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concluding that a gas-lease provision stating that the royalty would be "free and clear of all production and post-production costs and expenses" must "be regarded as" either "emphasizing the cost-free nature of the gas royalty, or as surplusage," because "like any other royalty, the gas royalty does not share in production costs"
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NO. 14–0302
01-29-2016
Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc., Petitioners, v. Martha Rowan Hyder, Individually, and as Independent Executrix and Trustee Under the Will of Elton M. Hyder, Jr., Deceased, and as Trustee Under the Elton M. Hyder Jr. Residuary Trust, and as Trustee of the Elton M. Hyder Jr. Marital Trust; Brent Rowan Hyder, Individually and as Trustee of the Charles Hyder Trust and as Trustee of the Geoffrey Hyder Trust; Whitney Hyder More, Individually and as Trustee of the Elton Matthew Hyder IV Trust, as Trustee of the Peter Rowan More Trust, as Trustee of the Lili Lowdon Hyder Trust, and as Trustee of the Samuel Douglas More Trust; and Hyder Minerals, Ltd., Respondents
Bart A. Rue, Matthew David Stayton, Kelly Hart & Hallman LLP, Fort Worth TX, for Chesapeake Exploration, L.L.C., Chesapeake Operating, Inc. David Jacob Drez III, Jacob Fain, Wick Phillips Gould & Martin, LLP, Fort Worth TX, James Wills IV, Jeffrey Wallace Hellberg, Wick Phillips Gould & Martin, LLP, Dallas TX, for Martha Rowan Hyder, Individually, and as Independent Executrix and Trustee, et al. Ken Slavin, Kemp Smith, LLP, El Paso TX, for Amicus Curiae, General Land Office of the State of Texas. Roger D. Townsend, Alexander Dubose Jefferson & Townsend LLP, Houston TX, for Amicus Curiae Longfellow Ranch Partners, LP, and Wesley West Minerals, LTD. John B. McFarland, Graves Dougherty Hearon & Moody, P.C., Austin TX, for Amicus Curiae National Association of Royalty Owners–Texas, Inc. (NARO-Texas), and Texas Land and Mineral Owners Association (TLMA). Marie R. Yeates, Vinson & Elkins LLP, Houston TX, Michael A. Heidler, Vinson & Elkins LLP, Austin TX, for Amicus Curiae Texas Oil & Gas Association.
Bart A. Rue, Matthew David Stayton, Kelly Hart & Hallman LLP, Fort Worth TX, for Chesapeake Exploration, L.L.C., Chesapeake Operating, Inc.
David Jacob Drez III, Jacob Fain, Wick Phillips Gould & Martin, LLP, Fort Worth TX, James Wills IV, Jeffrey Wallace Hellberg, Wick Phillips Gould & Martin, LLP, Dallas TX, for Martha Rowan Hyder, Individually, and as Independent Executrix and Trustee, et al. Ken Slavin, Kemp Smith, LLP, El Paso TX, for Amicus Curiae, General Land Office of the State of Texas.
Roger D. Townsend, Alexander Dubose Jefferson & Townsend LLP, Houston TX, for Amicus Curiae Longfellow Ranch Partners, LP, and Wesley West Minerals, LTD.
John B. McFarland, Graves Dougherty Hearon & Moody, P.C., Austin TX, for Amicus Curiae National Association of Royalty Owners–Texas, Inc. (NARO-Texas), and Texas Land and Mineral Owners Association (TLMA).
Marie R. Yeates, Vinson & Elkins LLP, Houston TX, Michael A. Heidler, Vinson & Elkins LLP, Austin TX, for Amicus Curiae Texas Oil & Gas Association.
Opinion
CHIEF JUSTICE HECHT delivered the opinion of the Court, in which JUSTICE GREEN, JUSTICE JOHNSON, JUSTICE BOYD, and JUSTICE DEVINE joined.
We deny the motion for rehearing. We withdraw our opinion of June 12, 2015, and substitute the following in its place.
Generally speaking, an overriding royalty on oil and gas production is free of production costs but must bear its share of postproduction costs unless the parties agree otherwise. The only question in this case is whether the parties' lease expresses a different agreement. We conclude it does and therefore affirm the court of appeals' judgment.
