Exxon Corp. v. Middleton

571 S.W.2d 349, 1978 Tex. App. LEXIS 3623

• Court: Court of Appeals of Texas
• Decided: August 23, 1978
• Docket: 1658
• Status: Published

Opinion

J. CURTISS BROWN, Chief Justice.

This is an appeal from a judgment for multiple plaintiffs in their suit to recover alleged deficiencies in royalty payments for gas produced from wells located on their lands in Chambers County, Texas.

GENERAL STATEMENT

In the early days of the oil industry in this state, natural gas was regarded more as a waste by-product of oil production than as a valuable resource. The gas produced along with oil was often simply burned or “flared.” Evidence in this case indicates that, at one time, one could drive for many miles at night through the East Texas Oil Field without turning on the lights of one’s vehicle. From the air, West Texas was said to look as if campfires of all of all of the armies in the history of the world were burning below.

During the 1930’s and perhaps earlier, various community and city systems utilizing substantial amounts of gas as a clean and efficient heating fuel were developed. These systems tended to expand the demand for natural gas, but the essentially local character of the use remained the same.

World War II was a catalyst for much change. Ancillary to the delivery of petroleum products to assist in the war effort, the so-called “Big Inch” and “Little Inch” pipelines had been put in place. Following the end of the war (and the elimination of danger from enemy action to shipping), these lines became available for the transportation of natural gas to various eastern and midwestern points not previously serviced. Based upon this beginning, a large and complex interstate pipeline system was developed to transport gas from the producing states for use in many highly populated areas of the county as home heating fuel, industrial fuel, and feedstock for various manufacturing processes.

Economics of the sale of natural gas involved the interests of the lessor (the landowner or owner of the minerals), the lessee (the firm, person or corporation drilling upon and operating the property), and the purchaser of the gas (usually a transmission company or a user of the product). In the beginning gas had little, if any, value, and it may be fair to say that an amount of care commensurate with that value was used in formulating gas royalty provisions in oil and gas leases. Printed forms were frequently used. It is undisputed in this record that until the early 1970’s gas was usually sold under long-term contracts. The reasons for these long-term contracts were at least two-fold. Firstly, a substantial financial commitment was involved in bringing a pipeline to the producing wells and thence to the user. This cost was coupled with the investment required for dehydration and compression, if necessary, to meet pipeline standards. Moreover, plants often stripped the liquid hydrocarbons from the gas to yield a valuable by-product. Naturally, one would not expect to invest in and provide such physical facilities at great expense only to have the supply of gas diverted to a new purchaser. Secondly, gas had to be used as produced until relatively recently. The manufacturer and storage of liquified natural gas and the use of some “storage” capacity in spent reservoirs have had little effect on the fact that gas is normally used as quickly as it is produced. These two economic facts of life led to the almost universal use of long-term gas purchase contracts.

The evidence discloses that in the late 1940’s, 1950’s and into the 1960’s, interstate gas sales led the way in matters relating to price and terms of contracts for such sales. Lessees, responding to their own interest in marketing their product, were under an additional pressure to make contracts for sale by reason of their implied obligation to use the care of a reasonably prudent operator to market the product and by reason of the natural desire of their lessors to receive royalty proceeds. More sophisticated provisions and clauses were developed during these years. “Most favored nations” provi sions, which were included in some contracts, had the effect of increasing the price to the highest of that paid by the purchasers or others in the area designated in the contract. Periodic reevaluation provisions were sometimes included. Arbitration provisions were made a part of some contracts. Distinctions were often made between “gas only” production and casinghead gas accompanying the production of oil.

The leadership of the interstate market in increasing prices and in fostering sophisticated contractual provisions for the sale of natural gas was seriously impacted by the decision of the Supreme Court of the United States in Phillips Petroleum Co. v. State of Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954). Phillips and subsequent decisions brought the price of interstate gas under the regulatory control of the Federal Power Commission. No doubt the industry had previously sensed the desirability of remaining “free,” but the choice became even clearer as the federal regulatory agency assumed full control of not only price but permissible contractual provisions in interstate contracts. Insofar as interstate gas was concerned, no “free” market existed. Weymouth v. Colorado Interstate Gas Company, 367 F.2d 84, 89 (5th Cir. 1966).

Throughout the history of the industry a “custom and usage” had developed under which the royalty owners were compensated by payment of a designated percentage of the “proceeds” of the sale of gas. From these proceeds were deducted severance taxes and, where applicable, the cost of compression or other processing of the gas needed to bring it up to pipeline specifications and to obtain the liquid content byproduct. This so-called “custom and usage” largely ignored the exact language of the oil and gas leases and their gas royalty provisions. The attitude was exemplified by the unequivocal testimony of one of the original lessors, who was a plaintiff in this suit. The lessor testified that he knew that the gas produced under his leases was being sold by Sun and that he understood that Sun was to pay royalties based upon what it got for that gas. Specifically, the following exchange took place during trial:

Q. They were supposed to base your royalty on what they got for the gas?

A. Always.

The complacency of the lease operators was shattered, however, by the holding of the Supreme Court of Texas in the case of Texas Oil & Gas Corporation v. Vela, 429 S.W.2d 866 (Tex.Sup.1968). The lease construed by the supreme court obligated the lessee to

deliver to the credit of lessor, free of cost, in the pipe line to which lessee may connect its or his wells, the equal one-eighth part of all oil produced and saved from the leased premises.

******

To pay to lessor as royalty for gas produced from any oil well and used by lessee for the manufacture of gasoline, one-eighth of the market value of such gas. If such gas is sold by lessee, then lessee agrees to pay lessor, as royalty, one-eighth of the net proceeds derived from the sale of said casinghead gas at the wells.

Id. at 870-71. The lease also required the lessee to

pay to lessor, as royalty for gas from each well where gas only is found, while the same is being sold or used off of the premises, one-eighth of the market price at the wells of the amount so sold or used.

