Gabriel Collins, “Potential Transaction Structures for Produced Water in Texas,” Texas Water Intelligence™, Water Note #4, 27 April 2017
Produced water ownership transfer is not simply a rehousing of legal liabilities and risks; it also opens the door to harnessing latent economic value. Once produced water has undergone a transfer of title that severs it from the original owner, that party no longer has any claim to the commodity, and it can be freely bought, sold, or otherwise transferred within the parameters allowed under the present regulatory regime.
The locus of value is shifting away from an exclusive focus on the service of disposing of produced water to the economic value inherent in the water itself. In other words, rather than being viewed simply as a fluid to be sent down a pipeline to a saltwater disposal well (SWD) and disposed of, produced water (including flowback) will be transferred between parties for value.
Such “value” primarily manifests itself in two ways. The first is a direct sale of water from one party to another. The second potential mode of realizing value for produced water relies on avoiding costs. If produced water has resale value to a range of frac’ers in an area, E&Ps may be able to persuade a midstream provider to (1) take the water at no charge, treat it, and resell it, or (2) take water for a combination of disposal and/or treatment and resale, but do so at a reduced charge per barrel that accounts for the water’s likely resale value.
If an E&P directly sells produced water in Texas, it may need to share sale proceeds with the surface estate owner. The way revenue sharing occurs will depend first on the contractual arrangements contained in the surface use agreement (SUA) governing the relationship between mineral and surface owner, and absent an SUA, would likely default to Texas common law criteria governing relations between the surface and mineral estates and payment of royalties.
- The mineral estate likely does not need to compensate the surface estate for produced water unless it earns revenue net of costs from sale of the water.
Surface owners seeking compensation for produced water transferred to a third party but not sold for a net profit would likely fail. Under Texas law, the mineral estate owner has “the right to use as much of the surface as is reasonably necessary to extract and produce the minerals,” otherwise broadly known as the “accommodation doctrine.” The accommodation doctrine primarily contemplates impairment of surface uses caused by actions of the mineral owner—for instance, placing pumpjacks in such a way that they block a farmer’s center pivot sprinklers from functioning properly.
The accommodation doctrine has not been applied to compensate surface owners for produced water that could have potentially been sold for a net revenue gain but was instead transferred without booking any revenue net of treatment and handling costs. The lack of precedent is unsurprising. E&Ps have no legal duty to market produced water and surface owners can contractually seek compensation for physical impositions caused by water handling operations—for instance, damage rentals made when water flowlines, recycling equipment, or other water-related infrastructure are installed.
For surface owners in Texas to successfully claim under the accommodation doctrine that as a general matter the mineral owner should compensate them for removing produced water from their land, they would have to demonstrate that:
- The mineral lessee’s use “completely precludes or substantially impairs” the existing use of the surface;
- There is “no reasonable alternative method available to the surface owner” through which it can continue its existing use of the surface; and
- There are “alternative reasonable, customary, and industry-accepted methods available to the [mineral] lessee” that will allow recovery of the minerals and also allow the surface owner to continue its existing use of the surface estate.
These standards all focus on damage to the surface estate—not on the potential economic value of a byproduct produced along with oil & gas whose removal from the hydrocarbon-bearing formation does not create any perceptible changes to the actual surface of the overlying tract.
Produced water recycling or reuse generally does not substantially interfere with a surface owner’s use of the parcel from under which the water originates, particularly if the actual treatment occurs off-tract. Indeed, in this scenario the water is simply transported off the tract into the treatment facility, which invokes the same general level of invasiveness as the “reasonable, customary, and industry-accepted” method that industry currently uses to resolve produced water issues: sending fluids by pipeline and/or truck to a deep injection well. And in such cases, surface owners can contract to receive damage payments and/or right of way rental fees.
To the best of this author’s knowledge, surface estate owners in Texas have never been able to claim, by law, compensation for produced water disposed of in SWDs off their tracts, despite the potential for SWD operators to forego disposal and instead resell the water to other oilfield users. Furthermore, courts are also likely to recognize the public policy benefits of using recycled produced water to displace the use of freshwater in dry areas of Texas. Against that backdrop, so long as the mineral estate is not selling produced water for net positive revenues after deduction of reasonable costs in handling and marketing the water, a court would likely not be inclined to overturn a system of water management that has successfully operated for decades.
- Any payment to the surface estate would likely only be made net of treatment and handling costs for the water.
Under Texas law, a “royalty” is generally defined as “the landowner’s share of production, free of expenses of production.” Although it is not subject to the costs of production, a royalty is usually subject to post-production costs, including taxes, treatment costs to render the commodity marketable, and transportation costs.” Parties may agree to modify terms of the general rule.
In practice, this means that the landowner and E&P would most likely split the net revenue left after pre-sale treatment costs and logistics charges that might be borne by the E&P. Either an outright sale or a takeaway transfer at reduced cost would reduce the E&P’s water-related lease operating expenses. A cost-neutral transfer of produced water between E&Ps or other entities would also reduce water-handling cost burdens and benefit corporate balance sheets.
If the E&P disposes of the produced water generated on the lease by either of the methods described above or by other means that do not make the transfer of the produced water profitable to the E&P on a net basis, then the E&P transferring the water likely will not owe the surface owner payment for the water, since even a partially avoided cost is still ultimately a cost. Depending on the contractual arrangements between the mineral owner and surface owner, a reduction in operating costs could lead to higher payments to royalty owners (if said royalty clauses award royalties based on a price net of post-production costs, since water handling often accounts for a significant portion of total lease operating expenses).
If the landowner refused to bear a reasonable share of post-production costs needed to make the water saleable, then the E&P would most likely simply revert to existing practices, either reusing the water for its own operations on the lease or sending it off for disposal via injection well.
Potential Transaction Structures for Produced Water in Texas
 Merriman v. XTO Energy, Inc., 407 S.W.3d 244, 248-249 (Tex. 2013).
 Merriman, 249.
 Heritage Res. Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996); Chesapeake Exploration, L.L.C. v. Hyder, No. 14-0302 (Tex. Jan. 29, 2016) .
**This analysis reflects the author’s personal assessments and opinions. It is not intended to provide legal advice and does not create an attorney-client relationship between the author and reader.**
The research and views expressed in this paper are mine alone and do not necessarily represent the views of the James A. Baker III Institute for Public Policy.