427 S.W.3d 472 (Tex.App.–San Antonio 2014).
The Hyder family leased 948 mineral acres in the Barnett Shale. Chesapeake Exploration, L.L.C., acquired the lessee's interest. The lease was negotiated and drafted by counsel for the Hyders and the original lessee.
The Hyder respondents include Martha Rowan Hyder, individually and as independent executrix and trustee under the Will of Elton M. Hyder Jr., deceased, as trustee under the Elton M. Hyder Jr. Residuary Trust, and as trustee of the Elton M. Hyder Jr. Marital Trust; Brent Rowan Hyder, individually and as trustee of the Charles Hyder Trust and as trustee of the Geoffrey Hyder Trust; Whitney Hyder More, individually and as trustee of the Elton Matthew Hyder IV Trust, as trustee of the Peter Rowan More Trust, as trustee of the Lili Lowdon Hyder Trust, and as trustee of the Samuel Douglas More Trust; and Hyder Minerals, Ltd. We refer to the lessors as the Hyders.
Petitioners are Chesapeake Exploration, L.L.C., and an affiliate that acts as its agent for all natural gas operations on the property, Chesapeake Operating, Inc. We refer to them collectively as Chesapeake.
The lease contains three royalty provisions. One is for 25% of “the market value at the well of all oil and other liquid hydrocarbons”. No oil is produced from the lease. Another royalty is for 25% “of the price actually received by Lessee” for all gas produced from the leased premises and sold or used. The lease adds that the royalty is expressly “free and clear of all production and post-production costs and expenses,” and lists examples of various expenses. The third provision, the one here in dispute, calls for “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production obtained” from directional wells drilled on the lease but bottomed on nearby land. The lease contains two other provisions relevant to our consideration. One is this disclaimer: “Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex.1996) shall have no application to the terms and provisions of this Lease.” The other is that “each Lessor has the continuing right and option to take its royalty share in kind”. No lessor has ever exercised that right. While the overriding royalty appears to be in kind, the parties do not disagree that it can be paid in money.
The lease provides that this royalty is “for natural gas, including casinghead gas and other gaseous substances produced from the Leased Premises and sold or used on or off the Leased Premises” and that “[i]n no event shall the volume of gas used to calculate Lessors' royalty be reduced for gas used by Lessee as fuel for lease operations or for compression or dehydration of gas.”
The royalty provision continues: “including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and Lessee's point of delivery or sale of such share to a third party. Lessor's royalty share shall also be free and clear of all costs of construction, operation or depreciation of any plant or other facilities or equipment used for processing or treating paid production.”
The lease states that “Lessee shall, within sixty (60) days from the date of first production from each [directional] well, convey to Lessors” the overriding royalty. The parties treat this royalty provision like a conveyance, and so do we. Only two of the respondents, Brent Rowan Hyder and Whitney Hyder More, are alleged to own overriding royalties. Because all respondents join in the arguments made here, we refer to the overriding royalties as due to the Hyders.
The Hyders and Chesapeake agree that the overriding royalty is free of production costs; they dispute whether it is also free of postproduction costs. There are twenty-nine producing gas wells on the leased or pooled land, seven of which are directional wells bottomed on and producing from lands not subject to the lease. Chesapeake sells all the gas produced to an affiliate, Chesapeake Energy Marketing, Inc. (“Marketing”), which then gathers and transports the gas through both affiliated and interstate pipelines for sale to third-party purchasers in distant markets. Marketing pays Chesapeake a “gas purchase price” for volumes determined at the wellhead or—during earlier periods—at the terminus of Marketing's gathering system. The gas purchase price is calculated based on a weighted average of the third-party sales prices received (the “gas sales price”) less postproduction costs. The overriding royalty Chesapeake pays the Hyders is 5% of the gas purchase price. The Hyders contend that their overriding royalty should be based on the gas sales price.
Marketing deducts, as postproduction costs, gathering and transportation costs and a 3% marketing fee.
After a bench trial, the trial court rendered judgment for the Hyders, awarding them $575,359.90 in postproduction costs that Chesapeake wrongfully deducted from their overriding royalty. The court of appeals affirmed. We granted Chesapeake's petition for review.
