Opinion ID: 2633380
Heading Depth: 2
Heading Rank: 1

Heading: Leases and the Allocation of Costs

Text: This court granted certiorari on four issues raised by the parties below. [8] Our analysis requires us to answer the question raised in the cross-petition for certiorari first, specifically, whether the leases at issue are silent with respect to how royalties are to be paid. In order to resolve the dispute among the parties here, we must look to the actual language of the leases at issue and determine if they address the allocation of costs, and thus, the calculation of royalty payments. We first note that there are four variations of lease language at issue in this case. However, notwithstanding the distinct language of each of the four lease types, there is some language common to all four lease types. Specifically, all of the leases contemplate that the royalties are to be computed at the well or at the mouth of the well. [9] We have not previously interpreted the type of lease language presented by the leases at issue in this case. Despite the differing language in each of the four types of leases, and despite the arguments raised that the at the well and at the mouth of the well language provides for the allocation of costs, we conclude that all of the leases are, in fact, silent with respect to the allocation of costs. The parties argue that the at the well lease language is determinative of the allocation of costs. Specifically, the lessees collectively argue that at the well or at the mouth of the well establishes a geographical point of valuation for determining royalty payments. As such, the lessees argue that costs incurred with respect to the processing of the gas after that point are to be shared by the lessors and lessees. The lessors, however, do not agree. For example, at least one of the lessors argues that our decision in Garman determined that at the well language is silent with respect to allocation of costs. We reject both parties' arguments. Notwithstanding an initial misleading appearance that the lease language provides for allocation of costs, it is apparent that when scrutinized in depth, each lease clause provision inadequately addresses allocation of costs. For example, the Type I lease contains two separate clauses. The first clause provides for royalties based on the gross proceeds from the sale of gas at the wellhead. Assuming a commonly understood definition of gross proceeds, this language seemingly suggests that costs would not be shared. [10] For example, gross proceeds means the total monies and other consideration accruing to an oil and gas lessee for the disposition of the oil. Oil and Gas Terms, supra, at 472; see also Mittelstaedt v. Santa Fe Minerals, Inc., 954 P.2d 1203, 1206 (Okla. 1998)(plain meaning of gross proceeds suggests payment to lessor is without deductions). Moreover, the second clause further confuses the meaning of the lease language as a whole. This clause provides that, for sales not occurring at the well, the royalties are to be paid based on the market value at the well, but in no event shall those royalties total more than 1/8th of the amount actually received for the sale. While this portion of the lease suggests that the royalties be paid based on the market value, there is no indication as to how such value is to be determined. Furthermore, this language does not indicate whether the calculation of market value at the well includes or excludes costs, and does not describe how those costs should be allocated, if at all, between the parties. Thus, because the lease language fails to even describe either the costs or the allowable deductions, it is silent with respect to all deductions. Similarly, the Type II lease provides that the royalties are to be calculated based on the proceeds from the sale of gas . . . at the mouth of the well. Commentators have suggested that a proceeds clause must either specify the place where proceeds are to be calculated, or the expenses which can be deducted. 3 Howard R. Williams & Charles J. Meyers, Oil and Gas Law  646.1, at 608.4-608.6 (2000)[hereinafter Williams & Meyers]. Assuming this position is adopted, this lease language indicates that the royalties are to be paid based on sales at the physical location of the well. However, this is not the only view. The Arkansas Supreme Court, for example, has held that proceeds at the well means gross proceeds where the lease does not refer to costs or use the term net proceeds. Hanna Oil & Gas Co., v. Taylor, 297 Ark. 80, 759 S.W.2d 563, 564-65 (1988). Thus, there is uncertainty as to how royalties should be calculated under this language. Moreover, this language does not provide any guidance in calculating a royalty payment for gas sold anywhere other than at the physical location of the well. Accordingly, this lease language not only fails to allocate costs between the parties, it fails to address costs in any sense. Likewise, the Type III lease provides that the royalties are to be paid based on the market price at the well for the gas sold. While the term market price suggests the actual price for which gas is purchased and sold, commentators and courts have also used the term interchangeably with market value. Oil and Gas Terms, supra, at 605-606. For gas actually sold at the well, this language might suggest that the