MITTELSTAEDT v. SANTA FE MINERALS, INC.

MITTELSTAEDT v. SANTA FE MINERALS, INC.
1998 OK 7
954 P.2d 1203
69 OBJ 490
Case Number: 84977
Decided: 01/20/1998
Mandate Issued: 02/19/1998
Supreme Court of Oklahoma

TED MITTELSTAEDT, an individual, RUTH MITTELSTAEDT, an individual, Plaintiffs-Appellees,
vs.
SANTA FE MINERALS, INC., a corporation, Defendant-Appellant.

[953 P.2d 1204]
CERTIFIED QUESTION FROM THE UNITED STATES COURT OF APPEALS FOR THE TENTH CIRCUIT.

¶ 0 Mineral lessee deducted a proportional share of transportation, compression, dehydration, and blending costs from the royalty interest paid to the lessors. Lessors sought to recover the amount of the deduction. On appeal before the United States Court of Appeals for the Tenth Circuit that Court certified the question to this court whether such was proper under a "gross proceeds" lease.

CERTIFIED QUESTION ANSWERED.

Gregory A. McKenzie, William K. Elias, Michael J. Massad, and Frank H. McGregor of MCKENZIE, MOFFETT, ELIAS & BOOKS, Oklahoma City, Oklahoma, For Appellees.

Gary W. Davis, Mark D. Christiansen, and Paul D. Trimble of CROWE & DUNLEVY, Oklahoma City, Oklahoma, and William H. Boyles, SANTA FE MINERALS, INC., Dallas, Texas, For Appellant.
Robin Stead, Donald F. Heath, Jr., HEATH, P.C., For Amicus Curiae National Association of Royalty Owners, Norman Oklahoma.

Brenton B. Moore, Tulsa, Oklahoma, OKLAHOMA MID-CONTINENT OIL & GAS ASSOCIATION, James C.T. Hardwick of HALL, ESTILL, HARDWICK, GABLE, GOLDEN & NELSON, P.C., Tulsa, Oklahoma,
Joseph W. Morris,Teresa B. Adwan, M. Benjamin Singletary of GABLE & GOTWALS, INC. For Amicus Curiae for Oklahoma Mid-Continent Oil and Gas Association,Tulsa, Oklahoma

SUMMERS, V.C.J.

¶ 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 case 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 [953 P.2d 1205] 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.1

¶ 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.

¶ 4 Our assignment requires us, at the outset, to analyze these Oklahoma cases: 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 [953 P.2d 1206] 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 . . . ."

¶ 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.

[953 P.2d 1207] ¶ 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 lease premises. See CLO at 262, 263 n.2. In Johnson there was no market for 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 nonoperating 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. VI.b.ii. This right checks 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.

Colorado concluded that no costs were allocable 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

¶ 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 case 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

Kansas' reasoning is consistent with our holding in Johnson v. Jernigan, supra. The [953 P.2d 1208] 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 Sternberger. 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 Sternberger 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

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.

[953 P.2d 1209] ¶ 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.

¶ 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. Jernigan, 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. [953 P.2d 1210] 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., HODGES, LAVENDER, HARGRAVE, JJ. - Concur

¶ 33 SIMMS, WILSON, JJ. - Concur in part; Dissent in part

¶ 34 OPALA, WATT, JJ. - Dissent in part

FOOTNOTES

1 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).

2 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).

3 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.

4 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. at 892. The I.R.S. determined that the dehydration plant was a nonproducing function. Id. The Kansas producer calculated gross income from the property for tax purposes and royalties using the same method. Id. 315 F.2d at 870 n.12.

5 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.

[953 P.2d 1210] OPALA, J., with whom WATT, J., joins, dissenting in part:

¶ 1 Pursuant to the provisions of the Uniform Certification of Questions of Law Act, 20 O.S. 1991 § 1601 et seq, the United States Court of Appeals for the Tenth Circuit (certifying court) certified the following question:

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?

