Melanie Reyes

Authors: Celia Flowers & Melanie Reyes

The proliferation in horizontal drilling over the last decade has given rise to new, complex legal issues.  One area where the law has increasingly lagged behind the technology is in the calculation of royalties for horizontal allocation wells – in particular, the question of the division of royalties from horizontal wells crossing adjacent units has dogged the petroleum industry in recent years.  While the issues of permitting and royalty apportionment have not been wholly resolved by Texas courts with regard to wells crossing adjacent unit lines, a review of existing Texas Railroad Commission orders and case law authority pertaining to wells crossing adjacent leases provides credible guidance.

1. Permitting horizontal wells as allocation wells with the Texas Railroad Commission (“RRC”) 

When sixty-five percent of the royalty interest owners within a pooled unit or units have approved a drilling plan and execute Production Sharing Agreement (PSA), the Texas Railroad Commission (RRC) will issue a PSA well permit.  Production Sharing Agreements and PSA permitting has become an accepted means of conducting business around horizontal drilling.  A bigger issue arises, however, when less than sixty-five percent of royalty owners fail or refuse to enter such an agreement.

While little case authority exists, the precursor to this issue originally arose with the RRC in the framework of whether pooling authority was required before a lessee could drill a horizontal well that crossed lease lines, where that lessee held leases on all tracts crossed by the horizontal well. The issue was presented to the RRC by EOG Resources Inc. for its Klotzman Lease (Allocation) Well NO. 1H (Status NO. 744730), Eagleville (Eagle Ford-2) Field, Dewitt County, as an Allocation Well Drilled On Acreage Assigned from Two Leases, Docket No. 02-0278952 (Sept. 24, 2013) (final order).  EOG filed an application for a drilling permit for a horizontal well purporting to form an approximately eighty-acre drilling unit by utilizing 40 acres from two separate leases.  EOG held a working interest in both leases.  However, the lessors had not given EOG pooling authority under the leases, and the Klotzmans and Reillys (lessors) protested EOG’s application for a drilling permit.

The lessors alleged the act of drilling across lease lines and producing from multiple tracts and leases constituted unauthorized pooling, despite the label attached to the permit application, and therefore, EOG Resources, Inc. had no good-faith claim to the right to drill the well. The lessors further argued that such a well would necessarily require the removal of captured minerals from the lease prior to measurement. In their view, the inescapable prospect of downhole commingling breaks down an analogy between an allocation well and a collection of wells isolating each lease. In the latter, production could be measured at the surface of each well, and no disputes would arise over what production is attributable to a particular lease. Lessors argued that the plain language of Rule 26 required measurement prior to removal of production from a lease.[1]

In response, EOG insisted that no pooling resulted from the drilling of an allocation well. Additionally, it asserted that Rule 26 had no applicability or relevance to downhole commingling. On the narrow question of whether it held a good-faith claim to the right to drill, EOG pointed to the leases, which indisputably granted the right to drill on and through the lands described in the leases.  It argued that because the rights and duties under a lease are a matter of contract between a lessor and lessee, it maintained that interpretation of contractual rights is the province of courts rather than the Commission.[2]

The RRC ultimately determined that EOG was not required to demonstrate any pooling authority in order for the RRC to issue a permit to drill a horizontal well that crosses lease lines, where all the leases involved are held by the lessee. Id.  The lessors filed suit in district court in Travis County, but the case settled before trial.[3]  Moreover, in the wake of the “Klotzman” challenge, the RRC has continued to issue permits to drill horizontal allocation wells where the applicants show a good-faith claim of a right to drill, which is satisfied with a showing of leasehold or mineral rights. Texas case law has long held that the RRC has authority to determine whether an applicant has such a good-faith claim.[4]

A horizontal allocation well refers to: 1) a horizontal well that traverses more than one tract in which 2) less than sixty-five percent of the royalty interest owners have approved the drilling plan (thus failing the RRC’s guidelines for issuing a Production Sharing Agreement or PSA well permit).   Instead of conditioning the grant of a permit for a horizontal allocation well upon an affirmative representation by the applicant that it has pooling authority or has otherwise obtained the consent from its lessors to drill the multi-tract horizontal well, the RRC only requires the applicant to represent that it has the entire working interest for those traversed tracts without any further representation by the applicant that it has pooling authority or has obtained the consent of royalty owners for a multi-tract well.

