Oil & Gas Alert. Drafting Lease Royalty Clauses in the Appalachian Basin after Kilmer

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1 April 27, 2010 Authors: C. Scott Gladden Billie Ann Maxwell K&L Gates includes lawyers practicing out of 36 offices located in North America, Europe, Asia and the Middle East, and represents numerous GLOBAL 500, FORTUNE 100, and FTSE 100 corporations, in addition to growth and middle market companies, entrepreneurs, capital market participants and public sector entities. For more information, visit Drafting Lease Royalty Clauses in the Appalachian Basin after Kilmer Introduction The legal landscape for oil and gas lessees drafting royalty clauses in Pennsylvania became significantly more promising with the Pennsylvania Supreme Court s decision in Kilmer v. Elexco Land Services Company on March 24, As a result of royalty clause implications of the Kilmer decision, the law in other Appalachian Basin states as compared to Pennsylvania is either less clear or more lessor-friendly on the subject of royalty clause interpretation. Regardless of the state involved, the royalty clause remains one of the most critical and most often litigated oil and gas lease provisions. The typical royalty payment related to a fraction of production seems like it should be an easy calculation because most oil and gas lessees agree that the lessor/lessee relationship generally involves the lessee bearing costs associated with production, while costs after production should be borne proportionately by the lessor and lessee. In that scenario, the lessee would pay all costs of drilling, hydraulic fracturing, and completing the well, but the lessor would then bear a proportionate allocation of post-production costs ("PPCs"), such as processing, treating, gathering, transportation, and compression. In recent years, the deduction of PPCs from royalty payments has received increased scrutiny and litigation nation-wide due to the increased value of the products at issue and the complexity of arrangements for downstream sales and services. Writing lease royalty clauses to achieve the simple and logical allocation of costs described above can be deceptively difficult, and this task is made more difficult by varying interpretations of royalty language and the lessee's implied duties in different states. The Kilmer decision gives lessees hope that a rational and reasonable reading of oil and gas lease language will prevail in Pennsylvania. However, given the value of reserves in the Appalachian Basin and the resulting public focus, the region s relatively new wave of royalty litigation is likely to continue in the other Appalachian states and potentially in Pennsylvania, especially regarding issues not addressed by the Kilmer Court. Because of the Appalachian states shortage of established law on the interpretation of what the petroleum industry may think of as standard lease clauses, there is little comfort available for lessees entering into leases in the region as to how their royalty clauses will be construed. While the direction royalty interpretation law will take is yet to be fully determined throughout the Appalachian Basin, some lessons can be learned from early results within the region and trends in the development of royalty clause law outside of the Appalachian Basin.

2 This article will focus first on the approach to the allocation of PPCs taken in states within the Appalachian Basin and beyond. Second, it will touch briefly on the problematic, but less litigated, use of "market value" in royalty clauses. A. Post Production Costs Two Lines of Logic The difficulty in predictably allocating PPCs in states like New York and Ohio where the courts have not yet weighed in on the allocation of PPCs stems from the differing scope of the implied duty to market in different states. As discussed in more detail below, Pennsylvania and West Virginia have taken dramatically different approaches to royalty clause interpretation. The conflicting interpretations by Pennsylvania and West Virginia mirror the range of theories applied in states outside the Appalachian Basin, where the allocation of PPCs has been determined primarily by two lines of logic: (1) a point of valuation or at the wellhead theory or (2) a marketable product doctrine. First, the following states use a point of valuation analysis and have concluded that lease language directing royalties to be paid or products to be valued at a specific point, such as at the wellhead, sets a point of valuation after which PPCs are proportionately borne by the lessor: California, Louisiana, Michigan, Mississippi, New Mexico, Texas and now apparently Pennsylvania (as discussed below). ii To slightly varying degrees, in these states the use of at the well or at the wellhead in a lease royalty clause will accomplish the allocation of PPCs described in the second paragraph above by causing the lessor to bear a proportionate share of costs related to hydrocarbon products incurred after such products reach the surface. The states following this majority rule have reached this result without apparent