Today's opinion adopts the Garman1 approach to determining the point of first marketability of gas. The court holds that (a) a lessee may not deduct a proportionate share of transportation, compression, dehydration, and blending costs from the royalty interest when such costs are associated with creating a first-marketable product; (b) the lessor must bear a proportionate share of these costs if the lessee can show that (1) post-production costs enhanced the value of an already marketable product and are reasonable and (2) actual royalty revenues increased in proportion to the costs assessed against the nonworking interest; and (c) [953 P.2d 1211] custom and usage should be considered in determining the scope of duties due under the lease.

¶ 2 Because I would apply the Anderson first-marketable product analysis,2 I recede from today's pronouncement. Under the Anderson approach (a) royalty will be paid on the price the lessee obtained or could have obtained for the sale of the first-marketable form of the gas and (b) the point of first-marketability is a question of fact. The lessee has no obligation to pay royalty on any additional value that post-production activities add to a marketable product. Generally no work-back calculations should be necessary other than a possible deduction of transportation costs if the point of first-marketability is not in the vicinity of the well.

I
ANATOMY OF LITIGATION

¶ 3 Ted and Ruth Mittelstaedt [Mittelstaedts or lessors] claimed they were not receiving the full 3/16 of the gross proceeds from the gas sold due them under the terms of a lease for their two gas wells in Canadian County. Santa Fe Minerals, Inc. [Santa Fe or Lessee] responded that it rightfully deducted from the 3/16 royalty payment the lessors' share of certain marketing expenses.

¶ 4 Santa Fe performed some compression operations and incurred related expenses at the wellhead but did not charge the royalty interests with these costs. The gas was then moved to a location off the leased premises, where Santa Fe paid fees to unaffiliated third parties for transportation, blending, dehydration, and compression of the gas. Santa Fe did charge a portion of these costs against the royalty interests. The gas was then transported further downstream where it was placed into the purchaser's pipeline. The lessors sued Santa Fe to recover the portion of costs that Santa Fe charged against their royalty interests.

II
THE NATURE OF THIS COURT'S FUNCTION
WHEN ANSWERING A CERTIFIED QUESTION
FROM A FEDERAL COURT

¶ 5 While in answering the queries posed by a federal court the parameters of state-law claims or defenses (identified by the submitted questions) may be tested, it is not this court's province to intrude (by its responses) upon the certifying court's decision-making process.3 The latter court must be left entirely free to assess the impact of the answers and to make its own appraisal of the proof in the case before it.4 Because this action is not before this court for decision, we must refrain from applying the declared state-law responses to the facts now known or to be elicited in the federal court litigation, which are in use or will be used in the summary adjudication process.5 The task of analyzing today's answers for their application to this case is deferred to the certifying court.

III
OKLAHOMA'S ROYALTY JURISPRUDENCE

¶ 6 My analysis requires an examination of three Oklahoma cases and an explanation why we should depart from their holdings: Johnson v. Jernigan [Johnson];6 Wood v. TXO Prod. Corp. [Wood];7 and TXO v. State ex rel. Comm'rs of the Land Office [CLO].8

Johnson v. Jernigan

¶ 7 In Johnson, gas lessors alleged that the lessees wrongfully deducted transportation costs from their 1/8th royalty interest in [953 P.2d 1212] the "gross proceeds" from gas production under the lease. Since there was no market on the leased premises (i.e., no willing buyer), the court allowed the lessee to charge against the lessor's royalty interest a share of the costs of transporting the gas to the nearest market.9 The court declared that the lessee's duty to market the gas does not include bearing the full cost burden of transportation to an off-site purchaser.10 Rather, the lessee's financial obligation ends when the gas is made available for market, and any further expenses beyond the leased property must be shared by the lessor.11

Wood v. TXO

¶ 8 In Wood, the court declined to extend the Johnson holding to allow lessees to deduct compression costs from royalty interests. The lessee in Wood built compressors on the premises because the natural pressure from the wells turned out insufficient to deliver the oil into the purchaser's on-site pipeline.12 The lessee then subtracted from the royalty payments the lessors' proportionate share of the compression costs. The lessors sought to recover these costs.13 The court held that, absent an agreement between the parties to share compression costs, the lessee must bear the entire expense of gas compression.14

