OPINION This case decides who owns produced water arising from a hydraulic fracturing operation: COG Operating, LLC (the existing mineral lessee) or Cactus Water Services, LLC (who later entered a produced water lease agreement with the surface owners). On cross-motions for summary judgment, the trial court decided the ownership question inCOG’s favor. Cactus appeals, contending the trial court’s judgment lacks support in the contractual language of the operator’s mineral lease and is unsupported by Texas jurisprudence, statutes, or regulations. We affirm. I. BACKGROUND COG is the mineral lessee under four leases, executed in 2005, 2010, and 2014, and covering approximately 37,000 acres in Reeves County, Texas (“the Leased Lands”), with two surface owners.[1] Under these leases, COG has the exclusive right to explore for and produce oil and gas on the Leased Lands: · 2005 and 2010 Collier Leases: “Lessor[s] . . . have GRANTED, DEMISED, LEASED and LET, and by these presents do GRANT, DEMISE, LEASE and LET exclusively unto the said Lessee, its successors and assigns, for the sole and only purpose of investigating, exploring, prospecting, drilling, mining and operating for oil and gas and other hydrocarbons, and of laying pipelines and of building tanks, power stations and structures thereon, to produce, save, take care of, store and treat products produced hereunder, and then to transport those products from the land in Reeves County, Texas [covered by the lease][.]“ · 2014 Collier Lease: “Lessor . . . hereby exclusively grants, leases and lets unto Lessee for the purpose of investigating, exploring, prospecting, drilling and producing oil and gas, from the [land covered by the lease].” · 2010 Balmorhea Lease: “Lessor . . . hereby grants, leases and lets exclusively unto Lessee for the purpose of investigating, exploring, prospecting, drilling and mining for and producing oil, gas, and other hydrocarbons, conducting exploration, geologic and geophysical surveys by seismographs, core test, gravity and magnetic methods, injecting gas, water and other fluids, and air into subsurface strata, laying pipe lines, building roads, tanks, power stations, telephone lines and other structures thereon, to produce, save, take care of, treat, transport and own said products, the [land covered by the lease].” COG’s operations in the Leased Lands center around a region in the Delaware Basin with dense shale and poor permeability. Given those conditions, COG’s operations have focused on drilling and completing horizontal wells—i.e., hydraulic fracturing, or “fracing.” Fracing involves “pumping fluid down a well at high pressure so that it is forced out into the formation,” which “creates cracks in the rock that propagate along the azimuth of natural fault lines in an elongated elliptical pattern in opposite directions from the well.” Coastal Oil & Gas Corp. v. Garza Energy Tr., 268 S.W.3d 1, 6 (Tex. 2008). The fluid contains proppants that keep those cracks open and allow oil and gas to flow to the wellbore. Id. at 6-7. However, what travels to the wellbore involves other substances too, both hydrocarbon and not. The composition of that fluid depends on the location, but here, those substances include sodium, calcium, potassium, strontium, barium, iron, carbon dioxide, and brine, or water molecules mixed with hydrogen sulfide and chloride. Once the stream reaches the surface, it is treated by equipment that separates out the oil and gas. What remains is referred to as produced water—a liquid containing chloride, sodium, calcium, potassium, strontium, barium, iron, hydrogen sulfide, carbon dioxide, trace amounts of oil, and water. Because fracing requires so much water per well, it also generates huge amounts of produced water, particularly in the Permian Basin. See Andrew J. Kondash et al., The Intensification of the Water Footprint of Hydraulic Fracturing, Science Advances (2018), https://www.science.org/doi/epdf/10.1126/sciadv.aar5982 (noting the median water usage of a Permian Basin well is 42,500 cubic meters). For example, since COG entered the mineral leases, its operations have resulted in nearly 52,000,000 barrels of produced water. And because produced water presents a danger to the surrounding environment, including “usable-quality water,” it must be carefully handled and disposed. 