
    Robert Lee MARTIN, Franklin Martin, Minerals, Inc., and Charles E. Brown v. John P. GLASS.
    Civ. A. No. 4-79-191-K.
    United States District Court, N.D. Texas, Fort Worth Division.
    Aug. 16, 1983.
    
      Frank Jennings, Jennings, Montgomery, Dies & Turner, Graham, Tex., for plaintiffs.
    Lee D. Vendig, Pickering & Vendig, Don Davis, Payne & Vendig, Dallas, Tex., for defendant.
    Ira Butler, Cantey, Hanger, Gooch, Munn & Collins, Fort Worth, Tex., for amicus curiae.
   MEMORANDUM OPINION

BELEW, District Judge.

This suit involves the construction of the gas royalty and overriding royalty provisions of an oil and gas lease.

Plaintiffs, Robert Lee Martin and Franklin Martin own royalty and overriding royalty interests, and Minerals, Inc., and Charles E. Brown own overriding royalty interests in an oil and gas lease in Jack County, Texas, designated as the Glass-Martin Lease, which is owned and operated by the Defendant John P. Glass, and located in an area known as the Fort Worth Basin.

Because of insufficient wellhead pressure, the Defendant installed a compressor to move the gas from the two producing wells on the lease into a nearby gathering line for marketing. The Defendant deducted compression charges from the proceeds of production attributable to the Plaintiffs’ royalty and overriding interests. Plaintiffs seek monetary damages for the alleged improper charges assessed and a declaratory judgment disallowing such charges from the proceeds of future production.

I.

This Court has jurisdiction pursuant to Title 28 U.S.C. § 1332 since there is diversity of citizenship between the parties and the amount in controversy exceeds $10,000. Suit was originally filed in the District Court of Jack County, Texas, but was removed by the Defendant to Federal Court. Plaintiffs Robert L. Martin, Franklin Martin, and Charles E. Brown are citizens and residents of the State of Texas. Plaintiff Minerals, Inc., is a Texas corporation with its principal place of business and registered office in Young County, Texas. Defendant John P. Glass is a citizen and resident of the State of Pennsylvania.

II.

The facts briefly are as follows:

On August 1, 1972, Ruby Joan Smith, et al, executed an oil and gas lease to Minerals, Inc., as lessee. Said lease, which is designated as the Glass-Martin Lease, reserved to the lessors a one-eighth (Vs) royalty and a one-thirty-second (Vk) overriding royalty in the seven-eighths (Vi) working interest of the lessee. Subsequent thereto, Plaintiffs Robert Lee Martin and Franklin Martin became the successors in interest to that of Ruby Joan Smith, et al, the lessors. At all times relevant, Robert Lee Martin and Franklin Martin owned, respectively, five-sixth (%) and one-sixth (V<¡) interests in said lease.

Minerals, Inc., thereafter assigned its interest in the lease to Wes-Mor Drilling, Inc., in October, 1972. By said assignment, Minerals, Inc., reserved a one-thirty-second (Vk) overriding royalty in the seven-eighths (%) working interest.

In November, 1972, Wes-Mor Drilling, Inc., assigned to the Defendant, John P. Glass, the above-described oil and gas lease. Said assignment was made subject to the overriding royalty interest reserved by Minerals, Inc.

By assignment dated March, 1973, Minerals, Inc., assigned to Charles E. Brown one-half (V2) of the overriding royalty interest reserved in the assignment of Wes-Mor Drilling, Inc., i.e. a one-sixty-fourth (Vm) overriding royalty in the seven-eighths (Vs) working interest. At all material times, hereto, Minerals, Inc., and Charles E. Brown have each owned one-half (%) of the one-thirty-second (Vk) overriding royalty in the seven-eighths (Vs) working interest, which was subsequently assigned to John P. Glass.