It is important to note, however, that Texas courts have routinely held that the RRC’s authority does not extend beyond the permitting process.[5]  Once the permit has been issued, the parties continue to be bound by their existing contractual relationships and longstanding common law (i.e. tort law).[6] Moreover, Texas courts have yet to specifically address the applicability of the above analysis, the permitting of horizontal wells as allocation wells, to scenarios involving adjacent units.

Upon filing and paying the required fee, it has become the practice of the RRC to routinely allow a permit, originally issued as a horizontal allocation permit, to be amended to become a PSA permit should the required number of royalty owners execute PSAs.

1. Payment of Royalties under an Allocation Well

The RRC refers to a “horizontal drainhole well” as any well that consists of one or more horizontal drainholes.[7] A horizontal drainhole is defined as that part of the wellbore that deviates at more or less of a right angle from the vertical wellbore; it begins at the penetration point, where it penetrates the field at an interval capable of production, and ends at the terminus point, the point farthest from the penetration point but within the producing interval. See id. § 3.86(a)(2), (5), (6) (2000). For purposes of designating a proration unit and allocating production allowables, units are determined by the length of the horizontal displacement between the penetration point and the terminus point, i.e., the horizontal displacement of the drainhole.[8]

The first case addressing the consequences of drilling horizontal wells across unpooled interests was Browning Oil Co. v. Luecke, 38 S.W.3d 625 (Tex.App.—Austin 2000, pet. denied). Humble Exploration Company, Inc. Oil Company obtained three leases from the Lueckes in 1979.[9]  Those leases were eventually assigned to Browning Oil Company, and in 1994, Marathon Oil Company and Browning Oil Company, Inc. entered into an operating agreement to develop the area which included the Lueckes’ acreage under the leases. Although those leases contained pooling provisions, they also contained anti-dilution provisions restricting the quantity of lease acreage that could be pooled with the lease.[10]

In late 1994, Marathon approached the Lueckes seeking to amend the leases to allow pooling for horizontal wells.  The effect of the proposed amendment would have nullified the anti-dilution provisions, and the Lueckes refused.[11] Nevertheless, in February 1995, Browning and Marathon drilled two successful horizontal wells across tracts, which included Luecke tracts. They filed a Certificate of Pooling Authority with the RRC, showing the location of the first well on a purported pooled unit consisting of 839.18 acres, 268.68 of which were owned by the Lueckes; and that the second well was located on a purported pooled unit consisting of 346.625 acres, 114.86 of which were owned by the Lueckes.

The Lueckes filed suit against Browning and Marathon, claiming that the purported “units” for the two horizontal wells violated the pooling provisions and the anti-dilution provisions in their leases. Following a jury verdict for the Lueckes, Lessees appealed.  The Court of Appeals determined with ease that the pooling and anti-dilution provisions of the leases applied to the horizontal wells.[12]

The appellate court concluded that Lessees were required to comply with the lease provisions and that they breached those provisions. However, with regard to the Lueckes’ claim that they were entitled to royalties for total production from the wells undiluted by distribution among other pooled landowners, the court disagreed. It concluded that because the breach rendered the pooled units invalid, the Lueckes were not entitled to receive royalties on oil and gas produced from tracts they did not own.[13]  As the court plainly stated, each tract traversed by the horizontal wellbore is a drillsite tract, and each production point on the wellbore is a drillsite.[14] However, “[a]lthough the Lueckes’ tracts are drillsite tracts, they cannot claim royalties for total production when they have no legal claim to oil and gas recovered from other lessors’ drillsite tracts.” [15]   The better remedy is to allow them to recover royalties as specified in the lease, compelling a determination of what production can be attributed to their tracts with reasonable probability.[16]

