Piney Woods Country Life Sch. v. Shell Oil Co., 539 F. Supp. 957 (S.D. Miss. 1982)
May 3, 1982
v.
SHELL OIL COMPANY, Defendant.
United States District Court, S. D. Mississippi, Jackson Division.
*958 *959 Ernest G. Taylor, Jr., Watkins, Pyle, Ludlam, Winter & Stennis, Kenneth I. Franks, George F. Woodliff, III, Heidelberg, Woodliff & Franks, L. Arnold Pyle, Barnett, Alagia & Pyle, Jackson, Miss., for plaintiffs.
W. F. Goodman, Jr., Paul Stephenson, Watkins & Eager, Jackson, Miss., Alvin B. Gibson, New Orleans, La., William Simon, Keith E. Pugh, Jr., James Robert Fox, Washington, D. C., for defendant.
OPINION
DAN M. RUSSELL, Jr., Chief Judge.
Piney Woods Country Life School, Ridgway Management, Inc. and other named plaintiffs brought the instant action, individually *960 and on behalf of a putative class[1] designated as all royalty owners in the Thomasville, Piney Woods and Southwest Piney Woods Fields, and other contiguous fields located in Rankin County, Mississippi, whose natural gas is being, has been and/or will be processed through Shell Oil Company's Thomasville Plant Facility. By their complaint, Plaintiffs challenge the propriety of royalty payments made by Defendant, Shell Oil Company (hereinafter referred to as "Shell"), on natural gas produced from five units[2] in the Thomasville, Piney Woods, and Southwest Piney Woods Fields. Specifically, Plaintiffs allege that: (1) Shell has, and is, improperly charging royalty owners for processing their share of the production from the subject fields at its Thomasville Plant; (2) Shell breached its duty under express and implied covenants to market by its alleged failure to obtain the highest and best price for gas sold to its primary purchaser; and finally, that, (3) Shell's method of calculating royalty payments on the basis of proceeds received from the sale of the natural subject gas rather than its "market value" is in violation of certain of the lease agreements. As relief, Plaintiffs request this Court to order Shell to pay to each of the named plaintiffs and to each class member their respective share of royalty computed on "market value" of the subject gas without deductions for expenses or charges incurred in processing or transporting.
Plaintiffs also allege that Shell violated the Sherman Act, 15 U.S.C. Sections 1 and 2, by an alleged illegal restraint of trade and commerce in the production, processing and sale of sour gas, sweet gas and sulphur, and by an alleged monopolization of the production, processing and sale of sour gas, sweet gas and sulphur in the geographic area consisting of the Thomasville, Piney Woods and Southwest Piney Woods Fields. On Defendant's Motion for Summary Judgment pursuant to F.R.Civ.P. Rule 56(c), this Court previously considered and disposed of Plaintiffs' antitrust claims, excepting from its finding Plaintiffs' claim under Section 1 of the Sherman Act which relates to Shell's alleged restraint of trade in its interstate sales of sulphur. As stated in its Opinion of December 3, 1976, the Court found that a genuine issue of material fact existed regarding the determination of the relevant market for sulphur sales and that further development of proof on this issue was appropriate. At trial, Plaintiffs offered evidence of Shell's allegedly monopolistic practices for the purposes of appeal. However, Plaintiffs declined to go forward with proof *961 on the alleged Section 1 violation. The Court hereby finds and concludes that such claim should be dismissed.
On December 28, 1976, the plaintiff class was tentatively certified under F.R.Civ.P. Rule 23 as including all royalty interest owners in Thomasville, Piney Woods, and Southwest Piney Woods Fields whose share of production is being processed through Shell's Thomasville Plant and whose claims exceed the jurisdictional amount of $10,000.00. Zahn v. International Paper Co., 414 U.S. 291, 94 S. Ct. 505, 38 L. Ed. 2d 511 (1973); Synder v. Harris, 394 U.S. 332, 89 S. Ct. 1053, 22 L. Ed. 2d 319 (1969). The Court ordered that notice be directed to the members of the tentative class informing each of their right to be excluded from this action. Thereafter, a class consisting of seventy-seven (77) members was finally certified by Order dated December 15, 1978.
Trial of this cause was had before the Court without a jury. With apologies to the parties and their attorneys for the inordinate delay in rendering an opinion in this cause, the Court hereby issues and enters the following Findings of Fact and Conclusions of Law pursuant to F.R.Civ.P. Rule 52(a).
FINDINGS OF FACT
As a result of its leasing efforts in the mid-1960's, Shell became the lessee in a substantial number of oil, gas and mineral leases in Rankin and Simpson Counties, Mississippi. After routine geophysical exploration of the area, Shell undertook a drilling program which resulted in the development of the three (3) natural gas fields in Rankin County, Mississippi: Thomasville, Piney Woods and Southwest Piney Woods Fields. It is the production from these fields which is the subject of the instant litigation.
Of thirteen (13) wells drilled in the three (3) fields, the proof indicates that production was being had from the following wells, to wit:
(1) L. D. BURCH # 1, from which production was first had on July 5, 1972, is located in the Thomasville Field on the following described 1280-acre unit:
Section 33, Township 4 North, Range 3 East; and Section 4, Township 3 North, Range 3 East; all in Rankin County, Mississippi.
(2) CRAIN # 1, from which production was first had on August 31, 1972, is located in the Thomasville Field on the following described 1280-acre unit:
Section 32, Township 4 North, Range 3 East; and Section 5, Township 3 North, Range 3 East; all in Rankin County, Mississippi.
(3) GARRETT # 1-R, from which production was first had on March 4, 1978, is located in the Thomasville Field on the drilling unit of the Garrett # 1 well, which was plugged and abandoned after it ceased production on May 11, 1977. The 1280-acre unit for the Garrett # 1-R well is described as follows:
West Half (W ½) of Section 27; Section 28 and East Half (E ½) of Section 27; all in Township 4 North, Range 3 East, Rankin County, Mississippi.
(4) COX-HARPER, from which production was first had on April 9, 1977, is located in the Piney Woods Field as the replacement for the Cox # 2 well. The Cox-Harper is located on the 1280-acre unit originally designated for the Cox # 2:
Sections 21 and 28, Township 3 North, Range 3 East, Rankin County, Mississippi.
(5) RIDGWAY MANAGEMENT # 1-R, from which production was first had on September 1, 1977, is located in the Southwest Piney Woods Field on the 1280-acre unit originally designated for the Ridgway Management # 1 well. Said unit is described as follows:
Sections 34 and 35, Township 3 North, Range 2 East, Rankin County, Mississippi.
The named plaintiffs and the class members own royalty interests in the oil, gas and minerals in, on and under the above-described drilling units. The leases and compensatory royalty agreements under which Plaintiffs are compensated for their respective *962 royalty interests are in evidence as Exhibits P-1(a) through P-1(hhhh) and P-2 through P-5.[3] These leases appear on seven (7) different lease forms which are designated in the oil and gas industry as follows:
(1) Paid-up Mississippi Rev. 7/17/45;
(2) CommercialForm CC-78;
(3) Producers 88-D9803 (Revised 10/1/48) with Pooling Provision;
(4) (Mississippi) Form 0-280 Rev. 3 (8-61) 5M-Producers 88 Rev.;
(5) Producers 88 (9/70)Paid up with Pooling Provision MississippiAlabama Florida;
(6) Producers 88 (9/70) with Pooling Provision MississippiAlabamaFlorida and
(7) Producers 88 RevisedAlabama Mississippi (11-56).
Among the seven (7) lease forms, there are three (3) different gas royalty clauses. Lease forms (1) and (2) above contain the following gas royalty provision, hereinafter referred to as the "Commercial" provision:
"... (b) on gas, including casinghead gas[4] or other gaseous substance[s], produced from said land and sold or used, the market value at the well of one-eighth ( 1/8 ) of the gas so sold or used, provided that on gas sold at the well the royalty shall be one-eighth ( 1/8 ) of the amount realized from such sale[s]...."
Lease forms (3) and (4) above contain the following gas royalty provision, hereinafter referred to as the "Producers 88-D9803" provision:
"... (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used off the premises or in the manufacture of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells royalty shall be one-eighth of the amount realized from such sale...."
Lease forms (5), (6) and (7) above contain the following gas royalty provision, hereinafter referred to as the "Producers 88 (9/70)" provision:
"... (b) to pay lessor on gas and casinghead gas produced from said land (1) sold by lessee, one-eighth of the amount realized by lessee, computed at the mouth of the well or (2) when used by lessee off said land or in the manufacture of gasoline or other products, the market value at the mouth of the well, of one-eighth of such gas and casinghead gas..."
The natural gas produced from the Thomasville, Piney Woods and Southwest Piney Woods Fields is "sour gas" which is natural gas that is contaminated with chemical impurities, notably hydrogen sulfide. Hydrogen sulfide, or "H2S"[5], is a highly poisonous compound composed of hydrogen and sulphur. As with other impurities found in a natural gas stream, H2S must be removed before the gas is of commercial quality. The amount, or concentration, of H2S in the gas stream commonly determines the procedure used to separate it from the methane gas, the marketable portion of the natural gas stream. Trace quantities of H2S can be vented into the atmosphere. Where venting presents a hazard or greater quantities of H2S are present, scrubbers physically separate the H 2S from the methane by absorption. When H2S is present in the gas stream in significant quantities, it is removed by a chemical process and, where profitable, converted into elemental sulphur, a marketable product. Processing plants, as customarily known in the gas industry, are for treating, sulphur recovery or natural gas liquid recovery. A particular processing plant is designed to accomplish any one or a combination of these functions, depending on the composition of the gas to be processed.
