[co-author: Brenda Eckert]

Is it mine? Is what’s in it mine too? The fight over produced water has become a contentious issue in the oil patch. Primarily, because it is a new and unforeseen source of revenue for operators and landowners. Oil and gas wells require water – lots of it, which results in the recovery of much water. As water treatment and recycling improves, fresh water grows increasingly scarce and regulation of fresh water increases these questions become more important. No doubt, if we could see disputes in the future, we would draft deeds and leases differently today. Therefore, until either a legal resolution is achieved, or the ability to monetize produced water disappears (unlikely) more and more disputes are certain to arise.

What was once considered a liability has now become an asset; the question is whose asset is it? This paper sets out to provide a general overview of how one of oil and gas’s biggest liabilities has quickly become—and I argue will continue to become—one of its greatest assets. We will examine: (1) what is produced water; (2) legislation surrounding produced water (specifically HB 2767 and HB 3246); (3) the present litigation landscape; (4) the impending constitutional fight, and (5) a discussion of the ownership of the constituent elements in the water (e.g. lithium).

Rags to Riches—What is Produced Water and Who Actually Owns It?

Generally speaking, produced water is water that comes out of the well with the crude oil during crude oil production. This produced water can include water existing in the shale formation, as well as water injected into the wellbore during production that is now flowing back. But is the produced water existing naturally within the shale formation properly considered groundwater? The Texas Water Code seems to answer “yes.” Specifically, the Texas Water Code further defines groundwater as “water percolating below the surface of the earth.”^[1] And, it is well established in Texas that groundwater is part of the surface estate, owned by the surface owner as a vested property right.^[2] Nevertheless, until a few years ago, the fight over produced water was not over who “wanted” to take it, but rather over who “had” to take it.

Produced water contains soluble and non-soluble oil/organics, suspended solids, dissolved solids, and various chemicals used in the production process. The ratio of produced water to oil varies from well to well and over the life of the well. Generally, this ratio is more than 3 parts of water per 1 part of oil, and in some parts of the world can exceed a ratio of 20 to 1. Quantifying and defining produced water can be difficult because both flowrate and composition change over the life of the well. It is currently estimated that the United States generates some 20 to 25 billion barrels of produced water each year. And, now that a market has been established, it is easy to see how a liability has now become an asset.

Traditionally, produced water was treated as a waste byproduct obligating operators to dispose of it in accordance with applicable disposal requirements. In 2013, the industry standard practice of obligating operators to dispose of produced water (typically by injecting the Produced Water into a disposal well) was codified by HB 2767.^[3] More recently, in 2019 HB 3246 added language which purportedly transferred not only liability, but ownership of the produced water to the operator.^[4]

But between 2013 and 2019 there were significant shifting economic opportunities with respect to produced water. By 2019, water haulers had already begun monetizing produced water by either dedicating it to companies who treat and sell recycled water, or treating and selling the recycled water themselves. Operators quickly followed suit. By treating and monetizing produced water, a question arose—who is entitled to the proceeds of sale from the produced water? Operators argue that historical practices, the language of the oil and gas lease and the recently enacted HB 3246 support their claims. Surface owners argue that since correlative rights are usufructuary, no ownership rights inure to the Operator in groundwater.

Since 2022, Operators have relied on the Texas Natural Resource Code §122 and have maximized the yield from produced water by investing millions of dollars in water recycling technology and in pipelines spanning the fracking fields. This has also compelled some Operators to import produced water from New Mexico and Louisiana.^[5]

The issues discussed in this paper do not apply to situations where the Operator has purchased groundwater for its operations or the underlying lease grants to the Operator the rights in groundwater and lithium.

1. Correlative Rights and the Implied Rights Protecting the Surface Estate

Texas recognizes the in-place ownership of minerals. Prior to severance, an owner (fee simple) enjoys proprietary rights and constitutional protections for all resources located within its boundaries. As in other states, Texas allows the surface and mineral interests to be severed. Upon severance, traditionally, the mineral estate possesses the hydrocarbons in place, while the surface estate retains all groundwater. Nevertheless, these divisions are always subject to the express terms of the conveying instrument. After severance, the mineral owner possesses the dominant interest over the surface estate. The mineral estate’s dominance is limited. It is not an ownership interest, but a usufructuary right subject to four important implied doctrines: the accommodation doctrine, the reasonable and non-negligent use of the surface, use as opposed to ownership, and use of the surface must benefit the mineral estate. For the purpose of this analysis, the most significant are the distinctions between use and ownership, and the implied doctrines that surface use must benefit the mineral estate.

2. The Implied Right to Use—Not Own—the Surface

Texas law establishes that a mineral owner holds an implied right of surface use, not ownership. While a mineral owner may use such part and so much of the surface as is reasonably necessary to comply with the terms of the mineral lease and effectuate its purpose, the implied right does not grant ownership of the surface to the mineral owner.