The appellate court, though not explicitly addressing commingling, applied a “reasonable probability” standard to the allocation of production from un-pooled tracts.  However, it expressly recognized the harm it could do to the burgeoning horizontal drilling industry and stated: “[d]raconian punitive damages for a lessee’s failure to comply with applicable pooling provisions could result in the curtailment of horizontal drilling. We decline to apply legal principles appropriate to vertical wells that are so blatantly inappropriate to horizontal wells and would discourage the use of this promising technology.” [17]  Thus, the court awarded the un-pooled owners “royalties for which they contracted, no more and no less.” [18]

More recently, the San Antonio Court of Appeals decided Springer Ranch Ltd. v. O.F. Jones III. et. al.[19]  Springer Ranch brought suit against Rosalie Matthews Sullivan (its neighbor) and other owners of adjoining mineral estates.  Springer Ranch sought a declaratory judgment with regard to a 1993 contractual agreement, originally executed to govern allocation of royalties with respect to vertical wells drilled on the parties’ properties.[20]  The lawsuit, however, arose years later following a dispute between the parties over allocation of royalties from a horizontal well.  The horizontal well bore was located on Spring Ranch’s land, crossed the boundary of Sullivan’s land, and ultimately, ended on Sullivan’s land.  The trial court held that the 1993 contract required that royalties from the horizontal well in dispute, and any future horizontal wells crossing the parties’ property lines, must be allocated based upon the productive portions of the well underlying the parties’ properties.[21]  An appeal followed.

On appeal, the appellate court acknowledged the distinction between the manner in which production is obtained from horizontal wells, as opposed to vertical wells, and explained that a horizontal well only produces hydrocarbons from the part of the well that lies within the hydrocarbon-bearing reservoir, or “correlative interval.”[22]  It further explained that “[a]long the horizontal displacement are take points through which hydrocarbons flow into the well.  A royalty, as a fraction of production, is only obtainable from the part of the SR2 well actually within the correlative interval. Despite Springer Ranch’s argument that the calculation should be based on the whole length of the well, it is not the whole length of the well from which the production is obtained…. the royalties must be allocated on the basis that the productive portions of the SR2 well are situated on both Springer Ranch’s and Sullivan’s properties.”[23]

These cases have generated a variety of methods employed by lessees/operators who must account to unpooled interest owners burdened by a portion of a horizontal well. Typically, these consist of calculating either: (1) the length of a horizontal drainhole within a tract relative to total length within the correlative interval; or (2) the number of take points within a tract relative to the total number along the entire horizontal drainhole.  It appears that absent unusual operational circumstances, production from a horizontal well should be allocated to each drill site tract proportionately based upon each tract’s share of the open wellbore in the pay zone.  Nevertheless, the Supreme Court of Texas has not addressed what standard governs damages for production from unpooled interests along a horizontal well.  Until it does, it appears that a lessee may allocate production on an unpooled basis, without liability under the commingling theory, provided it can establish with reasonable probability what production originates from the segment or segments of the drainhole within the unpooled lease.

• Hypothetical

Gas Unit #1 and Gas Unit #2 are adjacent units in Reeves County, Texas.  Both units and the leases within the units are currently held by production.  Happy Oil Co. owns 100% of the leasehold interest in both units.  Happy Oil Co. is in the process of drilling Big Gas Well — a horizontal well with a lateral drainhole crossing both Gas Unit #1 and Gas Unit #2.

Ideally, Happy Oil Co. should obtain PSAs from the royalty owners in both of the existing units with attention paid to getting the PSAs from owners along the drill path on the horizontal well.  Obtaining PSAs from these royalty owners adds contractual protection for Happy Oil Co., giving it specific contractual approval from those royalty owners of the method of allocation of production between the two existing units and among the royalty owners within each unit.   Should Happy Oil Co. obtain the required 65% of royalty owners in both units, Happy Oil Co. could obtain a PSA permit from the RRC.

If it is unclear at the beginning of the process whether the requisite percentage of royalty owners in both units will execute Production Sharing Agreements (PSAs), approving the allocation of production between the royalty owners within each unit for Big Gas Well, Happy Oil Co. will then be faced with obtaining an allocation well permit. Given the facts surrounding the drilling of Big Gas Well, where the lessee, Happy Oil Co., owns 100% of the leasehold interest in both units crossed by the horizontal well, the RRC would allow permitting of the well as an “allocation” well since the good faith claim of right to drill is satisfied.  Therefore, it would be efficient and prudent for Happy Oil Co. to proceed with drilling this well under an allocation permit.  And, if 65% of the royalty owners eventually execute a PSA, Happy Oil Co. could always amend its RRC permit from an allocation permit to a PSA permit (although, such additional efforts are probably unnecessary).

