Case Name: Ted MITTELSTAEDT, an individual, Ruth Mittelstaedt, an individual, Plaintiffs-Appellees, v. SANTA FE MINERALS, INC., a corporation, Defendant-Appellant
Court: Oklahoma Supreme Court
Jurisdiction: Oklahoma
Decision Date: 1998-01-20
Citations: 954 P.2d 1203
Docket Number: No. 84977
Parties: Ted MITTELSTAEDT, an individual, Ruth Mittelstaedt, an individual, Plaintiffs-Appellees, v. SANTA FE MINERALS, INC., a corporation, Defendant-Appellant.
Judges: ¶ 32 KAUGER, C.J, SUMMERS, V.C.J., and HODGES, LAVENDER and HARGRAVE, JJ., concur.
Reporter: Pacific Reporter 2d
Volume: 954
Pages: 1203–1219

Head Matter:
1998 OK 7
Ted MITTELSTAEDT, an individual, Ruth Mittelstaedt, an individual, Plaintiffs-Appellees, v. SANTA FE MINERALS, INC., a corporation, Defendant-Appellant.
No. 84977.
Supreme Court of Oklahoma.
Jan. 20, 1998.
Dissenting Opinion by Justice Opala Modified March 5, 1998.
Gregory A. McKenzie, William K. Elias, Michael J. Massad, and Frank H. McGregor of McKenzie, Moffett, Elias & Books, Oklahoma City, for Plaintíffs-Appellees.
Gary W. Davis, Mark D. Christiansen, and Paul D. Trimble of Crowe & Dunlevy, Oklahoma City, and William H. Boyles, Santa Fe Minerals, Inc., Dallas, TX, for Defendant-Appellant.
Robin Stead, Donald F. Heath, Jr., Heath, P.C., for Amicus Curiae National Association of Royalty Owners, Norman, Oklahoma.
Brenton B. Moore, Oklahoma Mid-Continent Oil & Gas Association, James C.T. Hardwick of Hall, E still, Hardwick, Gable, Golden & Nelson, P.C., Tulsa, Joseph W. Morris, Teresa B. Adwan, M. Benjamin Sin-gletary of Gable & Gotwals, Inc., for Amicus Curiae for Oklahoma Mid-Continent Oil and Gas Association, Tulsa, Oklahoma.
. Typical gas royalty clause types are "market value," "proceeds” ("gross” and "net"), and "in kind” clauses. Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269, 1272 n. 3.
. In Home-Stake the producer claimed an ad valorem tax exemption for a six-mile pipeline from a well to a trunk line claiming such was necessary for the production of gas from the well because production had not occurred until the gas was marketed. The court rejected this claim, and observed that absent a specific lease provision "marketing of oil or gas is not required in order to satisfy the habendum clause of a lease requiring production within one year, or as long thereafter as either is produced.” Id. 463 P.2d at 985. A similar, although not identical, argument was raised in Union Oil Co. v. Board of Equalization, 1996 OK 40, 913 P.2d 1330, where the taxpayer claimed that equipment at the wellhead was exempt from ad valorem taxation as necessary for production if the equipment was necessary to fulfill the implied covenant to make the product marketable. Id. 913 P.2d at 1334 n. 2. Resolution of the claim was unnecessary, and the Court did not address whether the claim was correct. Id.

Opinion:
SUMMERS, Vice Chief Justice.
¶ 1 Gas well lessors filed suit in Federal Court, claiming they were not getting the full "3/16 of the gross proceeds received for the gas sold" as called for in-the lease. Lessee in response explained it was deducting the lessor's share of post-production expenses in marketing the gas, and then remitting 3/16 of the proceeds as royalty. The trial court entered judgment in favor of the lessors for their portion of the proceeds deducted and withheld by the lessee, plus interest. The ease is now in the Tenth Circuit Court of Appeals. Since the case will turn on Oklahoma law the Circuit Court has certified the question to us, framed as follows:
In light of the facts as detailed below, is an oil and gas lessee who is obligated to pay "3/16 of the gross proceeds received for the gas sold" entitled to deduct a proportional share of transportation, compression, dehydration, and blending costs from the royalty interest paid to the lessor?