Id. at 868. After pointing out that the lease demonstrated that the parties knew how to provide for royalties payable based upon market price or market value and royalties based upon the proceeds from the sale of gas, the court concluded:

It is clear then that the parties knew how to and did provide for royalties payable in kind, based upon market price or market value, and based upon the proceeds derived by the lessee from the sale of gas. They might have agreed that the royalty on gas produced from a gas well would be a fractional part of the amount realized by the lessee from its sale. Instead of doing so, however, they stipulated in plain terms that the lessee would pay one-eighth of the market price at the well of all gas sold or used off the premises. This clearly means the prevailing market price at the time of the sale or use. The gas which was marketed under the long-term contracts in this case was not “being sold” at the time the contracts were made but at the time of the delivery to the purchaser. See Martin v. Amis, Tex.Com.App., 288 S.W. 431, 433. We agree with the Court of Civil Appeals, therefore, that the contract price for which the gas was sold by the lessee is not necessarily the market price within the meaning of the lease. See Foster v. Atlantic Refining Co., 5th Cir., 329 F.2d 485; Wall v. United Gas Public Service Co., 178 La. 908, 152 So. 561.

Id. at 871.

Secondly, the court rejected the petitioner’s contention that there was no evidence to sustain the finding of market value based upon the expert testimony presented by the respondent. With respect to “market value,” the court noted that the parties agreed that the market price of gas “is to be determined by sales of gas comparable in time, quality and availability to marketing outlets.” Id. at 872. In this connection, the court further held:

We agree with the Court of Civil Appeals that the mathematical average of all prices paid in the field is not a final answer to the difficult problem of determining market price at any particular time. But see Wall v. United Gas Public Service Co., supra, and Arkansas Natural Gas Co. v. Sartor, 5th Cir., 78 F.2d 924. In this instance, however, both the witness and the trial court were required to fix a figure that would be used in determining the amount that should have been paid to the royalty owners over a period of four years. If the rate of production were constant, that figure would be the average market price for the period.

Id. at 873. Other holdings of Vela will be noted hereinafter.

Viewed from the standpoint of the economic relationship between the lessor and the lessee, the course of events in the industry has been highlighted by the following: (a) the waste of large quantities of gas associated with oil production because of a lack of a viable market for gas in the early years; (b) the development of a substantial local gas service, particularly to areas accessible to available production; (c) the adoption of the sale of gas under long-term contracts or for the “life of the lease”; (d) the development of massive markets for interstate gas following World War II; (e) federal control and regulation of almost all aspects of interstate transactions including price and contract provisions beginning with court decisions in 1954 and continuing thereafter; (f) the decision by the Supreme Court of Texas in 1968 in Vela; and (g) the development of the so-called “energy crunch” in .the early 1970’s which, along with the Arab oil embargo, more fully defined the significant difference between the “free” intrastate gas market and the “regulated” inter state market and which vastly enlarged the price differential between these markets.

THE LITIGATION

The predecessors in interest to Exxon Corporation (Exxon) secured three oil and gas leases from A. D. Middleton in 1933 and 1934 and one lease from members of the White family in 1935. Sun Oil Company of Delaware (Sun) obtained two oil and gas leases from A. D. Middleton and others in 1940 and 1941, one lease from R. M. White in 1933, one lease from Lilly Mae Hamilton and O. B. Hamilton in 1933, and two leases from Felix Jackson and others in 1933 and in 1938.

Three lawsuits involving those leases were filed in February 1974. Triphene Middleton, David Mayes Middleton, and John Gregg Middleton (the Middletons) are the successors in interest to A. D. Middleton. They brought the first suit, alleging a deficiency in the amount of royalties paid by lessees Exxon and Sun for the years 1973, 1974 and 1975.

Similar allegations were made against Exxon and Sun in the second lawsuit. The plaintiffs in that suit are Mattie E. Dunn, individually and as co-executrix of the estate of Ida White; Ida L. Hebert, individually and as co-éxecutrix of the estate of Ida White; Forest M. Dunn; Ann McGown, individually and as co-executrix of the estate of Ida White; Anna Lee Dunn Had-dox; Michael R. McGown; Patrick Wayne McGown; Mary Beth McGown Messina; G. B. Hamilton, Jr.; Monroe Hamilton; Scott Hamilton; Anna Edwards; and W. S. Edwards. The plaintiffs in the second lawsuit (the Whites) are all successors in interest to the leases executed by R. M. White, the Hamiltons, and other members of the White family in 1933 and in 1935.

Identical allegations were made against Sun in the third lawsuit. The plaintiffs in that suit (the Jacksons) are Ocie R. Jackson, individually and as the executor of the estate of Felix Jackson and as trustee under the will of Felix Jackson, as independent executor of the estate of Arthur A. Jackson and as trustee under the will of Arthur A. Jackson, and as trustee of the Arthur Lea Jackson Trust No. 2 and the Felix Heath Jackson Trust No. 2; American National Bank of Beaumont, trustee of the Felix Heath Jackson Trust No. 1; Arthur Lee Jackson; Mary L. Jackson; Arthur T. Jackson, individually and as trustee of the Dorothy Jackson Henderson McKee Trust; Reginald F. Jackson; Quentin L. Jackson; Mamie Jackson Bundara; Annie Jackson Sams; Gwendolyn Jackson Price; Emily Humphrey, individually and as independent executrix of the will of Pearl Jackson; Lillian Jackson; Roscoe Jackson; Milton White; Robert White; Furl White; Clifford White; H. Robert Smith, Jr.; Theresa Smith; Owen Jackson; and Warren 0. Jackson. Exxon is not a party to the third lawsuit.