427 S.W.3d 472 (Tex.App.–San Antonio 2014).
58 Tex. Sup.Ct. J. 227 (Jan. 30, 2015).
In Heritage Resources, Inc. v. NationsBank, we noted that a royalty is free of production expenses but “usually subject to post-production costs, including taxes ... and transportation costs.” But we added that “the parties may modify this general rule by agreement.” We long ago defined an overriding royalty as “a given percentage of the gross production carved from the working interest but, by agreement, not chargeable with any of the expenses of operation.” That agreement is now understood to be part of an overriding royalty, and an overriding royalty is like a landowner's royalty in that it usually bears postproduction costs but not production costs, though the parties may agree to a different arrangement.
939 S.W.2d 118, 121–122 (Tex.1996); accord French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex. 2014).
Heritage Res., 939 S.W.2d at 122; accord French, 440 S.W.3d at 3.
MacDonald v. Follett, 142 Tex. 616, 180 S.W.2d 334, 336 (1944).
See Paradigm Oil, Inc. v. Retamco Operating, Inc., 372 S.W.3d 177, 180 n. 1 (Tex.2012) (“An overriding royalty is an interest in the oil and gas produced at the surface, free of the expense of production.” (internal quotation marks omitted)); see also Alamo Nat'l Bank v. Hurd, 485 S.W.2d 335, 339 (Tex.Civ.App.–San Antonio 1972, writ ref'd n.r.e.) (“An overriding royalty is first and foremost a royalty interest. In other words, it is an interest in oil and gas produced at the surface, free of the expenses of production.”).
See Heritage Res., 939 S.W.2d at 122 (noting that parties may agree to modify the general rule that a royalty, though not subject to production costs, is subject to postproduction costs); 8 H. WILLIAMS & C. MEYERS, OIL AND GAS LAW: MANUAL OF OIL AND GAS TERMS 731 (2014) (“One of the most important aspects of an ‘overriding royalty’ ... is that it is a ‘royalty,’ viz., in the absence of an express agreement to the contrary it is free of costs of which the lessor's royalty is free and it is subject to the costs to which the lessor's royalty is subject.”).
Two of the royalty provisions in the Hyder–Chesapeake lease are clear. The oil royalty bears postproduction costs because it is paid on the market value of the oil at the well. The market value at the well should equal the commercial market value less the processing and transporting expenses that must be paid before the gas reaches the commercial market.
See Heritage Res., 939 S.W.2d at 122.
Id.
The gas royalty in the lease does not bear postproduction costs because it is based on the price Chesapeake actually receives for the gas through its affiliate, Marketing, after postproduction costs have been paid. Often referred to as a “proceeds lease”, the price-received basis for payment in the lease is sufficient in itself to excuse the lessors from bearing postproduction costs. And of course, like any other royalty, the gas royalty does not share in production costs. But the royalty provision expressly adds that the gas royalty is “free and clear of all production and post-production costs and expenses,” and then goes further by listing them. This addition has no effect on the meaning of the provision. It might be regarded as emphasizing the cost-free nature of the gas royalty, or as surplusage.
Having lost on the issue in the court of appeals, 427 S.W.3d 472, 482, Chesapeake does not dispute in this Court that “the price actually received by the Lessee” for purposes of the gas royalty is the gas sales price its affiliate, Marketing, received, nor do the Hyders argue that the gas sales price was unfair. Cf. Phillips Petroleum Co. v. Yarbrough, 405 S.W.3d 70, 78 (Tex.2013) (“A duty to market is implied in leases that base royalty calculations on the price received by the lessee for the gas. Yzaguirre v. KCS Res., Inc., 53 S.W.3d 368, 373–74 (Tex.2001).”).
The court of appeals reasoned otherwise, relying on the “free and clear” language to conclude that both the oil and gas royalties are free of postproduction costs. 427 S.W.3d at 477–478. Chesapeake has not challenged that ruling in this Court.