The Texas Supreme Court has made this distinction in numerous decisions often in passing and in the context of defining the implied rights of mineral owners. In Getty Oil, the court held “the oil and gas estate is the dominant estate in the sense that use of as much of the premises as is reasonably necessary to produce and remove the minerals is held to be impliedly authorized by the lease.”^[6] Similarly, in Sun Oil, the court upheld the dominance of the mineral owner’s rights over the servient, surface estate, but tempered its holding by noting the implied right was limited to “use of such part and so much of the premises as is reasonably necessary to effectuate the purposes of the lease.”^[7] In the cases of Brown v. Lundell^[8] and Humble Oil & Refining Company v. Williams^[9] the court held, respectively, that the mineral owner had the right to “use so much of the land . . . as is reasonably necessary to comply with the terms of the lease,” ^[10] and “use as much of the premises, and in such a manner, as was reasonably necessary to comply with the terms of the lease and to effectuate its purposes.”^[11]

The Texas Supreme Court’s language is significant for two reasons, each of which represents a significant impediment to widespread acceptance, implementation, and use of water treatment technologies throughout the state. First, the rights of mineral owners are described in the context of use, not ownership. In each instance, the court’s recognition of a mineral owner’s implied right of surface use implicitly recognizes the surface estate owner’s ownership of the surface. Second, the court’s language confines surface use to effectuating the purposes of the mineral lease. In so doing, the court prohibits a mineral owner from using the surface in any manner that does not benefit the mineral estate of the subject tract and lands pooled therewith. This latter impediment is discussed in further detail in the following section.

The sale of an asset cannot be divorced from the issue of ownership; i.e., one must own something in order to sell it. A mineral owner’s right to water is usufructuary—giving it a present right of use only. Upon the expiration of the mineral lease and absent language to the contrary, the fee simple determinable interest held by the mineral lessee automatically reverts to the mineral estate owner, with it all rights, implied or otherwise. Notwithstanding the court’s likely deference toward the reasonably necessary use of water in hydraulic fracturing, mineral owners utilizing water treatment technologies to treat wastewater would ultimately be prevented from realizing any economic benefit from the sale of treated wastewater since such wastewater would remain the property of the surface estate owner. Without ownership, a mineral owner must acquire the rights to the produced water from the surface estate owner in order to sell treated wastewater and derive any economic benefit from the sale.

Except with regard to its own operations, without ownership, mineral owners are unlikely to be incentivized to adopt water treatment technologies. Furthermore, confirmation in Edwards Aquifer Authority that groundwater in place is a vested real property right subject to constitutional protection would mean that Texas may not sustain a mineral owner’s claim to ownership in treated wastewater produced from its well bore, where denial of the surface estate owner’s ownership would give rise to a takings claim.^[12]

3. Surface Use Must Benefit the Dominant Estate

Another limitation on the implied right of surface use confines use of the surface to that which benefits the mineral estate of that tract only and lands pooled therewith. Absent language to the contrary, a mineral owner is prohibited from using the surface of one mineral estate for the benefit of another. Since the purpose of a mineral lease is to enable the mineral owner to carry out mineral exploration, production, and development activities on the subject tract, the fee simple owner must have impliedly intended that a right to use the surface pass to the mineral owner. It follows then that use of the surface cannot be for the benefit of activities or any other purposes that do not benefit the mineral estate of the subject tract.

Texas cases have consistently held that the implied right of surface use is limited to that which benefits the mineral estate of the subject tract only, or acreage pooled therewith. In Robinson v. Robbins Petroleum Corporation, Inc.^[13] the mineral owner sought to undertake waterflood operations to re-pressure the formation.^[14] In doing so, Robbins Petroleum produced saltwater from the surface owned by Robinson, which Robinson acquired subject to the existing Wagoner oil and gas lease.^[15] Saltwater produced from the surface, which Robbins Petroleum included in a secondary recovery waterflood unit, was utilized to drive waterflood operations throughout the entire, field-wide unit, portions of which did not benefit the Wagoner lease.^[16] Robinson argued the use of his surface estate was unreasonable to the extent that it benefited other mineral estates within the unit and not included in the Wagoner lease.^[17] The court, distinguishing its ruling in Sun Oil as applicable to circumstances where use of the surface was for waterflood operations benefiting a single mineral estate only, agreed, holding:

Even if the waterflood operation is reasonably necessary to produce oil from premises of the Wagoner lease, it does not follow that the operator is entitled to the use of Robinson’s surface for the secondary recovery unit that includes acreage outside the Wagoner lease. . . Nothing in the Wagoner lease or the reservation contained in Robinson’s deed authorized the mineral owner to increase the burden on the surface estate for the benefit of additional lands.

Robinson, as owner of the surface, is entitled to protection from uses thereof, without his consent, for the benefit of owners outside of and beyond premises and terms of the Wagoner lease.^[18]

Likewise, in TDC Engineering, Inc. v. Dunlap^[19] a Texas appellate court held the mineral owner had the right to dispose of saltwater in injection wells located on the surface from which the saltwater was produced, but did not have the right, absent language to the contrary, to dispose of such saltwater on land covered by another mineral lease.^[20]

Where the express terms of a mineral lease permit pooling of tracts owned by separate surface estate owners, Texas cases have upheld a mineral owner’s implied right of surface use, but maintained that such surface use must be for the exclusive benefit of the collective mineral estate. In Delhi Gas Pipeline Corporation v. Dixon^[21] the court confirmed a mineral owner’s use of the surface was reasonable where the surface was included in a pooled unit as expressly permitted by the terms of the mineral lease. Delhi Gas laid a gas gathering pipeline, a portion of which ran across the surface owned by Dixon, to transport natural gas from a well located on another tract within the unit.^[22] In reaching its decision, the court acknowledged that the pipeline served only to transport gas from the well within the unit, and held that the pipeline did not violate Dixon’s rights even though transportation of the gas benefited a tract other than his own.^[23] In so holding, the court stated the mineral owner had “the right to use as much of the premises as is reasonably necessary to produce and remove the oil, gas, and other minerals [including] the right to use as much of the surface estate as is reasonably necessary to produce oil or gas from a well located on a production unit with which the tract has been unitized.”^[24]

