Chesapeake Exploration, L.L.C. and Chesapeake Operating, Inc., Petitioners, v. IV

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Supreme Court of Texas.

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

NO. 14-0302

Decided: January 29, 2016

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 –––;  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, 338 S.W.2d 143, 147 (Tex.1960) (interpreting “overriding royalty interest, free and clear of all cost of development”);  McMahon v. Christmann, 303 S.W.2d 341, 343 (Tex.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 –––. 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 –––. From this the Court reasons that “cost-free” must cover post-production costs, otherwise there would be nothing to except.  See ante at –––. 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 ––– 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 _. 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 –––, 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.

* * *

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.

Jeffrey V. Brown, Justice