Wood v. TXO Production Corp. ( 1993 )

854 P.2d 880 (1992)

Fox WOOD III, and Regan Lee Wood, Plaintiffs,
v.
TXO PRODUCTION CORPORATION, a foreign corporation, Defendant.

No. 75929.

Supreme Court of Oklahoma.

July 7, 1992. As Corrected on Limited Grant of Rehearing May 24, 1993.

Clark S. Wood, Sallisaw, for plaintiffs.

David A. Cheek, A. Michelle Campney, McKinney, Stringer & Webster, P.C., Oklahoma City, for defendant.

HARGRAVE, Justice.

We are presented with a question certified to this court from the United States District Court for the Eastern District of Oklahoma, pursuant to the Uniform Certification of Questions of Law Act, 20 Ohio St. 1981 §§ 1601 et seq., to wit:

"Is an oil and gas lessee/operator who is obligated to pay the lessor `3/16 at the market price at the well for the gas sold', entitled to deduct the cost of gas compression from the lessor's royalty interest?"

We answer in the negative.

On December 12, 1978, Plaintiffs executed two (2) oil and gas leases in favor of Sabine Production Company, retaining a 3/16 royalty interest. Sabine's interest ultimately was transferred to defendant, TXO Production Corporation. TXO is the current operator of two gas wells on the leased premises, the Wood 1-1 and the Wood G# 1, and sells the gas produced under separate contracts which obligate TXO to deliver the gas into the purchasers' lines at a pressure sufficient for entry, at TXO's expense. For some period of time, the wells produced at a pressure sufficient to enter the purchasers' lines without artificial compression. At some later point, the pressure from the two wells fell below the required pressure for delivery. TXO built compressors on the lease premises and subtracted the lessors' proportionate share of the compression costs from the royalty payments due to lessors for production from the two wells. Plaintiffs sued in federal court to recover the previously withheld compression charges. The lessors state that they were not consulted prior to building the compressors, nor did they have any input regarding the costs incurred in establishing the compressors.

Authorities in oil and gas producing states are split on whether the lessee can charge the lessors for their proportionate costs of compression. Kansas and Arkansas do not allow the lessee to deduct compression costs, while Louisiana and Texas do. Some authorities believe that marketing expenses should be included as lessee's operating costs because, without marketing, there is no production in paying quantities. Other authorities argue that the lessee has fulfilled his duty by obtaining gas capable of producing in paying quantities, and that the lessee should not have to bear alone the costs of "enhancing" the product obtained, and the analysis centers on determining when a marketable product has been obtained. The authorities holding the second view make a distinction between production and "post production" costs, holding that the lessor must bear its proportionate share of "post production" costs. We reject this analysis in Oklahoma. We have said only that the lessor must bear its proportionate share of transportation costs where the point of sale was off the leased premises. Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970).

We said, in Johnson v. Jernigan, supra, regarding costs of transporting gas:

"When the lessee has made the gas available for market then his sole financial obligation ceases, and any further expenses beyond the lease property must be borne proportionately by the lessor and the lessee."

We are not, based upon the facts before us, prepared to require the lessor to bear compression costs as a matter of law where there is no agreement between the lessor and lessee to share those costs.

The defendant argues that compression, in this case, is analogous to transporting, because all that compression in this case is doing is "pushing" the gas into the purchasers pipeline, much like loading oil onto a tank truck. We have not yet held that the lessor is required to bear any costs of transportation where the point of sale is on the leased premises. In our view, the gas is "sold" when it enters the purchaser's line. Here that line is on the leased premises and there is no "transportation" cost. The defendant further argues that without compression there will be no sale and thus no royalty at all for the lessor. This argument is not persuasive. There are many steps in the production or post-production processes that, if not performed, would result in no sale. The lessee is in a position to provide specifically in its leases that lessors will be required to share in compression costs.