Similarly, in Miller v. Crown Central Petroleum Corporation^[25] the Millers purchased the surface of two tracts subject to an existing oil and gas lease, which permitted the pooling of lands.^[26] Following several years of oil production from the formation, Crown Central obtained approval from all mineral owners to undertake waterflood operations.^[27] Without the Millers’ approval, Crown Central buried a pipeline beneath the surface of the Millers’ tracts to transport saltwater to another tract included within the waterflood operation.^[28] Finding that the language of the mineral lease expressly granted Crown Central the right to pool the Millers’ tracts with other lands, the court held there was insufficient evidence to support a finding that Crown Central acted unreasonably, since its use of the surface benefited the mineral estate as provided by the mineral lease.^[29]

Application of this limitation to treated wastewater means that, notwithstanding the implied right of surface use, the use of such wastewater is confined to that which benefits the mineral estate of the subject tract only and lands pooled therewith. The implied rights limit the ability of mineral owners to take advantage of treated wastewater. It does not encourage them to hydraulically fracture additional wells or utilize such wastewater in other oilfield operations, unless it benefits the subject mineral estate and lands pooled therewith. However, the use of treated wastewater would be prohibited and unreasonable to the extent it benefited a tract other than the tract from which it was produced, or was used for purposes unrelated to effectuating the mineral lease.^[30]

Legislative History and Current Controversies

1. Legislative History of Tex. Nat. Res. Code § 122

In 2013, the Texas Legislature passed HB 2767—adding Section 122 to the Natural Resources Code—to encourage the recycling of produced water. Prior to HB 2767, the ownership of oil and gas waste was not prescribed by the courts or the legislature, mainly because it was viewed as just that—waste to be disposed. Accordingly, the legislature first passed HB 2767 to clear up any ambiguity and provide recyclers comfort that once they take possession of oil and gas waste, they own it. Notably, Section 122 includes “produced water” in the definition of “fluid oil and gas waste” that is governed by the statute. Section 122 provides that when a person takes possession of produced water to treat it for a subsequent beneficial use, that produced water becomes that person’s property.

In 2019, Section 122 was amended by HB 3246. HB 3246 expressly provided a carve-out for “an oil or gas lease” and “surface use agreement[s]”. Moreover, HB 3246 changed Section 122.002 to include operators that reuse produced water for beneficial use as owners of fluid oil and gas waste. While sparse, case law strongly suggests that produced water is part of the groundwater estate and thus the property of the surface owner. HB 2767 and 3246 then, in effect, transfers ownership of what is a real property right from one party (the surface owner) to another (the operator or recycler).

As previously discussed, the dominant mineral estate comes with an implied right to use as much of the surface—including groundwater—as is reasonably necessary to extract and produce the minerals. As part of that implied right, the operator has a duty to dispose of the waste, including the produced water, that is a byproduct of the oil and gas process. Typically this disposal is accomplished when the produced water is treated and injected into an injection well. Nevertheless, one man’s trash is another man’s treasure, and now that produced water has become a commodity with economic value, surface owners want—and deserve—to be compensated. Where surface owners or groundwater lessees are not compensated, disputes are sure to arise.

2. Present Legislative Landscape—The Texas Produced Water Consortium

The Texas Produced Water Consortium (TXPWC) was established on June 18, 2021, by Senate Bill 601with the purpose of bringing together information and resources to study the economics and technologies related to beneficial uses of produced water. Texas Tech University was charged with bringing together the stakeholders and producing a report that would suggest ways to “better enable the beneficial uses of produced water.”^[31] The TXPWC submitted a report to the Texas Legislature in September 2022.

Both the creation of the Consortium and the report they authored provides stakeholders a limited view of how the Texas Legislature might modify or expand the Natural Resource Code pertaining to produced water. The recycling of produced water rather than depleting the virgin groundwater is a strong motivation for the government to incentivize recycling of the produced water. However, the stakeholder operators were practical to ensure that the TXPWC report understood the cost-benefit of recycling large amounts of produced water. Even though the Consortium contained legal and policy subcommittees, there were not concrete recommendations pertaining to the legal ownership of produced water as discussed in this article.^[32]

The Consortium will continue its work studying the practice of recycled produced water as long as funding exists. Continuing to monitor its work will allow stakeholders an inside view of the trajectory of legislation on this important topic.

3. Present Litigation Landscape—COG Operating LLC vs. Cactus Water Services, LLC et al.

In COG Operating LLC (“COG”) vs. Cactus Water Services, LLC et al. (“Cactus Water”),^[33] COG acquired oil and gas leasehold rights in 37,000 acres in the Delaware Basin (“COG Leases”). After COG entered the COG Lease, Cactus entered into “Produced Water Lease Agreements” with a surface owner for underground water in depths covering the same acreage covered by the COG Leases. Under the produced water Lease Agreements, Cactus would pay the surface owner a royalty for such water once monetized. Simultaneously, COG received payment for dedicating its produced water to a third-party service provider. Thereafter, Cactus Water made demand on COG’s service providers and COG filed suit. Cactus Water did not dispute COG’s leasehold rights. Rather, Cactus Water claimed COG improperly profited from the sale of produced water rightfully belonging to the surface owner who had already leased the produced water to Cactus. COG argued that as defined by Section 122 of the Texas Natural Resources Code, produced water is not groundwater, but ordinary oil and gas waste. Therefore, COG’s position was that the possessor of the produced water was the owner and party obligated to dispose or treat and reuse the produced water.^[34]

On November 2, 2021, the Reeves County District Court granted COG’s summary judgment, affirming COG’s ownership rights in the subject-produced water and holding that COG: (1) owns, among other things, the products contained in commercial oil and gas bearing formations that are produced from COG wells on four leases, and (2) has the right to exclusive possession, custody, control and disposition of the product stream, which stream includes water produced from COG’s oil and gas wells. The court’s decision was based largely on an examination of the granting clause in the COG Lease which provided COG the right of “investigating, exploring, prospecting, drilling, mining and operating for oil and gas and other hydrocarbons” and for “laying pipelines and building tanks, power stations and other structures thereon, to produce, save, take care of, store and treat products produced hereunder, and then transport those products from the land.”