As to royalty allocation, Happy Oil Co. should allocate royalties among the owners in each unit in the amount each owner proportionately owns in the existing unit multiplied by the percentage that such unit’s acreage occupies in the area covered by the measured horizontal wellbore.  This method incorporates the methods that meet the specifications set forth thus far in Browning and Springer Ranch:  (1) the length of a horizontal drainhole within a tract relative to total length within the correlative interval; or (2) the number of take points within a tract relative to the total number along the entire horizontal drainhole.  Said method could also be committed to writing in the form of a PSA, which, as noted would provide additional contractual protection.

1. Conclusion

Technology moves at a rapid rate.  Unfortunately, cases move through the court system at a snail’s pace.  Thus, practitioners do not always have proper guidance when the case law lags behind.  Nevertheless, although the permitting processes and royalty calculations for horizontal wells is still developing, there is enough authority from both the RRC and Texas courts that practitioners can now proceed with reasonable assurance that acceptable methods used in lease line cases will eventually be adopted for unit purposes as well.

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[1] Rules 26(a)(2) and 27(a) provide that oil and gas are generally to be measured before leaving the lease from which they are produced.  See 16 Tex. Admin. Code §§ 26(a)(2), 27(a) (2012); see also Clifton A. Squibb, “The Age of Allocation: The End of Pooling As We Know it?”, 45 Tex. Tech L. Rev. 929, Texas Tech Law Review, Summer, 2013, fn. 21, 81-89 (citing closing briefs made before RRC).

[1] Id.

[1] Reily. v. R.R. Comm’n of Texas, No. D-1-GN-13-004306(98^th Dist. Ct., Travis Cty., Tex. Dec. 23, 2013).  EOG was also involved in another suit with similar issues. However, that suit has likewise been settled insofar the claims asserted against EOG’s relating to the above issues are concerned.  Spartan Texas Six Capital Partners, Ltd. v. Perryman, 494 S.W.3d 735 (Tex.App.—Houston [14^th Dist.] 2016, aff’d as modified).

[1] See Magnolia Petroleum Co. v. R.R. Comm’n, 170 S.W.2d 189, 191 (Tex. 1943).

[1] See FPL Farming Ltd. v. Environmental Processing Systems L.C., 351 S.W.3d 206 (Tex. 2011).

[1] Id.

[1] See 16 Tex. Admin. Code §3.86(a)(4) (2000).

[1] Browning Oil Co. v. Luecke, 38 S.W.3d 625, 635 (Tex.App.—Austin 2000, pet. denied).

[1] Id. at 636.

[1] Id. at 637.

[1] Id. at 638.

[1] Id. at 640. 

[1] Id. at 645. 

[1] Id. at 635. 

[1] Id. at 646. 

[1] Id. at 647. 

[1] Id. 

[1] Id. 

[1] 421 S.W.3d 273 (Tex. App.—San Antonio 2013, no pet.).

[1] Id. at 277.

[1] Id. at 277-78.

[1] Id. at 285.

[1] Id. at 286.

Authors: Celia Flowers & Melanie Reyes

Texas jurisprudence has long held that the royalty “stick” of the mineral estate is free of production costs. Although the royalty interest is not subject to production costs, royalty is usually subject to post-production costs. Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118, 122 (Tex. 1996). Nevertheless, parties are free to contract around this general rule and may allocate post-production costs however they see fit. See id. The ability to contract around default laws seems relatively simple. Whatever the law holds, the parties simply sign a contract to achieve a different result. Unfortunately, the courts have made this process much more difficult in the context of drafting around the post-production cost deduction default rules. And, the problem primarily lies in the manner in which a particular royalty is valued and the time/place where the value determination is made. Without an in-depth understanding of royalty valuation methods, many drafters find themselves attempting to draft around default laws that simply cannot be altered. This is further complicated by the fact that there are numerous means of valuing a royalty.