Accordingly, the Defendant, John P. Glass, is the owner of the working interest in the first two (2) tracts of the oil and gas lease from Ruby Joan Smith, et al to Minerals, Inc., covering 711.25 acres of land, more or less, in Jack County, Texas. The Defendant drilled two producing gas wells. The parties have stipulated that both wells were producing wells, however, there was insufficient wellhead pressure to cause the gas to flow into the nearby gathering line. It became necessary to install a compressor on the lease. If the gas were not compressed, it could not be marketed, and would either be flared (wasted) or the wells would have to be shut in. Therefore, James McCauley, Vice President of Operations, Trans-Texas Energy, Inc., agent for Defendant, made the decision to rent a compressor from Halliburton Resources Management and place it in use. The Defendant gathered the gas, delivered it into the compressor, transmitted it along the flow-line, through the gas meter, to a pipeline system owned by Southwest Gas Pipeline, Inc., and purchased by Brazos Electric Power Cooperative.

The cost of compression was charged against both royalty and working interests on a pro rata basis. Said charges were based upon the quantity of gas which passed through the compressor during a given period.

III.

The issues presented for the Court’s determination are as follows:

1. Under the lease and royalty provisions, may the Defendant/operator, John P. Glass, deduct compression charges from the royalty and overriding royalty proceeds due Plaintiffs.

2. If compression charges are deductible from the royalty and overriding royalty interests, were said charges excessive.

3. Has the conduct of the Plaintiffs, upon receipt of the monthly (or periodic) payments since July, 1976, created an accord and satisfaction.

4. Are the Plaintiffs entitled to recover reasonable attorney’s fees from the Defendant.

IV.

1. Are compression charges deductible from nonoperating interests?

The central issue is whether the compression charges are proportionately chargeable against the royalty and overriding royalty interests. Plaintiffs contend that the gas compression charges, which have been deducted upon a pro rata basis from their royalty and overriding royalty interests since production began in 1976, are improper and unauthorized and are in violation of the terms and provisions of the oil and gas lease, and the assignment. The proceeds of production attributable to each of such interests should be paid to the respective owners thereof free and clear of all exploration, drilling, development, completion, operating and marketing costs.

The Defendant, on the other hand contends that the deduction of compression charges is proper and authorized by the terms and provisions of the lease and royalty provisions; that such expenses are a portion of the marketing and/or transportation costs which the lease, assignments and the law specifically authorize to be imposed.

The Court is of the opinion that the Defendant’s position should be sustained.

Generally, a royalty is an expense-free interest, paid out of production, over the life of the lease. It is free of all costs of development and production, Alamo National Bank of San Antonio v. Hurd, 485 S.W.2d 335, 338 (Tex.Civ.App. — San Antonio 1972, writ ref’d n.r.e.), but may share in any costs incurred subsequent to production. See 3 Williams Oil & Gas Law (Matthew Bender) § 645 p. 591, et seq. This general rule may be modified by the respective parties, a division order, or gas purchase contract.

An overriding royalty is a royalty, except that it is earned out of the lessee’s or operator’s interest, and is in addition to the lessor’s royalty. Usually it is free from all costs incident to development, production and operation. Id. at 339; Cameron v. Stephenson, 379 F.2d 953, 955 (10th Cir.1967). An overriding royalty is an interest running throughout the life of the lease. See: 43 Tex.Jur.2d Oil and Gas § 383, pp. 25-28.

Royalties, generally, are payable “in cash or in kind.” In other words, a royalty owner is entitled to receive either his proportionate share of the actual mineral produced (e.g.) in barrels of oil, or the market value in cash of his proportionate share (e.g.) ten dollars ($10.00) per barrel of oil. However, due to the physical properties of gas, payment “in kind” is usually not feasible. Thus royalties on gas are generally paid “in cash.”

In order to determine the amount of royalty to be paid in cash, the lease must be examined to ascertain the point at which the royalty clause fixes the price of the gas.

The pertinent parts of the gas royalty provisions of the lease for the benefit of Plaintiffs Robert Lee Martin and Franklin Martin are as follows:

“3. The royalties to be paid by Lessee are: ... (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold on or off the premises, one-eighth of the net proceeds at the well received from the sale thereof...”