Kansas and Arkansas courts have held that the lessee must bear the cost of installing and operating a compressor where compression was required in order to market the gas. Schupbach v. Continental Oil Company, 193 Kan. 401, 394 P.2d 1 (1964), Gilmore v. Superior Oil Company, 192 Kan. 388, 388 P.2d 602 (1964), Hanna Oil and Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563 (1988). See also, Skaggs v. Heard, 172 F. Supp. 813 (S.D.Tex. 1959).

In Schupbach v. Continental Oil Company, 193 Kan. 401, 394 P.2d 1 (1964), the Supreme Court of Kansas held that the trial court erred in concluding that the lessee was entitled as a matter of law to charge reasonable costs for compressing gas for market and in directing that those costs be retained by the lessee in computing royalties due to the royalty owners. The gas royalty in the lease in that case required the lessee to pay to the lessors "1/8th of the proceeds of the sale thereof at the mouth of the well." The issue was whether the lessee-operator could deduct a 1/8th share of its claimed compression costs to market the gas from the proceeds of the gas produced and sold under said lease. The compressor station was located on the lease as was the gas purchaser's pipeline. The Court noted that the lessee did not consult the lessors and royalty owners as to the location, size, or number of stations, nor as to any intent on its part to charge compression costs to the royalty owners. The Schupbach Court cited Gilmore v. Superior Oil Co., 388 P.2d 602 (Ks. 1964), as settling the issue. In Gilmore the Supreme Court of Kansas under identical royalty provisions, found that the lessee had the duty of making the gas marketable and could not recover from the lessors the expense of installing a compression station because such installation was a necessary expense in the process of making the gas marketable. The Supreme Court of Arkansas in Hanna Oil & Gas Co. v. Taylor, 759 S.W.2d 563 (Ark. 1988), construed a gas royalty clause of "1/8th of the proceeds received by Lessee at the well for all gas (including all substances contained in such gas) produced from the leased premises and sold by Lessee" to mean total proceeds and found it unnecessary to go beyond the clear language of the agreement to hold that the lessee was not entitled to deduct compression costs. The Court noted that if the lessee's intention had been to do so, they would have made some reference to costs or "net" proceeds.

In Oklahoma we have equated the gas purchase contract price with the market value. Tara Petroleum Corp. v. Hughey, 630 P.2d 1269 (Okla. 1981).^[1] One of the risks borne by the lessee in exploring for gas is that the gas will be low pressure. In our view, the implied duty to market means a duty to get the product to the place of sale in marketable form. Here the compressors and the connections to the gas purchasers' pipelines are on the leased premises. There is no sale at a distant market and no necessity of transporting the product to the place of sale as there was in Johnson v. Jernigan, supra. Cessation of marketing can mean the termination of the lease. Townsend v. Creekmore-Rooney Co., 332 P.2d 35 (Okla. 1958).

The cases from Texas and Louisiana that allow deduction of compression costs from the royalty interest represent a different approach or interpretation of the lessee's duty to market. A Louisiana case, Merritt v. Southwestern Electric Power Co., 499 So. 2d 210 (La. Ct. App. 1986), involved a delivery point for the sale of gas off the lease premises. That opinion noted that Louisiana already had held that extraction costs, costs of property depreciation, costs of gathering and delivering gas into a pipeline system were chargeable to the lessors as "post production" costs. The Louisiana court was using a "reconstruction" approach to determine market value: Gross proceeds, less costs of taking gas from the wellhead to the point of sale. The Texas case relied on is Martin v. Glass, 571 F.Supp 1406 (N.D.Tex.Ft.Worth 1983). The royalty clause in that case provided for royalty of "1/8 of the net proceeds at the well received from the sale thereof." (emphasis added). The court opined that "net proceeds" clearly suggests that certain costs are deductible. Another case, from Mississippi, Piney Woods Country Life School v. Shell Oil Company, 539 F. Supp. 957 (S.D.Miss. 1982), did not involve compression charges, but was a novel case involving sour gas that had to be treated in order to make it saleable. The court rationalized that expenditures made to convert a "valueless" commodity into one of greater value should be shared by the lessors. The market value definition in that case was that market value means current market value rather than contract price.