I. Royalty Valuation Methods
The two primary methods of royalty valuation are “market value” and “proceeds value”. The two primary times/places royalties are valued are “at the well” and “down-stream sales” to third parties. Understanding how, when, and where the royalty valuation takes place is the key to understanding how to allocate post-production cost deductions between the parties and how to draft around the default rules.

“Market value” is what a willing buyer would pay a willing seller in an arms-length transaction, generally determined by comparable sales. If comparable sales are unavailable, understanding the time/place of royalty valuation becomes of paramount importance. “Market value at the well,” means value at the well, net of any value added to the product after it leaves the wellhead. Judice v. Mewbourne Oil Company, 939 S.W.2d 133, 135 (Tex. 1996). This method deducts postproduction costs. Thus, all increase in the ultimate royalty value attributable to the expenses incurred after production is built in to the market value at the well equation.

“Proceeds” or “amount realized” royalty valuation methods require measurement of the royalty based on the amount the lessee in fact receives under its sales contract for the product. The caveat here, however, much like with the “market value” method, is the time/place of the valuation. If the lease language itself indicates that the point of sale takes place “at the well,” then, the equation contemplates post-production deductions. Thus, the coupling of “proceeds” or “amount realized” with “at the mouth of the well,” results in the same valuation as “market value at the well.”

II. No Post Production Deduction Clauses
The Texas Supreme Court’s first major holding related to attempts to draft around post-production cost deductions came in the 1996 Heritage Resources, Inc. v. NationsBank case. 939 S.W.2d 118 (Tex. 1996). In Heritage Resources, the royalty valuation method was “market value at the well.” However, the leases also included the following prohibition: “provided, however, there shall be no deductions from the value of Lessor’s royalty by reason of any required . . . transportation, or other matter to market such gas.” Id. at 120-121. The court noted that the “no deductions” clause only prohibited deductions from the “value of the Lessor’s Royalty.” See id. (emphasis added). Accordingly, the court reviewed the “no deductions” clause in light of the “market value at the well” royalty valuation method, holding that because post-production cost deductions are inherent in this valuation method, the “no deductions” clause necessarily became “surplusage” and therefore had no effect. Id.

Since Heritage Resources, drafters have taken is two-fold approach. First, the drafter attempts to remove any language marrying the “no deductions” clause with the “royalty valuation” method. Second, drafters attempts to expressly disclaim the Heritage Resources holding in the lease addendum. The effectiveness of this solution, however, has been called into question due to a series of cases. See Warren v. Chesapeake Exploration, L.L.C., 759 F. 3d 413 (5th Cir. 2014)(“no deductions” clause in addendum ineffective where royalty valuation method “at the well”); Potts v. Chesapeake Exploration, L.L.C., 760 F.3d 470 (5th Cir. 2014) (“no deductions” clause ineffective where royalty valuation method is “market value at the point of sale” but “point of sale” is at the well.)

After nearly 20 years, the Texas Supreme Court finally revisited Heritage Resources in the 2015 Chesapeake Exploration, LLC v. Hyder case. Hyder involved multiple royalty clauses. One valued royalty as market value at the well, one valued royalty as price actually received, and one value royalty as “gross production obtained.” The first two clauses were limited by the following: “The royalty reserved herein by [lessors] shall be free and clear of all production and post-production costs . . .” Id. The third clause, although containing no express post-production deduction limitation, was expressly called a “cost-free” royalty. Id. at 478. Finally, the lease included an express disclaimer of the Heritage Resources holding. Id. at 477.

The only issue that was explicitly decided by the Texas Supreme Court was whether the third royalty valuation method allowed for post-production cost deductions. Hyder, 2016 WL 352231 at 1. The court held that the “cost-free” designation prohibited the lessee from deducting post production costs. See id. at 2. Nevertheless, while the lessors in Hyder may have won the day, the war still seems to favor the lessees due to the court’s analysis therein.

The first problem with Hyder is that it gives effect to the “cost free” language in the third royalty valuation method, but it ignores the “free and clear” language limitation on the other to two royalty clauses in the same lease. Is “cost free” now a defined term of art that, regardless of timing of royalty valuation, frees the royalty (any royalty) of bearing post-production costs? Had the Heritage Resources case included the “cost free” language, would that result have been different, irrespective of the implication of timing? And, why is the term “cost free” effective but the phrase “free and clear of all post-production costs” surplusage?