In a 2 to 1 decision issued on July 28, 2023, the Court of Appeals in El Paso affirmed the decision of the trial court. Although the granting clauses in the underlying oil and gas leases do not mention “water,” the leases discuss water in the context of limitation (water use only from COG’s water wells, or consent required to use water). Analyzing the pertinent statutes, the court holds that groundwater and produced water are not the same. Citing Moser, the fact that at the time that the leases were negotiated, the parties were unaware of the pecuniary value of the produced water is irrelevant as to whether the substance is included in the grant or not—and that ownership of the produced water would deprive COG of its investment in the water infrastructure. The court also said that the lessor could have expressly reserved produced water in the granting clause of the lease, but it did not do so.

The dissent took the opposite approach. It said that groundwater is owned by the surface owner and that the implied correlative rights are rights of use, not ownership. The dissent opined that there is no distinction between groundwater and produced water. The term “water” is nowhere found in the lease granting clause, and that a substance cannot be conveyed unless expressly granted. No reservation of water was required in the leases when the language of the granting clauses did not convey it. Moreover, the ownership of groundwater does not change when produced from a wellbore even though by law and industry custom, the operator must dispose of it. It should be noted that the issue of a “taking” was not raised by the parties in the case.

The Inevitable Fight Over the Constitutionality of HB 2767 and HB 3246

The question is not “if” but “when” HB 2767 and HB 3246 will be challenged. Unquestionably, the fight over produced water will involve a fight over the constitutionality of this legislation. For many of us in the oil patch, the last time we examined constitutional law—and more specifically regulatory takings under the Fifth Amendment was probably in law school. Add to that, the Supreme Court’s unfortunate admission that “[c]ases attempting to decide when a regulation becomes a taking are among the most litigated and perplexing in current law,”^[35] and the produced water issue thorny. While not exhaustive, the following should serve as a refresher of how both the United States Supreme Court, and Texas Supreme Court have recently addressed regulatory takings.

The Takings Clause of the Fifth Amendment of the United States Constitution, made applicable to the States through the Fourteenth Amendment, provides that private property shall not “be taken for public use, without just compensation.”^[36] The Takings Clause “does not prohibit the taking of private property, but instead places a condition on the exercise of that power.”^[37] In other words, the Takings Clause “is designed not to limit the governmental interference with property rights per se, but rather to secure compensation in the event of otherwise proper interference amounting to a taking.”^[38]

The Texas Constitutional guarantee, though comparable, is worded differently. The Texas Constitution provides that “[n]o person’s property shall be taken, damaged or destroyed for or applied to public use without adequate compensation being made….” The Takings Clause of the Fifth Amendment states: “nor shall private property be taken for public use without just compensation.”^[39] The Texas Supreme Court has acknowledged that “One could argue that the differences in the wording of the two provisions are significant.”^[40]Accordingly, an examination of Federal and Texas law is necessary.

1. Federal Approach

The paradigmatic taking requiring just compensation is a direct government appropriation or physical invasion of private property.^[41] Indeed, until Pennsylvania Coal Co. v. Mahon ^[42] “it was generally thought that the Takings Clause reached only a ‘direct appropriation’ of property, or the functional equivalent of a ‘practical ouster of [the owner’s] possession.’”^[43]

Beginning with Mahon, however, the Court recognized that government regulation of private property may, in some instances, be so onerous that its effect is tantamount to a direct appropriation or ouster—and that such “regulatory takings” may be compensable under the Fifth Amendment. As Justice Holmes’ opined, “while property may be regulated to a certain extent, if regulation goes too far it will be recognized as a taking.”^[44] For this paper, we limit our examination to regulatory takings.

U.S. Supreme Court precedents stake out two categories of regulatory action that generally will be deemed per se takings for Fifth Amendment purposes. First, where government requires an owner to suffer a permanent physical invasion of the owner’s property—however minor—it must provide just compensation.^[45] A second categorical rule applies to total regulatory takings which completely deprive an owner of “all economically beneficial us[e]” of her property.^[46] The Supreme Court held in Lucas that the government must pay just compensation for such “total regulatory takings,” except to the extent that “background principles of nuisance and property law” independently restrict the owner’s intended use of the property.^[47]

Outside these two relatively narrow categories (and the special context of land-use exactions), regulatory takings challenges are governed by the standards set forth in Penn Central Transp. Co. v. New York City.^[48] In Penn Central, the Court acknowledged that it had previously been “unable to develop any ‘set formula’” for evaluating regulatory takings claims but identified “several factors that have particular significance.”^[49] Foremost among those factors are “[t]he economic impact of the regulation on the claimant and, particularly, the extent to which the regulation has interfered with distinct investment-backed expectations.”^[50] Additionally, the “character of the governmental action”—for instance whether it amounts to a physical invasion or instead merely affects property interests through “some public program adjusting the benefits and burdens of economic life to promote the common good”—may be relevant in discerning whether a taking has occurred.^[51] These Penn Central factors—though each has given rise to vexing subsidiary questions—have served as the principal guidelines for resolving regulatory takings claims that do not fall within the physical takings or Lucas rules.^[52]