¶ 9 The pronouncement noted that other jurisdictions are split on the question whether the lessors must bear their proportionate share of compression costs. While Louisiana and Texas jurisprudence allows the lessee to deduct compression costs,15 the court preferred the Kansas and Arkansas approach that prohibits such deductions.16 Hesitant to assign costs to the lessor who has no input into the lessee's marketing decisions, the court concluded that the lessee's implied duty to market encompasses all market preparation costs, including compression.17

¶ 10 Rejecting the lessee's argument that compression used to "push" the gas into the purchaser's pipeline is analogous to transportation and therefore deductible under Johnson, the opinion distinguished the facts in Wood from those in Johnson. In the latter case, the court held that the lessor must bear its share of transportation costs when the only possible point of sale is off the leased premises.

¶ 11 In Wood I was in dissent, preferring the Louisiana and Texas view that distinguishes production from post-production costs.

¶ 12 My dissent noted that the Kansas and Arkansas royalty approach unduly saddles the lessee with the entire expense of gas compression, including post-production compression costs, as an unfair burden for failing to include a cost-apportionment clause in the lease.

TXO v. State ex rel. Comm'rs of the Land Office

¶ 13 In CLO, the court held that compression, dehydration and gathering costs are not deductible from royalty interests but are the lessee's responsibility as part of the implied duty to market. While concentrating on the language of the lease,

¶ 14 Applying this test, the court reasoned that without compression gas is completely unmarketable.

IV
OKLAHOMA'S ROYALTY CALCULATION
METHOD IS FLAWED

¶ 15 Wood and CLO suffer from a common infirmity. Both correctly require the lessee to prepare the product for sale, but err in treating marketability as a question of law rather than one of fact.

¶ 16 Oklahoma royalty jurisprudence allows the physical location of marketing activities to cloud the determination of cost deductibility. The practice of requiring the lessee to pay for all on-site costs, which originated in Johnson,

¶ 17 After studying Professor Anderson's research and noting recent case law evolving in other jurisdictions, I now realize that the alternative solution I proposed in Wood - the Texas and Louisiana approach to royalty calculation - is equally flawed. Measuring the royalty payment at the wellhead is a property-based approach that requires the lessor to share costs once the extracted gas changes from real to personal property (i.e., the time of severance from the ground).

[953 P.2d 1215] ¶ 18 Extant body of United States jurisprudence demonstrates an absence of property-law type interpretation of royalty clauses, notwithstanding modern cases to the contrary.

¶ 19 In addition to its historical inaccuracy, the wellhead-based royalty determination uses an unrealistic mathematical calculation to determine the royalty amount. Since there are often no sales at the wellhead

¶ 20 The party in the best position to calculate costs and assign them to each stage of the marketing process is the lessee.

[953 P.2d 1216]
V
OKLAHOMA SHOULD DETERMINE ROYALTY OBLIGATIONS
BY USING THE FIRST-MARKETABLE PRODUCT MODEL

¶ 21 The question before us today provides the opportunity to re-analyze our approach toward oil and gas royalty clauses and the deductibility of transportation, compression, dehydration and blending costs from the royalty interest. Absent a lease provision to the contrary, the lessee should be solely responsible for producing a product marketable in fact. At this point "production" is complete, and any further costs should be shared proportionately by the lessor. In other words, the lessor should not receive any of the value added by the lessee's post-production refining. In coming to this conclusion, I have found instructive the writings of both Owen L. Anderson and Eugene Kuntz.

"Unquestionably, under most leases, the lessee must bear all costs of production. There is, however, no reason to impose on the lessee the costs of refining or processing the product, unless an intention to do so is revealed by the lease. It is submitted that the acts which constitute production have not ceased until a marketable product has been obtained. After a marketable product has been obtained, then further costs in improving or transporting such product should be shared by the lessor and lessee if royalty gas is delivered in kind, or such costs should be taken into account in determining market value if royalty is paid in money."