*963 The composite sour gas stream from all wells in the Thomasville, Piney Woods and Southwest Piney Woods Fields contains approximately thirty-five percent (35%) H2S, eight percent (8%) carbon dioxide and fifty-seven percent (57%) methane.[6] The Thomasville Plant, as a treating and sulphur recovery facility, removes H2S from the raw gas stream, processes it into elemental sulphur, and at the same time produces a dry methane gas from the "sweet" (free of H2S) gas stream. The plant is located in the West Half (W ½) of Section 27, Township 4 North, Range 3 East, Rankin County, Mississippi, on the designated unit of the Garrett # 1-R well at the end of a gas gathering system which collects raw gas from the Burch # 1, the Cox-Harper and the Ridgway # 1-R. Gas from the Garrett # 1-R and the Crain wells travels by direct pipeline to the plant.
When raw gas arrives at the Thomasville Plant for processing, it contains solutions, such as corrosion inhibitors, which are injected in the gas stream at the well. Removal of these solutions is by a gravity separator, a wide spot in the pipeline, which permits physical separation of the liquid solutions from the natural gas. These solutions are returned to the well site for reuse. The raw gas moves into the sulfinol contractor for the first phase of sulphur removal.
In the sulfinol contractor, which operates under 1000 ppsi (pounds of pressure per square inch), a sulfinol solution is added to the raw gas which causes a chemical reaction resulting in a physical absorption of the H2S and carbon dioxide by the sulfinol solution. The "sweet" methane gas, containing water, flows from the top of the sulfinol contactor to the glycol contractor. In the glycol contractor, the water is removed from the gas to produce the dry, sweet gas that is marketed.
Meanwhile, the sulfinol solution, bearing the acid gas, flows out the bottom of the sulfinol contactor into the sulfinol still. The reaction that occurred in the contractor is reversed by dropping the pressure in the sulfinol still to 13 ppsi and by adding heat produced by the sulfinol reboiler. The sulfinol solution is then recovered and returned to the sulfinol contactor for reuse.
The heated acid gas flows from the sulfinol still to the still overhead condensor where it is cooled. The water vapor produced in the cooling process is returned to the sulfinol contactor. The acid gas passes into the combustion furnace where air is added to oxidize the H2S into sulphur by the Claus Recovery Process. Such is achieved by three stages of catalytic conversion which produces sulphur in a vapor form. The sulphur is cooled and then stored in pits until sold.
Approximately ninety-seven and one-half percent (97½) of the H2S is recovered in the Claus process. The remaining two and one-half percent (2½%) travels to an incinerator stack where it is burned and vented into the atmosphere.
The cost of gas processing and sulphur recovery at the Thomasville Field, together with costs of gathering and transporting[7], are deducted by Shell in calculating payments to royalty interest owners for their respective interests in the subject gas. Similar charges are deducted pro rata from the working interest owners' shares of production. To compute these payments, Shell devised an allocation and accounting procedure which insures that each well is properly credited for its share of the production while reimbursing the plant for costs associated with processing the gas. This latter function is accomplished by equations which compute a "plant-lease split" of the residue gas and sulphur revenues. These equations are designed to accommodate such variables *964 as the costs of operating the gas treatment and sulphur recovery facilities, Shell's capital investment, the production rate and revenue received from production, while simultaneously recovering the cost of processing the gas and sulphur.
The equation used to compute the plant-lease split of residue gas is as follows:
FDP Gross
Sales Gas
[ (Treating ) ( ) ] MCF/D
[ (Plant ) ( Treating ) ( ) ] Total (Gathering ) (0.000728)
[ (Operating ) + ( Plant ) (0.000728) ] ×Plant + ( System ) ( Day )
[ (Cost ) (Investment) ( Day ) ] Inlet (Investment ) ( )
[ ($/Day ) ( $ ) ] MCF/D ( $ )
--------------------------------------------------------------------------------
FDP Average Daily Adjusted Net Sales Gas (MCF/D) × Average Adjusted Price
($/MCF)
The first factor appearing in the numerator of the above expression considers the cost per day of the gas treating plant. Such cost includes not only the actual operating cost of the plant in the form of expenses for payroll, materials, insurance, taxes, etc., but also reimbursement of the capital investment in the treating plant, together with a return on that investment. "Cost" is expressed in the formula by adding the daily operational cost of the treating plant to a recovery factor representing the plant investment multiplied by the daily factor.
The second factor appearing in the numerator of the equation is designed to allocate the cost expressed in the first factor to each well in proportion to its share of the inlet gas. Such is accomplished by dividing a particular well's field delivery point gross sales gas expressed in Mcf[8] per day by the total plant inlet gas also expressed in Mcf per day. The numerator of the equation, obtained by multiplying the first and second factors, expresses the cost in dollars per day that each well bears for the operation of the treating plant. Where applicable, an additional factor is calculated into the numerator to account for a well's pro rata share of the daily cost of the gathering system.[9] The denominator of the equation expresses the daily revenue to the well in a volume times sales price calculation. Once computed, the equation expresses the fractional share of revenue from production of each well retained by Shell to reimburse the cost of treating the sour gas at its Thomasville Plant.
Shell's sulphur formula,[10] paralleling that for residue gas, is designed to reimburse the plant for cost of sulphur recovery out of sulphur revenues. "Cost" is calculated to include operating costs of the sulphur conversion *965 plant as well as a capital recovery factor. Execution of the primary formula computes the plant's share of the total sulphur revenues. Further calculation is necessary to determine each royalty and working interest owner's pro rata contribution to the recovery cost.
The residue gas and the sulphur formulas operate subject to the "Sixty Percent Override Limitation."[11] The Limitation places a ceiling on the amount of revenue returnable to the plant for processing costs. It guarantees that the royalty owners will receive at least forty percent (40%) of their respective share of production without regard to costs incurred in treating the residue gas or in converting the sulphur.
Natural gas processed at the Thomasville Plant is sold under two gas purchase agreements: one, with Mississippi Chemical Corporation and Coastal Chemical Corporation, a partnership, hereinafter referred to as "MisCoa"; the other, with Mississippi Power & Light Company, hereinafter referred to as "MP&L".[12]
The Gas Purchase and Sale Contract with MisCoa was executed by the parties on May 31, 1972, with an effective date of May 22, 1972. This contract provides for an initial base price of fifty-three (53) cents per Mcf of adjusted net sales gas, or processed gas, delivered to MisCoa. After delivery of fifteen million (15,000,000) Mcf of processed gas, the contract provides for an increase in price to fifty-four and fifty-nine hundredths (54.59) cents per Mcf. The contract also provides for fixed price escalation in an amount of three percent (3%) of the base price in effect during the immediately preceding year. At the time of trial, MisCoa was paying sixty-three (63) cents per Mcf for gas. The MisCoa contract provides for a daily maximum of processed gas (46,667 Mcf per day) to be delivered to MisCoa, but there is no requirement for a minimum amount of gas to be delivered. The primary term of the MisCoa contract is thirteen (13) years. Provision is made for an extension of the contract for two (2) consecutive periods of one year each with a year's notice from buyer to seller. Thereafter, the term of the contract continues from year to year until cancelled upon notice by either party. The contract provides for transportation charges of four and one-half (4½) cents per Mcf.
The Gas Purchase and Sale Contract with MP&L is dated, and was executed, on May 23, 1972. This contract is for gas produced in excess of Shell's commitment to MisCoa with a maximum volume of fifteen thousand (15,000) Mcf per day. According to the provisions of the MP&L contract, the base price of the processed gas was forty-five (45) cents per Mcf. Price escalation was fixed at one (1) cent per year. The MP&L contract contained an "Area FPC Clause" which provided that if at any time during the contract term, the Federal Power Commission (or any other governmental authority having jurisdiction) prescribed a ceiling rate applicable to comparable gas which was higher than the price then provided to be paid by MP&L, then the price of the subject gas would be increased to equal the higher rate. Also included in the contract was a "favored nations clause" which provided that if, at any time, MP&L paid a *966 higher price for intrastate gas purchased from another producer, then such higher price applied to gas delivered under the terms of the instant contract. Application of the "favored nations clause" was subject to the following limitations:
"(a) Such higher price must be applicable to a gas reserve or reserves committed to Buyer which does not exceed by more than twenty-five percent (25%) the total volume of residue gas which is estimated to be delivered hereunder to Buyer.
"(b) Such higher price must be applicable to a contract or contracts generally comparable in terms to the terms hereof. In determining comparability the parties shall assign the value to Buyer of such factors as deliverability, variations in daily and annual take obligations, quality pressures, location and other features in such contract or contracts and in this contract, and such values shall be considered in the application of all or part of such higher price to this contract."
"(c) Such higher price shall not be applicable to this contract unless and until Seller has delivered or tendered to Buyer at least fifteen thousand (15,000) Mcf per day of residue gas for a period of sixty (60) consecutive days." (Gas Purchase and Sale Contract, May 23, 1972, Article 4, paragraph 4.5, pages 8 through 9).