The overriding royalty in the Hyder–Chesapeake lease is not as clear as either of the other two royalty provisions. The Hyders argue that the requirement that the overriding royalty be “cost-free” can only refer to postproduction costs, since the royalty is by nature already free of production costs without saying so. But as with the gas royalty, “cost-free” may simply emphasize that the overriding royalty is free of production costs. Chesapeake argues that “cost-free overriding royalty” is merely a synonym for overriding royalty, and a number of lease provisions discussed in other cases support that view.
See, e.g., McMahon v. Christmann, 157 Tex. 403, 303 S.W.2d 341, 343 (Tex.1957) (lease providing an “overriding royalty ... free of cost or expense”); R.R. Comm'n v. Am. Trading & Prod. Corp., 323 S.W.2d 474, 477 (Tex.Civ.App.–Austin 1959, writ ref'd n.r.e.) (agreement reserving an “overriding royalty of 3/8ths of 8/8ths of all the oil, gas and other minerals produced and saved from said lands ... free of all costs, except taxes”); Midas Oil Co. v. Whitaker, 123 S.W.2d 495, 495 (Tex.Civ.App.–Eastland 1938, no writ) (assignor's retention of “an overriding royalty of 7/32 of all oil, gas or other minerals ... free of cost to himself”).
The exception for production taxes, which we have said are postproduction expenses, cuts against Chesapeake's argument. It would make no sense to state that the royalty is free of production costs, except for postproduction taxes (no dogs allowed, except for cats). The exception for taxes might be taken to indicate that “cost-free” refers only to postproduction costs. But a taxes exception to freedom from production costs is not uncommon in leases, suggesting only that lease drafters are not always driven by logic.
Heritage Res., 939 S.W.2d at 122. The Texas Tax Code provides that all interested parties, including royalty owners, bear production taxes ratably. TEX. TAX CODE § 201.205.
See, e.g., Martin v. Glass, 571 F.Supp. 1406, 1410 (N.D.Tex.1983); Delta Drilling Co. v. Simmons, 161 Tex. 122, 338 S.W.2d 143, 147 (1960); McMahon, 303 S.W.2d at 350; Graham v. Prochaska, 429 S.W.3d 650, 653 (Tex.App.–San Antonio 2013, pet. denied); Am. Trading & Prod. Corp., 323 S.W.2d at 477; Wahlenmaier v. Am. Quasar Petroleum Co., 517 S.W.2d 390, 392 (Tex.Civ.App.–El Paso 1974, writ ref'd n.r.e.); see also Zephyr Oil Co. v. Cunningham, 265 S.W.2d 169, 172 (Tex.Civ.App.–Fort Worth 1954, writ ref'd n.r.e.) (lessor sought reformation of overriding royalty to include a share of the value of the gas produced, less pro rata taxes paid on the gas).
We thus disagree with the Hyders that “cost-free” in the Hyder–Chesapeake overriding royalty provision cannot refer to production costs. As noted above, drafters frequently specify that an overriding royalty does not bear production costs even though an overriding royalty is already free of production costs simply because it is a royalty interest. But Chesapeake must show that while the general term “cost-free” does not distinguish between production and postproduction costs and thus literally refers to all costs, it nevertheless cannot refer to postproduction costs here.
See supra n.19.
Chesapeake argues that because the overriding royalty is paid on “gross production”, the reference is to production at the wellhead, making the royalty tantamount to one based on the market value of production at the wellhead, which bears postproduction costs. “Gross” means “[u]ndiminished by deduction; entire”. We agree with Chesapeake, as do the Hyders, that “gross production” is the entire amount of gas produced, including gas used by Chesapeake or lost in postproduction operations. But the parties do not dispute that the overriding royalty may be paid in cash and not in kind, though the Hyders retained the right to take it in kind. Specifying that the volume on which a royalty is due must be determined at the wellhead says nothing about whether the overriding royalty must bear postproduction costs. This is clear from the other royalty provisions. The oil royalty is paid on all oil produced and bears postproduction costs. The gas royalty is due on all gas produced and used or sold—that is, all gas produced except that lost before sale or use. The gas royalty does not bear postproduction costs, not because it is based on a volume other than full production, but because the amount is based on the price actually received by the lessee, not the market value at the well.
Black's Law Dictionary 818 (10th ed.2014).