Although regulatory takings jurisprudence cannot be characterized as unified, the inquiries (reflected in Loretto, Lucas, and Penn Central) share a common goal. And, the Penn Central inquiry turns in large part, albeit not exclusively, upon the magnitude of a regulation’s economic impact and the degree to which it interferes with legitimate property interests. Although the property protection offered under the Texas Constitution differs slightly, Texas Courts still follow and apply the standards laid out in Penn Central.

2. Texas Approach

Unfortunately, takings cases are no more simplified under State Law. In fact, the Texas Supreme Court has called these legal battlefields “a ‘sophistic Miltonian Serbonian Bog.’”^[53] Fortunately, the Court has also acknowledged that “[t]here are small islands in the bog.”^[54] Specifically, Texas Courts follow the Supreme Court’s categories of per se and total regulatory takings.^[55] Texas also recognizes the Supreme Court’s admonition that regulation “effects a taking if [it] does not substantially advance legitimate state interests.”^[56] Otherwise, however, whether regulation has gone “too far” and become too much like a physical taking for which the constitution requires compensation requires a careful analysis of how the regulation affects the balance between the public’s interest and that of private landowners.

In short, both the United States Supreme Court and Texas Supreme Court look to the following factors:

a.“the economic impact of the regulation on the claimant”;

b. “the extent to which the regulation has interfered with distinct investment-backed expectations”; and

c. “the character of the governmental action.”^[57]

Nevertheless, the Courts have cautioned that these factors do not comprise a formulaic test. “Penn Central does not supply mathematically precise variables, but instead provides important guideposts that lead to the ultimate determination whether just compensation is required.” For example, the economic impact of a regulation may indicate a taking even if the landowner has not been deprived of all economically beneficial use of his property. Moreover, the three Penn Central factors are not exclusive in determining whether the burden of regulation ought “in all fairness and justice” to be borne by the public.^[58] Whether a regulatory taking has occurred, “necessarily requires a weighing of private and public interests”^[59] and a “careful examination and weighing of all the relevant circumstances in this context.”^[60] Accordingly, the Texas Supreme Court has said of regulatory takings issues, “we consider all of the surrounding circumstances”^[61] in applying” a fact-sensitive test of reasonableness.”^[62]

Therefore, while determining whether a property regulation is unconstitutional requires the consideration of a number of factual issues and surrounding circumstances. This is because while the appellate courts depend on the district court to resolve disputed facts regarding the extent of the governmental intrusion on the property, the ultimate determination of whether the facts are sufficient to constitute a taking is a question of law.^[63] And, this should not be surprising, after all the Texas Supreme Court already acknowledged the likelihood of this battle when it opined:

Suppose a landowner were prohibited from all access to groundwater. In its brief, the State concedes: “Given that there is a property interest in groundwater, some manner and degree of groundwater regulation could, under some facts, effect a compensable taking of property.” We agree, but the example demonstrates the validity of Day’s claim. Groundwater rights are property rights subject to constitutional protection, whatever difficulties may lie in determining adequate compensation for a taking.^[64]

3. Applicable Analytical Framework

If the Courts decide that title to the produced water belongs to a landowner (or a lessee pursuant to a lease agreement with a landowner), then the laws passed in 2013 and 2019 will have to be narrowly construed to exclude produced water in order to avoid a takings challenge. If “fluid oil and gas waste” includes produced water as stated in the statute, and the Courts disagree and decide produced water is actually groundwater owned by a landowner (or groundwater lessee), then the statute would be an unconstitutional violation of the Fifth Amendment and subject to takings claim. Following the Penn Central factors detailed above provides the authors’ views of how the Courts are likely to look at a produced water takings claim.

a. Deprivation of Economic Use

The first factor to consider is whether all economically viable use of a property has been denied. This determination “entails a relatively simple analysis of whether value remains in the property after the governmental action.”^[65] It is difficult to see how selling and transferring away a surface owner’s water does not deprive them of economic use. In Texas, groundwater is a vested property interest. And, like any vested property interest it is specific, has value, and is transferable. Injecting and back flowing groundwater and renaming it “produced water” does not change title.

Treating produced water is typically a three phase process by which the recycler separates—among other things—raw oil and gas products from water. These minerals are ultimately counted by the operators in total production and sent to the refinery. Simply stated, just because minerals co-mingle with water should not change who holds title—the operator does. Conversely, if the operator uses (but does not own) groundwater—as is its right under an oil and gas lease—why should the water separated from the oil and gas during recycling not be returned to the surface owner?

Prior to the economic viability of produced water, the operator’s use of the water ended once all minerals were extracted. Historic practices then dictated that the water was disposed of through injection into injection wells. Nevertheless, ownership remained unchanged, and through time operators and water recyclers created a market for recycled fracking water. Unquestionably, HB 2767 and HB 3246’s intent was to clarify the responsibility over disposal of produced water. But just as the minerals in produced water have economic value, so does the remaining treated produced water. When that produced water is injected into disposal wells, recycled, sold, or reused by the operator on another lease, the surface owner is left with no economic value in the recycled water. The question then becomes whether it advances a legitimate state interest?

b. Substantially Legitimate State Interest

The line between police powers and takings is a fine one. The government may affect partial takings if there is a “substantially legitimate government interest.”^[66] But, as previously shown, the impact of HB 2767 and HB 3246 is not to partially deprive landowners of their water, rather it deprives the surface owner of any continual enjoyment and use of the recycled water.