The clause reserving overriding royalty (Lease, para. 1, typed portion) for the benefit of Plaintiffs Martin:

“... the Lessors ... reserve an overriding royalty in the aggregate amount of Vfend of 7/sths of all oil, gas and other minerals saved, produced or sold from the premises and the production attributable to said interest is to be delivered to any pipeline for the credit of Lessors, free and clear of all cost of drilling, exploration or operation, SAVE AND EXCEPT said interest shall be subject to its proportionate part of all gross production, ad valorem and severance taxes.”

The clause reserving overriding royalty in the lease-hold assignment (Assignment of Oil and Gas Lease, p. 2) for the benefit of Plaintiffs Minerals, Inc., and Brown provides:

“... the interest assigned herein shall be subject to its proportionate part of a Vh nd of Vsths overriding royalty ... free and clear of all cost of exploration, development, completion and operation SAVE AND EXCEPT gross production, severance and ad valorem taxes ...”

As this Court’s jurisdiction is based upon diversity of citizenship, consideration of the proper construction of the gas royalty provisions here involved should begin with the law of Texas. Erie Railroad Co. v. Tompkins, 304 U.S. 64, 58 S.Ct. 817, 82 L.Ed. 1188 (1938). Furthermore, the Fifth Circuit has directed that:

“[u]nder Erie R.R. Co. v. Tompkins, 304 U.S. 64, 58 S.Ct. 817, 82 L.Ed. 1188 (1938), federal courts in diversity of citizenship must apply the law of the state in which they sit. Moreover, a federal court must follow the decision of an intermediate appellate state court in the absence of other persuasive indications that the highest court of the state would decide otherwise.” (Citing authorities).

Benante v. Allstate Insurance Co., 477 F.2d 553, 554 (5th Cir.1973). Also see: Fidelity Union Trust Co. v. Field, 311 U.S. 169, 61 S.Ct. 176, 85 L.Ed. 109 (1940). Accordingly, this Court, in reaching its determination, is bound by Texas law to the extent that it addresses the issues presented herein.

a. Where is point that fixes the price?

In resolving whether compression charges are deductible under the lease and royalty provisions herein, it must first be determined where said instrument establishes the point fixing the price (hereinafter referred to as point). The key phrases contained within the lease royalty clause are: “at the well received,” “the net proceeds,” and “sold on or off the premises.”

Initially, it should be noted that Plaintiffs have made no contention and offered no evidence that the above phrases are ambiguous, or should be interpreted in a special or technical sense. Accordingly, these phrases will be interpreted in accordance with their ordinary, popular and commonly accepted meanings. See, Phillips Petroleum Co. v. Gillman, 593 S.W.2d 152, 154 (Tex.Civ.App. — Amarillo 1980, writ ref’d n.r.e.); Climatic Air Sales, Inc. v. Climatic Air Distributors, 336 S.W.2d 461 (Tex.Civ. App. — Texarkana), rev’d on other grounds 162 Tex. 237, 345 S.W.2d 702 (1960). Further, absent the assertion of contract ambiguity, all terms of the contract should be construed in accordance with the meaning and natural import of the language used. Whitworth Estate v. Mangels of Texas, 363 S.W.2d 851 (Tex.Civ.App. — Waco 1962, no writ); Stahl Petroleum Co. v. Phillips Co., 550 S.W.2d 360 (Tex.Civ.App. — Amarillo, aff’d 569 S.W.2d 480 (Tex.1977).

It is well settled that the phrase “at the well received,” or similar terminology, establishes the “point” at the mouth of the well. In other words, Plaintiffs Martin are entitled to receive one-eighth (%) of the total gas delivered (produced) to the mouth of the well or the market value thereof. Accordingly, the royalty is free of all costs (e.g. exploration, drilling, operation, etc.) up to this point. See: Phillips Petroleum Co. v. Johnson, 155 F.2d 185 (5th Cir.1946); Freeland v. Sun Oil Co., 277 F.2d 154 (5th Cir.1960); Danciger Oil & Refineries, Inc. v. Hamill Drilling Co., 171 S.W.2d 321 (Tex. Sup.1943); LeCuno Oil Co. v. Smith, 306 S.W.2d 190 (Tex.Civ.App. — Texarkana 1957, writ ref’d n.r.e.).