Shell began its efforts to market the subject gas in mid-1970 at a time when sufficient drilling and testing in the subject fields had revealed the existence of a high pressure sour gas structure in the Smackover formation at a depth of approximately 21,500 feet. In October 1970, after testing of the Garrett # 1 and logging of the Burch, Shell anticipated a flow rate from the subject fields of approximately one hundred thousand (100,000) Mcf per day. At this time, Shell committed itself to building the Thomasville Plant. Prior to completion, Shell contracted for the sale of the gas to be processed therein.
In June 1971, John F. Bruskotter, a twenty-one year veteran in the oil and gas industry, became Shell's manager for natural gas marketing in the Southern region. Such position imbued Bruskotter with full responsibility for negotiating all sales and purchases in the Southern region. According to Bruskotter's testimony, one of Shell's early marketing decisions was whether the subject gas should be committed to the interstate or the intrastate market. Shell considered the interstate market too restrictive since regulation by the Federal Power Commission fixed gas prices according to vintage and region of production. Under FPC regulation, then current discoveries of gas in the subject fields would have been priced at approximately twenty-five (25) cents per Mcf. Shell expected the cost of processing the gas at Thomasville to be twenty-three (23) cents per Mcf, according to then available figures and predictions of future expenditures. An additional concern in submitting the gas to the interstate market was the jurisdiction of the Federal Power Commission in determining the volume, or rate, of production and in extending gas sales contracts contrary to the designated expiration date.
According to Bruskotter's testimony, prices offered in the intrastate market were generally equal to, or only slightly less than, those found in the interstate market. There were no confinements on the amount of gas that could be produced, consequently, there was a higher present value on production even though the price received in intrastate sales was slightly lower.
These considerations precipitated Shell's decision to commit the subject gas to the intrastate market. Early research by Shell, coordinated with the resources of the Mississippi Research and Development Center, Jackson, Mississippi, revealed that there was no major intrastate market in Mississippi. In June 1971, Shell was negotiating with three (3) potential purchasers: United Gas, MisCoa and MP&L. United's initial offer for an interstate sale at a purchase price of twenty-one (21) cents per Mcf with price escalation every four (4) or five (5) years was rejected with Shell's decision to restrict the subject gas to an intrastate market. Thereafter, United offered forty-two (42) cents per Mcf with one (1) cent *967 price escalation every four (4) years on a commitment of the subject gas to an intrastate pipeline to be built by United. Because United's pipeline system customarily transported gas in interstate commerce, Shell recognized the possibility that the Federal Power Commission might assume jurisdiction of the sale and reduce the ultimate sales price. Consequently, Shell rejected United's offer.
Mississippi Power & Light, considered the largest intrastate consumer of natural gas, was first contacted by Shell in 1969, but serious negotiations did not begin until mid-1971 after MP&L employed Mustang Fuel as its agent for securing gas supplies. MP&L's best offer, made prior to Shell's acceptance of MisCoa's offer, was forty-five (45) cents per Mcf with one (1) cent per year escalation and an area rate clause. There were, however, no other provisions for price escalation.
MisCoa's offer for the subject gas was fifty-two (52) cents per Mcf with fixed escalation of two percent (2%) per year. MisCoa had a plant-processing capacity of forty-four thousand (44,000) Mcf per day in 1971, and was, at that time, considering enlarging. MisCoa was willing to accept all gas marketed by Shell and, in fact, sought guaranteed delivery of their anticipated needs. Shell, uncertain of the volume of production, was not willing to make such a commitment. MisCoa, as a direct industry user, structured the price for its products on the price it paid for raw materials. Consequently, it was unwilling to include a favored nations clause in the price escalation provision because of the concomitant inability to control the price of its product.
In 1971, fixed escalation provisions were customarily for one percent (1%) or for one and one-half (1½) cents. Shell's goal in negotiations with MisCoa was a price of fifty-four (54) cents per Mcf with two percent (2%) fixed escalation. The compromise ultimately reached was fifty-three (53) cents per Mcf with three percent (3%) fixed escalation and a committed maximum daily delivery of 46,667 Mcf.
Shell's negotiations with MisCoa on price and volume were concluded in July 1971. A letter of intent was signed by the parties in February 1972. Shell considered this contract to be the most advantageous arrangement available to it regarding price, escalation and volume.
In May 1972, Shell concluded negotiations with MP&L for the sale of excess gas at a base price of forty-five (45) cents per Mcf. Figures available at the time of trial indicated that gas delivered to MP&L sold for $1.63 per Mcf. The substantial increase in price paid by MP&L resulted from the invocation of the Federal Power Commission area rate clause in the MP&L contract. At the time of trial, the favored nations provision has never affected pricing of gas sold to MP&L because of the limitation regarding the volume required to be delivered prior to its application.
Under provisions of the sales contracts with both MisCoa and Mississippi Power & Light, gas processed at Thomasville is delivered to the respective purchasers at field delivery points, which are part of a metering system on the raw gas stream upstream of the Thomasville Plant. The field delivery points for the Cox-Harper and Ridgway Management # 1-R wells are located on the respective leases and in the immediate vicinity of the respective wells. The field delivery point for the Garrett # 1-R well is located on the unit designated for said well but not on the lease on which the well is located. The field delivery points for the Crain # 1 well and the L. D. Burch # 1 well are located off of the respective units at the inlet to the Thomasville Plant. According to the testimony of Shell's corporate representative, Mr. John McLain, the Crain well is farthest from its designated field delivery point, and it is, "as the crow flies", approximately one (1) mile from the Crain # 1 well to its designated field delivery point.
Shell computes and pays gas royalty to royalty interest owners under the subject units for gas marketed as well as for gas *968 used as off-lease fuel[13] on "proceeds" from the sales of the subject gas. Shell computes and pays sulphur royalty under the gas royalty provisions of the respective leases on "proceeds" from sulphur sales.[14]
Max Powell, a consulting petroleum engineer from Texas with considerable experience in the industry, testified regarding market value of the subject gas. Powell has been continuously employed in the Texas oil and gas industry in such capacities as engineer for Halliburton Oil Well Cementing Company, hearings officer for the Texas Railroad Commission and chief engineer for Russell Maguire, an independent oil and gas operator. With Maguire, Powell was responsible for all drilling, completion, production and marketing decisions regarding approximately six hundred (600) wells.
As a private consulting petroleum engineer, Powell frequently conducts studies to project the market value of gas and offers his opinion as an expert. To prepare his opinion of the market value of the subject gas, Powell first obtained a map prepared by the Mississippi Oil and Gas Board which identifies state and county boundaries, oil and gas fields in the state, transmission lines and the particular product transmitted therein. The Oil and Gas Board also supplied Powell with a computer printout listing the locations of all fields in the state with a completion date of 1971 and later, the names of the pool or reservoir in each field from which production was obtained, the names of the respective operators, well names and numbers, their completion dates and cumulative production of oil, gas and water as of January 1, 1978.
Information regarding prices received by sellers for gas in the identified fields was obtained from the Severance Tax Division of the Mississippi State Tax Commission. Powell reviewed this information, secured laboratory analysis reports, and prepared "quality-control sheets". The "quality-control sheets" contained information on sales derived from the relevant market area which Powell considered potentially reliable. He initially began his search for market value by defining the relevant market area from which comparable sales would be drawn. Powell's initial search for a relevant market area necessarily encompassed the entire state. The actual market area selected for analysis consisted of seven noncontiguous counties which Powell believed had sufficient numbers of gas sales coming in the market to be representative of current market price. Once potentially relevant sales were isolated, he considered their comparability to the subject gas.
Powell testified that he examined information obtained from the State Oil and Gas Board regarding each sale insofar as its: date or month of first sales under which gas was delivered; location or availability of the field to a market; quantity, or amount of, reserves and its deliverability or the rate at which the reserves were produced and delivered; and quality of gas. Powell concluded that the subject gas should bring a price in the market equivalent to the top price received for gas sold anywhere in the state because, after processing, the subject gas was a superior quality fuel with large reserves and deliverability.
Powell arrived at his opinion of the market value of this gas by arithmetically averaging the top three prices for gas sold in a quarter from what he had designated as the relevant market area between January 1974 and January 1978 (Ex. P-34). Powell admitted that the prices he used were reflective of the net price received for gas from the respective wells and that he did not know whether the gas from the selected wells was marketed under one base contract or under three different contracts. Powell *969 explained that this occurred because prices are reported to the State Tax Commission by well and not by contract. Powell also stated that his opinion of the market value of the subject gas expressed the value of gas as sold and delivered at the tailgate of the Thomasville Plant rather than its market value at the wellhead.
Powell testified that he did not restrict the contracts he relied upon to the relevant time period, 1972 to the present, in order to capture the then-existing market conditions of transactions from other fields which represented new gas coming into the market. His figures failed to account for all gas delivered in January 1974 because that gas was sold pursuant to long term contracts and did not, according to Powell, reflect then current prices. Powell determined that these contracts would not have any impact on a decision concerning present market value of gas. Powell further stated that he did not restrict his contracts to quantities similar to the contracts in question. He believed that since even small quantities of gas command substantial prices, then large reserves and deliverability should obtain at least the same, if not higher, prices.
CONCLUSIONS OF LAW
I
Processing
Owners of royalty interests under producing units in the Thomasville, Piney Woods and Southwest Piney Woods Fields invoked the jurisdiction of this Court pursuant to Section 1 of the Sherman Act and 28 U.S.C. § 1332 to recover alleged insufficiencies in royalty payments. Plaintiffs contend that the formulas utilized by Shell to compute royalty payments wrongfully deduct from royalty's share of production the initial capital investment expended by Shell to construct the Thomasville Plant, a return on that investment, costs of operating the plant, costs of gathering and delivering the raw gas to the plant and costs of transporting the refined product sold to MisCoa in Yazoo City, Mississippi.