We choose to follow the holdings of the Kansas and Arkansas courts. We interpret the lessee's duty to market to include the cost of preparing the gas for market. The lessor, who generally owns the minerals, grants an oil and gas lease, retaining a smaller interest, in exchange for the risk-bearing working interest receiving the larger share of proceeds for developing the minerals and bearing the costs thereof. Part of the mineral owner's decision whether to lease or to become a working interest owner is based upon the costs involved. We consider also that working interest owners who share costs under an operating agreement have input into the cost-bearing decisions. The royalty owners have no such input after they have leased. In effect, royalty owners would be sharing the burdens of working interest ownership without the attendant rights. If a lessee wants royalty owners to share in compression costs, that can be spelled-out in the oil and gas lease. Then, a royalty owner can make an informed economic decision whether to enter into the oil and gas lease or whether to participate as a working interest owner.

We find that in Oklahoma the lessee's duty to market involves obtaining a marketable product. The certified question is answered in the negative.

CERTIFIED QUESTION ANSWERED.

SIMMS, ALMA WILSON, KAUGER and SUMMERS, JJ., concur.

OPALA, C.J., dissents by separate opinion in which HODGES, V.C.J., and LAVENDER and WATT, JJ., join.

OPALA, Chief Justice, with whom HODGES, Vice Chief Justice, and LAVENDER and WATT, Justices, join, dissenting.

The court pronounces today that absent an express agreement between the lessee (working-interest owner) and the lessor (royalty owner) to share compression costs, the expense of gas compression process is not deductible from the lessor's royalty interest. Its view rests on Kansas^[1] and Arkansas^[2] jurisprudence, which imposes upon the lessee the cost of installing and operating a compressor when compression is required to market the gas. Today's opinion reasons that if the lessee fails to include a cost-apportionment provision in the lease, he has an implied obligation to render the gas marketable by compression and bear the full cost of the compression process.

I cannot accede to the court's pronouncement. The Kansas and Arkansas approach imposes an undue burden on the lessee upon his failure to include a cost provision in the lease. It saddles the lessee (1) with the sole responsibility for adding a cost-apportionment clause to the lease and (2) with the entire expense of gas compression — including all post-production compression costs. This solution is both harsh and untenable. Louisiana^[3] and Texas^[4] jurisprudence offers the better-reasoned view. When the lease contains no cost-apportionment provision, the lessee is allowed to deduct from the lessor's royalty payment the expense of gas compression incurred to move the produced gas from the wellhead to the purchaser's pipeline. It is this approach that I would adopt today and, absent a contrary lease provision, I would allow post-production compression costs to be deducted from the lessor's royalty interest.

THE ANATOMY OF FEDERAL LITIGATION

TXO Production Corporation [TXO], the lessee, currently operates two wells owned by Fox and Regna Wood [Wood], the lessors. TXO sells gas produced from the wells under gas purchase contracts which obligate TXO, the seller, to increase the pressure of the incoming gas to the necessary level to effect gas delivery into the receiving pipeline. The contracts require TXO to bear the compression cost, which TXO deducted from royalty-interest payments due on the well's production. Wood brought the present federal-court action to recover the previously withheld charges. Pursuant to the Uniform Certification of Questions of Law Act, 20 Ohio St. 1981 §§ 1601 et seq., the United States District Court for the Eastern District of Oklahoma certified for out answer the following question:

"Is an oil and gas lessee/operator, who is obligated to pay the lessor `3/16 at the market price at the well for the gas sold', entitled to deduct the cost of gas compression from the lessor's royalty interest?"