royalty payments should be equal to the actual price received when the gas is sold, without any deductions for costs. Assuming, under the language in this type of lease, that the gas is sold at the well, there may be no costs to be allocated because this language only contemplates a sale at the physical location of the wellhead. However, because the sale of gas anywhere other than at the wellhead is not even contemplated by this language, this provision is surely silent with respect to any gas sold away from the well. Finally, the Type IV lease provides that royalties are to be calculated based on the proceeds received for gas sold from each well . . . or the market value at the well of such gas used off the premises. The first portion of this language regarding proceeds is unclear as to whether it is intended to refer to proceeds from the sale at the location of the well, or proceeds from the sale at the place of sale, if other than at the physical location of the well. In a proceeds type lease, the instrument should specify either the place where royalties are to be calculated, or the expenses to which the lessor is subject. 3 Williams & Meyers, supra,  646.1, at 608.4-628.6. Thus, differing interpretations of this language are possible because the intended meaning of this clause is unclear. Furthermore, the reference to a calculation based on market value of gas used off the premises does not clearly establish whether such a calculation would apply to gas sold off the premises. The use of the word or in the lease implies that there is a distinction between the calculation for gas sold from the physical location of a well and gas used off the premises. Neither phrase, referring to proceeds for gas sold at the well, or market value at the well for gas used off the premises, indicates whether there was an intent to allocate costs between the parties, nor whether deductions would be made prior to calculating royalties. Thus, like the other three types of leases, the Type IV lease language is also silent as to cost allocation. Our view that the leases are silent with respect to the allocation of costs is further solidified by the notion in contract law that language should be construed as a whole, and specific phrases or terms should not be interpreted in isolation. Simon v. Shelter Gen. Ins. Co., 842 P.2d 236, 239 (Colo.1992); Kuta v. Joint Dist. No. 50(J), 799 P.2d 379, 382 (Colo.1990). Specifically with respect to oil and gas leases, a royalty clause should be construed in its entirety and against the party who offered it, and in light of the fact that the royalty clause is the means by which the lessor receives the primary consideration for a productive lease. Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically, Part 2 (Should Courts Contemplate the Forest or Dissect Each Tree?), 37 Nat. Resources J. 611, 636 (1997)[hereinafter Anderson, Part 2]. The parties argue that the at the well and at the mouth of the well language at issue in this case is meaningful in allocating costs between the lessees and lessors. However, as we have discussed, this language in isolation is actually silent with respect to those costs. Moreover, the lease language contained in the rest of the contracts does not shed any light onto how, or even whether, this phrase was intended to address the allocation of costs. Although courts and commentators have disagreed over whether at the well language addresses allocation of costs, [11] other jurisdictions have acknowledged that at the well lease language is silent as to allocation of costs. For example, in Fox Wood III v. TXO Production Corp., 854 P.2d 880 (Okla. 1992), the Oklahoma Supreme Court implicitly determined that at the well language in a lease was silent regarding allocation of costs. Although the Oklahoma Supreme Court did not explicitly state that the lease provision was silent, it did conclude that, without an agreement that the lessee and lessor would share costs, the lessor could not be required to bear compression costs. Id. at 881. Although Anderson does not necessarily agree with the view that at the well language is silent with respect to allocation of costs, he does suggest that this language is sufficiently unclear that it may or may not accomplish the lessees' objectives, to share proportionately in costs, when read together with the royalty clause as a whole. See Anderson, Part 2, supra, at 635. Moreover, Anderson has suggested that lessees, in order to avoid alerting lessors of their motives, have intentionally used at the well language to avoid directly stating their objectives in sharing costs. See id. In a similar view, the Kansas Supreme Court, in Gilmore v. Superior Oil Co ., implicitly suggested that a lease containing at the well language was ambiguous, and as such, should be construed in favor of the lessor and against the lessee. 192 Kan. 388, 388 P.2d 602, 605 (1964). In a subsequent case, the Kansas Supreme Court adopted the position that at the well lease language may be silent as to post-production cost deductions. Specifically, in Sternberger v. Marathon Oil Co., the Kansas Supreme Court found that a lease directing royalty payments of one-eighth (1/8) of the market price at the well for gas sold or used was silent with respect to deductions. 