Further, “net proceeds” clearly Suggests that certain costs are deductible. “Net proceeds” is typically defined as the sum remaining from gross proceeds of sale after payment of expenses. WEBSTER’S New World Dictionary, 985 (1966), defines “net” as: “... left over after certain deductions or allowances have been made, as for expenses ...” Black’s Law Dictionary, 938 (4th Ed.) defines “net proceeds” as: “Gross proceeds less charges which may be rightly deducted. Pflueger v. United States, 73 App.D.C. 364, 121 F.2d 732, 736.” Because the parties contracted for “net proceeds,” instead of “proceeds,” it necessarily follows that deduction of some expense is proper, prior to payment of the royalty.

Finally, the phrase “sold on or off the premises” clearly implies that the value of royalty will be the same whether the gas is sold on or off the premises.

The Court is of the opinion that the gas-royalty clause of the lease in question should be interpreted as follows:

Regardless of whether the gas is sold on or off the leased premises, royalty is based on the value of all gas produced at the mouth of the well. Costs incurred prior to production are to be borne by the operator, while costs incurred subsequent to production (those necessary to render the gas marketable) are to be borne on a pro rata basis between operating and nonoperating interests.

See: 3 Williams Oil and Gas Law (Matthew Bender) § 645, p. 591 et seq.

The interpretation placed on the royalty clause herein is consistent with the interpretations given similar royalty clauses by Texas courts and the Fifth Circuit.

In Danciger Oil and Refineries, Inc. v. Hamill Drilling Co., supra, the question before the Court was whether the royalty payments were to be based on the value of the gas as produced or its value after the gas had been processed. The clause involved provided:

“Assignor ... shall be entitled to receive Vaith of all the oil, gas ... produced, saved and marketed at the prevailing market price ... free and clear of operating expenses ...”

The well produced sweet gas for which there was then no market. A Danciger subsidiary erected a plant on the leased premises through which the raw gas produced was separated and processed into gasoline, distillate and kerosene. Hamill contended it was entitled to be paid Vaith of the gross receipts of all products so manufactured, without deduction for the cost of processing. The district court and Court of Civil Appeals held for Hamill. The Texas Supreme Court reversed. In construing the term “operating expenses” from the royalty clause, the Supreme Court held that operating expenses referred to the expenses necessary to production, and not those involved in processing the product subsequent to production. The basic holding was that Hamill was entitled to be paid his royalty at the “prevailing market price” of the sweet gas when produced and was not entitled to share in the increase received from sale of the processed products. That is, the royalty was based on the value of the gas at the point of production (at the mouth of the well).

LeCuno Oil Co. v. Smith, supra, involved a royalty clause which contained the phrase “at the well.” The royalty owners claimed that the lessee was not entitled to deduct from such royalty the costs of “dehydrating, gathering, transporting and processing.” The Court found that such costs were properly deductible. The Court stated in pertinent part:

“... there was no market for the gas at the well and the price received by LeCuno for the gas and for which it is accountable to the appellees would be the amount received by LeCuno for the gas, less the cost of dehydration, gathering, transporting and processing.” (306 S.W.2d at 193).

The Court also affirmed the trial court’s submission of the following issue:

“What do you find from a preponderance of the evidence is a reasonable charge, if any, for gathering transporting and compressing the gas?” (Emphasis added).

The lessee had objected to this instruction on the ground that it was entitled to deduct the “actual,” rather than the “reasonable” costs.

As to the issue of the gas royalty clause, the Court held that LeCuno, the lessee, was entitled to deduct from the royalty payments, the royalty owners’ pro rata part of LeCuno’s reasonable costs for gathering, transporting and compressing the gas used or sold off the land in question.

With reference to Texas precedent, the Court said:

“Under facts similar to these the Supreme Court in Danciger Oil & Refineries, Inc., 171 S.W.2d 321 held that the producer was liable for the fair and reasonable value of the gas. Deducting the cost of gathering and treating from the good faith sale price ... arrives at its fair and reasonable value.”