16 TEX. ADMIN. CODE § 3.13(a)(1)(R.R. Comm. of Tex., Casing, Cementing, Drilling, Well Control and Completion Requirements). That process is highly regulated in Texas and includes penalties for improper disposal. See id. § 3.8. While the handling, treatment, and disposal of produced water have long been costly expenditures for operators, recent water treatment technologies have made the reuse of such waste possible, creating a new industry in which treated wastewater can be sold back to operators for drilling. Christopher M. Matthews, The Next Big Bet in Fracking: Water, THE WALL STREET JOURNAL (Aug. 22, 2018), https://www.wsj.com/articles/the-next-big-bet-in-fracking-water-1534930200. Since COG began operations on the Leased Lands, it has disposed of its oil and gas waste, including produced water. To aid that process, COG has both surface use compensation agreements (SUCA) and right-of-way agreements (ROW Agreements) with the surface owners to facilitate its use of the surface estate when it transports product and waste from its wells. The SUCA gives COG the right to: [C]onstruct, operate and maintain tank battery sites . . . for the gathering, storing, and transporting of oil, gas, other petroleum products, water, and/or any other liquids, gases or substances which can be transported through a pipeline. Said site is to include tanks, pipelines, pipeline connections and other fixtures and appurtenances reasonably necessary or convenient to Operator’s use and Operations of the lands as a tank batter[y] site. It also provides that “‘[f]resh water lines, produced water lines and flow lines may be laid on the surface of the Lands.’” The ROW Agreements also grant COG the right to lay pipelines for the “transportation of oil, gas, petroleum, produced water and any other oilfield related liquids or gases[.]” COG’s production facilities can store roughly 24-hours’ worth of produced water before it must be sent offsite; otherwise, production must stop. COG has incurred significant costs in handling and disposing its produced water from the Leased Lands, paying over $20.5M to its liquid-waste disposal contractor from December 2018 through March 2021.[2] COG’s leases notwithstanding, in 2019 and 2020, the surface owners transferred to Cactus all the surface estates’ water rights on the Leased Lands. The leases give Cactus ownership and the right to sell all water “produced from oil and gas wells and formations on or under the [covered properties].” “Water” is defined as: [A]ny and all water contained in and produced from geologic formations under the Subject Property through any wellbores drilled for the production of oil, gas, and natural gas liquids (collectively, ‘hydrocarbons’), whether economically productive or not, regardless of salinity. ‘Water’ excludes all water originating from shallow geological intervals that do not and have never produced oil, other hydrocarbon liquids, and/or natural gas anywhere in the Permian Basin. ‘Water’ also excludes water purposely and directly produced from the Ogallala, Pecos Valley Alluvium, Edwards Trinity, Dockum Aquifers or any other freshwater aquifers. Cactus informed COG of its produced water leases in early March 2020. COG then sued, seeking a declaratory judgment that it has the sole right to the produced water by virtue of its mineral leases, SUCAs, and at common law. Cactus counterclaimed, asserting its right of ownership over the produced water under its own leases. But unlike the produced water leases, none of the mineral leases define the term “water.” The 2005 and 2010 leases do, however, specifically limit COG’s use of water on the Leased Lands: [COG] shall have no right to use water which is on or under the above described land, except it may itself drill a water well and then use the water from that well in its conduct of the drilling operations that actually are conducted on land covered by this lease. Similarly, the 2014 lease states, “No water from any source from said land shall be used for any purpose without written consent of Lessor.” Thus, COG and Cactus dispute whether the mineral leases conveyed produced water to COG. If so, the surface owners’ later transfer of produced water to Cactus is void. Both parties moved for summary judgment, and the trial court granted summary judgment in COG’s favor. After the parties nonsuited their remaining claims, the trial court entered a final judgment declaring that COG owns, by virtue of