257 Kan. 315, 894 P.2d 788, 794 (1995). Despite the conclusion that the lease was silent as to deductions, however, the Kansas Supreme Court concluded that the lease was not ambiguous, and that the language at issue specifically provided the point of valuation for the royalty payments. Id. at 794-95. Because that court concluded that the royalty valuation point was at the physical location of the well, it further concluded that both lessees and lessors were responsible for their proportionate shares of costs to transport the gas away from the well location to the market. [12] Id. at 799-800. In the case before us, the court of appeals arrived at the same conclusion. The court of appeals held that the at the well provisions must be given some meaning, particularly with respect to transportation costs, but that the same language is silent with respect to allocation of other costs. Rogers, 986 P.2d at 972-73. We disagree with this interpretation. The court of appeals' interpretation does not acknowledge that the at the well and at the mouth of the well language has greater implications than the limited significance of a mere determination of a location for royalty valuation purposes. Thus, attempting to give such limited significance to at the well language requires assumptions to be made about the nature of the costs involved. [13] Specifically, the suggestion that at the well language allocates transportation costs, without allocating other costs, attempts to give limited significance to that phrase, without acknowledging that transportation costs often include other costs. Accordingly, at the well language cannot adequately address the allocation of transportation costs without also addressing other costs associated with transporting gas. The cost of gathering, compression, and dehydration should be included, because they may all be necessary to physically transport the gas. Thus, it is inconsistent to carve out a rule for transportation costs alone. In addition, we conclude that it is also inconsistent to carve out a rule for different types of transportation costs. Whether transportation costs are incurred to transport the gas for a short distance or to a distant market is irrelevant in determining whether those costs should be allocated between the lessors and the lessees. Instead, the determination of whether transportation costs (either short or long distance) are to be allocated between the parties is based on whether the gas is marketable before or after the transportation cost are incurred. Gas marketability must be addressed first, together with the function of the actual costs incurred. It must be determined whether those actual costs stem from the transportation of a marketable product, or whether they were costs incurred to make the product marketable. Therefore, we decline to adopt the view that at the well or at the mouth of the well language determines the allocation of transportation costs, but is silent with respect to all other costs. This view is both internally inconsistent and inconsistent with our view that the implied covenant to market controls the allocation of costs under circumstances where lease language fails to address cost allocation. Moreover, by holding that at the well allocates transportation costs, the court of appeals does not acknowledge that the general rule regarding transportation costs assumes that gas is marketable as it emerges from the wellhead. Instead, the court of appeals essentially adopts the rule that, as a matter of law, transportation costs are deductible. [14] The general rule that transportation costs are allocated between the two parties after the gas is marketable is really part of a much broader rule. That broader rule holds that costs incurred after a marketable product has been obtained, that either enhance the value of the product or cause the product to be transported to another location, are shared by the lessee and the lessor. 3 Eugene Kuntz, A Treatise on the Law of Oil and Gas,  40.5, at 351 (1989 & 2001 Supp.)[hereinafter Kuntz]. Accordingly, the analysis of whether transportation costs are deductible begs the question of when the gas is marketable. If gas is marketable at the physical location of the well, then transportation costs may be shared between the lessee and the lessor. However, if gas is not marketable at the physical location of the well, either because it is not in a marketable condition, or because it is not acceptable for a commercial market, then the lessee has not met its burden of making the gas marketable. Thus, transportation costs may not be deducted from royalty payments. Adopting the view that the at the well language determines which costs are deductible from royalty payments fails to acknowledge that deductibility of costs is determined by whether gas is marketable, not by the physical location of the gas or the condition of the gas. Accordingly, we decline to hold here that transportation costs are deductible from royalty payments as a matter of law when a lease includes at the well language. Other jurisdictions have given differing views of the meaning of at the well language, and have found that instead of being silent, that language is sufficient to allocate costs. Specifically, in Piney Woods Country Life School v. Shell Oil Co., the Fifth Circuit concluded that at the well describes both location (place of sale) and quality of gas for the purpose of determining royalty calculations. 