The three original lawsuits were consolidated into a single suit, which was tried to the court in January 1977. The court rendered judgment for the Middleton plaintiffs against Exxon in the amount of $1,027,-299.00 as additional royalties on gas for the years 1973, 1974 and 1975, and $132,333.00 as prejudgment interest. The Middletons were granted judgment against Sun in the amount of $67,711.00 as additional royalties for the period from April 1,1974 to December 31, 1975, and $6,585.00 as prejudgment interest. The court granted judgment for the Whites against Exxon in the amount of $179,611.00 as additional royalties for the years 1973,1974 and 1975, and $28,322.00 as prejudgment interest. The Whites were granted judgment against Sun in the amount of $155,701.00 as additional royalties for the period from April 1, 1974 to December 31, 1975, and $15,551.00 as prejudgment interest. The Jacksons were granted judgment against Sun in the amount of $799,675.00 as additional royalties from April 1, 1974 until December 31, 1975, and prejudgment interest in the amount of $82,079.00. The appellants Exxon and Sun appealed the trial court’s judgment in the consolidated action. The Mid-dletons, Whites and Jacksons, all appellees herein, filed a limited appeal to two portions of the judgment. We shall discuss each appeal separately.

EXXON’S APPEAL

The leases in effect between the Middle-tons and Exxon and between the Whites and Exxon are located in what is known as the Anahuac Field in Chambers County, Texas. Some of the natural gas produced in 1973,1974 and 1975 from wells located on the appellees’ leases was processed at Exxon’s Anahuac Gas Plant, which is not located on the premises of any of the appellees’ leases. The processed gas was delivered by Exxon at the tailgate 1 of its Anahuac Gas Plant to the City of Anahuac, the Houston Pipeline Company, and the Exxon Gas System.

The gas sales contract between the City of Anahuac and Exxon did not contain a specific dedication of reserves by Exxon to the performance of that contract. The contract did provide that the price paid by the City of Anahuac for the gas would be Exxon’s “field price” plus certain tax reim bursements. In order to compute its field price, Exxon reviews Purchaser’s Monthly Gas Reports (PMG Reports) 2 filed by twenty-six major pipeline purchasers in a marketing area consisting of Texas Railroad Commission (TRC) District 3 and seven adjoining counties. Exxon divides the total price reported as paid for one month in each quarter of the year for the gas currently delivered to those major purchasers in the marketing area by the total volume of the gas delivered. The quotient, according to Exxon, is the volume weighted average price for most of the gas sold in the marketing area approximately two to three months before the time for which Exxon is attempting to set its field price. From that volume weighted average price, Exxon makes projections of what the current volume weighted price is. The projected current volume weighted price is Exxon’s field price. The royalties that Exxon paid the appellees for gas sold to the City of Anah-uac were calculated by Exxon on the basis of the proceeds received by Exxon from the sale of that gas at the field price.

Exxon’s gas sales contract with the Houston Pipeline Company contained a dedication of gas reserves by Exxon to the performance of that contract. Exxon calculated and paid royalties for gas sold to the Houston Pipeline Company on the basis of the proceeds of that sale.

During 1973, 1974 and 1975, some of the gas produced on the appellees’ leases was processed by Exxon and delivered to the Exxon Gas System at the tailgate of Exxon’s Anahuac Gas Plant. The Exxon Gas System is an intrastate marketing system owned by Exxon. Gas delivered to the System is marketed to fifteen industrial customers pursuant to written contracts with those customers. None of the fifteen contracts dedicates specific gas reserves from specific gas fields connected to the System. The gas produced from the appel-lees’ leases and delivered to the System was sold to Exxon’s “east end customers,” which are Gulf States Utilities Company, E. I. Du Pont De Nemours and Company, and Nech-es Butane Products Company. The Exxon Gas System delivered gas to each east end customer at the customer’s “plant gate.” The royalties paid by Exxon on gas sold to the System’s east end customers were calculated on the basis of Exxon’s field price.

Exxon has assigned twenty-seven points of error. In its first six points of error, Exxon alleges that the trial court misinterpreted the gas royalty clause contained in Exxon’s leases with the predecessors in interest to the Middletons and Whites. The gas royalty clause contained in those leases provides that royalties

on gas, including casinghead gas or other gaseous substances, produced from said land and sold or used off the premises or in the manufacture of gasoline or other product therefrom, [shall be] the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalties shall be one-eighth of the amount realized from such sale .

The trial court construed the word “sold” to mean the delivery of gas to a purchaser under a gas purchase contract. The court therefore held that, in order to calculate royalties under the gas royalty clause, the market value of the gas is to be determined at the time of delivery as if the gas were available for new contract commitments.

Exxon contends that the interpretation given the clause by the trial court was erroneous because the evidence was legally and factually insufficient to support that interpretation. Exxon claims that the only way that gas could be sold before 1972 was pursuant to long-term contracts which contained built-in price adjustment mechanisms. Exxon maintains that the parties understood that natural gas could not be sold on a daily basis, and that any assumption to the contrary would be illogical and unreasonable. Exxon argues, therefore, that natural gas is not “sold” each time a specific volume of that gas is delivered, but, rather, is “sold” when the contract specifying the terms and conditions of the delivery of the gas is executed.

In considering Exxon’s legal sufficiency points, we must review the evidence in the light most favorable to the court’s judgment, considering only the evidence and inferences which support the judgment and rejecting the evidence and inferences contrary thereto. Rourke v. Garza, 530 S.W.2d 794, 799 (Tex.Sup.1975). In considering Exxon’s factual insufficiency points, we must review all of the evidence, and we may set the judgment aside only if it is so contrary to the overwhelming weight of all of the evidence as to be clearly wrong or manifestly unjust. In re King’s Estate, 150 Tex. 662, 244 S.W.2d 660, 661 (1951).