Plaintiffs submit that because "royalty" has customarily been defined as "a share of production free of the costs of production", their royalty should be wholly free of any proportionate costs to prepare the subject gas for market. Plaintiffs contend the function performed by the Thomasville Plant is a "production" function and that performance of such is incident to lessee's duty to market,[15] the costs of which are to be borne solely by lessee. According to Plaintiffs, all gas wells ordinarily produce gas which is mixed with salt water and other contaminants which must be separated from the gas stream prior to delivery of the gas to the market. Therefore, Plaintiffs submit that the Thomasville Plant performs separation and contaminant disposal functions similar to wellhead facilities and is a production, rather than a manufacturing or processing, facility.
Defendant contends that production ceases once the product is extracted from the earth and all costs incurred subsequent thereto in preparing the product for market are processing costs to be borne proportionately by royalty and by working interest owners. Shell concedes that royalty is the landowner's share of production, free of the expenses of production, and that the lessee has the duty to market. Shell recognizes that said duty generally requires a lessee to bear all costs of market research, study, investigation and negotiations with potential purchasers, and further, the costs of certain separators, flowlines, storage tanks and disposal equipment which perform basic "at the well" functions.[16] However, Shell *970 rejects Plaintiffs' contentions that lessee's obligations to produce and market requires lessee to materially enhance the value of a product by processing.[17]
Prior to its operations in the Thomasville area, Shell contends that no producer in the industry had been able to successfully produce a deep, high pressure sour gas well. Shell maintains that the presence of extremely sour gas at great depths, coupled with unprecedented pressures, created an entirely novel situation for an industry which had not successfully produced high pressure hydrogen sulfide gas. According to Shell, the raw gas stream produced contains large amounts of hydrogen sulfide requiring that the gas be processed to obtain a marketable product. Shell believed that the wellhead value of the produced gas could be substantially increased by construction of a processing plant. Therefore in 1970, despite the inability to predict volume and continuity of production, and the unavailability of a third party willing to assume responsibility for construction and operation of a processing plant absent a guaranteed volume, Shell undertook to design and erect a plant in order that the subject gas could be produced.
Shell contends that the plant-lease split adequately compensates royalty owners for their share of production even though it recoups direct operating costs, cost of plant capital investment, and, where applicable, gathering costs incurred in bringing gas to the plant because these costs were necessary to convert worthless gas and to recover sulphur in commercial quantities from the sour gas stream. In essence, Shell contends that production of the subject gas ceases once the raw gas is extracted from the earth and that costs incurred thereafter in preparing the commodity for market are to be borne proportionately by royalty and by working interest owners. In support of its argument, Shell relies on the language contained in the leases which provides that Shell's royalty obligation is based on the value of the raw gas "at the well".[18]
Royalty is defined in Mississippi as "a share of the production or profits reserved by the owner for permitting another to use or develop his property".[19] The working interest is distinguished from royalty in that royalty: (1) is a share of production free of any costs of discovery and production with (2) no right to do any act or thing to discover and produce the oil and gas.[20] The working interest in minerals, the primary developer, on the other hand, is: (1) responsible for costs of discovery and production in addition to being (2) given the right to discover and produce oil and gas.[21] Indeed, in the oil and gas industry,
"... it is common knowledge that the landowner does not, and usually could not, himself provide the money, therefore, the usual and almost universal method for finding oil and bringing it to the surface being for the landowner to authorize a person or corporation engaged in such business to find the oil and bring it to the surface, approximating all that he produces thereby to himself except an agreed portion thereof reserved by and to be delivered, or its value paid, *971 to the landowner and usually designated as royalty ...."[22]
The United States Supreme Court in Federal Power Commission v. Panhandle Eastern Pipe Line Co., 337 U.S. 498, 518, 69 S. Ct. 1251, 1262, 93 L. Ed. 1499 (1949) concluded that the "natural and clear" meaning attributable to "production" of gas is "the act of bringing forth gas from the earth".[23] Costs attributable to production have been defined as "expenses incurred by the lessee in exploring for mineral substances and in bringing such substances to the surface".[24] These expenses include "costs of geophysical surveys; drilling costs; tangible and intangible costs incurred in testing, completing or reworking a well, including the cost of installing a Christmas tree".[25]
Royalty is customarily subject to a proportionate share of the costs incurred subsequent to production where, as is usually the case, the royalty, or non-operating interest, is payable "at the well".[26] Among these costs borne by non-operating interests are: (1) gross production and severance taxes; (2) transportation charges or other expenses incurred in transporting the minerals produced from the wellhead to the place where the buyer takes possession thereof; (3) expenses of treatment required to make the mineral product salable, e.g., expenses of dehydration; (4) expenses of compressing gas to make it deliverable into a purchaser's pipeline; and (5) manufacturing costs incurred in extracting liquids from gas or casinghead gas, viz., costs incurred in adding value to the wellhead product.[27]
Plaintiffs contend that the Thomasville Plant performs a production function. Plaintiffs present this contention to the Court as a novel issue. The Court, however, finds abundant precedent in the Fifth Circuit and elsewhere to support its conclusion that production ceases once the product is extracted from the earth. The Court finds and concludes that the function performed by the Thomasville Plant is subsequent to production and is a processing function whereby large expenditures are made to convert a "valueless commodity into one of greater value". Freeland v. Sun Oil, 277 F.2d 154, 158 (5th Cir. 1960). As succinctly stated by the Fifth Circuit in Freeland, "... costs which are essential to make a commodity worth anything or worth more must be borne proportionately by those who benefit." Consequently, royalty is obligated to contribute proportionately to the costs of processing the product.
The court in Freeland considered whether Louisiana law[28] required a lessor to share proportionately in the costs of a gas extraction *972 process whereby gas was "stripped of recoverable fluids" and converted into a merchantable product. The liquid content of the gas was not separated on the leased premises. Rather it was carried with the full gas stream to a processing plant where the gas was subjected to separation, absorption and dehydration processes. The processing plant in this case was not owned and operated by the lessee. The processor retained, under the processing contract, a certain percentage of the end product as compensation for construction and operating costs. The balance was returned to the lessee-oil companies which paid one-eighth royalty computed thereon. Royalty challenged the percentage retained by the third party processor.
The record in Freeland, as in the case sub judice, established that gas at the wellhead had little marketability and no demonstrated market value. In order to enhance the value of the gas, it was necessary to process it through an expensive gasoline extraction plant. The court concluded that royalty was subject to a proportionate share of processing costs because "the availability of the extracting process and its application had enhanced the value of the product". The court undertook a thorough analysis of Louisiana law to determine the gas valuation from which royalty would be computed. The court concluded that:
"[t]he contract would be harsh unless the costs were shared ... 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.... In this sense, he bears his proportionate part of that cost...."[29]
Plaintiffs seek to shield themselves from costs of materially enhancing the value of the subject gas by maintaining that this function is to be performed by Shell pursuant to its duty to market the product. Plaintiffs' contention lies in the theory that the Thomasville Plant is necessary to "produce" merchantable gas and that "production" cannot be realized without the plant and pipeline facilities. Therefore, these facilities must be labeled "production" facilities for which royalty bears no cost. However, Plaintiffs offer no authority for their contention. The Court believes that Plaintiffs would have difficulty supporting same, as, not unexpectedly, the judiciary overwhelmingly endorses the industry practice of royalty sharing in costs incurred by the lessee in processing and transporting gas in fulfillment of its marketing responsibilities.[30] Even though the lessee may be under a duty, express or implied, to market production, this duty does not require an assumption of all costs.
Plaintiffs cite two Kansas cases in support of their position: Schupbach v. Continental Oil, 193 Kan. 401, 394 P.2d 1 (1974); Gilmore v. Superior Oil Co., 192 Kan. 388, 388 P.2d 602 (1964). In Gilmore, the Kansas Supreme Court ruled that the lessee has a duty to pay for gas compression expenses necessary to make gas marketable and that those expenses could not be passed on to royalty. The court reasoned as follows:
*973 "[i]f it is the lessee's obligation to market the product, it seems necessarily to follow that his is the task also to prepare it for market, if it is unmerchantable in its natural form. No part of the costs of marketing or of preparation for sale is chargeable to the lessor." 388 P.2d at 607.
The court reached a similar conclusion in Schubach. However, such results conflict with the finding by the Kansas Supreme Court in Matzen v. Hugoton Products Co., 182 Kan. 456, 321 P.2d 576 (1958), where the court held that proper chargeable operating expenses, including gathering, processing and dehydrating, must be deducted to calculate the value of gas "at the wellhead".
The authority relied upon by Plaintiffs is unconvincing, apparently in conflict with prior authority and certainly not binding on this Court. This Court finds that Plaintiff's position is unduly harsh and totally untenable and that the only equitable conclusion is to hold that lessor and lessee shall bear proportionately costs of materially enhancing the value of the subject gas. As stated in Freeland,
"... costs essential to make a commodity worth anything or worth more must be borne proportionately by those who benefit." 277 F.2d at 159.