The second Hyder problem is that, in dicta, the court opines that by making a lease a “proceeds lease,” this, in and of itself, is sufficient to avoid post-production cost deductions from the lessor’s royalty. See id. at 2. But, this conclusion is inconsistent with prior law relating to “proceeds leases.” The high court has previously held that a “proceeds lease” that uses a “net proceeds” methodology, per se, contemplates post-production cost deductions. This is so because a “net proceeds” calculation is synonymous with the amount realized, calculated at the mouth of the well. Conversely, a “gross proceeds” lease would theoretically not allow such deductions. See Judice, 939 S.W.2d at 136.

It’s important to note that in the 5th Circuit Potts case, the lease at issue was a proceeds lease, but the court held that the lessor’s royalty still bore the cost of post-production activities. In that case, the author (who wrote the concurrent opinion in Heritage Resources) was very careful to stress that the underlying reasoning behind Heritage Resources was not a matter of “market value” versus “proceeds” methodologies. The Heritage Resources reasoning stems from the “when and where” valuation — specifically, at what point is the royalty valued: at the well or downstream after processing? In Potts, the point of sale was at the well; thus, the lessor’s royalty included post-production cost deductions. This “timing” analysis, although perhaps overly complicated, at least makes logical sense and provides a more solid understanding of the rule set out in Heritage Resources.

But, the Texas Supreme Court does not address Potts at all in Hyder. Unfortunately, in connection with the first two royalty clauses at issue in Hyder, the court does not address the “timing” analysis, either. In failing to do so, the question of whether a “no deductions” clause will have any effect on a “proceeds” lease that calculates royalty at the mouth of the well is left unclear. The Hyder case expressly states: “the price-received basis for payment in the lease is sufficient in itself to excuse the lessors from bearing postproduction costs.” Hyder, 2016 WL 352231 at 2. Standing alone, that statement seems to imply that timing does not matter – call it a proceeds lease and no deductions. But, as noted, such an implication flies in the face of long-standing Texas law with respect to how a price paid at the well calculation is derived, and it undermines the only logical reasoning behind the Heritage Resources holding – that timing is the key. If this Hyder statement relates solely to “gross proceeds” leases, it could be harmonized with existing law. But, a “net proceeds” lease, as examined in both Judice and Potts, is a different animal altogether.

Another aspect of the Hyder case that is interesting is the court’s rejection of the Heritage Resources disclaimer. In the context of “timing,” again, this holding makes sense. If a royalty is valued at the well – be it market value or actual price received – those calculations include post-production cost deductions, and thus, a disclaimer of the Heritage Resources holding is as ineffective as a “no deductions” clause. But, again, the court veers away from the timing analysis in its analysis of the royalty clauses. Still, the bottom line seems to be that a disclaimer of Heritage Resources is of no effect under any circumstances.

As to the specific holding in the case as it relates to the royalty clause, the court states:

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. Id. at 5.

Finally, the Hyder dissent is worth note. The majority held that the “cost-free” language of the overriding royalty clause controlled, but the dissent focused on the “gross production” language. Hyder, dissent, 2016 WL 352231. The dissent notes that “gross production” is not as familiar a term as “market value at the well” or “amount realized, calculated at the mouth of the well.” Id. But, based on the standard definition of “gross” and “production,” the dissent concludes this phrase is synonymous with an “at the well” calculation. See id.

Under such a reading, the dissent would have held that the “cost free” language was surplusage because, as Heritage Resources holds, a “no deductions” prohibition clause cannot free a royalty from a valuation method that is inherently based on a post-production cost deduction calculation. In other words, gross production is what is obtained at the well, and thus, no post-production costs have been incurred at the time of production. The dissent would have resolved this tension “to give full meaning to ‘gross production,’ which defines the interest where “cost-free” is only an adjective describing it.” Id.