After applying both standards of review, we conclude that the trial court interpreted the gas royalty clause correctly. We recognize, as a practical matter, that natural gas must be sold “under long-term contracts because the pipelines must have a committed source of supply sufficient to justify financing, construction, and operation.” Foster v. Atlantic Refining Company, 329 F.2d 485, 488 (5th Cir. 1964) (footnote omitted). The gas royalty clause in the leases between Exxon and the appellees is very similar, however, to the one that was construed by the Texas Supreme Court in Vela. In the present case, the gas royalty clause provides that a royalty equal to one-eighth of the market value at the wells will be paid on gas produced on the appel-lees’ lands and “sold or used off of the premises”; in Vela, the gas royalty clause provided that a royalty equal to one-eighth of the market price at the wells would be paid on gas produced on the lessor’s land “while the same is being sold or used off of the premises . . . Vela, supra at 868 (emphasis added). The supreme court held in Vela that the gas royalty clause obligated the lessee to calculate royalties on the basis of the prevailing market price at the time of the sale or use of the gas. The court construed the words “being sold” in the gas royalty clause to mean the time of the delivery of the gas to purchasers, and not the time at which the contracts for sale of the gas to purchasers were executed. Id. at 871.

The supreme court’s construction of the words “being sold” in Vela is controlling in this case. Just as gas was “being sold” in Vela when it was delivered to purchasers, so was gas in the present case “sold” when it was delivered by Exxon at the tailgate of its Anahuac Gas Plant to the City of Anah-uac, the Houston Pipeline Company, and the Exxon Gas System. The trial court did not err, therefore, in holding that Exxon was required to pay royalty on gas produced on the appellees’ lands equal to one-eighth of the market value of the gas at the time the gas was delivered, and not the market value when Exxon executed long-term contracts for the sale of that gas. Accord, Foster v. Atlantic Refining Company, supra at 489 (interpreting Texas law); Martin v. Amis, 288 S.W. 431, 433 (Tex.Com.App.1926, jdgmt. adopted); Butler v. Exxon Corp., 559 S.W.2d 410, 416 (Tex.Civ.App. — El Paso 1977, writ ref’d n. r. e.).

Exxon asserts, in point twelve and other related points, that the trial court erred in adopting the method for determining the market value of natural gas that was used by the appellees’ expert witness, William S. Hudson. Hudson was shown to be an eminently qualified expert witness. Most of the recitations of this opinion concerning the history and practices of the oil and gas industry, as related to the production and marketing of natural gas, are based on his testimony. Hudson did not limit his consideration of sales to the Anahuac Field. He took as the comparable marketing area for his calculation TRC Districts 2, 3 and 4. These districts comprise a very large part of the gas-producing area of South Texas, ranging from Kleburg County through the Gulf Coast and into East Texas. Hudson obtained PMG Reports from the State Comptroller’s Office. He reviewed more than 30,000 gas sales transactions that were described in the reports in order to determine prices paid for gas in each transaction. He calculated the market value of gas produced from the appellees’ leases during 1973,1974 and 1975 by averaging the three highest prices paid per million b. t. u.’s of gas in TRC Districts 2, 3 and 4 during the first month of each quarter of those years. Hudson did not consider in his calculations any sales in which the seller was a transmission company or an affiliate of the purchaser, nor did he consider any sales if the same or similar purchase price did not appear in the PMG Reports for Districts 2, 3 and 4 in the following quarter. In forming his opinion of market value of the gas, Hudson did not take into consideration the price at which gas was in fact sold and the circumstances surrounding the contract for the sale of that gas, nor did he consider the price and circumstances of sales of gas that were comparable in time, quality, quantity and availability of outlets. His opinion of value, which was adopted by the trial court, was based on a determination of the three highest prices in Districts 2, 3 and 4 and on the assumption that the gas was free for sale each quarter. He did not compute the average price of all new gas sales; he computed the average of only the three highest such sales, regardless of volume, quality and availability of marketing outlets.

We agree with Hudson’s exclusion of sales by gas transmission companies because the sale prices often include large transmission charges. Furthermore, Hudson correctly declined to consider sales in which the seller was an affiliate of the purchaser because he felt that such sales might not be arm’s-length transactions. It would be manifestly unjust for a lessee to sell gas to a subsidiary or to an affiliated firm, person or corporation for a low price and allow that company to extract a larger price in the resale of such product. To allow a lessee to pay royalty out of a shallow pocket while receiving proceeds in a deep pocket would be intolerable.

The basic question presented is whether Hudson’s testimony meets the test of market value enunciated in Vela. An analysis of the Vela standards for legal determination of “market price” or “market value” of gas should begin with the opinion of the San Antonio Court of Civil Appeals in that case. Texas Oil & Gas Corporation v. Vela, 405 S.W.2d 68 (Tex.Civ.App. — San Antonio 1966), rev’d, 429 S.W.2d 866 (Tex.Sup.1968). In that case, the appellants took the position that there was no evidence to sustain the trial court’s finding of a market price of 16.047 cents per million cubic feet (mcf) and that such finding was against the great weight and preponderance of the evidence. The appellants also complained of the admission of testimony regarding prices paid under other gas contracts in the Lopeno Field. When gas was first discovered on the lease, there was no pipeline into the field. Nordan & Morris entered into a contract with United giving that company the exclusive right to purchase, on a ratable basis, all gas produced from the lands of the lessors in the Lopeno Field for the life of the lease. The contract price was 3.5$ per mcf, which was reduced to 2.3 ± with the adoption of the Standard Gas Measurement Law, Tex. Laws 1949, ch. 519. Nordan & Morris thereafter entered into several similar gas purchase contracts with various lease owners and operators in that field. Although neither the supreme court nor the court of civil appeals placed particular emphasis upon this fact, it appears from the opinion that the rights of the buyer had ultimately been transferred to a wholly owned subsidiary of the appellant Texas Oil & Gas Corporation. This fact is significant to this court in light of the obvious injustice of allowing payment of royalties based upon a contract with an affiliated company for a low price and the subsequent receipt by the affiliate of a higher price upon the resale of the gas. As a matter of fact, the record in Vela revealed that the subsidiary company would not disclose the ultimate proceeds actually obtained from the sale of Vela gas. For many years, production from the field was sold to the only pipeline serving it. This was the one constructed by United. In 1960, following the discovery of Wilcox production (previous production had been only from the Queen City sands), Tennessee Gas started taking pipeline deliveries of gas. In 1962, Alamo Gas commenced taking deliveries through a line that it had constructed. These contracts provided for prices ranging from 13$ to 17.24$ per mcf. The Tennessee contracts were under Federal Power Commission regulation, and the Alamo contract involved a long-term contract with the City of San Antonio. At that point in time, according to testimony presented in the case presently under consideration, the effect of government interference had not yet fully impacted the industry so as to create the wide disparity which later developed following the Arab oil embargo and the so-called “energy crunch.”