I

PRINCIPLES GOVERNING DEDUCTIBILITY OF POST-PRODUCTION COSTS

Oil and gas producing states differ on whether the lessor should bear any burden of the compression cost — Louisiana and Texas allow the lessee to deduct this cost,^[5] while Arkansas and Kansas do not.^[6] I would today adopt the former view, supported by the majority of commentators, that post-production compression costs are deductible from the lessor's royalty interest.^[7]

Most oil and gas leases require the lessee to bear production costs.^[8] Gas is measured at the wellhead,^[9] and payment is based on the price of gas at the well both under the lease here in suit as well as under most leases.^[10] Because the price of gas is determined at the well, the lessee's implied duty to market the gas does not include the burden of expenses incurred after the gas passes through the wellhead, or post-production costs.^[11] If compression is necessary to effect delivery into the pipeline, it is a post-production cost which, absent an express contrary provision in the lease, should be proportionately shared by the lessor. On the other hand, if compression is necessary to produce the gas, or to get the gas up to the wellhead, then compression is a cost of production to be borne by the lessee.

II

NON-DEDUCTIBILITY OF GAS COMPRESSION CHARGES — THE KANSAS AND ARKANSAS APPROACH

The Kansas and Arkansas approach of burdening the lessee with post-production compression costs originated in a trilogy of cases — Gilmore v. Superior Oil Co., Schupbach v. Continental Oil Co., and Hanna Oil and Gas Co. v. Taylor.^[12]

In Gilmore the Kansas Supreme Court announced that the lessee has a duty to pay for gas compression expenses necessary to make gas marketable and that those expenses cannot be passed on to the royalty owners. The court reasoned that since the lessee is obligated to market the product, it necessarily follows that the lessee has the task of preparing the gas for market if it is unmerchantable in its natural form. No part of the costs of marketing or of preparation for sale is chargeable to the lessor.^[13] The Kansas court reached a similar conclusion in Schupbach.^[14]

In Hanna, the Arkansas Supreme Court holds that a lessee may not deduct compression costs from royalty payments when an oil and gas lease contains a proceeds royalty clause.^[15] The absence of a contract provision allowing compression costs to be apportioned obligates the lessee rather than the lessor to bear that post-production expense. Hanna rests its nondeductibility logic on two factors: (1) the clear language of the lease, which fails to provide for compression costs, and (2) the parties' construction of the agreement, which is shown by the lessee's conduct in waiting 2 1/2 years before deducting compression costs.^[16]

Many commentators strongly criticize Gilmore, Schupbach and Hanna as contrary to the great weight of opinion.^[17] Some of these authors view the cases as inconsistent with the extant jurisprudence of the respective states and would give them a restrictive application.^[18]

I cannot countenance Arkansas' and Kansas' judicial enlargement of the lessee's duty to market the gas. That jurisprudence unduly penalizes lessees by requiring them to bear post-production compression costs.^[19]

III

DEDUCTIBILITY OF POST-PRODUCTION GAS COMPRESSION CHARGES — THE TEXAS AND LOUISIANA APPROACH

Texas and Louisiana jurisprudence provides the better reasoned view. It utilizes a production/cost dichotomy^[20] which distinguishes "production" costs from "post-production" costs. Lessees are allowed to deduct the cost of compression from the royalty interest when it is termed "post-production".

In Merritt v. Southwestern Elec. Power Co.^[21] the Louisiana appellate court holds that unless the parties agree otherwise, a lessee can deduct a proportionate share of post-production compression costs from the royalty payments under a market-value-at-the-well royalty provision. Neither the lease nor the division order in Merritt expressly permitted or prohibited a deduction for compression costs.^[22] Although the well could produce without the compression, the pressure was insufficient to push the gas into the pipeline.^[23]The court stated that compression which is necessary for the gas to reach the wellhead is a production cost, but compression that is necessary only to push the gas from a producing well into a pipeline is a post-production cost or marketing cost which is deductible from royalty payments.^[24]