Chesapeake argues that the gas royalty provision shows that when the parties wanted a postproduction-cost-free royalty, they were much more specific. But as we have already said, the additional detail in the gas royalty provision serves only, if anything, to emphasize its cost-free nature. The simple “cost-free” requirement of the overriding royalty achieves the same end.
The overriding royalty provision reads as though the royalty is in kind, but Chesapeake does not argue that it must be, and in fact the royalty has always been paid in cash. Were the Hyders to take their overriding royalty in kind, as they are entitled to do, they might use the gas on the property, transport it themselves to a buyer, or pay a third party to transport the gas to market as they might negotiate. In any event, the Hyders might or might not incur postproduction costs equal to those charged by Marketing. The lease gives them that choice. The same would be true of the gas royalty, which is to be paid in cash but can be taken in kind. The fact that the Hyders might or might not be subject to postproduction costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash. The choice of how to take their royalty, and the consequences, are left to the Hyders. Accordingly, we conclude that “cost-free” in the overriding royalty provision includes postproduction costs.
The Hyders offer another reason for our conclusion. They argue that the lease's disclaimer of any application of the holding of Heritage Resources shows that the parties intended an overriding royalty free of postproduction costs. That case involved royalty provisions based on the market value of gas at the well with “no deductions from the value of the Lessor's royalty by reason of any” postproduction costs. The Court concluded that the no-deductions phrase was unambiguous and ineffective to free the royalties from postproduction costs. Justice Owen's concurring opinion, which became the plurality opinion for the Court, explained:
Heritage Res., 939 S.W.2d at 120–121.
Justice Baker initially delivered the opinion for the Court, joined by Chief Justice Phillips, Justice Cornyn, Justice Enoch, and Justice Spector. Id. at 120. Justice Owen, joined by then-Justice Hecht, concurred in the judgment. Id. at 124. Justice Gonzalez, joined by Justice Abbott, dissented. Id. at 131. On rehearing, Chief Justice Phillips joined Justice Owen, Justice Cornyn and Justice Spector joined Justice Gonzalez, and Justice Enoch recused himself. 960 S.W.2d 619, 620 (Tex.1997) (Gonzalez, J., dissenting on denial of motion for rehearing).
There is little doubt that at least some of the parties to these agreements subjectively intended the phrase at issue to have meaning. However, the use of the words “deductions from the value of Lessor's royalty” is circular in light of this and other courts' interpretation of “market value at the well.” The concept of “deductions” of marketing costs from the value of the gas is meaningless when gas is valued at the well. Value at the well is already net of reasonable marketing costs. The value of gas “at the well” represents its value in the marketplace at any given point of sale, less the reasonable
cost to get the gas to that point of sale, including compression, transportation, and processing costs. Evidence of market value is often comparable sales, as the Court indicates, or value can be proven by the so-called net-back approach, which determines the prevailing market price at a given point and backs out the necessary, reasonable costs between that point and the wellhead. But, regardless of how value is proven in a court of law, logic and economics tell us that there are no marketing costs to “deduct” from value at the wellhead.
....
As long as “market value at the well” is the benchmark for valuing the gas, a phrase prohibiting the deduction of post-production costs from that value does not change the meaning of the royalty clause.... All costs would already be borne by the lessee. It could not be said under that circumstance that the clause is ambiguous. It could only be said that the proviso is surplusage.
939 S.W.2d at 130–131 (26 citations omitted).
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Market value, if calculated without reference to factors necessary to that determination, is not market value.
Heritage Resources does not suggest, much less hold, that a royalty cannot be made free of postproduction costs. Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text. A disclaimer of that holding, like the one in this case, cannot free a royalty of postproduction costs when the text of the lease itself does not do so. Here, the lease text clearly frees the gas royalty of postproduction costs, and reasonably interpreted, we conclude, does the same for the overriding royalty. The disclaimer of Heritage Resources' holding does not influence our conclusion.
* * * * *
The court of appeals' judgment is affirmed.
JUSTICE BROWN filed a dissenting opinion, in which JUSTICE WILLETT, JUSTICE GUZMAN and JUSTICE LEHRMANN joined.
Jeffrey V. Brown, Justice
I withdraw my June 12, 2015 dissenting opinion and substitute the following in its place.