The court concluded that there was no prior Texas case setting forth the proper rule for determination of “market price” of gas sold under a long-term contract. The court found no help in Foster v. Atlantic Refining Company, supra, for the reason that the evidence of market price was not controverted in that case. In considering the question presented, the court said:

It is elemental contract law that since the lessor is not a party to the gas purchase contract entered into between lessee and a third party, he is not bound by the terms of same, if they are in conflict with lessee’s obligations under the lease. However, we must not overlook the fact that gas is only sold under long-term contracts, and that a reasonably prudent operator, in the exercise of good faith, might be required to enter into such a contract. Le Cuno Oil Co. v. Smith, Tex.Civ.App., 306 S.W.2d 190, wr. ref. n. r. e.; Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas, S.W. Legal Foundation, Fourth Institute on Oil & Gas, 181-191.

In our opinion the proper rule is that the price paid under a gas purchase contract entered into between lessee and a third party is not necessarily the “market price” as provided for in the lease. However, this price, together with the circumstances of such contract, should be considered along with evidence of comparable sales to determine the market price.

The trial court found that the Nordan & Morris gas purchase contracts were entered into in good faith and there was no other market for the gas during the early years, of the Lopeno Field. In 1957 the Fifth Circuit Court of Appeals upheld the validity of one of these contracts in a suit between the assignee of the Seller and the Buyer under such a contract. See Standard Oil Co. of Texas v. Lopeno Gas Co., 5 Cir., 240 F.2d 504. Appellees Vela were not parties to the Nordan & Morris gas purchase contracts. Further, they did not execute a division order authorizing payment in accordance with the contract price. Cf. Phillips Petroleum Co. v. Williams, 5 Cir., 158 F.2d 723; Summers, Oil & Gas, § 589.

Under the undisputed evidence, the 1935 contract price is substantially below the price being paid for gas during the years in controversy. The Alamo and Tennessee contracts executed in 1959-1962, called for a price from 13$ to 17.24$ per mcf. Appellants’ witness Faucett, an officer of the corporation owning the Alamo line, testified that most contracts during this period called for a price of 12$ per mcf, less compression costs. The president of appellant Texas Oil & Gas Corporation admitted that, unless the contract price controlled, the market price of the Vela gas was 8$ per mfc. There is no evidence that appellants were bound to sell the Vela gas for the price asserted in the purchase contracts. The trial court did not err in entering judgment for a price in excess of the contract price under the record in this case.

All parties agree that comparable sales of gas are those comparable in time, quantity, quality, and availability of marketing outlets. Phillips Petroleum Co. v. Bynum, supra [5th Cir., 155 F.2d 196]. The disagreement on this appeal is whether the appellees offered sufficient evidence within this test.

Appellees’ case is based upon the testimony of their expert witness, Jack K. Baumel, whose testimony covers some 200 pages in the statement of facts. Baumel is a consultant petroleum and natural gas engineer and was formerly senior engi neer of the Oil & Gas division of the Railroad Commission of Texas. He testified that he had been familiar with the Lopeno Field for many years. He had been on a retainer for a subsidiary corporation which gathered gas for the Alamo line and, in fact, testified in its behalf at a hearing before the Railroad Commission in 1963 when the Queen City sand was divided into two reservoirs. In preparation for testifying in this ease, he made a study based on production of gas and sales from the Upper Queen City sand, the 2700-foot sand, and the Wilcox sand in the Lopeno Field. This study was largely based upon the State Comptroller’s records of sales.

Mr. Baumel determined the amounts of gas sold from each well in the Lopeno Field during the pertinent period, and the value received for same. By division of these sums, he arrived at an “average price” received for all gas sold during this period and testified this was the “market price.” In arriving at this “average price,” he disregarded all gas sold under the Nordan & Morris Gas Purchase Contracts, because he said they were too far out of line. The prices on the twelve wells he considered ranged from 13<p to 17.24$ per mcf, and the average price was 16.047$ per mfc. Since the gas from the Upper Queen City sand was of low pressure, he deducted a compression charge of 3$ per mcf, and testified that 13.047$ per mcf was the market price of the Vela gas.

405 S.W.2d at 74-75.

Following its announcement of the legal principles involved, the court of civil appeals considered the evidence in the case and concluded that Baumel’s testimony adequately supported the trial court’s findings of market value. Significantly, the court stated:

The record shows that appellants’ gas is committed to a contract with Central Power & Light Co., at Laredo, and the terms of this contract with appellants’ subsidiary corporation were not introduced in evidence.

Id. at 75. The court further stated:

The “average price” method used by Baumel in determining “market price” can not be the final answer to the difficult problem of determining market price of gas despite its simple application. For example, in this field it would lead to the result that none of the lessees of the twelve wells considered by Baumel are paying the market price. Royalty from all but three is in excess of this price. Further, if the technique of disregarding the prices paid under the contract then under consideration is followed, this would result in a different “average price” for each contract in the field. However, Baumel’s average price of 13.-047$ was corroborated, in that sales from two Upper Queen City wells were based on prices of 14.078$ and 13.00$. It was his testimony that these prices were net and included all gathering and compression charges.

Id. (footnote omitted).