726 F.2d 225, 231, 240 (5th Cir.1984)(interpreting Mississippi oil and gas leases). Thus, based on the determination that production ends when gas is severed from the earth, and that the lessee's duty to produce gas has then been satisfied, the Fifth Circuit held that expenses incurred after production may be charged against a royalty computed at the well. Id. at 240. Therefore, that court held that both transportation costs and other processing costs may properly be deducted from royalty payments because the royalty valuation point was at the location of the well and was based on the quality of the gas at the well. Id. Similarly, the Michigan Court of Appeals concluded that at the well language refers to proceeds minus refining and transportation costs, as opposed to proceeds at the point of sale, where refining and transportation costs are not deducted. Schroeder v. Terra Energy, Ltd., 223 Mich.App. 176, 565 N.W.2d 887, 893 (1997). However, even the Michigan Court of Appeals acknowledged that it is unclear why the parties would choose to use the language `at the wellhead' to allocate post-production costs rather than just stating expressly the allocation of such costs. Id. at 894. Likewise, Texas law supports the view that at the well establishes the point of valuation at the physical location at the mouth of the well. Martin v. Glass, 571 F.Supp. 1406, 1411 (N.D.Tex.1983). In Martin, the court concluded that under Texas law, post-production costs are properly deducted from royalty payments under an at the well lease. Id. at 1411-16. That court further concluded that because gas is produced when it is severed at the wellhead, and the lessee's duty to market gas ends when gas is produced, the compression costs at issue were incurred subsequent to production, and thus, were properly deductible from royalty payments as post-production costs. Id. at 1415-17; see also Judice v. Mewbourne Oil Co., 939 S.W.2d 133, 136 (Tex.1996)(Value at the well means the value of the gas before it has been compressed and before other value is added in preparing and transporting the gas to market.). We disagree, however, with these jurisdictions because they fail to recognize that the implied covenant to market controls the lessee's duty to make the gas marketable. Instead, these jurisdictions have adopted the rule that the lessee's duty has ended once gas is severed from the wellhead, and thus, any costs incurred subsequent to that physical removal are to be shared by the parties. In Colorado, we decline to follow the rule that gas is produced once physically severed, and thus, decline to adopt the reasoning regarding the deductibility of costs adopted by these jurisdictions. See Garman, 886 P.2d at 657-61. However, notwithstanding the fact that we may be in the minority of states adopting this approach, we believe that it is the more sound analysis, and that it is consistent with our jurisprudence. Finally, in interpreting leases like those in this case, we are mindful of the generally accepted rule that oil and gas leases are strictly construed against the lessee in favor of the lessor. Wilson v. Wakefield, 146 Kan. 693, 72 P.2d 978, 980 (1937); Ladd v. Upham, 58 S.W.2d 1037, 1039 (Tex.Civ.App. 1933); Davis v. Cramer, 837 P.2d 218, 225 (Colo.App.1992)(oil and gas leases are construed liberally in favor of lessor and strictly against lessee); Hill v. Stanolind Oil & Gas Co., 119 Colo. 477, 489, 205 P.2d 643, 649 (1949)(doubt as to contract's meaning should be resolved against the one who prepared it); Anderson, Part 2, supra, at 636 (an oil and gas lease offered by a lessee should be construed against the lessee); 2 W.L. Summers, The Law of Oil and Gas  372, at 487-94 (1959 & 2000 Supp.)[hereinafter Summers](uncertainty or ambiguity as to meaning of contract will be construed against party who prepared the contract; in oil and gas industry that is usually the lessee). This rule is generally based on the recognition that the bargaining power between a lessor and lessee is similar to that historically found between an insurance company and its customers. Ladd, 58 S.W.2d at 1039. Thus, the parties are in similar unequal positions. For example, lessors are not usually familiar with the law related to oil and gas leases, while lessees, through experience drafting and litigating leases, generally are. Id.; see also West v. Alpar Res., Inc., 298 N.W.2d 484, 490-91 (N.D.1980)(failure to expressly provide for deductions of expenses in ambiguous lease language will result in disallowance of such deductions because lease must be construed strongly against lessee). Accordingly, based on our interpretation of the at the well and at the mouth of the well language common to the four lease types at issue, we conclude that the leases in this case are silent with respect to allocation of costs. We disagree with those jurisdictions that conclude that at the well is sufficient to allocate costs. Moreover, we disagree with the conclusion that at the well language addresses transportation costs, while not addressing other costs incurred in processing the gas. Instead, we conclude that because the leases are silent, we must look to the implied covenant to market, and our previous decision in Garman v. Conoco , to determine the proper allocation of costs.