¶ 2 We conclude that this clause, when considered by itself, prohibits a lessee from deducting a proportionate share of transportation, compression, dehydration, and blending costs when such costs are associated with creating a marketable product. However, we conclude that the lessor must bear a proportionate share of such costs if the lessee can show (1) that the costs enhanced the value of an already marketable product, (2) that such costs are reasonable, and (3) that actual royalty revenues increased in proportion with the costs assessed against the nonworking interest. Thus, in some cases a royalty interest may be burdened with post-production costs, and in other cases it may not.
¶ 3 The two wells are in Canadian County. Some compression operations and associated expenses were performed at the wellhead. Lessee Santa Fe Minerals, Inc. did not charge the royalty interests with these costs. But then the gas was moved downstream to a location off the leased premises, where Santa Fe paid unaffiliated third parties for transportation fees, blending fees, dehydration fees, and compression fees. Santa Fe charged a proportion of these costs against the royalty interests. The gas was then moved further downstream where it was placed into the purchaser's pipeline. The Mittlestaedts went to court to recover that portion of the latter costs charged against their royalty as lessors. The trial court, in one of its rulings, recognized as an undisputed fact that the expenses in controversy incurred by Santa Fe "were incurred for the purpose of improving the quality of the gas produced from the wells involved, thereby resulting in a higher price being received from the purchaser and to permit sale at better, higher-priced markets."
¶4 Our assignment requires us, at the outset, to analyze these Oklahoma eases: Wood v. TXO Production Corp., 1992 OK 100, 854 P.2d 880, TXO Production Corp. v. State ex rel. Commissioners of the Land Office, 1994 OK 131, 903 P.2d 259, (because Wood and this second case both involve TXO we will refer to it as CLO), and Johnson v. Jernigan, 475 P.2d 396 (Okla.1970).
¶ 5 In Wood we rejected the idea that compression costs to "enhance" (or make marketable) a product should be shared by the royalty interest. Wood, 854 P.2d at 881. However, we also said in Wood that "in Oklahoma the lessee's duty to market involves obtaining a marketable product." In our case the royalty owners rely upon the first above quote. The lessee relies upon the latter, arguing that its duty is fulfilled by delivering a marketable product at the leased premises, and that costs incurred after the this duty is fulfilled may be allocated proportionately to the royalty interest. It is noteworthy that in Wood the compression took place on the leased premises.
¶ 6 In CLO the lessee wanted to charge .compression and dehydration costs to the lessors. Our Court said no, these operations were required to make the gas marketable, as required by the Lessees's implied covenant to market. The enhancement operations in CLO, as in Wood, took place at the wellhead, on the leased premises.
¶ 7 In Johnson v. Jernigan, the lessee wanted to charge the lessor its proportionate share of transportation costs to the nearest market. We allowed that to happen because there was no market available for the gas at the lease. The lessee's duty to market did not include bearing the full burden of delivery to an off-site purchaser.
¶ 8 In all these opinions the Court had to fix the rights and duties of the parties according to the language of the leases and the implied covenants that go with them. The clause immediately preceding the "gross proceeds" clause in our case is an in kind clause requiring the lessee "To deliver to the credit of lessor free of cost, in the pipe line to which it may connect its wells, the 3/16 part of all oil. In CLO we stated that the lease phrase "without cost into pipelines" modifying an "in kind" clause also referred to lessee's 1/8 payment of the market value of the gas sold to the lessor. Id. 903 P.2d at 261. We then concluded that the 1/8 market value paid to the lessor did not bear any of the lessee's costs from processes necessary to get the product into the pipelines. Id. Unlike the present case, in CLO delivery to the purchaser's pipeline occurred at the leased premises.