II
Marketing
Plaintiffs contend that Shell's failure to procure a price redetermination clause in the MisCoa contract was a breach of Shell's implied duty as lessee to market. This breach, according to Plaintiffs, entitles them to royalty based upon market value regardless of lease provisions which require that gas royalty be paid on the "amount realized" by lessee.
In support of their position, Plaintiffs refer to Shell interoffice communications[31] which Plaintiffs contend reflect Shell's awareness that prices for natural gas would increase. Plaintiffs contend that such awareness required Shell to negotiate appropriate terms in the MisCoa contract. In the absence of such action, Plaintiffs submit they are entitled to more protection than that provided under an "amount realized" royalty provision.[32]
Shell ardently opposes Plaintiffs' position. Shell contends that at all times it fulfilled its duty to market as a reasonably prudent operator by exercising "due care" and "reasonable diligence" in investigating and procuring buyers for the subject gas. According to Shell, in the absence of proof of failure by lessee to market gas with the diligence of a reasonable prudent operator, there are no judicial decisions requiring that payment of royalty under "amount realized" royalty provisions be based upon any standard other than the amount actually realized by the lessee.
Because of a lessee's exclusive control over the production and development of oil and gas, the law imposes upon the lessee certain implied covenants; namely, to reasonably develop, produce, operate and market production.[33] A lessee, bound by implied obligations, is held to the standard of conduct, in Mississippi, of the "prudent operator".[34] The test for his performance generally applied is whether or not the lessee has used due care and diligence.[35]*974 Due care and diligence is defined as that care and diligence which would be exercised in a particular situation with due regard to the interests of both lessor and lessee.[36] Furthermore, reasonable diligence on the part of the lessee must conform to, and be governed by, what is expected of persons of ordinary prudence in the industry under similar circumstances, conditions, practices and procedures.[37] Among the facts and circumstances which are to be considered in determination of the lessee's diligence in marketing the gas are: availability of marketing facilities, i.e., presence of pipelines and efforts of the lessee in securing extensions of pipelines into the field; pressure and quality of gas as affecting its marketability; amount produced; prevailing market price and time and manner of the performance of such acts as might result in marketing.[38] What constitutes reasonable time and due diligence depends on the particular facts.
In support of their proposition that a lessee has an implied duty to market natural gas at a current market value under a lease provision basing royalty on the amount realized from the sale of such gas, Plaintiffs cite Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex.Civ.App.1979). The dispute in Amoco concerned eighteen (18) oil and gas leases, each of which provided that on gas sold at the wells the royalty would be one-eighth ( 1/8 ) of the amount realized from such sale. The working interests owners had been selling gas to one of four different purchasers, each of whom had its own gas pipeline connected to the well. The several owners of the oil and gas leasehold estates in the tracts of land pooled same to form another unit containing 640 acres. The question confronted by the Texas court was whether Amoco had breached any legal duty when approximately twenty months after the new unit began producing gas, it committed and dedicated such gas to a long term contract on terms providing one-half (½) of the amount at which gas was then being sold to other purchasers from the same well and with no right for future price redetermination based on market increases, and while doing so obtained for itself extra benefits in respect to other properties in which the lessors had no interest.
The court concluded that Amoco, by dedicating additional leases in June 1975, obtained an increased price for gas already dedicated under a prior contract from seventeen (17) cents per Mcf to seventy (70) cents per Mcf. Although this increase represented a substantial benefit for both parties, it also meant that on some leases, royalty owners would receive gas royalty payments which were one-half (½) the original price with limited provisions for future accelerations. Therefore, the court concluded that the lessees had breached their implied covenant to market natural gas at a fair market value under a lease providing for royalty based on amount realized. The court reasoned that the breach committed by Amoco was its failure to secure the highest price reasonably obtainable. Therefore, in deciding the issue of whether there exists a duty to market the gas "at any particular price, particularly when the lease provided for royalty based on the `amount realized' from such sale", the court determined that the lessee's duty is to secure the highest price reasonably obtainable. The court's determination that the lessee must procure the highest price obtainable does not, as Plaintiffs contend, entitle lessors to *975 royalty computed on market value under an "amount realized" gas royalty provision.
Plaintiffs further submit that Craig v. Champlin Petroleum Co., 300 F. Supp. 119 (W.D.Okl.1969), aff'd, 421 F.2d 236 (10th Cir. 1970), supports their position that the lessee's duty to market the gas entitles the lessors to current market value for such gas. The trial court in Craig, however, specifically found that Champlin Petroleum "made absolutely no effort to find a market for the gas" although a viable market was available and that "had it not been for Champlin's failure, or its refusal, to seek out a market for the gas ..., a market could have easily been found."[39] Therefore, the court concluded that Champlin failed to exercise due diligence in marketing the gas; thereby breaching its duty. Upon such finding, the court held that lessors were entitled to recover the prevailing market price under lease clauses providing for payment to lessors of "the prevailing market price for gas".
The Court finds neither Amoco nor Craig applicable to the issue of Shell's alleged failure to fulfill its obligation to market the gas. Indeed, this Court concludes upon a review of its findings, that Shell fulfilled its implied obligation to market the gas as a reasonable prudent operator in the exercise of due care and diligence. Specifically, Shell's failure to procure a price renegotiation clause in the MisCoa contract was not a breach of its implied duty to market.
Shell commenced its search for a viable market in 1969 upon discovery of gas in the Thomasville Field. Two years of intense market research of potential purchasers was undertaken to secure a buyer for the large volume of gas anticipated. At the time the MisCoa contract was negotiated in 1971, gas was customarily being sold under long-term contracts for terms up to twenty (20) years at fixed prices with minimal fixed price escalation clauses. Indefinite pricing clauses were not commonly obtainable in 1971-1972. Of several potential purchasers, Shell narrowed its alternatives to United Gas Pipeline Company, Mississippi Power & Light Company (MP&L) and Mississippi Chemical Company (MisCoa). United's best offer was rejected early and in June 1971, Shell notified MP&L that its offer for the primary gas sale was not competitive. In that same month, Shell accepted MisCoa's offer in the amount of fifty-three (53) cents per Mcf delivered at Yazoo City, Mississippi, escalating three percent (3%) per year after delivery of fifteen million (15,000,000) Mcf. The final contract with MisCoa was signed May 22, 1972. In December 1971, MP&L offered to purchase the excess gas over and above that purchased by MisCoa at forty-five (45) cents per Mcf escalating at one (1) cent per Mcf per year. The final contract with MP&L was signed May 23, 1972 with the addition of a favored nations clause. If Shell had committed the gas to the interstate market, the sales price would have been approximately twenty-five (25) cents per Mcf. The prices received under the MisCoa contract were the best obtainable and the highest known for any gas sale in the United States at the time the contract was executed.
III
Point of Sale
Plaintiffs contend that royalty owners whose leases with Shell contain the Commercial or the Producers 88-D9803 provisions are entitled to royalty computed on "market value" of the subject gas because it is being sold off of the respective lease premises. According to Plaintiffs, gas is ordinarily "sold" where it is measured and delivered. Plaintiffs assert that the purchasers of the subject gas do not have pipelines or other facilities connected to the field delivery points where Defendant maintains the subject gas is measured and delivered. Additionally, Plaintiffs contend that the sales of gas should not be measured at the designated field delivery points because, at those points, hydrogen sulfide and other contaminants are still mixed with *976 the methane. Contract specifications regarding quality and quantity of gas are not met until the gas is metered in Yazoo City. Further, Shell retains total and exclusive custody and control of the gas, assuming risk for loss, until it reaches Yazoo City, Mississippi. Therefore, according to Plaintiffs, the actual point of sale for the MisCoa gas would be Yazoo City, Mississippi.
Defendant counters Plaintiffs' argument by referring to the gas sales contracts which designate the field delivery points as the points of sale for the subject gas. Defendant contends that the provisions of the sales contract designating points of sale are controlling because the point of sale for personal property is determined by the intentions of the parties as embodied in the sale contract itself. According to Defendant, title to the subject gas passes at the field delivery points, or the points in the respective fields where the gas is "initially measured, sold and delivered" pursuant to provisions of the sales contract.[40] Furthermore, Defendant submits that Miss.Code Ann. § 75-2-106(1) (1972) provides that a "sale" consists of title passing from seller to buyer for a price. Shell maintains that it sold the entire raw gas stream at the respective field delivery points and that title to same passed at those points even though Shell contractually reserved the right and assumed the obligation to process the gas and to redeliver it. According to Defendant, custom and practice within the oil and gas industry recognizes this procedure.[41] The Court considers the cases cited by the parties to be enlightening; it, however, believes that the Uniform Commercial Code controls this issue.[42]
Miss.Code Ann. Section 75-2-107(1) (Supp.1980) provides that "a contract for the sale of minerals or the like (including oil and gas) ... is a contract for the sale of goods within this chapter...."
Section 75-2-401(1) provides:
"[t]itle to goods cannot pass under a contract for sale prior to their identification to the contract.... Subject to these provisions and to the provisions of the chapter on Secured Transactions (Chapter 9), title to goods passes from the seller to the buyer in any manner and on any conditions explicitly agreed to by the parties." (emphasis added).
Section 75-2-401(2) continues by providing that "[u]nless otherwise explicitly agreed title passes to the buyer at the time and place at which the seller completes his performance with reference to the physical delivery of the goods...."[43]
Furthermore, Miss.Code Ann. Section 75-2-501(1) (1972) states:
"the buyer obtains a special property and an insurable interest in goods by identification of existing goods as goods to which the contract refers even though the goods so identified are nonconforming and he has an option to return or reject them. Such identification can be made at any time and in any manner explicitly agreed to by the parties."