LeCuno and Danciger are cited in 43 Tex.Jur.2d Oil and Gas § 389, p. 48 in support of the statement:

“The lessee’s obligation to market is to market at the well, and thus in computing the market value of the gas at the well for royalty purposes the lessee is entitled to reimbursement for the lessor’s proportionate part of the reasonable cost of transporting the gas to the market, dehydrating, compressing, or otherwise making the gas suitable for marketing, including extraction costs resulting from processing.” (Emphasis added).

The Fifth Circuit’s decision in Phillips Petroleum Co. v. Johnson, 155 F.2d 185 (5th Cir.1946), was typical of its holdings on the construction of gas royalty provisions similar to the ones here involved. The clause under consideration, which was almost identical to the one at bar, provided:

“... lessor shall be paid at the rate of Vs of the net proceeds derived from sale of gas at the mouth of the well.” (Emphasis added).

Applying Texas law, the Fifth Circuit stated that:

“net proceeds ... generally means the receipts, less expenses, of an actual sale ... Insofar as the gas was ‘marketed’ we think the stipulation for a share of the ‘net proceeds derived’ ought to be enforced, effect being given to the words ‘net at the mouth of the well’ by allowing as expense the cost of transporting, separating and marketing ... we hold that as applied to the Defendant’s handling of this gas the measure of accountability is ... Vs of the proceeds of sale of the residue gas, less a proper credit for the cost of transportation, separating and sale.”

In Shamrock Oil & Gas Co. v. Coffee, 140 F.2d 409 (5th Cir.1944), the Court construed the following royalty provisions:

“On gas produced from said land and sold or used off the land, or in the manufacture of gasoline, including casing-head gas, the market price at the well of Vs of the gas so sold or used, provided that if and when lessee shall sell gas at the wells, lessor’s royalty therefrom shall be Vs of the amount realized from such sale.”
The Court, applying Texas law, stated: “The contract is that if Shamrock sold the gas at the mouth of the well the royalty owners would take their part of what it sold for. In the event the gas were used by Shamrock to make gasoline or otherwise or was sold after being removed from the lease the royalty owners were to have the market price at the mouth of the well.” (Emphasis added). (140 F.2d at 410).

A more recent decision by the Fifth Circuit and one which is subsequent to the decision by Judge Allred in the Skaggs case, hereinafter addressed, is Freeland v. Sun Oil Co., 277 F.2d 154 (5th Cir.1960). The question in Freeland was whether the lessor was required to bear any of the expense of processing the gas. The gas was carried to a processing plant where it went through various separators and other equipment, and condensate and various other liquids were removed. The processing plant was owned by a third party who received 35.7% of the end products. The lessee oil companies paid Vs royalty on the 64.3% which was returned, but the lessors contended that they were entitled to royalty on 100% of the end product. The lease provided:

“The royalties to be paid by Lessee are: ... (b) on gas, including casinghead gas or other gaseous substance, produced from said land and [1] sold or used off the premises or in the manufacture of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on [2] gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale ...”

In either event, under that clause, the “point” was “at the well” but the method of determining value was different in that under Subdivision 1 the lessor’s royalty was determined by the market value of the substance, while under Subdivision 2 it was determined by the amount realized which could easily be different.

The Court discussed the method for determining the market value of the gas which it considered applicable, and said:

“To put it another way: in the analytical, process of reconstructing a market value where none otherwise exists with sufficient definiteness, all increase in the ultimate sales value attributable to the expenses incurred in transporting and processing the commodity must be deducted. The royalty owner shares only in what is left over, whether stated in terms of cash or an end product. In this sense he bears his proportionate part of that cost, but not because the obligation (or expense) of production rests on him. Rather, it is because that is the way in which Louisiana law arrives at the value of the gas at the moment it seeks to escape from the wellhead.” (277 F.2d at 159) (Emphasis added).

It should be noted that while Freeland involved the application of Louisiana law, it appears that Texas and Louisiana law are the same; both jurisdictions allow the deduction of post-production cost when royalty is determined “at the mouth of the well.” See: Haynes v. Southwest Natural Gas Co., 123 F.2d 1011, 1012 (5th Cir.1941). Compare Wall v. United Gas Public Service Co., 178 La. 908, 152 So. 561 (1934) and LeCuno Oil Co. v. Smith, Id.