I disagree with the Court that the overriding royalty clause expresses an intent to modify the default rule that such an interest bears post-production costs. I would reverse the court of appeals and hold that Chesapeake's deduction of post-production costs was proper. I respectfully dissent.
The disputed clause gives the Hyders a “cost-free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production obtained from each [directionally drilled] well.” This Court has held that “[a]n overriding royalty is an interest in the oil and gas produced at the surface, free of the expense of production.” Paradigm Oil, Inc. v. Retamco Operating, Inc., 372 S.W.3d 177, 180 n. 1 (Tex.2012) (quoting Stable Energy, L.P. v. Newberry, 999 S.W.2d 538, 542 (Tex.App.–Austin 1999, pet. denied)). Though it is free of production expenses, an overriding royalty generally bears its share of post-production costs. French v. Occidental Permian Ltd., 440 S.W.3d 1, 3 (Tex.2014) (citing Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121–22, 123 (Tex.1996)); Blackmon v. XTO Energy, Inc., 276 S.W.3d 600, 604 (Tex.App.–Waco 2008, no pet.) (“Whatever costs are incurred after production of the gas or minerals are normally proportionately borne by both the operator and the royalty interest owners.” (emphasis in original) (quoting Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 444–45 (Tex.App.–Corpus Christi 2006, pet. denied))). Parties to a lease, however, are free to allocate those costs as they wish. French, 440 S.W.3d at 8 (citing Heritage, 939 S.W.2d at 121–22). As with any other contract, we construe an oil-and-gas lease to give effect to the intent it expresses. Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex.2005) (per curiam).
I agree with the Court that the measure of the overriding royalty here—“gross production obtained from each such well”—refers to the total volume of minerals extracted from the ground before any are used to fuel production or transportation or are lost en route to market. Exxon Corp. v. Middleton, 613 S.W.2d 240, 244 (Tex.1981) (“Production means actual physical extraction of the mineral from the land.” (citing Monsanto Co. v. Tyrrell, 537 S.W.2d 135 (Tex.Civ.App.–Houston [14th Dist.] 1976, writ ref'd n.r.e.))); Blackmon, 276 S.W.3d at 604 (“Historically, ‘production’ ceases once the lessee extracts oil or gas from the ground at the wellhead.” (quoting Byron C. Keeling & Karolyn King Gillespie, The First Marketable Product Doctrine: Just What Is the “Product”?, 37 ST. MARY'S L.J. 1, 88–89 (2005))). I disagree, however, that this measure allows valuation downstream at any point of sale. The clause does not refer to any point of resale downstream. It implicates only one location—the wellhead at which point each directional well produces.
By contrast, the Hyders' gas royalty is “twenty-five percent (25%) of the price actually received” upon resale by Chesapeake. That price necessarily reflects any post-production value added, and the Court rightly observes it thus does not bear post-production costs. See ante at 871; cf. Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 137 (Tex.1996) (holding royalty based on “gross proceeds” would not allow deductions but royalty based on “net proceeds” would). The parties could have expressed the overriding royalty similarly, but they did not do so. See Middleton, 613 S.W.2d at 245 (“If the parties intended royalties to be calculated on the amount[-]realized standard, they could and should have used only a ‘proceeds-type’ clause.” (emphasis in original)).
Post-production activities will add value to the Hyders' overriding royalty—their share of minerals produced from the directional wells—but they have not yet done so at the time of production. Though the overriding royalty may not have been expressed using the familiar market-value-at-the-well language, I read its value as being just that. Cf. Heritage, 939 S.W.2d at 131 (Owen, J., concurring) (“There are any number of ways the parties could have provided that the lessee was to bear all costs of marketing the gas.”).
I further disagree that whether the Hyders accept cash rather than their share of production in kind should affect that value. Had they taken the actual gas as it was produced, they certainly would incur post-production and transportation costs in marketing the gas. They could, of course, also use that gas on the property for whatever purpose they found useful. But the manner in which they accept their royalty should not determine the value they receive. That Chesapeake undertook to market the gas should not saddle Chesapeake with post-production costs or entitle the Hyders to more than the royalty for which they bargained.