Moreover, Miss.Code Ann. Section 75-2-105(4) (1972) provides:
"an undivided share in an identified bulk of fungible goods is sufficiently identified to be sold although the quantity of the bulk is not determined. Any agreed proportion of such a bulk or any quantity thereof agreed upon by number, weight or other measure may to the extent of the seller's interest in the bulk be sold to *977 the buyer who then becomes an owner in common."
Therefore, this Court concludes that the gas sales contracts which designate the field delivery points as the points of sale for the subject gas embody the true intentions of the parties and are controlling. Accordingly, under the provisions of the MisCoa contract, sales of the gas produced at the Ridgway # 1-R and the Cox-Harper wells occur on the lease on which the well is located; the sales of gas from the Garrett # 1-R well, on the designated unit; and, for the Crain # 1 and L. D. Burch # 1 wells, at respective field delivery points located near the inlet of the Thomasville Plant.
The Commercial provision requires that royalty be computed on market value for gas "sold or used ... provided that on gas sold at the well the royalty shall be one-eighth ( 1/8 ) of the amount realized...." The Producers 88-D9803 requires that royalty on gas "sold or used off the premises ... be paid on the market value ... of the gas so sold or used, provided that on gas sold at the wells royalty be computed on amount realized from such sale...." Under the former clause, royalty owners are entitled to be paid for their share of production sold computed on market value of all gas sold or used, unless the sale of such gas occurs at the well. Under the latter clause, royalty is entitled to their share of production computed on market value where the gas is sold or used off the premises, subject again to the condition that royalty be computed on amount realized when the gas is sold at the well.
The threshold question in the resolution of the instant issue necessarily becomes whether the sales of the subject gas occur "at the well". The points of sale of the subject gas, the respective field delivery points, are located upstream of the Thomasville Plant at points where the respective raw gas streams are metered prior to said gas' being commingled and processed. Thus, under the provisions of the sales contract, the subject gas is being sold in its raw form, subject to terms of the contract which provide for its redelivery to Shell for processing. Despite the variance in distances of field delivery points from the Christmas trees of the respective wells, this Court finds that such sales were made "at the well". The Court reasons that the location of the field delivery points for the Garrett # 1-R, Crain # 1 and L. D. Burch # 1 wells is off of their respective leases, and in the case of the Crain and Burch wells, their respective designated units, is insignificant as the use of "off the premises" and "at the well" in the Producers 88-D9803 does not describe circumstances intended to be mutually exclusive. Consequently, the Court concludes that royalty owners should be compensated for their share of production sold under the subject contracts based on the amount realized from such sales. Under each of the subject royalty provisions, royalty on gas "used" by Shell off the land or premises is to be computed on market value "at the well" or "at the mouth of the well". Testimony at trial indicated that Shell uses "amount realized" as the basis on which it computes payments to royalty owners for "off-lease" fuel. Under such circumstances, all royalty owners are clearly entitled to royalty computed on the market value of gas so used.
IV
Market Value
Having concluded that Plaintiffs are entitled to receive royalty computed on "market value" for off-lease fuel used by Shell, the Court is called upon to define "market value" as it appears in the subject gas royalty clauses. Plaintiffs contend that royalty is entitled to market value prevailing at the time the gas is produced, sold and delivered. In support of its argument, Plaintiffs cite the Court to a plethora of cases from various jurisdictions which construe "market value" as current market value rather than the initial contract price.
Defendant counters Plaintiffs' theory of market value by alerting the Court to the realities of the oil and gas industry. According to Shell, market value cannot be determined without considering the manner *978 in which a commodity is sold. In this case, Defendant contends the proof clearly established that in 1971 and 1972 natural gas was customarily sold under long-term contracts which did not contain provisions for price redetermination, i.e. favored nations clauses. Purchasers sought irrevocable commitments for terms averaging twenty (20) years to ensure a continuous supply of gas. Thus, Defendant submits, the proceeds derived from the sale of gas were permanently established for the term of the contract upon its execution. Although the gas royalty provisions in the subject leases do not define "market value", Defendant maintains that it must necessarily be determined as of the date of execution of the contract.
A determination of the instant issue requires an in-depth analysis of the available legal precedents. Any such analysis must commence with the well-known case of Texas Oil & Gas Corp. v. Vela, 405 S.W.2d 68 (Tex.Civ.App.1966), rev'd in part and aff'd in part, 429 S.W.2d 866 (Tex.1968). Although not the first case in which a court considered the issue of current market value versus contract price, Vela is the most definitive authority on the subject. In Vela, royalty sought to recover alleged deficiencies in royalty payments made pursuant to the provisions of the 1933 oil, gas and mineral lease which 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 the premises, one-eighth of the market price at the wells of the amount so sold or used."
Plaintiffs sought to define "market price" as the current market value of the gas.[44] The defendant argued that "market price" was the price contracted for in good faith by the lessee pursuant to its duty to market.
The Texas court determined as follows:
"... 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 contract in this case was not `being sold' at the time the contracts were made but at the time of delivery to the purchaser. [citation omitted]." (emphasis added).[45]
Therefore, the court concluded that the contract price was not necessarily the market price within the meaning of the royalty provision even though such interpretation would prove financially burdensome to a lessee who has made a long-term contract without protection against price increases. The court found support for its conclusions in Foster v. Atlantic Refining Co., 329 F.2d 485 (5th Cir. 1964); Wall v. United Gas Public Service Co., 178 La. 908, 152 So. 561 (1934) and Martin v. Amis, 288 S.W. 431 (Tex.1926). In Martin v. Amis, the Supreme Court of Texas concluded that a contract for the sale of gas is an executory contract which is effected only upon delivery of the product to the purchaser.[46]
*979 In Wall v. United Gas Public Service Co., the Louisiana Supreme Court concluded that market price is the actual price at which a given commodity is currently sold. The court reasoned that prior to the moment the gas reached the surface, neither party owned anything other than the right to explore and reduce the gas to possession. Thereafter, the parties are vested with proportionate ownerships. Their proportionate share is to be determined according to the value of gas as fixed by market price at the time title vests.[47]
In Foster v. Atlantic Refining Co., the Fifth Circuit considered the current market valuecontract price dichotomy. The plaintiff in Foster sued to recover alleged deficiencies in royalty payments based upon the royalty provision which stated as follows:
"... [t]he conventional royalties to be paid by Lessor are: (a) on oil and gas, including all hydrocarbons, one-eighth of that produced and saved from said land, the same to be delivered to the credit of the Lessor into the pipeline and to be sold at the market price therefor prevailing for the field where produced when run."
The lessee entered a twenty-year contract in 1950 with an escalation of one percent (1%) every five years. The evidence in the case established that the price prevailing in the field was thirteen (13) cents in 1957 and fourteen (14) cents in 1958-62. During that same period, the lessee was receiving eight to nine (8-9) cents. The lessee advanced the argument that at the time it executed the 1950 contract, it received a higher initial price and an agreement for a substantially higher daily take of gas than could have been negotiated with other pipelines in the area. Lessee considered plaintiff's position untenable as no purchaser would buy large quantities of gas on a day-to-day or other short term basis. The Foster court rejected defendants' arguments stating:
"... [t]he obligation of Atlantic to pay royalties is fixed and unambiguous. It made the gas sales contract with full knowledge of this obligation and did nothing to protect itself against increases in price. The fact that its purchaser would not agree to pay the market price prevailing at the time of deliveries does not destroy the lease obligation."[48]
Furthermore, the court concluded that
"... the 1950 contract was an executory contract for the sale of gas with an executed sale of gas being effected when the gas came into possession of the pipeline. ... The lease calls for royalty based on the market price prevailing for the field where produced when run. The fact that the ascertainment of future market price may be troublesome or that the royalty provisions are improvident and result in a financial loss to Atlantic is not a web of the Court's weaving."[49]
Shell attempts to distinguish Foster and Vela on the basis of the language contained in the respective royalty provisions. The district court in Kingery v. Continental Oil Co., 434 F. Supp. 349, 353-54 (W.D.Tex. 1977), rev'd on other grounds, 626 F.2d 1261 (5th Cir. 1980), concluded otherwise. The court in Kingery found that the decisions in Vela and Foster were predicated on an earlier Texas ruling, Martin v. Amis, supra, which held that a contract for the sale of gas is an executory contract with the sale being effected only upon delivery. The execution of the contract does not constitute a completed sale and does not confer any rights unto the parties while the gas remains in place.
The royalty provision in Kingery is similar to the Producers 88-D9803 considered in the instant case. It provides for gas royalty as follows:
*980 "... [where gas is] sold or used off the premises ... the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the well, royalty shall be one-eighth of the amount realized from such sale."