its mineral leases, the oil, gas, and other products contained in the commercial oil and gas bearing formations that are produced from the COG wells on the properties; that COG has the right to exclusive possession, custody, control, and disposition of the product stream produced from the wells under the mineral leases so long as the leases remain in effect; and that Cactus has no rights in or to the product stream from COG’s wells so long as the mineral leases remain in effect. Cactus appealed. II. STANDARD OF REVIEW We review a trial court’s granting of summary judgment de novo. Lujan v. Navistar, Inc., 555 S.W.3d 79, 84 (Tex. 2018). When parties bring cross-motions for summary judgment, each party’s burden is to establish it is entitled to judgment as a matter of law. Miles v. Tex. Cent. R.R. & Infr., Inc., 647 S.W.3d 613, 619 (Tex. 2022). When one party’s motion is granted and the other is denied, on review we “‘determine all questions presented’ and ‘render the judgment that the trial court should have rendered.’” Id. (quoting City of Garland v. Dall. Morning News, 22 S.W.3d 351, 356 (Tex. 2000)). Declaratory judgments are reviewed under the same standards as other judgments, looking to the procedure used in the trial court to resolve the issue, and applying the standard of review applicable to that procedure. Browne v. Ortiz, 657 S.W.3d 704, 708 (Tex. App.—El Paso 2022, no pet.). In this case, because the summary judgment included declaratory portions, we also review the declaratory portions of the judgment de novo. See Sanchez v. Barragan, 624 S.W.3d 832, 838 (Tex. App.—El Paso 2021, no pet.). III. ANALYSIS Cactus argues the trial court’s ruling on summary judgment has no support in the mineral leases, nor in Texas’s jurisprudence, statutes, or regulations. COG responds that consistent with the relevant statutory and regulatory landscape, the mineral leases necessarily convey the oil and gas product stream, which includes the produced water. We begin with the mineral leases. “When interpreting a written contract, the prime directive is to ascertain the parties’ intent as expressed in the instrument.” URI, Inc. v. Kleberg Cnty., 543 S.W.3d 755, 757 (Tex. 2018). When, as here, several instruments pertain to the same transaction, those instruments may be read together to determine the parties’ intent, even if the parties executed the instruments at different times. Fort Worth Indep. Sch. Dist. v. City of Fort Worth, 22 S.W.3d 831, 840 (Tex. 2000). While our “focus is on the words the parties chose to memorialize their agreement,” we recognize “language is nuanced, and meaning is often context driven.” URI, Inc., 543 S.W.3d at 757. To that end, Texas courts have long construed words in the context in which they are used. Id. at 764. That includes “the commercial or other setting in which the contract was negotiated and other objectively determinable factors that give a context to the transaction,” as “[s]etting can be critical to understanding contract language[.]” Id. at 768 (citations omitted). Though surrounding facts and circumstances “cannot be used to augment, alter, or contradict the terms of an unambiguous contract,” they can “inform the meaning of language.” Id. at 758. “Understanding the context in which an agreement was made is essential in determining the parties’ intent as expressed in the agreement, but it is the parties’ expressed intent that the court must determine.” Anglo-Dutch Petroleum In’l, Inc. v. Greenberg Peden, P.C., 352 S.W.3d 445, 451 (Tex. 2011). Our approach is “holistic” and aimed at determining intent from all words and parts of the contract. Greer v. Shook, 503 S.W.3d 571, 582 (Tex. App.—El Paso 2016, pet. denied). Ultimately, our goal is to objectively determine what the parties intended by construing the contract “from a utilitarian standpoint bearing in mind the particular business activity sought to be served.” Reilly v. Rangers Mgmt., Inc., 727 S.W.2d 527, 530 (Tex. 1987). Cactus contends that the mineral leases grant the right to “oil, gas and other hydrocarbons,” or the right to “oil and gas,” which does not encompass all produced water from the oil-and-gas bearing formations. Cactus also contends that because the mineral leases limit COG’s use of surface water, the leases do not allow COG to sell produced water to third parties for off-premises use. Its argument hinges on the chemical