Professor Anderson agrees with this approach:

"A court should begin its analysis of royalty clauses by recognizing three fundamental principles: First, 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. Second, in light of legal history and absent an express lease provision, a lessee that discovers oil or gas in paying quantities is obliged to 'produce' a 'marketable product' so that the lessor can realize royalty income. Third, the point where a marketable product is first obtained is the logical point where the exploration and production segment of the oil and gas industry ends, is the point where the primary objective of the lease contract is achieved, and therefore is the logical point for the calculation of royalty."

¶ 22 While I believe the distinction between production and post-production marketing activities is the key to royalty analysis, I no longer accept the property-based notion that production is complete when the gas or oil is severed from the ground at the wellhead.

¶ 23 We should not needlessly complicate royalty-clause interpretation by focusing solely on specific terms, such as "market value," "market price," "proceeds," or "amount realized."

¶ 24 The point at which a first-marketable product is obtained should be a question of fact. The exact nature of the market must be determined by the trier of fact to discover the point of production at which there are both willing sellers and buyers, and royalty should be determined by the market value of the product at that point, less any actual and reasonable deductions for transportation costs incurred in the event that the marketing point is not in the vicinity of the well.

¶ 25 Today's opinion relies heavily on two recent variations of the first-marketable product theory - Garman v. Conoco, Inc.

"absent an assignment provision to the contrary, overriding royalty interest owners are not obligated to bear any share of post-production expenses, such as compressing, transporting and processing, undertaken to transform raw gas produced at the surface into a marketable product."

Referring to Kuntz's treatise, the court declared that any costs incurred to enhance the value of an already marketable gas are chargeable against royalty interests.

"We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994). That case 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."

¶ 26 The court's reliance on Garman and Sternberger is misplaced since neither represents a perfect incarnation of a true first-marketable product model. Garman diverges from that theory by requiring that the lessee show that post-production costs are reasonable and that they led to a proportionate increase in the lessor's royalty revenues.

¶ 27 Sternberger, which incorrectly requires the lessee to demonstrate the reasonableness of post-production costs, fails by treating marketability as a question of law rather than one of fact.

¶ 28 The Anderson first-marketable-product analysis - which recognizes that the point of marketability is necessarily a question of fact - is clearly superior to both the extant Oklahoma jurisprudence (Johnson, Wood, and CLO) and to the Garman model. I would today adopt the concept of a factual inquiry into the point of first-marketability, which treats all post-production costs the same. My concept would eliminate the calculation of royalty on the value of gas after compression, dehydration or gathering, when the gas may have been marketable before undergoing some or all of these processes. The Anderson approach would implement the marketability-based royalty calculation model announced, but not actually applied, in Wood and CLO.

¶ 29 The wellhead-based royalty valuation also is supplanted by the first-marketable product model. While the foundation of both calculations is a production/post-production dichotomy, the first-marketable product model conforms to the historical practice of determining royalty obligations at the point of marketability. When using this model (except for a possible transportation adjustment),

VI
SUMMARY

¶ 30 Recent studies and case law have provided the necessary tools to repair the infirm underpinnings of Oklahoma's royalty jurisprudence by creating a new approach that is both historically and logically sounder. The first-marketable product method eliminates location-based royalty analysis without disrupting Oklahoma's implied duty to market oil and gas. Resting royalties on actual market value corrects the deficiencies in the wellhead-based calculation.

¶ 31 I would accordingly respond to the certifying court by stating that in Oklahoma the lessee is responsible for all marketing costs until a first-marketable product is obtained. Royalty would be paid on the actual market value of the gas at that point. Other than possible transportation adjustments in [953 P.2d 1219] the event that the first market is not in the vicinity of the well, there should be no need for inquiring into the reasonableness of post-production costs and no proportional-increase requirement. This is so because under the theory I espouse, the lessor would receive no value from the lessee's post-production (post-marketable) enhancement of the product.

FOOTNOTES

1 Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994).

2 For a discussion of Professor Anderson's model of first marketability, see Part V, infra.

3 See Uniform Laws Annotated, Uniform Certification of Questions of Law Act/rule (1995); Goldschmidt, Certification of Questions of Law; Federalism in Practice, American Judicature Society (1994).