Significant to note; the Supreme Court, in Sartor v. Arkansas Natural Gas Corp., 321 U.S. 620, 64 S.Ct. 724, 88 L.Ed. 967 (1944), Rehearing Denied, 322 U.S. 767, 64 S.Ct. 941, 88 L.Ed. 1593, expressly recognized that in determining a gas royalty payable “at the well,” Louisiana law provided for a proportionate deduction of the costs of gathering and delivering the gas to a pipeline. The case cited by the Circuit Court of Appeals in determining Louisiana law on this point was Sartor v. United Gas Public Service Company, 186 La. 555, 173 So. 103 (1937), which in turn cited Wall v. United Gas Public Service Company, supra.

In Wall, the Louisiana Supreme Court held that the lessor must bear a proportionate share of post-production costs, stating “the lessee cannot be taxed with the whole costs of marketing the gas.”

It is apparent that the position taken by the Louisiana Supreme Court is essentially the same position taken by the Texas Court in LeCuno.

The Plaintiffs rely heavily upon the case Skaggs v. Heard, 172 F.Supp. 813 (S.D.Tex.1959). However, the Court is of the opinion that the Plaintiffs’ reliance upon Skaggs is wholly misplaced. The Amicus Curiae brief submitted herein stresses that the decision in Skaggs was erroneous and therefore should carry no precedential value. This argument was well received by the Court. However, assuming Skaggs is binding upon this Court, said case is clearly not in point.

This was a suit by the lessee’s successor against the royalty owners “to recover a proportionate part of the cost of operating a compressor unit necessary to deliver gas from two producing wells into the purchaser’s pipeline on the lease, 330 feet from the wells.”

The pertinent provisions in the lease as to gas royalty to be paid to lessors were:

“(2) An equal one-fourth (Vi) part of the amount received by Lessee at the well when said gas, including casinghead gas or other gaseous substances produced from said land is sold at the well by Lessees to others; and
“(3) An equal one-fourth (Vi) part of the market value at the well of such gas, including cashinghead gas or other gaseous substances produced and saved from said land when not sold at the well but used or sold off the leased premises otherwise than for the purpose hereinafter set forth.” (Emphasis added).

As quoted above, there were two clauses, one with a particular stipulation where the sale occurred “at the well;” the other with a different stipulation where “not sold at the well but used or sold off the leased premises.” The argument in Skaggs involved where the sale occurred, and hence which clause applied.

In the case at bar, it is irrelevant where the sale occurs as the royalty clause provides that the royalty is the same regardless of where the gas is sold; “sold on or off the premises.”

Further, the Court placed a lot of weight upon the conduct of the parties for years prior to suit. As stated by the Court,

“After installation of the compressor Kelley (lessee) operated the lease for about 11 months. He made no attempt before, during or after that time to impose a charge on defendants for a proportionate part of the cost and operation of the compressor.” (172 F.Supp. at 814).

The compressor was installed on January 1, 1955. Thereafter, the original lessee, Kelley, sold the working interest to Skaggs, who took over operation of the lease. Skaggs made no demand on the royalty owners for compression charges until September 1, 1956. In the meantime, the royalty owners received their royalty, with no deductions for compressor costs.

The importance the Court gave to these facts is shown at pages 816-817 of the opinion:

“The most that can be said for plaintiff, is that the meaning of ‘sold at the well to others’ is doubtful; wherefore the construction placed thereon by the parties becomes important, entitled to great weight and, to my mind is decisive.”

In the case at bar, the facts are just the opposite. Plaintiffs, for approximately four years, received their royalty payments with a proportionate part of compression costs having been deducted before they raised a question about such deductions.

Finally, the court itself, at page 816, noted that plaintiff cited many cases which depended on provisions “altogether different from those used here.” In the footnoted cases which the court characterized as “altogether different, and distinguishable,” it cited Danciger and LeCuno, supra; Matzen v. Hugoten Production Co., 182 Kan. 456, 321 P.2d 576 (1958), cited in Defendant’s original brief; and, noted that Phillips Petroleum Co. v. Johnson, supra, “called for !4 of the net proceeds derived from gas at the mouth of the well’ (emphasis in original).

b. Were compression changes post-production ?