As detailed in the bill’s analysis, the legislature proposed that operators would be less likely to recycle water if there was no basis for them to profit from it.^[67] Unquestionably, the state has an interest in recycling produced water, seeing operators reuse produced water in fracking operations, and therefore reducing the amount of potable water necessary to produce future wells.

c. Proper Exercise of Police Power

There are no unfettered rights—let alone property rights—as “[a]ll property is held subject to the valid exercise of the police power.”^[68] And, the authors do not question whether the legislature may regulate the exploration and exploitation of the state’s natural resources. As shown in Edwards Aquifer Auth. v. Day^[69] Texas has and continues to protect water as a natural and finite resource. But, the Texas Supreme Court also knows the fight over groundwater is coming^[70] and will protect the groundwater rights of surface owners much the same as it does the oil and gas rights of the mineral estate owner.^[71] Accordingly, the legislation would create a complete economic deprivation of a surface owner’s groundwater rights—simply because the groundwater has been injected into a well or was percolating in an oil producing strata.

What’s In It? The Ownership of Lithium in Produced Water.

After drinking a tasty beverage – we may often ask, “What’s in it?” Sometimes found in solution in produced water are economically significant quantities of lithium. Lithium is an element and is listed as “Li”. It has a weight of “2” on the Periodic Table. Commercial quantities of lithium have been discovered in the United States and demand for the “lightest metal known to man is expected to increase ten-fold by 2028. The industry seems prime to takeoff now more than ever.^[72]

One of those commercialized technologies—called “direct lithium extraction”—may lead to the recovery of otherwise unrecoverable, diluted lithium found in hyper-saline produced water derived from well bores. This lithium may then be used to create batteries that store electricity for electric vehicles and other power needs. As a result, it has become a valuable commodity.^[73]

1. The Technology of Extraction

Direct Lithium Extraction (“DLE”) is a process created to eliminate the environmental impact and time constraints for which evaporative technology is criticized. Generally, DLE processes lithium quicker than traditional evaporation by extracting lithium from brine (hyper saline water) using filters, membranes, ceramic beans or other equipment.^[74] The surface footprint currently occupied by evaporation ponds substantially decreases as this processing equipment is found in small warehouses or buildings at or near the well site.

DLE technology is in its infancy and includes adsorption, ion exchange, and solvent extraction.^[75] For the lay person (including your authors), adsorption is the easiest process to understand. Adsorption is the process by which the Lithium Chloride molecule (LiCl) found in brine is physically adsorbed (aka the adhesion of a molecule onto the surface of another)^[76] onto sorbent and is removed with a strip solution.^[77] The next two processes are heavy on chemistry, light on layman understanding. Ion exchange is when the lithium ion in brine is chemically absorbed into a solid ion exchange material and swapped for another positive ion.^[78] And finally, solvent extraction is when concentrated brine is mixed with an organic liquid, stripped free, and further concentrated.^[79]

As the most developed DLE technology,^[80] adsorption resins are synthetic round-shaped beads designed to meet a specific pore size, surface area, and porosity in order to purify, extract, separate, concentrate, and decolorize lithium.^[81] Lithium chloride molecules from the brine infiltrate the atomic layers of an adsorbent. After lithium chloride attaches to the adsorbent, it is washed with a diluted lithium chloride stream to remove unwanted ions and remove the lithium chloride resulting in recovery of more than 90% of the lithium present.

2. The Economics

Goldman Sachs has prepared one of the most comprehensive white papers on DLE technology and economics.^[82] The first exhibit in the public work is an economic comparison of lithium brine extraction methods, comparing evaporation and DLE.^[83] It demonstrates stark economic differences between evaporation and DLE. For example, the most obvious is the production time; evaporation takes months to years while DLE takes hours to days. The recovery rate is 30% more in DLE than in evaporation (60% v. 90%). While capex is nearly identical, the most shocking statistic is that operating expense for DLE—a brand new technology that will only become more efficient—is $500 per ton cheaper than evaporation ($3,300/t v. $2,800/t).

3. Ownership of Brine and Its Constituent Elements and Minerals

The more difficult question for energy law practitioners becomes: to whom do the constituent elements found in brine belong—the surface estate or mineral estate? Fortunately, for potential lithium production states like Arkansas, the answer is clear-ish with a regulatory backstop.^[84] Unfortunately for Texans, however, that answer right now is as clear as drilling mud.