conflict with a previously recognized implied duty to market. In states acknowledging that at the wellhead language is intended to determine the point after which PPCs will be shared, the implied duty to market means merely an obligation for the lessee to prudently attempt to sell the petroleum products produced from the lease. iii Second, Colorado, Kansas, Oklahoma, and West Virginia have expanded the implied duty to market to include an implied duty to make products marketable at no cost to the lessor, thereby shifting to the lessee some treating, processing and compression costs related to lessor s share of production incurred prior to the physical point at which a marketable product is obtained or further downstream in the case of Virginia (as discussed below). iv The states that have taken the marketable product approach have often done so despite lease language that set a physical point of valuation. v Pennsylvania With the Kilmer decision, the Pennsylvania Supreme Court signaled its willingness to include Pennsylvania among the majority of states that allow the deduction from the lessor s share of production of PPCs incurred downstream of a specified point, regardless of whether a marketable product exists at that point or where the sale of the product takes place. vi The question before the Pennsylvania Supreme Court in Kilmer was not what PPCs could be deducted from royalty payments, but whether the deduction of PPCs from a 1/8th royalty created a violation of the Pennsylvania Minimum Royalty Act, which voids leases that result in payment of less than a 1/8th royalty. vii However, the Court examined not only the application of the Pennsylvania Minimum Royalty Act but also the PPC allocation theory that should be presumed to be encompassed by the Act at the time it was enacted. viii In determining that the assumptions underlying the Act were those consistent with a net back to the wellhead value approach, the Kilmer Court discussed and impliedly discounted much of the logic used to support more lessor-friendly market value or sales point methodologies in some other states. ix As positive a result for lessees as the Kilmer decision represents, it must be kept in perspective. The lease royalty clause at issue in Kilmer did not use the words at the wellhead or at the well ; instead, it went into some detail as to what costs would be shared by the lessor, and the Kilmer Court stopped short of addressing the permissibility of PPC deductions under the terms of the subject lease. x Therefore, the question remains open as to what, if any, royalty clause language beyond at the well or at the wellhead will be necessary in Pennsylvania to allocate PPCs downstream. While the Kilmer Court discussed the concept of wellhead valuation thoroughly enough to imply a favorable outlook on April 27,

3 the use of that terminology in royalty clauses, a lessee would still be wise to draft with a goal of certainty as to PPCs until cases following Kilmer directly address the effect of at the wellhead alone in a royalty clause as a determinative measure for allocating PPCs. West Virginia and the Rest of the Appalachian Basin In the Appalachian Basin, only West Virginia has affirmatively expanded the implied duty to market to an obligation for the lessee to incur costs downstream of the wellhead related to a lessor s portion of production. xi In 2001, the West Virginia Supreme Court went beyond the marketable product doctrine and instituted an implied sales point doctrine, in which a lessee has an implied duty to bear all costs upstream of the point of sale, absent express language to the contrary in the lease. xii The West Virginia Supreme Court later reached a similar result in Estate of Tawney v. Columbia Natural Resources when it found that the lease was ambiguous despite language that the royalty would be paid net of all costs beyond the wellhead. xiii Whether the remainder of the Appalachian states will follow the point of valuation rule adopted by Pennsylvania and the majority of states, the marketable product doctrine, West Virginia s trailblazing sales point rule, or some other theory entirely remains to be seen. The issue in drafting lease royalty clauses in West Virginia or any other Appalachian state that may elect to follow a marketable product or sales point methodology then is whether a lessee can negate an existing or potential implied duty to market with express language and what language is sufficient to do so. The extent to which a royalty clause must expressly eliminate the implied duty in order to effectively allocate a proportionate share of PPCs to the lessor remains unclear in marketable product states generally and in West Virginia specifically, but royalty clauses that are specific and include easily quantifiable formulas can minimize the risk inherent in the Appalachian Basin's developing royalty jurisprudence. Even the most lessor-protective examples of royalty case law and legislation allocating PPCs nation-wide defer to express language of the lease, although the extent of the express language required is not always clear. Most