¶ 9 In CLO we examined the language of the lease. Id. 903 P.2d at 260-261. We use the plain meaning of the terms when doing so. Trawick v. Castleberry, 275 P.2d 292, 294 (Okla.1953). Using the plain meaning of the phrase "gross proceeds" suggests that the payment to the lessor is without deductions. See Pioneer Telephone Co-op. Inc. v. Oklahoma Tax Commission, 1992 OK 77, 832 P.2d 848, where we defined "gross receipts" for the purpose of sales taxes and used its plain meaning. This view of gross receipts has also been used when interpreting a royalty clause: "The term 'gross proceeds' usually implies no deductions of any kind." Altman and Lindberg, Oil and Gas: Non-Operating Oil and Gas Interests' Liability for Post-Production Costs and Expenses, 25 Okla.Law Rev. 363, 375 (1972), [citing, Brown, Royalty Clauses in Oil and Gas Leases, 16 Oil & Gas Inst. 161 (SW. Legal Found.1965) ]. Consistent with this approach, we have explained that when the lease requires payment of the "market value" of the gas this value "means the gas purchase contract price." Helmerich & Payne, Inc. v. State ex rel. Commissioners of the Land Office, 1997 OK 30, ¶ 12, 935 P.2d 1179, 1181. But when certain circumstances are present this definition of "gross receipts," as being a value with no deductions, has been tied to the value of the product at a certain location, that is, the leased premises, or wellhead.
¶ 10 In Johnson v. Jernigan, 475 P.2d 396 (Okla.1970) we explained that gross proceeds "has reference to the value of the gas on the lease property without deducting any of the expenses involved in developing and marketing the dry gas to this point of delivery." Id. 475 P.2d at 399. Thus, "gross proceeds" does indicate an amount without deduction from, or charge against, the royalty interest, but only when the point of sale occurs at the leased premises.
¶ 11 The third clause discussed by the parties provides that the lessee will "pay lessor for gas produced from any oil well and used off the premises, or for the manufacture of casing-head gasoline or dry commercial gas, 3/16 of the gross proceeds, at the mouth of the well, received by lessee for the gas-" A producer has a duty to market gas from a producing well. Tara Petroleum Corp. v. Hughey, 1981 OK 65, 630 P.2d 1269, 1273. The parties argue whether this clause means that the lessee's duty to market is measured by the performance of the lessee at the wellhead. This contention requires discussion of a lessee's implied covenant to market.
¶ 12 In CLO we first analyzed the lessee's duties as specified by the lease. After we concluded that the lessor did not pay certain post-production costs because of the language of the lease, we then explained that the result in that case was consistent with our opinion in Wood, discussing a lessee's implied covenant to market gas. Id. 903 P.2d at 261. We said that the lessee must make the gas available to market at the leased premises (wellhead). Making the gas available to market at the leased premises means that the lessee must produce the gas in a marketable form at the leased premises. Thus, when discussing a lessee's duty to provide a marketable product at the leased premises we said that "the implied duty to market means a duty to get the product to the place of sale in marketable form. Here [in both Wood and CLO] the compressors . are on the leased premises." (quoting Wood, emphasis deleted) Id. 903 P.2d at 262.
¶ 13 The Mittelstaedts argue that when the sale is at a distant market the implied duty of the lessee under the lease is to pay for all of those costs associated with delivering the gas at the point of sale, i.e., to get the product to the place of sale in marketable form at the expense of the lessee. This view is incorrect as to distant markets. We explained in CLO that our ruling in Johnson v. Jernigan, 475 P.2d 396 (Okla.1970) was still good, and that a lessor may be required to pay its proportionate share of transportation costs when the sale occurs off the léase premises. See CLO at 262, 263 n. 2. In Johnson there was no market fbr the product at the leased premises. Johnson allows allocating transportation costs to lessors when the point of sale is away from the lease only when no market for the product is available at the lease. When there is a market available at the wellhead transportation costs to a point of sale at a distant market should not be allocated against the lessors' interest except in those circumstances that we will later explain.
¶ 14 In Wood we explained that nonworking interest owners (royalty owners) have no input into the cost-bearing decisions. 854 P.2d at 883. These owners have no input on the marketing decisions. If costs were imposed on royalty owners they "would be sharing the burdens of working interest ownership without the attendant rights." Id. We then said that if a lessee wants royalty owners to share in the post-production costs then that must be stated in the lease. Id.