Likewise, I think the “cost-free” designation should not operate to add value to the Hyders' overriding royalty, and I disagree with the Court that it expresses an intent to abrogate the default rule that the lessee bears post-production costs. Though it need not be further spelled out that a royalty interest is free of production costs, parties commonly do so anyway. See, e.g., Martin v. Glass, 571 F.Supp. 1406, 1410 (N.D.Tex.1983), aff'd, 736 F.2d 1524 (5th Cir.1984) (interpreting overriding royalty that was “free and clear of all cost of drilling, exploration or operation”); Delta Drilling Co. v. Simmons, 161 Tex. 122, 338 S.W.2d 143, 147 (1960) (interpreting “overriding royalty interest, free and clear of all cost of development”); McMahon v. Christmann, 157 Tex. 403, 303 S.W.2d 341, 343 (1957) (considering overriding royalty that was “free of cost or expense”); Midas Oil Co. v. Whitaker, 123 S.W.2d 495, 495 (Tex.Civ.App.–Eastland 1938, no writ) (interpreting overriding royalty that was “free of cost”). As the Court recognizes, courts often read such language as simply stressing the production-cost-free nature of a royalty without struggling to ascertain any additional meaning. See ante at 873–74. I would do so here.
The Court points out that the disputed clause excepts from the “cost-free” designation the Hyders' share of production taxes, which—everyone knows—are actually post-production costs. See ante at 874. From this the Court reasons that “cost-free” must cover post-production costs, otherwise there would be nothing to except. See ante at 874. This logic rests on the assumption that the parties, no doubt in studied fidelity to our precedents, considered production taxes to be post-production costs.
It is true that we have, on occasion, generally categorized taxes as a post-production cost. See Heritage, 939 S.W.2d at 122 (holding overriding royalty is free of production expenses but “usually subject to post-production costs, including taxes”). The parties in this case, however, do not speak about taxes generally. Rather, they refer specifically to production taxes. I am not convinced Heritage necessarily compels the Court's characterization of production taxes as post-production costs. The question here, however, is not what the semantics in Heritage compel, but what the parties intended. The Court reaches the counterintuitive conclusion that by excepting production taxes, the parties meant to carve out a post-production cost. Regardless of what Heritage suggests, I believe the parties figured “production taxes” to be a production cost.
Moreover, as the Court recognizes, parties often allocate tax liability on the royalty owner while at the same time specifically emphasizing that the royalty is free from production costs. See, e.g., Martin, 571 F.Supp. at 1410 (interpreting overriding royalty that was “free and clear of all cost of drilling, exploration or operation, SAVE AND EXCEPT said interest shall be subject to its proportionate part of all gross production, ad valorem and severance taxes”); Delta Drilling, 338 S.W.2d at 147 (interpreting overriding royalty that was “free and clear of all costs of development, except taxes”); R.R. Comm'n v. Am. Trading & Prod. Corp., 323 S.W.2d 474, 477 (Tex.Civ.App.–Austin 1959, writ ref'd n.r.e.) (interpreting overriding royalty that was “free of all costs, except taxes”). The drafting in those instances suggests some parties consider taxes production costs. Furthermore, the taxes at issue here are specifically referred to as “production taxes” in the Tax Code, aligning them with production, not post-production, costs. See Tex. Tax Code §§ 201.001(6), .051, .052 (imposing production tax calculated on “market value of gas produced and saved” and defining production as “gross amount of gas taken from the earth”). Accordingly, I do not believe the reference to production taxes here compels the inference that the parties intended “cost-free” to include post-production costs.
In addition to Heritage, the Court cites section 201.205 of the Tax Code in support of its view that production taxes are post-production costs. See ante at 874 n.20. Section 201.205 provides that production taxes “shall be borne ratably by all interested parties, including royalty interests.” The Court presumably believes this statute negates the argument that production taxes can be considered a production cost. If an overriding-royalty interest is free of post-production costs but shares in the production tax, the argument goes, the production tax cannot be a production cost.