Having determined that post-production costs are properly deductible from royalty, it must now be determined whether the compression charges were post-production and were properly deducted. The Court is of the opinion that they were.

Under the law of Tekas, gas is “produced” when it is severed from the land at the wellhead. Lone Star Gas Co. v. Murchison, 353 S.W.2d 870 (Tex.Civ.App.— Dallas 1962, writ ref’d n.r.e.) The facts established that “production” of gas had been obtained from two wells on the Glass-Martin lease. (There was sufficient pressure to bring the gas to the wellhead or mouth of the well.) There was no evidence introduced to the contrary. In fact the parties stipulated that “at all times material to the suit, the Defendant has had two productive gas wells, on the Glass-Martin lease.” (See paragraph 6(d) of Pre-trial Order). Therefore, this is sufficient to hold the nonoperating interests liable for their proportionate share of compression costs, as such costs were incurred subsequent to production.

Further, in support of the Court’s holding, it should be apparent that production is futile without potential disposition of the product. It is well recognized and acknowledged that the working interest operator has a duty to market the product once production has been achieved. Rhoads Drilling Co. v. Allred, 123 Tex. 229, 70 S.W.2d 576, 585 (1934); Cole Petroleum Co. v. United States Gas and Oil Co., 121 Tex. 59, 41 S.W.2d 414, 416 (1931); Ashland Oil and Refining Company v. Cities Service Gas Co., 462 F.2d 204, 213 n. 9 (10th Cir.1972); 3 Williams, Oil and Gas Law, § 645 pp. 605-6 (1979); 3 Kuntz, Law of Oil and Gas, p. 323 (1967); 2 Summers, Oil and Gas, § 415 p. 631 (Perm.Ed.1958); M. Merrill, Covenants Implied in Oil and Gas Leases, p. 212 (2nd Ed. 1940). This is true when the royalty is payable in money (as opposed to in kind) because the royalty owner is so dependent upon the lessee in order to realize his royalty return. Cole Petroleum Co. v. United States Gas and Oil Co., supra, twice quoting from M. Merrill, Covenants Implied in Oil and Gas Leases, supra, at p. 2, 151; A. Thuss, Texas Oil and Gas, Sec. 126, pp. 172-73 (2nd Ed. 1935). However, the duty to market is a separate and independent step, once or more removed from production, and as such is a post-production expense, and the lessee is entitled to a pro rata reimbursement. Phillips Petroleum Company v. Johnson, supra, 155 F.2d at 189; 3 Kuntz, Law of Oil and Gas, supra, at p. 323.

The parties stipulated that there was insufficient pressure at the wellhead to enable the gas to enter the purchaser’s gathering line without compression. The gas was useless and had no market value at the wellhead unless, and until, it could be moved into the gathering line. Accordingly, there was no market for the gas “at the well.” In order to market the gas, it first had to be compressed. Under the lease here involved, the distance between a potential market (gathering line) and the wellhead is immaterial. There existed no purchaser, or market, for the gas as it existed in the wellhead because of its low pressure. Thus, compression being required to market the gas, said charges were post-production costs and as such were properly deductible from nonoperating interests.

c. Are compression charges deductible from overriding royalties?

Plaintiffs seek to distinguish the landowner’s obligation to pay his part of compression costs necessary to move the gas into a pipeline from the obligation of owners of the overriding royalty. They argue that the provision in the overriding royalty clause “delivered to any pipeline for the credit of lessors” excuses them from the payment of compression costs. Their position is untenable.