4 See, e.g., Shebester v. Triple Crown Insurers, 974 F.2d 135, 137 (10th Cir. 1992).

5marker2fn0

Schmidt v. United States, 1996 OK 29, 912 P.2d 871, 873; Brown v. Ford, 1995 OK 101, 905 P.2d 223, 226; Bonner v. Okla. Rock Corp., 1993 OK 131, 863 P.2d 1176, 1178 n. 3; Shebester v. Triple Crown Insurers, 1992 OK 20, 826 P.2d 603, 606 n. 4.

 

Cir. 1984); Parker v. TXO Prod. Corp., 716 S.W.2d 644 (Tex.Civ.App.1986).

Other cultures provide a similar property-free determination of royalty share. Ancient Greek royalty owners were paid in pure silver rather than in the ore discovered by the miners. Anderson, supra note 40, Part 1, discussion at notes 118-120 (noting T. A Rickard, Man and Metals, A History Of Mining In Relation To The Development Of Civilization (1932). In Rome a royalty owner received cut marble instead of the unfinished, unmarketable stone recovered from the earth. Id., Part 1, discussion in text at notes 121-122 (quoting Clyde Pharr, The Theodosian Code And Novels And The Sirmondian Constitutions, Book X, Title 19 (1952)). A net-proceeds approach to royalty calculation was standard practice in early Spanish law. Id., Part 1, discussion in text at notes 123-126. The tradition of Western jurisprudence weighs against the use of a property-based royalty calculation.

See

54 Kuntz, supra note 53, § 40.5 at 351 (1989)(emphasis supplied). See also West v. Alpar Resources, Inc., 298 N.W.2d 484, 489 (N.D. 1980), in which the court observes that most oil and gas scholars agree the lessor should pay a share of post-production costs, but disagree as to the point at which "production" is complete.

55 Anderson, supra note 34, Part 2, discussion in text at notes 110-112 (emphasis supplied, footnotes omitted).

56 Wood, supra note 7 at 83 (Opala J., dissenting).

57 See discussion in supra note 41.

58 Anderson, supra note 34, Part 2, discussion in text at notes 12-13. See also Tara Petroleum, supra note 36 at 1272.

59 See generally Maurice Merrill, Covenants Implied in Oil and Gas Leases § 85 (2d ed. 1940). Given the large number of small interest-owning lessors, any suggestion that negotiation commonly occurs is absurd.

60 Anderson, supra note 34, Part 2, discussion in text after note 4 and in text at Section 3, conclusion, prior to note 305.

61 Id., Part 2, discussion in text after note 4.

62 Id., Part 2, discussion in text at notes 113-123, 254-274.

63 Professor Anderson does note that long-established case law has allowed the lessee to charge the lessor for a proportionate share of reasonable and actual transportation costs where the marketing point is not in the vicinity of the well. Anderson, supra note 34, Part 2, discussion in text at notes 145-146.

64 Garman, supra note 1.

65 Sternberger, supra note 16.

66 Id. at 661 (emphasis added).

67 Id.

68 Sternberger, supra note 16.

69marker2fn0

Id.

70 Id.

71 Anderson, supra note 34, Part 2, discussion in text at note 262.

72 Id., Part 2, discussion in text at note 306.

73 Anderson, supra note 40, Part 1, discussion in text at notes 5-8. Allowing the lessor to profit from the lessee's downstream enhancements would complicate the royalty calculation. While some lessees sell the gas without making many improvements, other lessees are vertically integrated, making several enhancements before selling the final product. If lessees must share downstream earnings, lessors in the latter situation would reap large profits while those in the former relationship would only receive royalty on the sale to the next middleman in the marketing process. Anderson, supra note 34, Part 2, discussion in text at notes 314-319.

74 Anderson, supra note 34, Part 2, discussion in text at note 311.

75 Sternberger, supra note 16.

76 See supra note 63.

77 It is interesting to note that nothing in the court's opinion appears to prohibit a lessee from paying royalty on a known first-market value. As I understand today's pronouncement, it merely limits the lessee's right to use a work-back valuation method.