Virginia, with the cost adding $4.00 to $6.00 per barrel.

Conclusion

Watch this space for future blog posts addressing the valuation issues faced by companies operating in this space.

Mercer Capital has significant experience valuing assets and companies in the oil and gas industry. Because drilling economics vary by region, as touched on above, it is imperative that your valuation specialist understand the local economics impacting your company. Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas related valuations have been used to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.

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Haynesville Shale M&A Update: 2025 in Review

Key TakeawaysHaynesville remains a strategic LNG-linked basin. 2025 transactions emphasized long-duration natural gas exposure and proximity to Gulf Coast export infrastructure, reinforcing the basin’s importance in meeting global LNG demand.International utilities drove much of the activity. Japanese power and gas companies pursued direct upstream ownership, signaling a shift from traditional offtake agreements toward greater control over U.S. gas supply.M&A was selective but meaningful in scale and intent. While overall deal volume was limited, announced transactions and reported negotiations reflected deliberate, long-term positioning rather than opportunistic shale consolidation.OverviewM&A activity in the Haynesville Shale during 2025 was marked by strategic, LNG-linked transactions and renewed international investor interest in U.S. natural gas assets. While investors remained selective relative to prior shale upcycles, transactions that did occur reflected a clear pattern: buyers focused on long-duration gas exposure, scale, and proximity to Gulf Coast export markets rather than short-term development upside.Producers and capital providers increasingly refocused efforts on the Haynesville basin during the year, including raising capital to acquire both operating assets and mineral positions. This renewed attention followed a period of subdued transaction activity and underscored the basin’s continued relevance within global natural gas portfolios.Although the Haynesville did not experience the breadth of consolidation seen in some oil-weighted plays, the size, counterparties, and strategic motivations behind 2025 transactions reinforced the basin’s role as a long-term supply source for LNG-linked demand.Announced Upstream TransactionsTokyo Gas (TG Natural Resources) / ChevronIn April 2025, Tokyo Gas Co., through its U.S. joint venture TG Natural Resources, entered into an agreement to acquire a 70% interest in Chevron’s East Texas natural gas assets for $525 million. The assets include significant Haynesville exposure and were acquired through a combination of cash consideration and capital commitments.The transaction was characterized as part of Tokyo Gas’s broader strategy to secure long-term U.S. natural gas supply and expand its upstream footprint. The deal reflects a growing trend among international utilities to obtain direct exposure to U.S. shale gas through ownership interests rather than relying solely on long-term offtake contracts or third-party supply arrangements.From an M&A perspective, the transaction highlights continued willingness among major operators to monetize non-core or minority positions while retaining operational involvement, and it underscores the Haynesville’s attractiveness to buyers with a long-term, strategic view of gas demand.JERA / Williams & GEP Haynesville IIIn October 2025, JERA Co., Japan’s largest power generator, announced an agreement to acquire Haynesville shale gas production assets from Williams Companies and GEP Haynesville II, a joint venture between GeoSouthern Energy and Blackstone. The transaction was valued at approximately $1.5 billion.This acquisition marked JERA’s first direct investment in U.S. shale gas production, representing a notable expansion of the company’s upstream exposure and reinforcing JERA’s interest in securing supply from regions with strong connectivity to U.S. LNG export infrastructure.This transaction further illustrates the appeal of the Haynesville to international buyers seeking stable, scalable gas assets and highlights the role of upstream M&A as a tool for portfolio diversification among global utilities and energy companies.Reported Negotiations (Not Announced)Mitsubishi / Aethon Energy ManagementIn June 2025, Reuters reported that Mitsubishi Corp. was in discussions to acquire Aethon Energy Management, a privately held operator with substantial Haynesville production and midstream assets. The potential transaction was reported to be valued at approximately $8 billion, though Reuters emphasized that talks were ongoing and that no deal had been finalized at the time.While the transaction was not announced during 2025, the reported discussions were notable for both their scale and the identity of the potential buyer. Aethon has long been viewed as one of the largest private platforms in the Haynesville, and any transaction involving the company would represent a significant consolidation event within the basin.The reported talks underscored the depth of international interest in Haynesville-oriented platforms and highlighted the potential for large-scale transactions even in an otherwise measured M&A environment.ConclusionWhile overall deal volume remained selective, the transactions and reported negotiations in 2025 reflected sustained global interest in U.S. natural gas assets with long-term relevance. Collectively, the transactions and negotiations discussed above point to a Haynesville M&A landscape driven less by opportunistic consolidation and more by deliberate, long-term positioning. As global energy portfolios continue to evolve, the Haynesville basin remains a focal point for strategic investment, particularly for buyers seeking exposure tied to U.S. natural gas supply and LNG export linkages.

An Overview of Salt Water Disposal

The Impact of the Shale Boom

The Need for Disposal and Means

Geographic Distribution