4. Texas

We have discussed the ownership of produced water, now we will discuss the ownership of lithium which may be contained in the produced water. There is substantial confusion surrounding the question of what is included in a reservation or grant of “other minerals” in Texas. The confusion created by Texas courts is the result of balancing two interests which are generally at loggerheads: the right of the surface owner to preserve its surface integrity and the right of the mineral owner to produce his substances for a profit.^[85] Below, we start by taking a look at Texas’s attempt to clarify the ownership of saltwater and brine. Then we will become granular, looking at the meaning of “other minerals” in severances before 1983 and after 1983.

a. Robinson v. Robbins Petroleum and its Forbearers

There is no better case—and, by happenstance, a very important case in our present ownership predicament—to highlight the tension between a surface owner and mineral owner during development than Robinson v. Robbins Petroleum^[86]. We discussed the case earlier in the context of the implied rights given mineral owners in the surface estate. Now we will analyze Robinson Regarding the ownership of the elements contained in produced water. The Court said:

“The first question presented is whether salt water is part of Robinson’s surface estate … We are not attracted to a rule that would classify water according to a mineral contained in solution … It is the water in which these parties are concerned and not the dissolved salt. If a mineral in solution or suspension were of such value or character as to justify production of the water for extraction … The substance extracted might well be the property of the mineral owner … [T]he water itself is an incident of surface ownership … [S]aline content has no consequence upon ownership.”^[87]

That means that brine is owned by the surface estate in Texas, right? Not exactly. In seeming conflict with the holding in Robinson, citing the Supreme Court and San Antonio Court of Appeals, one Texas court held that saltwater is a mineral within the meaning of “other minerals.”^[88] In Ambassador Oil Corp., an individual who owned both the surface and mineral estate underlying part of a pooled unit sued the operator seeking a declaration over his rights to saltwater and damages for third-party sales.^[89] In both the subject lease and the unitization agreement, the phrase “other minerals” was used in the grant.^[90] Basing its reasoning on the fact that salt is a mineral, the appellate court held the phrase “other minerals” included saltwater.

Interestingly, in reaching its decision, the Ambassador Oil Corp. Court cited the Texas Supreme Court case of State v. Parker.^[91] In Parker, the issue was whether a Texas constitutional release of all “mineral substances” on certain surface patents included a salt lake.^[92] Holding in favor of the mineral owner, and also basing its decision on the fact that salt is a mineral, the court held that the phrase “mineral substances” included the salt lake.^[93]

Without expressly overruling them, Robinson seemingly reaches conflicting conclusions with its forbearers Ambassador Oil Corp. and Parker on whether brine (a.k.a., saltwater or produced water) is included in a grant of “other minerals.” Because Robinson is a later Supreme Court opinion, however, it should control the question of whether saltwater is included in the phrase “other minerals.” But, even if Robinson controls, it leaves open the inquiry: If saltwater belongs to the surface estate, is a mineral dissolved in said saltwater included in the phrase “other minerals” when the mineral in solution is “of such value” that it “justif[ies] production of the water for extraction”?^[94]

The purpose for which the water is extracted is important. For example, in Cain v. Neuman,^[95] the court held that “[s]alt, an admitted mineral . . .” was continuously produced in paying quantities sufficient to continue in effect a lease granting “oil, gas and other minerals.” The operator in Cain produced salt by injecting water into the salt formation and piping the brine to its chemical plant A royalty was also paid on the salt production.

b. The “Tests” for Other Minerals

Since Robinson and its forbearers, Texas has taken two somewhat fact-intensive and formulaic approaches to determining whether a mineral falls within the grant of “other minerals” in the chain of title. Fortunately, practitioners know that Texas courts have expressly rejected the following ways to determine what is a “mineral”: the rule of ejusdem generis;^[96] a technical, scientific definition;^[97] and an inquiry into whether the parties had knowledge of the substance’s value or existence at the time of execution.^[98]

Unfortunately, the tests Texas courts do apply do not provide much more clarity than the ones they rejected. In Texas, for grants or reservations of “other minerals” before June 8, 1983, we apply the “Surface Destruction Test,” but for those after June 8, 1983, we apply the “Ordinary and Natural Meaning Test.”

Beginning in 1919, courts in Texas disagreed on whether the extraction method for a mineral should be considered in determining whether that mineral is owned by the surface or mineral estate. In Luse v. Boatman, an appellate court held that a reservation of “coal and mineral” included oil and gas as part of the severance because “it makes no difference whether the means used for extracting the mineral is … pick and shovel … or by drill or bit.”^[99] However, three decades later, the Texas Supreme Court pivoted, concluding that the term “mineral rights” should be interpreted “according to its ordinary and natural meaning.”^[100] In so doing, the court identified four factors to consider: (1) the nature of the substance; (2) its relation to the soil; (3) its use and value; and (4) the effect of removal on the land. As our state’s jurisprudence evolved, the fourth factor—the effect of removal on the land—became the exclusive factor for determining whether a substance belonged to the mineral estate or surface estate.^[101]

c. The Surface Destruction Test (Pre-1983)

1971 can be deemed the year the “surface destruction test” was deployed in full force by the Texas Supreme Court in Acker v. Guinn.^[102] In Acker, the owners of a half interest “in and to all of the oil, gas and other minerals in and under and that may be produced” sued for a declaration that they owned the iron ore which extended from outcroppings to fifty feet below their tract.^[103] Evidence showed that the only way to mine the iron ore was by open pit mining methods. The court reasoned that because “the surface owner could make practically no beneficial use of his land where the mining operations are in progress” and beneficial uses included “farming, ranching, and timber production,” iron ore belonged to the surface estate.^[104] It was here that the court succinctly set forth the surface destruction test:

“Unless the contrary intention is affirmatively and fairly expressed, therefore, a grant or reservation of “minerals” or “mineral rights” should not be construed to include a substance that must be removed by methods that will, in effect, consume or deplete the surface estate.”^[105]

As one commentator noted, the surface destruction test was largely based on the premise that a rational surface owner would not convey a substance of which production would deprive him of beneficial use of his land.^[106] Unfortunately for practitioners, despite expanding the surface destruction test to include, as part of the surface estate, substances within 200 feet of the surface as a matter of law, the court changed its mind about that premise just a few years later.