In Martin v. Glass^[25] the U.S. District Court for the Northern District of Texas, applying Texas law, holds that on the basis of a net-proceeds-at-the-well royalty provision, the royalty interest owners could be charged their proportionate share of the cost of compression to move the gas from producing wells into the gathering line. The court based its decision on a finding that gas production had already been obtained from the wells before compression.^[26] In a factually similar case, Parker v. TXO Production Corp.,^[27] the Texas Court of Appeals, citing Martin with approval, holds that, absent contrary terms in the lease, (1) compression costs to increase production are not chargeable to the non-operating royalty interests, but that (2) post-production costs of compressing gas to make it deliverable into a purchaser's pipeline are normally to be borne proportionately by the operator and the royalty interest owners.^[28]

SUMMARY

I would adopt the Texas and Louisiana view^[29] rather than that of Kansas and Arkansas. The latter charges the lessee, but not the lessor, with a duty to include within the lease a cost-bearing clause for future gas compression needs. I would not unequally burden one party while freeing the other from this responsibility. Both the lessee and the lessor are able to include a compression-cost provision in the lease. Gas compression necessary to effect delivery of gas into the pipeline is a post-production cost which should be borne equally by the lessor and lessee. In the absence of a specific provision prohibiting the deduction of post-production compression costs, I would allow a lessee to deduct this expense from the lessor's royalty payments.

NOTES

[1] An Oklahoma federal district court case, Harding v. Cameron, 220 F. Supp. 466 (W.D.Okla. 1963), contained the statement that:

"The rule in Oklahoma fixing the `value' or `market price' of gas at the wellhead and processed by the lessee through a compressor plant constructed by it is the gross price which the lessee receives from the purchaser less the actual cost of compression and reasonable depreciation on its compressor plant."

The Harding case, however, involved casinghead gas, for which there was no market value at the well, and thus, the court was "reconstructing" a market value using a work-back approach. The lessors also had agreed at pretrial to bear a part of the compression costs.

[1] Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964); Gilmore v. Superior Oil Co., 192 Kan. 388, 388 P.2d 602 (1964). For a discussion of the Kansas and Arkansas view, see infra Part II.

[2] Hanna Oil and Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563 (1988).

[3] Merritt v. Southwestern Elec. Power Co., 499 So. 2d 210 (La. App. 1986). For a discussion of the Texas and Louisiana view, see infra Part III.

[4] Martin v. Glass, 571 F. Supp. 1406, 1416 (N.D.Tex. 1983) affirmed without opinion, 736 F.2d 1524 (5th Cir.1984); Parker v. TXO Production Corp., 716 S.W.2d 644 (Tex.Civ.App. 1986).

[5] Martin v. Glass, supra note 4; Parker v. TXO Production Corp., supra note 4; Merritt v. South-western Elec. Power Co., supra note 3.

[6] Hanna Oil and Gas Co. v. Taylor, supra note 2; Schupbach v. Continental Oil Company, supra note 1; Gilmore v. Superior Oil Co., supra note 1.

[7] 3. E. Kuntz, The Law of Oil and Gas § 40.5(b) at 352 [1989]; 3 Williams, Oil and Gas Law § 645.2 at 596-597, 603-604 [1989]; Case Note, Oil and Gas — Deduction of Compression Costs from Lessor's Royalty Payments, 14 Kan.L.Rev. 128, 132 [1965]; R. Altman & C. Lindberg, Oil and Gas: Non-Operating Oil and Gas Interests' Liability for Post-Production Costs and Expenses, 25 Okl.L.Rev. 363, 365-366, 379 (1972); Note, Costs Deductible by the Lessee in Accounting to Royalty owners for Production of Oil or Gas, 46 La.L.Rev. 895, 906 (1986). Many text-writers, based on a dictum in a federal case, place Oklahoma in the "deductible category". See Harding v. Cameron, 220 F. Supp. 466 (W.D.Okl. 1963).