composition of water: Because water is not a hydrocarbon, Cactus argues that water was not conveyed as part of the mineral estate. Thus, Cactus urges the produced water was later conveyed through produced water leases it entered with the surface owners. COG argues the leases must be construed to effectuate the parties’ general intent to convey oil and gas in their natural form. Because produced water is part of the single, combined product stream that arises from its wells, COG contends it owns the produced water as a waste byproduct. COG also claims ownership through its development rights under its mineral leases, which include the right to dispose of the waste generated by its wells. The parties’ disagreement as to whether produced water is part of the mineral estate essentially depends on whether “produced water” is, as a matter of law, water or if it is waste. Because the terms “water” or “produced water” are not defined in the mineral leases, we look to state statutory and regulatory definitions for relevant context. See Endeavor Energy Res., L.P. v. Discovery Operating, Inc., 554 S.W.3d 586, 595 (Tex. 2018) (“Although mineral leases are contracts, they are subject to legal and regulatory restrictions.”); URI, Inc., 543 S.W.3d at 764 (recognizing the context in which words are used may encompass the circumstances present when the contract was entered). The Texas Natural Resources Code, Texas Water Code, and the Railroad Commission Rules each define “oil and gas waste”: ‘[O]il and gas waste’ means waste that arises out of or incidental to the drilling for or producing of oil or gas . . . includ[ing] salt water, brine, sludge, drilling mud, and other liquid, semiliquid, or solid waste material[.] TEX. NAT. RES. CODE ANN. § 91.1011. ‘Fluid oil and gas waste’ means waste containing salt or other mineralized substances, brine, hydraulic fracturing fluid, flowback water, produced water, or other fluid that arises out of or is incidental to the drilling for or production of oil or gas. Id. § 122.001(2). ‘Oil and gas waste’ means waste arising out of or incidental to drilling for or producing of oil, gas, or geothermal resources . . . . The term includes but is not limited to salt water, brine, sludge, drilling mud, and other liquid or semi-liquid waste material. TEX. WATER CODE ANN. § 27.002(6). Oil and gas wastes—Materials to be disposed of or reclaimed which have been generated in connection with activities associated with the exploration, development, and production of oil or gas or geothermal resources . . . . The term ‘oil and gas wastes’ includes but is not limited to, saltwater, other mineralized water, sludge, spent drilling fluids, cuttings, waste oil, spent completion fluids, and other liquid, semiliquid, or solid waste material. 16 TEX.ADMIN.CODE § 3.8(a)(26) (R.R. Comm. of Tex., Water Protection). The Texas Water Code and Railroad Commission Rules also define water as follows: ‘Fresh water’ means water having bacteriological, physical, and chemical properties which make it suitable and feasible for beneficial use for any lawful purpose. TEX. WATER CODE ANN. § 27.002(8). ‘Groundwater’ means water percolating below the surface of the earth. Id. § 35.0029(5). Surface or subsurface water—Groundwater, percolating or otherwise . . . . 16 TEX. ADMIN. CODE § 3.8(a)(29) (R.R. Comm. of Tex., Water Protection). This framework draws a clear distinction between produced water and groundwater. “[W]hen the legislature uses certain language in one part of the statute and different language in another, the [C]ourt assumes different meanings were intended.” Ineos USA, LLC v. Elmgren, 505 S.W.3d 555, 564 (Tex. 2016) (quoting DeWitt v. Harris Cnty., 904 S.W.2d 650, 653 (Tex. 1995)) (alterations in original). The relevant legal definitions of oil and gas waste include produced water. And because the Legislature defines produced water as oil and gas waste, it cannot also be groundwater. Indeed, the definitions of oil and gas waste echo what COG’s petroleum engineering expert points out: the term “produced water” is essentially a misnomer, as it bears little resemblance to water given the “numerous constituents” it contains other than water. Instead, produced water is more accurately classified as a waste byproduct of oil and gas production.