An overriding royalty is, first and foremost, a royalty interest. That is, it is an interest in the gas produced at the surface free of the expenses of production to that point. Alamo National Bank v. Hurd, 485 S.W.2d 335, 339 (Tex.Civ.App. — 1972, writ ref’d n.r.e.); Griffith v. Taylor, 156 Tex. 1, 291 S.W.2d 673 (1956). As such, an overriding interest is subject to expenses incurred subsequent to production. While the Court has been unable to locate Texas precedent directly on point, the Oklahoma Supreme Court addressed this issue in Matter of the Application of Martin, 321 P.2d 659 (Okl.1957). In that case, the overriding royalty reservation provided that the interest reserved:

“... shall be delivered by the Assignee to the Assignors free and clear of all costs of developing, equipping and operating said properties, so that said reserved interest shall be in the nature of a perpetual overriding royalty ...” (321 P.2d at 661).

The overriding royalty reservation further provided that the owner should pay certain taxes and for delivery of assignor’s share of production to the pipeline. The Court held that the royalty owner was only entitled to the price of the raw gas at the wellhead. In that case, the overriding royalty owner was claiming royalty based upon the processed products. The Court said:

“We also hold that appellees are not entitled to any share of the hydrocarbons’ proceeds, as such. However, if convenience or other considerations dictates paying them for their share of the casing-head gas by paying them a portion of such proceeds, then such payment should not be made without deduction of a reasonable charge for processing.” (321 P.2d at 665).

Further, the overriding royalty provisions provide that said interests shall be free and clear of all costs of drilling, exploration, development, completion and operating expenses. Skid clauses provide that the royalty shall be subject to its proportionate part of all gross production, ad valorem and severance taxes. Clearly, the overriding royalty clauses refer only to costs incident to getting the gas to the surface. Accordingly, there is no basis for different treatment of the regular royalty and the overriding royalty.

2. Reasonableness of compression charges.

Also at issue in this case is the reasonableness of the compression charges. Plaintiffs contend tha/t such charges were excessive. Testimony at trial established that in order to market the gas by entering the 600 pound high pressure gathering line of the purchaser, it was necessary to install a compressor upon the leased premises; that James McCauley rented a compressor for a monthly charge from Halliburton Resources; that he was obliged to rent a two-stage compressor because the pressure at the wellhead was about 25 pounds, and such pressure had to be raised to 600 pounds to enter the gathering line, and such operation required a two-stage compressor; that he picked the size of the compressor based upon the estimated volume of gas available from current tests of the well; that he picked Halliburton in lieu of other suppliers based on availability, field service, performance and price, deciding that the Halliburton compressor was the best available in view of such considerations; that it would be too expensive to purchase a compressor, in that the compressor cannot be moved readily, without sizable expense, from one lease to another, and the right stage and size compressor must be available on the lease while the gas requires compression; that most operators rented compressors when necessary; and that more production was anticipated in the future.

The testimony further established that a typical charge for compression in the Fort Worth Basin was fifteen to twenty-five cents per MCF per stage of compression. Further, while a compression charge might vary from a few cents per MCF to in excess of $1.00 per MCF, the cost per MCF was strictly a mathematical calculation based solely on the volume of gas which was processed through the compressor during any given period. When the volume of gas processed through the compressor went down, the charge per MCF automatically went up, and therefore the matter was solely determinable by the volume of gas processed. If, in the future, production rose again and the volume of gas processed through the compressor rose, the charge would drop down to a more “typical” cost per MCF per stage in the Basin area.

Based upon the above, the Court holds that the compression charges incurred by the Defendant were reasonable. The Defendant cannot be held responsible, in the context of the issues presented in the matter at bar, for the declining production of the two wells on the lease.

V.

The remaining issues are not addressed herein, as the holdings of the Court render said issues moot.

VI.

Judgment will be entered in accordance with this opinion. 
      
      . As to application of Mississippi law to royalty provisions of an oil and gas lease see: Piney Woods Country Life School, et al v. Shell Oil Company, 539 F.Supp. 957 (1982).
     
      
      . The lessee’s obligation to market is to market at the wells, and thus in computing the market value of the gas at the well for royalty purposes the lessee is entitled to reimbursement for the lessor’s proportionate part of the reasonable cost of transporting the gas to the market, dehydrating, compressing, or otherwise making the gas suitable for marketing, including extraction costs resulting from processing. (Emphasis added). 43 Tex.Jur.2d Oil & Gas, § 398 p. 47.
     