[8] R. Altman & C. Lindberg, supra note 7 at 370. "Production of gas" is the act of bringing forth gas from the earth. Martin v. Glass, supra note 4 at 1415; Piney Woods Country Life School v. Shell Oil Co., 539 F. Supp. 957, 971 (S.D.Miss. 1982), aff'd on this point, 726 F.2d 225, 240 (5th Cir.1984), reh'g denied, 750 F.2d 69 (5th Cir.1984), cert. denied, 471 U.S. 1005, 105 S. Ct. 1868, 85 L. Ed. 2d 161 (1985); 3 H. Williams & C. Meyers, Oil and Gas Law 762 (8th ed. 1987).

[9] The "place of production" is generally viewed as being the wellhead. Martin v. Glass, supra note 4 at 1415; 8 Williams, supra note 7 at 83-84, 137, 1070 (8th ed. 1987 and Supp. 1989) (the place of production is generally viewed as the Christmas tree of a well, and Christmas tree is another term for wellhead); Lynam, Royalty and Overriding Royalty Payments and Deductible Expenses, 6 E.Min.L.Inst. § 14.07 at 14-9 (1985).

[10] Altman & Lindberg, supra note 7 at 366. Gas royalty clauses generally provide for the payment to the royalty owner of a sum of money based on a fraction of: (1) proceeds of the sale; (2) market value or (3) market price of the gas. 8 H. Williams & C. Meyers, supra note 7 at 402 (8th ed. 1987); Lynam, supra note 9 at, § 14.03 at 14-4; Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions, 4 Inst. on Oil & Gas L. & Tax'n 181, 212 (1953); Note, supra note 7 at 896; Comment, Value of Lessor's Share of Production Where Gas Only Is Produced, 25 Tex.L.Rev. 641, 642-643 (1947). These three approaches to royalty calculation represent different methods for establishing a standard for converting production into monetary payments. See Hanna Oil and Gas Co. v. Taylor, supra note 2, 759 S.W.2d at 566 (Hays, J., dissenting); Lynam, supra note 9, § 14.03 at 14-4. Regardless of the type of royalty clause in the lease, the royalty is generally determined by deducting post-production costs incurred by the lessee. Lynam, supra note 9, § 14.07 at 14-9; Siefkin, supra at 216; Note, supra at 907.

[11] Martin v. Glass, supra note 4 at 1416; Piney Woods Country Life School v. Shell Oil Co., supra note 8 at 972; Hanna Oil and Gas Co. v. Taylor, supra note 2, 759 S.W.2d at 566 (Hays, J., dissenting); 3 E. Kuntz, supra note 7, § 40.5(b) at 350-351; Siefkin, supra note 10 at 201; Case Note, supra note 7 at 131; Casamassima, Royalty Valuation Rulemaking of the Mineral Management Service — Impact on OCS Operations, 39 Oil § Gas L. & Tax'n 8.04 at 8-13 (1988); Note, supra note 7 at 910; Comment, supra note 10 at 644. Contra, M. Merrill, Covenants Implied in Oil and Gas Leases § 85 at 214-215 [1940]. Merrill has been criticized, see Siefkin, supra note 10 at 199; Altman & Lindberg, supra note 7 at 370.

[12] Schupbach v. Continental Oil Co., supra note 1; Gilmore v. Superior Oil Co., supra note 1; Hanna Oil and Gas Co. v. Taylor, supra note 2.

[13] Gilmore, supra note 1. Underlying Gilmore's rationale is Professor Merrill's concept of burdening the lessee with the entire incidence and cost of improving and transforming the product into a more valuable commodity by compression, dehydration or processing. Id. 388 P.2d at 607. This theory is anchored on an implied duty of the lessee under an oil and gas lease to market the oil and gas. Merrill states that this view is "supported by the general current of authority." M. Merrill, supra note 11, § 85 at 215.