From the opinion of the court of civil appeals in Vela, we draw the following conclusions with respect to factors which should be taken into account in determining the market value of gas: (1) the relevant marketing area is the field in which the gas is produced; (2) consideration must be given to the fact that a reasonably prudent operator, in exercise of good faith, may be required to enter into a long-term contract (however, such gas purchase contract between lessee and a third party is not necessarily the “market price” as provided for in the lease; such contract price and the circumstances thereof should be considered along with evidence of comparable sales to determine market price); (3) the comparable sales to be considered are those comparable in time, quantity, quality and availability of marketing outlets; and (4) the “average price” method is not conclusive of market price but is more than a scintilla of evidence which, along with corroboration of comparable sales from the field, will support a trier of fact’s finding as to market value.

The supreme court began its analysis of the market value question in Vela with the following observations:

As indicated above, the trial court found that the market price of the gas during the four-year period was 13.047$ per mcf. This finding, if it has any support in the evidence, must rest upon the testimony of Mr. Jack K. Baumel. Our statement concerning the witness and his testimony is taken largely from the opinion of the Court of Civil Appeals. Baumel is a consultant petroleum and natural gas engineer who had been employed by the Railroad Commission of Texas and by other governmental agencies. He had been familiar with the Lopeno Field . for many years, and before testifying in this case he made a study of production and sales of gas from the field. The records of sales in the office of the Comptroller of Public Accounts were the principal source of his information, but he also considered the gas sales contracts made by the various producers in the field.

Mr. Baumel ascertained the amounts of gas sold from each well in the field during the four-year period and the amount received for the same. This included production from the Upper Queen City sand, the 2,700-foot Queen City sand, and the Wilcox sand. By mathematical calculation he determined that the average price received for all gas sold during the period, except that marketed under the Nor-dan & Morris contracts, was 16.047$ per mcf. He stated that the amounts received pursuant to the Nordan & Morris contracts were disregarded because such contracts were too far out of line. Since the gas from the Upper Queen City sand was of low pressure, he deducted a compression charge of 3$ per mcf from the average price, and testified that 13.047$ per mcf was the market price of the Vela gas.

The parties agree that the market price of gas is to be determined by sales of gas comparable in time, quality and availability to marketing outlets.

429 S.W.2d at 871-72.

Further, in connection with the evaluation question, the supreme court held:

We agree with the Court of Civil Appeals that the mathematical average of all prices paid in the field is not a final answer to the difficult problem of determining market price at any particular time. But see Wall v. United Gas Public Service Co., supra, and Arkansas Natural Gas Co. v. Sartor, 5th Cir., 78 F.2d 924. In this instance, however, both the witness and the trial court were required to fix a figure that would be used in determining the amount that should have been paid to the royalty owners over a period of four years. If the rate of production were constant, that figure would be the average market price for the period. Baumel’s conclusion as to the market price of the gas in question is corroborated, moreover, by the sales of Queen City gas under amendments to the existing contracts. As for respondents’ contention that there is no demand for Queen City gas at the price found by the trial court, it does not appear that any well in the field is shut in for lack of a market. In these circumstances and where purchasers have amended their contracts to cover additional Queen City wells at equal or greater prices, it may fairly be inferred that there was a demand for the Vela gas at 13.047$ per mcf.

Respondents rely upon Phillips Petroleum Co. v. Bynum, supra; Arkansas Natural Gas Co. v. Sartor, supra; Shamrock Oil & Gas Corp. v. Coffee, 5th Cir., 140 F.2d 409; and Sartor v. United Gas Public Service Co., 186 La. 555, 173 So. 103. These cases are to be distinguished on the facts. The gas involved in Bynum was used for the extraction of gasoline and other products. There was no market for the same from companies which dealt in gas for heating and fuel, and it was held that the amounts paid by such companies was not competent evidence of market price. Certain contracts were held inadmissible in Arkansas Natural Gas, because the undisputed testimony showed that the guaranty to deliver large quantities of gas from another field constituted part of the consideration for the price paid and there was no evidence that would enable the jury to determine what this amounted to. The court went on to say, however, that:

“It is also apparent that the stipulation as to average prices paid under contracts substantially similar to the lease in suit was improperly excluded. The same is true in respect to the testimony of Har-grove wherein his opinion as to the established market price at the well and the prices paid in other sales, under substantially similar conditions, was sought to be elicited.”

In Coffee it was held that market price is to be determined by comparable sales and not by the opinions of witnesses as to what the purchasers could or should have paid. The contracts introduced in United Gas Public Service imposed obligations upon the producers so different from those assumed by the plaintiffs that the court concluded the same did not constitute evidence as to the market price of the plaintiffs’ gas. Here the record shows the prices paid by other purchasers in comparable sales, and in our opinion the evidence supports the finding of the trial court as to market price.

429 S.W.2d at 873-74.

In determining the market price of gas, we conclude from the supreme court’s holding in Vela that: (1) the relevant marketing area is the field in which the gas was produced; (2) the market price of gas is to be determined by reference to sales of gas comparable in time, quality and availability to marketing outlets; (3) the mathematical average of all prices paid in the field is not a final answer to determining market value price at any particular time; (4) the relevant period of time to be used in determining the amount that should have been paid to the royalty owners is the specific period in question; and (5) an expert’s opinion based upon a mathematical average of prices paid in the field and corroborated by comparable sales from the field during the relevant period may afford a basis for determining market price.

We hold that the method adopted in this case does not meet the requirements outlined by the supreme court in Vela. Hudson did not define the relevant market area as the Anahuac Field. He refused to give weight to any contracts for sale of gas from this field. The sales that he considered were not shown to be comparable in time, quality and availability to marketing outlets. He selected only the highest prices paid in TRC Districts 2, 3 and 4 that satisfied his criteria. He made no mathematical average of all prices paid in the field, nor did he seek to corroborate such an average with comparable sales as defined by the supreme court. His consideration of price data compiled on a quarterly, rather than monthly, basis is inconsistent with the time period at issue in the case. We therefore sustain Exxon’s points and order the case reversed and remanded as to Exxon.