legislation and state courts only attempt to fill in the gaps in the event of ambiguity in the lease. For example, the Wyoming Royalty Payment Act s laundry list of costs that cannot be deducted from royalty payments contains a complete exception to its applicability if such deductions are expressly provided for by specific language in an executed written agreement.... xiv Case law in West Virginia and Colorado, putting those states at the forefront of the development of the marketable product doctrine, allows for the implied duty to market to be trumped, at least in part, by express lease language. xv Unfortunately though, courts in West Virginia have set difficult and impractical standards for what constitutes an unambiguous allocation of pre-sales point PPCs to lessor, raising disheartening questions as to the lengths to which a result-oriented court there or elsewhere in the region may go in the future to find royalty language ambiguous and therefore open to interpretation and supplementation by an implied duty. xvi Despite the lack of a clear standard as to what will be sufficient to expressly rather than impliedly or judicially determine the allocation of PPCs in marketable product states, a lessee s best hope of lessening the risk that it will later be burdened by costs that are intended to be shared by the lessor remains lease language that covers both: (i) a physical point of valuation, after which lessor shall expressly share costs up to and beyond the point of sale or the point at which a marketable product is obtained, and (ii) in an included but not limited to approach, the types of PPCs that will be deducted from royalty payments, in the same proportion of such total costs as the royalty percentage bears to the total production. B. Market Value Leases Lease royalty clauses based upon the market value of products appear in many current industry forms. Historically, market value lease language was drafted by lessees to permit the deduction of PPCs from the royalty owner s share of proceeds at varying points of sale, the intention being to net back to a wellhead value result regardless of the point of sale. xvii Under this intended meaning, market value was designed to account for the fact that a product delivered to a commercial hub had more value than that product at the wellhead where the lessor was to conceptually take possession in- April 27,

4 kind. This approach was intended to allow the increased value of a product (or costs incurred to increase to the value) to be deducted in netting back from the proceeds received by the lessee to the wellhead market value upon which the royalty was to be paid. However, some courts and royalty owners have read market value royalty clauses as requiring (at least as an alternative in the absence of arm s-length sales) a royalty valuation methodology based on product prices in the area separate and distinct from the proceeds received by the lessee. This means that a lessee may in certain circumstances be responsible for a survey of regional market conditions at the time of royalty payment. xviii Under such an interpretation, these clauses become prohibitively impractical to implement and subject even a lessee s most diligent marketing efforts to later secondguessing. What appears to be an extreme reading of market value language may not become law in the Appalachian Basin, but based on the controversy created in states with more developed royalty case law, lessees in the region may be wise to avoid references to market value. Additionally, whenever possible, the lessee should tie royalty payment calculations to a less subjective measure such as the proceeds actually received by the lessee, less deductions for PPCs. Conclusion Lessees do not always get to pick their royalty language, but to the extent they do, lessees should take into account trends in case law and legislation as seen with the Kilmer decision in Pennsylvania. However, in the still largely unsettled landscape of Appalachian Basin oil and gas law, a lessee should attempt clarity, specificity, and thoroughness to increase the chances of a predictable and hopefully unlitigated outcome. While the use of industry terms, assumed meanings, and silence as to certain foreseeable circumstances may be the best result that a lessee can achieve in negotiation of a particular lease royalty clause, the lack of developed law and the high profile of the industry in the Appalachian Basin mean a more direct correlation between the vagueness of lease terms and the likelihood of litigation. If interpretations of royalty payments in the Appalachian states, other than West Virginia, develop along the path followed by Pennsylvania and the other at the wellhead states, the use of standard lease terms may be sufficient to establish the valuation point and determine which costs are to be deducted in calculating back to the royalty value at that physical point. However, in West Virginia and any of the states in the Appalachian Basin that may select a more royalty-friendly approach, lessees would be wise to include language that is specific as to: (i) the physical point after which all costs will be shared by the lessor up to and beyond the point of sale or the point at which a marketable product is obtained, (ii) a non-exclusive list of types of costs that will be expressly shared by the lessor, in the same proportion of such total costs as the royalty percentage bears to the total production, and (iii) the objective amount upon which the royalty will be calculated such as the proceeds actually received by the lessee, less the proportionate deduction of PPCs. While less critical after Kilmer, this same approach will also provide a measure of certainty in Pennsylvania, where judicial royalty clause interpretation took a dramatic step forward last month but still remains open to further development. 