[14] Schupbach, supra note 1, followed Gilmore's rationale because both case scenarios were identical.

[15] The sole issue considered by the court was whether the lessee was entitled to deduct from the lessor's royalties a pro rata share of its compression costs. The applicable royalty clause in that case states that: "Lessee shall pay Lessor one-eighth of the proceeds received by Lessee at the well for all gas (including all substances contained in such gas) produced from the leased premises and sold by Lessee." The court focused on the word "proceeds" in the royalty clause and, based on its common meaning, held that the lessee was not entitled to deduct compression costs. The most compelling support for its conclusion (that compression costs are not deductible) the court derived from the fact that the lessee did not begin deducting compression costs until some two and one-half years after it had begun compressing gas.

In Hanna (Hays, J., dissenting), supra note 2, 759 S.W.2d at 565, a justice observes that the majority focuses on the plain meaning of the word "proceeds" while ignoring the equally crucial term "at the well". The dissent notes that the term "at the well" is one of art describing the place where the royalty is calculated, and that "due to the low pressure of the gas, there would be no sales at the well, and hence no royalties, but for the compression." (Emphasis added) In support of its view the dissent cites Altman & Lindberg, supra note 5. Hanna is discussed in Casenote, Hanna Oil and Gas Co. v. Taylor: Compression Costs in Oil and Gas Leases — Who Pays?, 43 Ark.L.Rev. 201, 214-15 (1990), where the author states: "The Taylor decision appears to be precedent only for cases based on the same lease provision... . [T]his case is a departure from the law previously espoused by the Arkansas Supreme Court." See also Note, Oil and Gas — Deductions Under a Proceeds Royalty Lease — Arkansas Puts Pressure on Lessee, Hanna Oil and Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563 (1988), 12 U.Ark.Little Rock Law Journal 395, 404 (1990).

[16] Hanna Oil and Gas Co. v. Taylor, supra note 2, 759 S.W.2d at 565.

[17] [A] Gilmore Criticism: Altman & Lindberg, supra note 7 at 376-379, criticize Gilmore for confusing the lessee's duty to exercise diligence in marketing with an obligation to pay all of the marketing costs — a duty which the authors state has little support, if any, in decisional law. The duty to market is a separate and independent step, once or more removed from production, and as such is a post-production expense ..." Martin v. Glass, supra note 4 at 1416, citing Phillips Petroleum Company v. Johnson, 155 F.2d 185, 189 (5th Cir.1946).

Altman & Lindberg reason that since compression, dehydration and processing are post-production costs, it follows that they should all be treated similarly to transportation by apportionment of the costs. As to compression costs alone, the authors state that "... it is quite defensible to contend that such costs are comparable to the costs of trucking production to a distant pipe line since both are merely logistical methods by which the gap between production and pipe line is transcended regardless of whether such gap is measured in inches or miles. Therefore, since trucking expenses are considered transportation expenses and are equitably shared between lessor and lessee so should compression costs."

Altman & Lindberg criticize both Gilmore, supra note 1, and Merrill's rationable, supra note 13, in their commentary, stating that the "`general current of authority' is not supported by the cases cited by Dr. Merrill." Id. supra note 7 at 377. In a later article, Merrill withdraws from his unequivocal statement and acknowledges that the decisions vary. Merrill, Implied covenants in Oil and Gas Leases, 1959 U.Ill.L.F. 584, 595. See also 1964 A.B.A.Sec.Min. and Nat.Resources L.Committee Report 69, where the editor states that "[t]his case appears to be entirely contrary to the great weight of opinion, and in fact, cannot be reconciled with established precedent in the State of Kansas."