We overrule Exxon’s contention that its “field price” is the appropriate measure of the market value of the gas produced from appellees’ leases in 1973, 1974 and 1975. Exxon’s field price is computed, in part, on the basis of sales of gas in interstate commerce. The price of gas sold in interstate commerce during 1973, 1974 and 1975 was regulated by the Federal Power Commission. 3 See United Gas Improve. Co. v. Callery Properties, Inc., 382 U.S. 223, 227, 86 S.Ct. 360, 363, 15 L.Ed.2d 284 (1965). Frederick M. Perkins, Exxon’s vice-president for production, testified that the price set by the FPC on gas sold in interstate markets was lower than the price the gas would bring if sold in intrastate markets in Texas. The parties have stipulated that, at all times material to this dispute, all of the gas produced from wells located on the appellees’ leases was sold in intrastate markets in Texas. Exxon’s field price, therefore, is based on sales of gas that are not comparable to sales of gas produced from wells located on the appel-lees’ leases, and may not be an accurate reflection of the market value of that gas.

Even Exxon recognizes that its field price does not always represent the market value of gas. Perkins testified that if gas from the appellees’ leases delivered to the Exxon Gas System were uncommitted, 4 it could have sold for a price that was higher than Exxon’s field price. Indeed, Exxon does not compute royalties payable for gas produced from new reservoirs discovered by drilling after January 1, 1972 in new or old fields and connected to the Exxon Gas System in the same manner in which it computes royalties payable on gas produced at the same time from old reservoirs discovered before that date. Instead, Exxon computes market value for royalty purposes on gas from reservoirs discovered after that date, which Exxon refers to as “new vintage gas,” by a method that is similar in many respects to that which was used by Hudson to determine market value of gas produced from the appellees’ leases. Exxon determines the market value for new vintage gas by computing the arithmetic average of the three highest prices paid by a pipeline in sales of more than one million cubic feet of gas per day in TRC Districts 1 through 6, adjusted to reflect the heating capacity of that gas. Our holding that this gas is sold when delivered obviates Exxon’s assertion that there can be one market value for gas produced from wells which were discovered before January 1, 1972, and another market value for gas produced from wells discovered after that date.

Exxon contends, in point of error nineteen, that the trial court erred in holding that certain division orders executed by the Middletons and the Whites and delivered to Exxon did not modify Exxon’s obligation to pay royalties in accordance with the gas royalty clause provisions of their lease agreements. The division orders referred to by Exxon provide that it will pay royalties on the basis of the market value at the wells of gas sold or used off the appel-lees’ leases. The division orders do not vary Exxon’s obligation under the gas royalty clause of the lease agreements, and the trial court did not err, therefore, in so holding.

By reason of our holdings as above set forth, we find it unnecessary to reach Exxon’s other points of error, and we will fore-go any discussion of them.

SUN’S APPEAL

A portion of the natural gas produced during 1973,1974 and 1975 from wells located on the lands leased by the appellees to Sun was gathered and processed off those lands at the Union Texas Petroleum (UTP) Winnie Plant under a gas processing agreement between Sun and UTP’s predecessor. The gas was sold by Sun to Pan American Gas Company and its successor Amoco Gas Company, at the tailgate of the Winnie Plant. Sun calculated and paid royalty to the appellees on the basis of the proceeds that Sun received from those sales.

Gas produced during 1973, 1974 and 1975 from wells on land leased by R. M. White to Sun was sold by Sun to Exxon and Houston Pipeline Company. Sun delivered that gas to its purchasers on the lease premises, but not at the mouth of any well on the lease. The gas was transported from the premises by those purchasers before being resold or used. Sun calculated and paid royalties to the Whites on the basis of the proceeds Sun received from the sale of the gas.

The gas royalty clause contained in the leases between the appellees and Sun provided that Sun would pay,

on gas, including casinghead gas or other gaseous substances, produced from said land and sold or used off the premises, or used in the manufacture of gasoline or other products therefrom, by lessee, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at wells, the royalty shall be one-eighth of the amount realized from such sales.

The trial court found that gas produced from wells located on land leased by R. M. White to Sun was sold “at the wells.” The court therefore held that Sun was obligated to pay royalties equal only to one-eighth of the amount realized from those sales. The court found, in contrast, that gas produced by Sun from wells located on other lands leased by the appellees to Sun was sold “off the premises.” The court held that the appellees are entitled to a judgment against Sun for the difference between the royalties paid by Sun on the basis of the proceeds from the sales and the royalties that Sun should have paid on the basis of market value of the gas.

Sun has assigned twenty-four points of error. For purposes of this appeal, we need consider only points nine through thirteen. Sun contends, in those points, that the trial court erred in holding that certain division orders did not modify Sun’s royalty obligations. The appellees have stipulated that they are all signatories to, or successors in interest to signatories to, division orders executed and delivered to Sun in 1952. The division order executed by R. M. Middleton and delivered to Sun stated, in pertinent part:

You are hereby authorized to make payment for all royalties payable on gas produced and saved from said lease or unit on and after said effective date hereof in accordance with the foregoing Division of Interest and the following provisions, and the undersigned agree to accept payments so made in full payment of the royalties due them respectively:

* * * * * *

2. The royalties payable to the undersigned on gas produced and saved from said lease or unit shall be computed on the value of the quantities marketed . such value to be determined as follows:

* * * * * *

B. The value of gas processed in a plant . . . shall be the sum of (1) the proceeds derived from sale of such liquids, . . . plus (2) the proceeds derived from the sale of residue gas

******

6. . Each transfer, assignment or conveyance of any part or all of the interest of any undersigned party shall be made subject to this division order. .

******

7. This division order is directed to you as the operator of said lease or unit, and shall be binding upon and inure to the benefit of your successors as such operator, in behalf of all present or future owners of working interest in said lease or unit. This division order shall remain in force during the life of the respective lease(s) under which payment is due the undersigned and shall be binding upon each undersigned party and his heirs, legal representatives, successors and assigns. .