[3] The same legal and regulatory framework also contains provisions to protect groundwater from oil and gas waste and require proper disposal of that waste. For example, the Railroad Commission Rules state no one “may cause or allow pollution of surface or subsurface water in the state” and require a permit for any disposal of oil and gas wastes. 16 TEX. ADMIN. CODE §§ 3.8(b), (d)(1). The rules place liability for improper disposal squarely on the operator. See id. §§ 3.8(d)(5)(B) (“No generator, carrier, receiver, or any other person may improperly dispose of oil and gas wastes or cause or allow the improper disposal of oil and gas wastes.”), (h) (“Violations of this section may subject a person to penalties and remedies specified in the Texas Natural Resources Code, Title 3, and any other statutes administered by the commission.”). This distinction underscores the understanding of produced water as oil and gas waste—something that operators must keep from contaminating usable quality water—rather than water. See id. § 3.13(a)(1). Characterizing produced water as oil and gas waste, rather than groundwater, also conforms with industry practice. Indeed, produced water has long been treated as a liability, not an asset, both throughout the fracing industry and in the context of COG’s operations on the Leased Lands. Here, since COG began drilling on the Leased Lands, the surface owners never tried to claim ownership over the produced water before entering the produced water lease with Cactus. The mineral leases were likewise executed before the parties perceived produced water as a substance with value. However, “[t]he knowledge of the parties of the value, or even the existence of the substance at the time the conveyance was executed” is “irrelevant to its inclusion or exclusion from a grant of minerals.” Moser v. U.S. Steel Corp., 676 S.W.2d 99, 102 (Tex. 1984). To read the mineral leases as reserving produced water—something that exists separate from oil and gas only after processing and treatment—for the surface estate would give the surface estate (and thus Cactus) “the benefit of costs and risks [COG] voluntarily undertook.”[4] Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 706 (Tex. 2008). The mineral leases were negotiated against this backdrop—with a legal framework distinguishing oil and gas waste from groundwater, making clear that produced water is categorized within the former, and placing the burden of its safe disposal on operators, and according to years of the common industry practice in which operators have processed, transported, and disposed of oil and gas waste. Reading the mineral leases in the context in which they were made “elucidates the meaning of the words employed[.]” See URI, Inc., 543 S.W.3d at 765. Here, that context clarifies that the grant of “oil, gas and other hydrocarbons” or “oil and gas” includes the rights and duties associated with disposing of its waste, including produced water, which cannot be extracted separate from the oil and gas. See Turner v. Big Lake Oil Co., 96 S.W.2d 221, 226 (Tex. 1936) (“One of the by-products of oil production is salt water[.]“). Nothing in the mineral leases indicates that the parties intended to upend the definitions of these terms or common practices. Indeed, they could have—through an express reservation. TEX.NAT.RES.CODE ANN. § 122.002; see Sharp v. Fowler, 252 S.W.2d 153, 154 (Tex. 1952) (“A reservation of minerals to be effective must be by clear language. Courts do not favor reservations by implication.”). But here there is none: Though the mineral leases restrict COG’s use of “water” on the Leased Lands, that has no bearing on COG’s right to the oil and gas waste byproduct from its wells.[5] In sum, nothing in the mineral leases suggests the parties intended to assign rights at a molecular level, following both extraction from the well and post-production processing. Nor do the mineral leases indicate an intent to reserve oil and gas waste produced through COG’s drilling operations. Reading the mineral leases in the context in which they were executed confirms COG has the exclusive right to the oil and gas product stream, including the produced water.[6] The subsequent leases purporting to convey produced water rights to Cactus were thus ineffective.[7] IV. CONCLUSION Having overruled each of Cactus’s issues on appeal, we affirm. YVONNE T. RODRIGUEZ, Chief Justice July 28, 2023 Before Rodriguez, C.J., Palafox, and Soto, JJ. Palafox, J. Dissenting