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For more information, visit K&L Gates is comprised of multiple affiliated entities: a limited liability partnership with the full name K&L Gates LLP qualified in Delaware and maintaining offices throughout the United States, in Berlin and Frankfurt, Germany, in Beijing (K&L Gates LLP Beijing Representative Office), in Dubai, U.A.E., in Shanghai (K&L Gates LLP Shanghai Representative Office), in Tokyo, and in Singapore; a limited liability partnership (also named K&L Gates LLP) incorporated in England and maintaining offices in London and Paris; a Taiwan general partnership (K&L Gates) maintaining an office in Taipei; a Hong Kong general partnership (K&L Gates, Solicitors) maintaining an office in Hong Kong; a Polish limited partnership (K&L Gates Jamka sp. k.) maintaining an office in Warsaw; and a Delaware limited liability company (K&L Gates Holdings, LLC) maintaining an office in April 27,

5 Moscow. K&L Gates maintains appropriate registrations in the jurisdictions in which its offices are located. A list of the partners or members in each entity is available for inspection at any K&L Gates office. This publication is for informational purposes and does not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting a lawyer K&L Gates LLP. All Rights Reserved. 1 Kilmer v. Elexco Land Servs. Co., No. 63 MAP 2009, 2010 WL (Pa. March 24, 2010). ii Atlantic Richfield Co. v. State of Cal., 214 Cal. App. 3d 533, (1989); Merritt v. Southwestern Elec. Power Co., 499 So. 2d 210, 214 (La. App. 1986); Schroeder v. Terra Energy, Ltd., 565 N.W.2d 887, 893 (1997); Piney Woods Country Life Sch. v. Shell Oil Co., 539 F. Supp. 957, 971 (S.D. Miss. 1982), aff d on this point, 726 F.2d 225 (5th Cir. 1984); Creson v. Amoco, 10 P.3d 853, 857 (N.M. Ct. App. 2000); Kilmer, 2010 WL , at *8; Heritage Res., Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996). iii Darr v. Eldridge, 346 P.2d 1041, 1044 (N.M. 1959); Cabot Corp. v. Brown, 754 S.W.2d 104, 109 (Tex. 1987). iv Rogers v. Westerman, 29 P.3d 887, (Colo. 2001); Sternberger v. Marathon Oil Co., 894 P.2d 788, 799 (Kan. 1995); Mittelstaedt v. Santa Fe Minerals, 954 P.2d 1203, 1216 (Okla. 1998). v Wood v. TXO Prod. Corp., 854 P.2d 880, 881 (Okla. 1992); Rogers, 29 P.3d at vi See Kilmer, 2010 WL , at *9. vii Id. at *1. viii Id. at *8-9. ix See id. at *3-4 and 8-9. x Id. at *2. xi Wellman v. Energy Res., Inc., 557 S.E.2d 254, (W.Va. 2001); Estate of Tawney v. Columbia Natural Res., LLC, 633 S.E.2d 22, 30 (W.Va. 2006). xii Wellman, 557 S.E.2d at 265. xiii Estate of Tawney, 633 S.E.2d at 28. xiv WYO. STAT. ANN (a) (2007). xv Wellman, 557 S.E.2d at 265 (stating that if an oil and gas lease provides that lessor shall bear some part of the costs incurred between the wellhead and the point of sale, the lessee shall be entitled to credit for those costs to the extent that they were actually incurred and were reasonable ; however, [b]efore being entitled to such credit... the lessee must prove, by evidence of the type normally developed in legal proceedings requiring an accounting, that he, the lessee, actually incurred such costs and that they were reasonable. ); Rogers, 29 P.3d at 896 (stating that where the lease language is silent, we must look to the implied covenant to market, and thus, whether the gas is marketable )(emphasis added). xvi See Wellman, 557 S.E.2d at 265; Estate of Tawney, 633 S.E.2d 22, 30 (ruling that... language in an oil and gas lease that is intended to allocate between the lessor and the lessee the costs of marketing the product and transporting it to the point of sale must expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale, identify with particularity the specific deductions the lessee intends to take from the lessor s royalty (usually 1/8th), and indicate the method of calculating the amount to be deducted from the royalty for such post-production costs ). xvii See, John S. Lowe, Developments in Nonregulatory Oil & Gas Law, 32ND OIL & GAS INST. 117, (1981); see, e.g., Wall v. United Gas Publishing Serv. Co., 152 So. 561 (La. 1934). xviii See, e.g., Howell v. Texaco, 112 P.3d 1154, 1159 (Okla. 2004); Shelton v. Exxon Corp., 719 F. Supp. 537, 549 (S.D. Tex. 1989), rev d on other grounds, 921 F.2d 595 (5th Cir. 1991); Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 871 (Tex. 1968). April 27,