For a critical discussion of the Kansas cases (Gilmore and Schupbach) see Piney Woods Country Life School v. Shell Oil Co., supra note 8 at 973, where the court expressly discredits these cases as contrary to the weight of opinion as well as "unconvincing"; see also Ashland Oil & Refining Co. v. Staats, Inc., 271 F. Supp. 571, 575 (D.Kan. 1967). In reference to the Gilmore decision, 3A W. Summers, The Law of Oil and Gas § 589, 21 n. 18 (Supp. 1990), states: "Though this text was cited, it is believed the case is contrary to the majority rule and lays upon the lessee a financial burden not necessarily a part of the duty to market". See also Casamassima, supra note 11, 8.04 at 8-14 n. 42; 1964 A.B.A.Sec.Min. & Nat.Resources L.Committee Report 69, supra; Case Note, supra note 11 at 129-130.

[A] Schupbach Criticism: Altman & Lindberg, supra note 7 at 378 n. 78, observe that the author of a separate opinion in Schupbach (Fontron, J., concurring), supra note, 1, appears to join the pronouncement reluctantly, because, although acknowledging that he is bound by Gilmore, he says that "[i]t offends my sense of logic to say that the market value of gas at the mouth of the well is the price for which gas is ultimately sold after having been so processed that it has become marketable. I would consider that market value of gas at the well would be that amount for which it could be sold, after deducting such reasonable expenses as was required to render it saleable... ."

[18] Altman & Lindberg, supra note 7. The authors contend that these cases "are probably, in fact, unsupportable under Kansas law, and should be given a restrictive application." Id. at 379.

[19] Ashland Oil and Refining Co. v. Staats, Inc., supra note 17 at 575), in referring to the decisions in Gilmore and Schupbach, states, "We will not so enlarge the lessee's duty to market production ... the two state cases do not support such a holding and nowhere have we found the lessee's duty to market thus extended." Id. at 575.

[20] The Texas and Louisiana approach is developed in Merritt v. Southwestern Elec. Power Co., supra note 3, Martin v. Glass, supra note 4 and Parker v. TXO Production Corp., supra note 4. But see Skaggs v. Heard, 172 F. Supp. 813 (S.D.Tex. 1959), which has been cited for the proposition that the gas producer may not deduct compression costs from royalty proceeds. Skaggs has been criticized for the same reasons as Gilmore, supra note 1, and has been described as a sui generis case with authority only for the facts therein. Altman & Lindberg, supra note 7 at 375.

[21] Supra note 3.

[22] Merritt v. Southwestern Elec. Power Co., supra note 3.

[23] Merritt v. Southwestern Elec. Power Co., supra note 3 at 211.

[24] Merritt, supra note 3 at 213.

[25] Supra note 4 571 F. Supp. at 1415.

[26] Martin v. Glass, supra note 4 at 1415. In holding that compression costs were properly deducted, the court first found that the royalty was to be based on the value of the gas at the wellhead; it then considered the nature of compression costs. Since under Texas law gas is produced when it is severed from the land at the wellhead, the court decided that production had been obtained from the wells, as there was sufficient pressure to bring the gas to that point. The court then noted that compression is an element of the marketing function, because it is a of separate and independent step, once or more removed from production." Compression costs were thus held to be a post-production expense to be borne proportionately by the royalty owner and his lessee.

[27] Supra note 4 716 S.W.2d at 648. Parker notes that both the oil and gas lease and the facts under review in that case were similar to those in Martin v. Glass, supra note 4.

[28] Both Martin and Parker base their allowance of compression cost deduction on a characterization of when the costs occurred. If the cost is termed "production" costs, the lessee is required to bear the expense. "Post-production" expenses are equally borne by both the lessee and the lessor. Martin, supra note 4, at 1411-1412, Parker, supra note 4, at 648.

[29] According to one textwriter, utilizing the Kansas and Arkansas view causes a "certain amount of confusion... . [B]ecause compression costs are normally considered post-production expenses, there [would be] no clear division ... between costs that should be borne solely by the lessor and those that should be shared pro rata by the lessor and lessee." Note, supra note 15 at 404.