d. The Ordinary and Natural Meaning Test (Post-1983)

In 1983, the Texas Supreme Court formally recognized that its Acker, Reed I, and Reed II jurisprudence had created fact-intensive uncertainty through application of the surface destruction test and wholeheartedly abandoned it as the standard for determining what is included in a reservation or grant of minerals.^[107] In Moser v. U.S. Steel Corp., owners of the surface asked the court to quiet title to uranium deposits on a tract of land.^[108] The document severing the estates reserved to the mineral owner, “all of the oil, gas, and other minerals of every kind and character, in, on, under and that may be produced[.]”^[109] The trial court applied the surface destruction test and the mineral owner prevailed because in-situ leach mining was the only method available in 1949 (the time of execution) and that would not destroy the surface.^[110] Concluding, however, that the surface destruction test “has resulted in title uncertainty,” the Texas Supreme Court ruled that “title to uranium is held by mineral estate as a matter of law” and announced a return to the ordinary and natural meaning test for mineral severances after June 8, 1983.^[111] The court succinctly proposed the ordinary and natural meaning rule as follows:

[A] severance of minerals in an oil, gas and other minerals clause includes all substances within the ordinary and natural meaning of that word, whether their presence or value is known at the time of severance.^[112]

5. The Tests Applied to Lithium

Although there is no Texas case law directly on the question, it is probable that lithium is a mineral when analyzed through either the lens of the ordinary and natural meaning test (post-1983) or the surface destruction test (pre-1983).

As for the ordinary and natural meaning test, on its face, there appears to be little to no controverting evidence that someone would not consider lithium within the ordinary and natural meaning of the word “mineral.” For instance, lithium is found beneath the surface of the earth, it is not a building material (sand, limestone, gravel, caliche); it is silvery white in color; it is found in the periodic table of elements; and it is a metal. Tellingly, Texas courts have recognized other silvery white metals found underground and on the periodic table of elements as minerals under the ordinary and natural meaning test; namely, uranium in Moser.

Notably, Section 75 of the Texas Property Code, which deals with escheat of unclaimed mineral proceeds, defines “mineral” in reliance on the ordinary and natural meaning test. The statute does not specifically mention lithium in the litany of substances enumerated as minerals, but does give some context and includes “any other substance that is ordinarily and naturally considered a mineral[.]” It further states that such substances are defined as “minerals” regardless at what depth they are found. This appears to be an attempt to override the surface destruction test. However, Section 75 has limited application since it only addresses escheat matters, but it was enacted after Moser took effect and appears to be the Texas legislature’s only attempt to define “minerals.” It’s a contextual argument at best.

As for the surface destruction test, like the court of appeals in Moser—which applied the surface destruction test and held that uranium did not result in substantial destruction of the surface when mined by in-situ leaching—Is there a reason to distinguish lithium from uranium? Lithium extraction in Texas will most likely occur by means of producing brine water through a wellbore and then processing out the lithium at the surface through DLE.^[113] The impact will be de minimis if not non-existent on ranching, farming, or timber harvesting—the focus of those pre-Moser courts and a mining methods “substantial impact”.^[114] And as a result, likely not a substantial destruction of the surface, and thus, a mineral.

However, since water is an attribute of the surface estate as a matter of law and that issue was decided post-Moser, an argument can be made that mining lithium from brine should be considered substantial destruction of the surface as much of the brine is consumed before reinjecting into the sub-surface strata. This is similar to the correlative rights argument made in Robbins (i.e., producing brine for use on another tract was an unreasonable use of the surface) which also held that brine was not included in the grant of other minerals.^[115] However, Robinson may be distinguished when extraction of the brine is done specifically to recover the lithium and not the water. For the operator in Robinson, salt extraction was not the objective, the objective was injecting the salt-laden groundwater for oil and gas extraction, and the court noted that specifically.^[116]

Whether lithium is within the ordinary and natural meaning of “mineral” or the extraction of the substance would consume the surface would be, in most cases, is a question of fact. Thus, a legislative solution may be appropriate.

6. What’s In It?

With regard to the ownership of lithium in solution in produced water, the answer in Texas is unclear. The implied rights given mineral owners to use the surface is a usufruct not a right of ownership. A question exists whether the statutory legislation can grant ownership in the produced water without it being considered a taking. However, as we saw in Cactus, the granting clause in the lease may be interpreted to grant ownership of the produced water and its constituent elements to the operator. Also, if the courts decide that lithium is a “mineral” under Moser, the mineral owner may own the lithium and the surface owner the raw produced water. Help.

CONCLUSION

How landowners and operators respond to these changes depends upon terms of their underlying oil and gas leases. If currently bound by a lease the lease terms will govern as HB 3246 provides a carve-out allowing a contractual provision to override the statutory provision. This carve-out would also affect surface use agreements which contain the relevant water terms. Alternatively, operators and surface owners alike may consider entering new leases which add language affording them the right, but not the obligation, to take the produced water in kind for their purposes. Either way, produced water’s ongoing transformation from liability to asset is certain to create more and more litigation until the constitutionality of HB 2767 and HB 3246 is determined.

While mineral extraction from brine has existed for many years, the law in Texas on the matter is still in its infancy. Texas case law provides clues about the ownership of lithium as extracted from brine and the rights of the surface owner, but investment in the industry would benefit from settling those matters under the law. Rather than waiting on development of case law, which could take a long time and may not produce clear answers, Texas may consider a legislative solution addressing these issues.