Two problems arise. First, a statutory provision requiring that a royalty interest bear its share of production taxes does not morph a production cost into a post-production cost. Instead, it simply creates a statutory exception to the common-law default rule that an overriding-royalty interest is free of production costs. Second, the pro-rata nature of production taxes only bolsters the reading that “cost-free” does not refer to post-production costs. The clause grants Hyder a “cost-free (except only its portion of production taxes) overriding royalty.” (emphasis added). The clause does not require Hyder to pay all production taxes, but rather appears to be written with an awareness of the pro-rata scheme imposed by statute. What follows is a much easier reading than the Court's construction: the parties intended “cost-free” to emphasize the default rule that Hyder's royalty interest is free of production costs but, sensibly assuming production taxes might be production costs, clarified that Hyder was not relieved of his statutory share of the production-tax burden.
As recognized in Heritage, royalty clauses that purport to modify a royalty valued at the well are inherently problematic. 939 S.W.2d at 130 (Owen, J., concurring) (“The concept of ‘deductions' of marketing costs from the value of the gas is meaningless when gas is valued at the well.”). Here, no post-production costs have been incurred at the time of production, and it means nothing to say the overriding royalty is free of those yet-to-be incurred costs. I would resolve this tension to give full meaning to “gross production,” which defines the interest where “cost-free” is only an adjective describing it.
Where the overriding royalty interest is merely “cost-free,” the 25% oil-and-gas royalty is specified as being:
free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and Lessee's point of delivery or sale of such share to a third party.
(emphasis added). The Court touches on the interpretive issues this language presents. Because the gas royalty is valued by sale price after post-production value has already been added, the Court deems the language ineffective and suggests it is surplusage or it at most emphasizes the cost-free nature of the gas royalty. Ante at 873. I agree. Application to the oil royalty, defined as “twenty-five percent (25%) of the market value at the well,” is no less problematic. As Heritage illustrates, a market-value-at-the-well royalty is calculated by deducting post-production costs, and a court may have difficulty giving effect to language that may be read as intent to free the royalty from those costs. While the “free and clear” language here may seem to express intent that both royalties do not bear post-production costs, giving it that effect is logically difficult. This may be where the so-called Heritage disclaimer, located in the oil-and-gas royalty clause, comes into play. I do not argue with the Court's assessment that Heritage “holds only that the effect of a lease is governed by a fair reading of its text,” ante at 876, and I agree a disclaimer of that precedent cannot itself free a royalty of post-production costs. But the “free and clear” language here is similar in specificity to the language held ineffective in Heritage, which provided “there shall be no deductions from the value of Lessor's royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.” 939 S.W.2d at 120– 21. The disclaimer could be interpreted as a belt-and-suspenders attempt to ensure the “free and clear” language is given effect despite its conflict with the oil royalty's market-value-at-the-well definition.
We are not asked to resolve these interpretive issues. But the vast difference between the royalty and overriding royalty clauses drills home my interpretation of the latter. If the extensive, specific, and detailed “free and clear” language should be read as only emphatic or surplusage, so should the mere “cost-free” designation. If the “free and clear” language expresses intent to modify the market-value-at-the-well oil royalty so that it does not bear post-production costs, the mere “cost-free” adjective cannot express the same intent as to the overriding royalty.
For the same reasons, I disagree with the Hyders that the Heritage disclaimer requires a broad construction of “cost-free.” Where the oil-and-gas royalty's extensive “free and clear” language resembles the language interpreted in Heritage, the overriding royalty's language does not. Where the “no deductions” language in Heritage was meaningless and ineffective, I read “cost-free” as redundant but not meaningless. And though the disclaimer expressly extends to “the terms and provisions of this Lease,” its location in the oil-and-gas-royalty clause highlights that it is intended to support the “free and clear” language, not to give the simple “cost-free” designation any additional meaning.
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Parties are free to allocate post-production costs as they wish, and “[o]ur task is to determine how those costs were allocated under [this] particular lease[ ].” Heritage, 939 S.W.2d at 124 (Owen, J., concurring). I read the overriding-royalty clause as granting the Hyders a percentage of production before post-production value is added and without allocating their share of post-production costs to Chesapeake. I would thus hold Chesapeake properly deducted post-production costs to arrive at the royalty's value and would reverse the court of appeals' judgment.
JUSTICE WILLETT, JUSTICE GUZMAN, and JUSTICE LEHRMANN, dissenting.