The court, relying on Vela and Foster as definitive of the market value issue, concluded that market value is to be determined as of the time of delivery, that a completed sale[50] of gas does not occur at the time of the execution of the initial sale contract, and finally, that the differences in the language in Vela and Foster was a "distinction without a difference."[51]
In Sartor v. United Carbon Co., 183 La. 287, 163 So. 103 (1935), plaintiffs sought to recover alleged deficiencies in royalty payments, and as early as 1935, the Louisiana Supreme Court, relying on Wall v. United Gas Public Service Co., held that the language in the lease requiring that royalty be paid market price at the well was synonymous with market price at the field where produced. Two years later in Sartor v. United Gas Public Service Co., 186 La. 555, 173 So. 103 (1937), the Louisiana court stated that "... [w]here there is no stipulation to the contrary, ... `market value' is understood to mean the current market price paid for gas in the well or field where produced."[52]
In the case of J. M. Huber Corp. v. Denman, 367 F.2d 104 (5th Cir. 1966), the meaning of "market value" was discussed by the Fifth Circuit. Royalty owners contended they were entitled to receive royalties based on current market value rather than a stated percentage of the price received by the lessee from its pipeline purchaser. The lessors refused to enter a lease agreement with the lessee until it procured a purchaser. The lessee contended that "market price" in the lease was not to be used in its traditional sense since the gas had a specified market, its contract; the market price of such committed gas was the amount received for such gas delivered to its specified market; and, the lessors are estopped from asserting the existence of another market because of their participation in committing this gas. The Court of Appeals disagreed with the lessors' contentions, holding that "market value" should be construed literally and not as synonymous with or identical to the proceeds received under the contract. The court determined that the lessors' condition precedent, the execution of the contract with a pipeline purchaser, signified their desire to be paid royalties on the current value of the gas being delivered.
Indeed, in the companion case to Huber, Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84 (5th Cir. 1966), the Fifth Circuit defined "market value" in interstate sales of gas as "what a willing seller and willing buyer in a business which subjects them and the commodity to restriction and regulation, including a commitment for a long time period, would agree to take and pay...."[53] The court then clarified its definition of market value stating that the question is "in a business in which gas is sold under long term commitments, what is the current price which it theoretically would bring?"[54] (emphasis supplied). According to the Kansas Supreme Court in Lightcap v. Mobil Oil Corp., 221 Kan. 448, 562 P.2d 1, 5-6 (1977), the Weymouth and Huber cases stand for the proposition that market value is not synonymous with actual proceeds. Moreover, the Kansas court construed Huber to mean that a "market value lease on its face calls for payment at the *981 theoretical free market value."[55] (emphasis supplied).
Shell supports its contention that the contract price governs royalty payments by relying upon the "`immediate sale' concept" advanced by the Mississippi Supreme Court in Simpson v. United Gas Pipeline Co., 196 Miss. 356, 17 So. 2d 200, 202 (1944). According to Defendant, the Simpson case conclusively established that the gas is "sold" upon execution of the gas sales contract. The lessors in Simpson sought royalty computed upon market value rather than amount realized. The lessee's contract with its purchaser required that a division order, executed by royalty, be provided. The court found that the division order, which incorporated the lease agreement, stated that the owners were to be paid in accordance with the contract, thus clearly establishing and fixing the basis on which royalty was to be paid as the contract price. In the court's words there was "an immediate sale of the gas". Simpson is clearly distinguishable in that the division order dictated the price on which royalty was to be computed.[56] The Mississippi Supreme Court, bound by the provisions of the division order, did not consider the market value issue.
After careful consideration of the testimony elicited on this issue, the extensive briefs submitted by counsel[57] and the policy arguments advanced, this Court concludes that the term "market value", as found in the royalty provisions in this cause, means current market value rather than the contract price. The Court further concludes that the holdings in Vela, Foster and Wall apply to this case regardless of the disparities in the gas royalty provisions. The conclusions of this Court are founded upon the premise expressed in those cases that a contract for the sale of gas is executory in nature with an executed sale being effected only at the time gas is delivered to the purchaser. The Court finds further support for its conclusions in the Uniform Commercial Code, Miss.Code Ann. Sections 75-2-105 and 75-2-107 (Supp.1978). Section 75-2-105 provides as follows:
"(1) `Goods' means all things (including specially manufactured goods) which are moveable at the time identification to the contract for sale.... `Goods' also includes the unborn young of animals and growing crops and other identified things attached to realty and described in the section on goods to be severed from realty (§ 75-2-107).
"(2) Goods must be both existing and identified before any interest in them can pass. Goods which are not both existing and identified are `future' goods. A purported present sale of future goods or of any interest therein operates as a contract to sell." (emphasis added).
Section 75-2-107 provides as follows:
"(1) A contract for the sale of minerals or the like (including oil and gas) or a structure or its materials to be recovered from realty is a contract for the sale of goods within this chapter if they are to be severed by the seller but until severance a purported present sale thereof which is not effective as a transfer of an interest *982 in land is effective only as a contract to sell." (emphasis added).
The Court concludes that Sections 75-2-105 107 support the reasoning of the decisions in Vela, Foster, and Wall, and that a complete sale did not occur upon the execution of the initial contract. The subject gas was sold when it reached the points of sale designated in the sales contracts; therefore, "market value" under the subject royalty provisions is construed as "current market value" unless otherwise specified.
V
Comparables
Having determined that market value is to be construed as current market value, it is now incumbent upon the Court to determine how such value is to be computed in the instant case. Our discussion begins with Texas Oil and Gas Corp. v. Vela, 429 S.W.2d 866 (Tex.1968).
As previously stated, the Texas Supreme Court held in Vela that when the gas royalty clause of an oil, gas and mineral lease is based upon a "market value" standard, royalty is entitled to payment based upon market price prevailing at the time of physical delivery and not upon the market price as determined at the time of commitment. In regard to determining market value, the court concluded that such is to be determined by sales of gas comparable in time, quality, and availability to marketing outlets.[58] Moreover, the Vela court cautioned 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."[59]
After a review of the evidence, the court concluded that the testimony of the royalty interest owners' expert witness, a petroleum and natural gas consulting engineer, provided the necessary scintilla of evidence to support the trial court's decision to award royalty a recovery based upon such testimony. The expert related his familiarity with the field in question and his study of production and gas sales from the field. The principal sources of his information were records of sales in the office of the Comptroller of Public Accounts and sales contracts made by various producers in the field. The expert then ascertained the volumes of gas sold from each well in the field and the amounts received for same during the period in question. By mathematical calculation, the average price received for all gas sold during that period was determined. The expert recognized that market value might be affected by the type, the quality, the pressure, the reserves[60] and the deliverability. Where applicable, compression charges were deducted.
The expert made a market value determination which involved calculation of "average price" received for gas sold from the field during that period by dividing the value received for the gas sold by the volume thereof. Although the Vela court accepted the expert's testimony as sufficient to support the judgment, corroboration by actual gas sales from wells in the field with comparable net prices was significant in the court's decision. Despite the opportunity to develop definitive guidelines regarding a method to compute market value, the court retreated from an in-depth analysis of the issue.
The Vela court's solution for calculating market value was criticized and rejected in Butler v. Exxon Corporation, 559 S.W.2d 410, 416 (Tex.Civ.App.1977). The court in Butler disapproved of Vela's volume-weighted average formula, and instead, accepted market value figures calculated by plaintiff's expert. Plaintiff's expert, Max Powell, began his testimony with a tabulation *983 of gas sales in a seven-county area in South Texas. Under his approach, the top three sales in the county for each quarter were averaged to determine market value during such period. He stated that all sales used in the computations were comparable in quantity, quality, and availability of gas and that his determination was based on new gas coming into the market under current market conditions. Defendant-lessee failed to offer testimony in rebuttal. The court, again declining to resolve the issue, chose to follow the unrefuted testimony of plaintiff's expert. This case is illustrative of the ad hoc basis upon which the resolution of this most important and illusive issue has been made.
Hoping to glean a ray of hope, this Court turns to Exxon Corporation v. Middleton, 571 S.W.2d 349 (Tex.Civ.App.1978), rev'd, 613 S.W.2d 240 (Tex.1981), the case chosen by the Texas Supreme Court to serve as vehicle for its attempt to clarify application of the Vela decision.[61] In Middleton, the court discussed and clarified the method for determining market value of gas committed under long-term contracts utilizing a two-tiered approach which focused on when gas is sold and on how market value is determined. The comparability test announced in Vela was reiterated and expounded upon by the court. The following principles of broad applicability emerged:
(1) Market value should be determined as though the gas is free and available for sale;
(2) Market value may be calculated by using sales of gas comparable in time, quality, quantity, and availability to marketing outlets;
(3) Sales comparable in time are those made under contracts executed contemporaneously with the sale of the subject gas;
(4) Sales comparable in quality are those of gas having similar physical properties and legal characteristics;
(5) Sales comparable in quantity are those of gas sold in similar volumes;
(6) Sales of gas comparable with respect to availability of marketing outlets are those which could have been sold to the same type market (e.g., intrastate or interstate);
(7) Comparable sales should be drawn from the relevant market area which may be, but is not required to be, the field from which the subject gas is produced.[62]
According to the Middleton court, comparability in time requires that the sales occur "under contracts executed contemporaneously with the sale of the gas in question",[63] or, in other words, the contract execution date rather than the date of delivery determines comparability. Additionally, to be comparable, contracts must have similar obligations between the parties.
Comparability in quality requires not only similarity in physical properties, i.e., sweet, sour or casinghead gas,[64] but also in legal characteristics, such as whether the gas is sold in the intrastate or interstate market.[65]
*984 In addition to considering sales similar in time and quality, Middleton required that comparable sales be limited to those involving similar quantities of gas.[66]
Lastly, to be comparable, sales must be derived from those whose availability to marketing outlets is similar to the gas in question. Moreover, comparable sales should be drawn from the relevant market area. Declining to follow Vela's conclusion that the relevant market area extended only to the field[67] from which the gas was produced, the Middleton court found that the size of the relevant market area depended upon the facts in each case.