The other division orders executed by the appellees and delivered to Sun contained provisions that were either identical to or very similar to those contained in the division order that was executed by R. M. Middleton. The trial court held that the division orders were supported by consideration until March 30, 1974 but were unsupported by consideration after that date. The court also held that the division orders were subject to revocation by the appellees and were revoked by implication when the appellees served Sun with copies of their pleadings on March 30, 1974.

The written division orders executed by the appellees and delivered to Sun gave rise to a contractual relationship between the appellees and Sun. Chicago Corporation v. Wall, 156 Tex. 217, 293 S.W.2d 844, 846 (Tex.Sup.1956); Shell Oil Company v. State, 442 S.W.2d 457, 460 (Tex.Civ.App. —Houston [14th Dist.] 1969, writ ref d n. r. e.). There is a statutory presumption that all written contracts are supported by consideration. Unthank v. Rippstein, 386 S.W.2d 134, 137-38 (Tex.Sup.1964); Maykus v. Texas Bank & Trust Co. of Dallas, 550 S.W.2d 396, 398 (Tex.Civ.App. — Dallas 1977, no writ); Waters v. Waters, 498 S.W.2d 236, 241 (Tex.Civ.App. — Tyler 1973, writ ref’d n. r. e.); Tex.Rev.Civ.Stat.Ann. art. 27 (1969). The burden was therefore on the appellees to prove that the division orders were unsupported by consideration. Tex.R.Civ.P. 94.

Not only did the appellees fail to prove a lack of consideration, but the division orders imposed upon Sun the obligation to do certain things which Sun had not previously been bound to do. For example, the division orders obligated Sun to keep charts and records available for the appel-lees’ inspection at all reasonable times through the end of the calendar year following the calendar year in which the charts and records were obtained. The trial court correctly held, therefore, that the division orders were supported by consideration prior to March 30, 1974. Just as the appellees failed to prove a lack of consideration prior to March 30,1974, so did they fail to prove a lack of consideration after that date. The division orders were, and continue to be, valid written agreements modifying the gas royalty clause contained in Sun’s leases with the appellees. The trial court erred in finding that the division orders were unsupported by consideration after March 30, 1974. We therefore sustain Sun’s points of error eleven, twelve and thirteen.

The trial court also erred in holding that the division orders could be, and were, unilaterally revoked by the appellees. The division orders constituted binding written contracts. The orders stated that they would “remain in force during the life of the respective lease(s) . . . .” Although the parties could have rescinded the division orders by mutual agreement, the appellees were not entitled to revoke or rescind the orders unilaterally. Texas Gas Utilities Company v. Barrett, 460 S.W.2d 409, 414-15 (Tex.Sup.1970).

We acknowledge that it has sometimes been said that division orders are binding until revoked. E. g., J. M. Huber Corporation v. Denman, 367 F.2d 104, 110 (5th Cir.1966). Contra, Butler v. Exxon Corp., 559 S.W.2d 410, 416-17 (Tex.Civ.App. —El Paso 1977, writ ref’d n. r. e.). In this case, the trial court found that the division orders were revoked by the institution of this suit, despite continued acceptance of payment by the lessors of the royalties calculated in accordance with the division orders during the pendency of the suit. However, unlike the case at issue, the Butler case and others involved routine division orders without the consideration we have found here. We should not be understood as holding that the execution of division orders would prevent relief from fraud, accident or mistake or preclude the correction of mathematical calculations. Nor do we in any way indicate that relief could not be obtained from unusual or unfair provisions imposed by a party having a superior bargaining power or position. See Blaffer v. Powers, 169 S.W.2d 536, 540-41 (Tex.Civ.App. — Galveston 1943, writ ref’d w. o. m.).

We sustain Sun’s points of error nine and ten.

APPELLEES’ CROSS POINTS

The appellees have assigned two cross points. They contend, firstly, that the trial court erred in finding that gas produced from the appellees’ leases and sold at Exxon’s Anahuac Gas Plant was “sold at the wells.” The appellees assert, rather, that the gas was “sold or used off the premises.” The trial court found that the Anahuac Gas Plant was not located on the premises of any of the appellees’ leases. The court also found that sales by Exxon to the City of Anahuac and the Houston Pipeline Company were made at the tailgate of the Anahuac Gas Plant. The court’s finding that the gas was sold at the tailgate of the Anahuac Gas Plant is inconsistent with, and better supported by the evidence than, the finding that the gas was “sold at the wells.” We therefore sustain the appellees’ first cross point.

The appellees assert, in their second cross point, that the division orders they executed and delivered to Sun did not modify Sun’s duty to pay royalties based upon the market value of gas produced from wells located on their leases. We reject this contention for reasons previously stated in our discussion of Sun’s appeal.

JUDGMENT

That portion of the judgment holding that Exxon is not obligated to pay royalties based on the market value of gas produced from the appellees’ lands and sold at the tailgate of the Anahuac Gas Plant is reversed and remanded for the trial court to determine and award to the Middletons and the Whites the difference between the royalties paid by Exxon and the market value at the wells of one-eighth of the gas so sold.

The judgment against Exxon is reversed and remanded for trial in accordance herewith. The judgment against Sun is reversed and rendered that the appellees take nothing in their actions against Sun.

1 . Gas delivered at the tailgate of a processing plant, also known as “tailgate gas,” is gas from which the processing plant has removed all liquid hydrocarbons and impurities.

2 . A PMG Report, which is also known as a Form 60-150, is a form that is filed with the State Comptroller for severance tax purposes.

3 . We do not believe that the Texas courts will apply the principles of Vela to federally controlled or regulated interstate gas, since there can be no “market value” or “market price” in a price-regulated environment, although we recognize that the supreme court did permit the consideration in Vela of the price of regulated gas sold to Tennessee Gas from the Lope-no Field. We also note that in 1977, FPC functions were transferred to the new Federal Energy Regulatory Commission, and the FPC was terminated. Department of Energy Organization Act, 42 U.S.C.A. §§ 7171, 7172, 7293 (Supp.1977).

4 . We express no opinion regarding whether gas delivered to the Exxon Gas System was, in fact, committed.