¶ 15 The Supreme Court of Colorado, reviewed our decision in Wood and came to similar conclusions.
Allocating these costs to the lessee is also traceable to the basic difference between cost bearing interests and royalty and overriding royalty interest owners. Normally, paying parties have the right to discuss proposed procedures and expenditures and ultimately have the right to disagree with the course of conduct selected by the operator. Under the terms of a standard operating agreement nonoperat-ing working interest owners have the right to go "non-consent" on an operation and be subject to an agreed upon penalty. See A.A.P.L. Form 610-1989 Model Form Operating Agreement Art. Vl.b.ii. This right cheeks an operator's unbridled ability to incur costs without full consideration of their economic effect. No such right exists for nonworking interest owners.
Garman v. Conoco, Inc., 886 P.2d 652, 660 (Colo.1994).
Colorado concluded that no costs were alloca-ble to the nonworking interests when the costs were to create a marketable product. Id. But the court then concluded that when additional costs were incurred to increase the value of the gas already marketable those costs could be allocated to the noninterest owners under certain conditions:
To the extent that certain processing costs enhance the value of an already marketable product the burden should be placed upon the lessee to show such costs are reasonable, and that actual royalty revenues increase in proportion with the costs assessed against the nonworking interest.
Id. 886 P.2d at 661.
¶ 16 The Supreme Court of Kansas then agreed with this as an accurate statement of the law in Kansas as to transportation costs. Sternberger v. Marathon Oil Company, 257 Kan. 315, 894 P.2d 788 (1995). It said that:
We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo.1994). That ease involves a certified federal question. In it, the Colorado Supreme Court held as we believe the law in Kansas to be: Once a marketable product is obtained, reasonable costs incurred to transport or enhance the value of the marketable gas may be charged against nonworking interest owners. The lessee has the burden of proving the reasonableness of the costs. Absent a contract providing to the contrary, a nonworking interest owner is not obligated to bear any share of production expense, such as compressing, transporting, and processing, undertaken to transform gas into a marketable product. In the case before us, the gas is marketable at the well. The problem is there is no market at the well, and in that instance we hold the lessor must bear a proportionate share of the reasonable cost of transporting the marketable gas to its point of sale.
Sternberger, 894 P.2d at 800.
Kansas' reasoning is consistent with our holding in Johnson v. Jernigan, supra. The Kansas Court then reviewed our decisions in Wood and CLO, and explained that Wood was consistent with Kansas law and that CLO involved a lease provision and facts that distinguished it from Stemberger. Sternberger, 894 P.2d at 801-804. The agreement on this issue between Kansas and Colorado as to the lessee's burden is also noteworthy because of what we said in Wood.
¶ 17 In Wood we explained that Oklahoma's rule for nonallocation of costs in creating a marketable product was similar, although not identical, to that in Kansas. Wood, 854 P.2d at 881. We stated in Wood that we followed the approach used by the courts in Kansas and Arkansas. Wood, 886 P.2d at 882. This was discussed by the Colorado Supreme Court in Garman. Garman, 886 P.2d at 658.
¶ 18 Thus, we agree with both Stemberger and Garman. When the gas is shown by the lessee to be in a marketable form at the well the royalty owner may be charged a proportionate expense of transporting that gas to the point of purchase. Johnson v. Jernigan, supra. The lessee bears the burden of showing that such cost is reasonable, and that actual royalty revenues increased in proportion with the costs assessed against the nonworking interest. Garman v. Conoco, Inc., supra. Thus, in this controversy whether the royalty interest must bear transportation costs away from the lease will depend upon whether the lessee can meet its burden.
¶ 19 In both Wood and CLO we were concerned with operations on the leased premises to make the product marketable. However, this does not mean that costs incurred after severance at the wellhead are necessarily shared by the lessors. We expressly rejected this approach in Wood. See Wood, 854 P.2d at 882. Post-production costs must be examined on an individual basis to determine if they are within the class of costs shared by a royalty interest.