Despite the inherent problems with the new Hyder decision, the Texas Supreme Court now has the opportunity to clarify the opinion in light of the problems raised by the dissent as the case of Commissioner of General Land Office of State of Texas v. Sandridge Energy, Inc. is now at the high court and briefs on the merits have been submitted. 454 S.W.3d 603 (Tex. App.—El Paso 2014, pet filed). Sandridge Energy involves the interpretation of the following clause: “gross production or the market value thereof such value to be based on the highest market price paid or offered for gas of comparable quality in the general area where produced and when run, or the gross price paid or offered to the producer whichever is greater.” Id. at 608. The El Paso court of appeals determined this clause equivalent to be a market-value at the well valuation. See id. at 616. It will be interesting to see if the high court grants petition for review, and if so, how the opinion attempts to harmonize the case with Hyder.

II. WHERE DO WE GO FROM HERE?
After 20 years of drafting around Heritage Resources, the majority of practitioners are looking back and realizing that their efforts to work around the holding were most likely in vain. Due to the Hyder opinion, Lessors who may have seen their royalty free of post-production costs could now be receiving royalty checks for lower amounts. The question now is: How do we draft a royalty valuation clause and/or no-deductions clause to meet the understanding of the parties?

At first glance, for lessees, the answer seems relatively clear. If the royalty is calculated as the market value “at the mouth of the well,” the royalty is subject to post-production costs irrespective of the addition of a no-deductions clause or a Heritage Resources disclaimer. But, due to the Hyder language that the price-received basis for payment is “sufficient in itself to excuse the lessors from bearing postproduction costs,” the implication is that any “proceeds” could free the lessor’s royalty from postproduction costs whether it is a gross proceeds or a net proceeds lease. This may be an unintended consequence of the Hyder language, but the argument is not ripe for adjudication, and drafters will have to hope the high court eventually clarifies this language. In the meantime, if the lessee wants the lessor to bear post-production costs, the safest bet is to calculate the lessor’s royalty as market value at the well.

For lessors, the picture is even less clear. Drafters now know that a market value at the well royalty valuation will render a no deductions clause surplusage no matter what language they use in the no deductions clause. But, what about “market value at the point of sale”?

This will depend on “where” the actual point of sale occurs. If evidence demonstrates the point of sale is “at the well,” the lessor is back to square one and a no deductions clause will be ineffective. Thus, it becomes imperative that the lessor determine “where” the actual point of sale will occur before relying on this language. Moreover, a lessee may change its point of sale over the course of a lease. Accordingly, lessors may need to firm up the point of sale language to something more specific such as: “cost free royalty, calculated by the market value at the final point of sale, downstream, after all processing, transporting, gathering, marketing, and other post production operations have occurred.

As to a proceeds lease, lessors, like the lessees, would be at risk relying on the Hyder language. To be fool-proof, a proceeds lease should be just as specific as a market value lease. Therefore, the royalty valuation clause should specifically state that the royalty is “cost free, calculated by the gross proceeds or total amount realized at the final, downstream point of sale, after all processing, transporting, gathering, marketing, and other post production operations have occurred.

CONCLUSION
Whether the drafter is preparing a lease favorable to a lessor or lessee, the traps inherent in formulating a cost-free or burdened royalty are now abundant due to the confusing nature of the case law. As noted, the courts’ analyses logically turn on timing. However, because Hyder arguably steers away from this logic, the effects of proceeds leases are now unclear. Thus, drafters, in order to be safe, should use succinct, specific language in the royalty valuation clause and stop relying on no-deduction addendums until Texas courts hopefully, one day, shore up this issue with a clear, bright-line edict.

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[1]           Chesapeake Exploration, L. L. C. v. Hyder, 2016 WL 352231 1. ; 59 Tex. Sup. Ct. J. 290 (Tex. Jan. 29, 2016) opinion substituted for Chesapeake Exploration, L. L. C. v. Hyder, 58 Tex. Sup. Ct. J. 1182 (Tex. 2015).  *Please note, the original opinion was withdrawn and a new opinion substituted in its place on January 29, 2016.  A detailed review of the substituted opinion, however, demonstrates no significant, substantive changes between the original and the new opinion.  Citations in this paper will be made to the Texas Supreme Court’s most recent Hyder opinion.