¶ 20 The lessee has a duty to provide a marketable product available to market at the wellhead or leased premises. Generally, custom and usage in the industry are used in determining the scope of duties created by the lease. Heiman v. Atlantic Richfield Co., 1995 OK 19, n. 4, 891 P.2d 1252, 1257 n. 4; Matzen v. Hugoton Production Co., 182 Kan. 456, 321 P.2d 576, 582 (1958). Neither the facts given us nor the legal arguments on the certified question identify custom and usage with respect to the individual costs at issue when the leases were executed.
¶ 21 It is common knowledge that raw or unprocessed gas usually undergoes certain field processes necessary to create a marketable product. These field activities may include, but are not limited to, separation, dehydration, compression, and treatment to remove impurities. See Exxon Corporation v. United States, 33 Fed.Cl. 250, 271 (1995) where the producer discussed the "normal field production activities" to determine the representative market or field price for calculating the gross income from the property for the purpose of a percentage depletion deduction for federal income taxes.
¶ 22 In CLO we stated that "the costs for compression, dehydration and gathering are not chargeable to Commissioners [lessors] because such processes are necessary to make the product marketable under the implied covenant to market." CLO, 903 P.2d at 263. We said:
According to TXO's brief in chief, dehydration "involves removal of moisture from gas before it enter's the purchaser's pipeline." Such a process is necessary in order to make the product marketable and involve costs incident to delivering the product into pipelines. As such, costs of dehydration are not chargeable against Commissioners under Wood.
CLO, 903 P.2d at 262.
In Exxon the federal court reached the conclusion that dehydration was a nonproducing rather than producing function for the purpose of the depreciation allowance calculation. However, the Exxon court was well aware that its conclusion was not necessarily the same for calculating royalties.
¶ 23 This Court too, has observed that a term used for the purpose of calculating a tax may have a different meaning in calculating a royalty. See Oklahoma Tax Commission v. Sun Oil Company, 489 P.2d 1078, 1081 (Okla.1971) where this Court relied upon In re Home-Stake Production Co., 463 P.2d 983 (Okla.1969) in explaining that the value of gas for the purpose of the gross production tax was not necessarily calculated in the same manner as its value for the purpose of paying royalties. Additionally, one term may not have a uniform definition throughout the industry, and custom and usage may vary. See Mason v. Ladd Petroleum Corp., 1981 OK 73, 630 P.2d 1283, 1285, where we noted a diversity in accepted accounting practices, leading to opposite results. The parties have not shown that the actual costs at issue are, or are not, treated by the industry as production costs or post-production costs for our purpose.
¶24 In CLO when discussing gathering we stated that gathering occurs prior to the product being placed into the purchaser's pipeline, and "As such, gathering is not a deductible expense." CLO, 903 P.2d at 262-263. It is argued from this quote that every cost, of whatever nature, incurred prior to delivery to purchaser is a cost that cannot be allocated to a royalty interest governed by a gross proceeds clause. We are invited to overrule Johnson v. Jemigan, supra, as inconsistent with CLO.
¶ 25 We stated in CLO that in Oklahoma gathering is a cost of production, i.e., to make a marketable product, and is not a cost allocated to a royalty interest, but our discussion included a reaffirmation of Johnson v. Jernigan, supra. CLO, 903 P.2d at 263. Our conclusion that dehydration was a non-allocated cost rested upon similar grounds. Id. 903 P.2d at 262.
¶26 Generally, costs have been construed as either production costs which are never allocated, or post-production costs, which may or may not be allocated, based upon the nature of the cost as it relates to the duties of the lessee created by the express language of the lease, the implied covenants, and custom and usage in the industry. We conclude that' dehydration costs necessary to make a product marketable, or dehydration within the custom and usage of the lessee's duty to create a marketable product, without provision for cost to lessors in the lease, are expenses not paid from the royalty interest. However, excess dehydration to an already marketable product is to be allocated proportionately to the royalty interest when such costs are reasonable, and when actual royalty revenues are increased in proportion to the costs assessed against the royalty interest. It is the lessee's .burden to show that the excess dehydration costs charged against the royalty interest occurred to a marketable product, i.e., that the cost is a post-production cost. It is also the burden of the lessee to show both the reasonableness of the costs and that the royalty revenues increased in proportion with the costs assessed against the royalty interest.
¶ 27 The certified question asks us to determine whether blending costs are a post-production expense. The exact nature of the "blending" is not identified. The analysis for blending costs is the same as for dehydration costs. Blending costs necessary to make a marketable product are not costs allocated to the royalty interest. Blending costs to an already marketable product are to be allocated proportionately to the royalty interest when such costs are reasonable, and when actual royalty revenues increase in proportion to the costs assessed against the royalty interest. The lessee has the burden of showing the reasonableness of the cost, the proportional increase in revenues to the royalty interest, and that the cost was incurred to alter a marketable product. The lessee must show that the cost was a post-production cost.
¶28 In Wood one issue was whether a lessor's interest must bear a proportionate share of compression expenses when the compression was necessary to provide a marketable product because of low pressure. We expressly declined to make compression costs a form of transportation cost that may be charged against the royalty interest. Wood, 854 P.2d at 881-882. This holding is consistent with Kansas, where compression costs both on and off the lease necessary to place the gas into the purchaser's pipeline are not costs allocated to the royalty interest. See Sternberger, 894 P.2d at 798, explaining, Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964). However, in Wood we noted that there was no sale at a distant market, and no necessity to transport the product.
¶ 29 Clearly, compression on the leased premises to push marketable gas into the purchaser's pipeline is a cost not allocated to the royalty interest. Wood, supra. We decline to turn compression costs into costs paid by the royalty interest merely by moving the location of the' compression off the lease. However, we recognize that when marketable gas is transported off the lease to a point where its constituents are changed, additional compression may then become necessary to push the changed product into a purchaser's pipeline. We conclude that off-lease compression costs may be allocated to the royalty interests if such costs are reasonable, when actual royalty revenues increase in proportion to the costs assessed against the nonworking interest, and when the compression is associated with enhancing an already marketable product off the lease. The lessee bears the burden of showing the reasonableness of the cost and the increase in royalty revenues resulting from the compression costs.
¶ 30 In sum, a royalty interest may bear post-production costs of transporting, blending, compression, and dehydration, when the costs are reasonable, when actual royalty revenues increase in proportion to the costs assessed against the royalty interest, when the costs are associated with transforming an already marketable product into an enhanced product, and when the lessee meets its burden of showing these facts.
¶ 31 CERTIFIED QUESTION ANSWERED.
¶ 32 KAUGER, C.J, SUMMERS, V.C.J., and HODGES, LAVENDER and HARGRAVE, JJ., concur.
¶ 33 SIMMS and ALMA WILSON, JJ., concur in part and dissent in part.
¶ 34 OP ALA and WATT, JJ., dissent in part.
. A royalty is an agreed return paid for the oil, gas, and minerals, or either of them, reduced to possession and taken from the leased premises. A royalty is a share of the product or proceeds therefrom, reserved to the owner for permitting another to use the property. Elliott v. Berry, 206 Okla. 594, 245 P.2d 726, 729 (1952).
. It is undisputed that the third parties receiving the fees are unrelated or unaffiliated to Santa Fe. We do not address the effect of lessee-affiliated gas marketers attempting to capture the costs of marketing. See A. Wright & C. Sharpe, Direct Gas Sales: Royalty Problems for the Producer, 46 Okla.L.Rev. 235 (1993).
. The conclusion in Exxon, 33 Fed.Cl. at 275-276, relied upon the opinion in Hugoton Production Company v. United States, 161 Ct.Cl. 274, 315 F.2d 868 (Ct.Cl.1963). In Hugoton the producer claimed that its central dehydration plant was a producing (as opposed to nonproducing) function. Id. 315 F.2d at 892. The I.R.S. determined that the dehydration plant was a nonpro-ducing function. Id. The Kansas producer calculated gross income from the properly for tax purposes and royalties using the same method. Id. 315 F.2d at 870 n. 12.