The plaintiff-royalty owner's expert in Middleton reviewed over 30,000 Purchasers' Monthly Gas Tax Reports to formulate his opinion of market value. These reports, filed monthly with the Texas State Comptroller of Public Accounts, contain the name of the purchaser and seller, the month and year of each sale, the lease and county of production, quality, volume, price and whether the gas was produced from an oil well or a gas well. To arrive at his opinion of market value, the expert computed the arithmetical average of the three highest prices paid for the first month of each quarter for any quantity of gas anywhere in the relevant market area designated as Texas Railroad Commission Districts 2, 3 and 4. By expert testimony, Exxon sought to convince the court that its "field price" was market value. Field price is calculated by dividing the total price paid for gas currently being delivered to all major purchasers in one month for each quarter by the total volume of gas delivered. The "field" utilized by Exxon's expert was Texas Railroad Commission District 3 plus seven adjoining counties.
The trial court adopted plaintiff's expert's determination of market value. On appeal, the Court of Civil Appeals disapproved of both experts' opinions: plaintiff's, because it failed to satisfy Vela; and Exxon's, because its price was computed in part on interstate sales. The Supreme Court of Texas held that testimony by plaintiff's expert was sufficient to support the trial court's determination of market value and affirmed usage of Texas Railroad Commission Districts 2, 3 and 4 as the relevant market area based on testimony that price redetermination clauses of many gas purchase contracts utilized that as the relevant market area for gas produced along the Gulf Coast. Sales on which the expert relied were found to be comparable in quality *985 as most of the gas was "sweet" and all moved in the intrastate market. Moreover, the court noted that the expert adjusted his figures to compensate for variances in Btu content[68] and that the sales were comparable regardless of the volume. The court concluded that the expert also satisfied requirements of comparability in time and availability to marketing outlets. The Supreme Court rejected Exxon's computations because its sales were not comparable in quality (Exxon's "field price" included interstate, as well as intrastate sales) and because Exxon made a distinction in the method of computing field price depending on the gas' vintage.
The Middleton court elaborated somewhat on the comparability test enunciated in Vela and reiterated Vela's conclusion that "a mathematical average of all prices paid in the field is `not a final answer to the difficult problem of determining market value at any particular time.'" However, the Middleton court failed to adopt the formula on which Vela relied in determining market value. The Vela court had approved the expert's calculation which computed market value as the average price received for all gas sold in the field. The Middleton court accepted the expert's determination of market value derived from the arithmetical average of the three highest prices of gas sales in the relevant market area. This approach had been utilized by the expert in Butler v. Exxon Corporation, 559 S.W.2d at 413.
In Exxon Corporation v. Jefferson Land Company, Inc., 573 S.W.2d 829 (Tex.Civ. App.1978), Exxon proposed to compute market value by obtaining records from the Comptroller's office which reflected amounts paid for each quarter for all natural gas by all producers in the Texas Railroad Commission District No. 3 and seven other East Texas counties. Gross receipts were then divided by total production which resulted in the "weighted average market price". The court in Jefferson approved of such method.[69]
Any determination of market value initially requires designation of a relevant market area from which comparable sales may be drawn. The Texas courts have recognized that the market area will vary according to the facts in each case.[70] Once relevant market area is established, comparable sales within that area form the basis for calculating market value. Because of the sophistication and complexity of the industry, courts have come to rely on industry experts to formulate methods of computing market value. Generally, these experts *986 are allowed reasonable flexibility and discretion in explaining the rationale and facts underlying their opinions.[71] Their opinions may be based upon sales that are fairly comparable and objections go to weight and not admissibility.[72] Indeed, in most cases, "some evidence" supportive of the trial court's determination of market value has been deemed sufficient to sustain the court's finding.[73]
However, this Court hesitates to blindly follow the opinions given by industry experts. In the case sub judice, it is our conclusion that the data relied upon Plaintiffs' expert, Mr. Max Powell, in formulating his opinion regarding market value, fails to satisfy the comparability tests enunciated in Vela and Middleton and that his method of computation fails to accommodate necessary factors in determining the market value of the subject gas. This Court scrutinized the testimony presented by Powell and struggled without success to find demonstrative comparability in sales on which Powell relied and to understand the theoretical basis for his computation. Such is not surprising in light of the treatment heretofore accorded this issue.[74]
After considerable analysis, this Court makes the following conclusions with regard to determining comparability of sales in the oil and gas industry:
First, sales must be comparable in time. This standard requires that market value be derived from contracts executed contemporaneously with the sale of the subject gas. This Court previously determined that contracts for the sale of gas are executory contracts with completion occurring upon delivery. This conclusion, of necessity, requires an examination of all contracts for the sale of gas, otherwise comparable, executed since the date of the first sales of the subject gas.
Gas is comparable in quality when its properties are legally and physically similar. Legal comparability requires that the gas sales compared must occur in the same market, interstate or intrastate. Physical comparability limits analysis of comparable sales to those sales having similar characteristics. One must consider and take into account in finding comparability, whether the compared gas is sweet or sour, its BTU content and its pressure.
Comparability in quantity indicates that the sales of gas compared must be of similar volumes.
Lastly, to be comparable, sales must be derived from those whose availability to marketing outlets is similar to the gas in question. Availability to marketing outlets takes into consideration potential customers, deliverability, and reserves.
As a matter of law, courts have held that comparability in sales requires only that the sales be reasonably similar. The Court anticipates that it will be difficult to find sales that are truly comparable. Despite the apparent flexibility which "reasonable similarity" imparts, it is incumbent upon the parties, in the first instance, to present relevant evidence of comparable sales and upon the court in the second instance, to scrutinize and weigh such evidence to ensure its probative value.
Defendants have indefatigably maintained that sales of sweet gas cannot be compared to sales of the subject gas which, in its raw state, is sour. The Court can readily perceive that the two are incomparable and that their sales prices would vary significantly. Sour gas is less valuable because of expenses necessary to render it merchantable. However, the subject gas is *987 comparable to sweet gas in that it is processed prior to marketing.[75]
From the testimony at trial, it is apparent that oil and gas resources in Mississippi are relatively undeveloped and that production from the subject fields was an unprecedented discovery in its volume, deliverability and reserves. While the Court believes that such would render sales of the subject gas comparable to any sale of gas otherwise comparable, these factors limit comparability in view of the requirement that sales be similar in their quantity and availability to market. The unprecedented volume, deliverability and reserves of production in the Thomasville, Piney Woods and Southwest Piney Woods Fields distinquishes the subject gas from other discoveries in Mississippi. Ideally, sales relied upon should be comparable in these respects. In states having more extensive oil and gas production, the quest for comparability would not be complicated, as here, by their absence. Appreciating this difficulty, the Court has formulated a method for computing market value which we believe accounts for these novel circumstances. Additionally, we believe this method of computation addresses the escalating price of gas while acknowledging the reality of the oil and gas industry that gas is generally committed under long-term contracts even though sold upon delivery.
As discussed above, courts addressing this issue have used various approaches in computing market value. In Vela, the court mathematically computed an average of all sales in the field during the relevant time by dividing the value received by the volume sold. In Jefferson, the court computed market value by dividing the total receipts reported for one month in each quarter for gas delivered in the market area by the total volume of gas delivered. In Butler and in Middleton, the courts accepted a mathematical average of the highest three prices in the relevant market area computed for the first month of each quarter during the relevant period. By far the easier solution for this Court would be the adoption of one of these methods. The Court, however, believes there is a more equitable approach available which will acknowledge more fully the requirements of comparability. Once the relevant market area is defined and comparable sales are identified, the Court concludes that computation of market value should be made by the division of net sales receipts derived from sales of comparable gas (after necessary adjustments for variances in Btu content and compression charges) by the total volume sold.[76]
The Court has not undertaken an assignment of a dollar and cent valuation to the subject gas because of the lack of relevant evidence addressing comparability. We recognize the necessity for further proof on this matter and hereby instruct the attorneys to contact the Court for direction.
IV
Attorney's Fees and Prejudgment Interest
Plaintiffs contend they are entitled to recover their attorneys' fees and costs, including expert expenses, due to Defendant's alleged bad faith in handling Plaintiffs' royalty payments. Defendant submits Plaintiffs' claims for such relief are based upon a frivolous allegation of bad faith. Both parties rely upon Alyeska Pipeline Service Co. v. The Wilderness Society, 421 U.S. 240, 95 S. Ct. 1612, 44 L. Ed. 2d 141 (1977), for support.
According to Alyeska, the "American Rule" dictates that: "... the prevailing litigant is ordinarily not entitled to collect a reasonable attorneys' fee from the loser, ... absent statute or enforceable contract, ... willful disobedience of a court order, ... or when the losing party has acted in *988 bad faith, vexatiously, wantonly, or for oppressive reasons...."[77]
Before this punitive device is triggered, it is essential that the successful litigant substantiate the existence of "bad faith" by the unsuccessful litigant. The record in the case sub judice is totally devoid of any basis for awarding attorneys' fees and costs against Shell under the "bad faith" exception to the American Rule. Therefore, Plaintiffs are not entitled to this relief.
Plaintiffs further contend they are entitled to recover six percent (6%) simple interest on the amounts of royalty they allege were wrongfully withheld by Shell from the date that royalty should have been paid until the present. Defendant maintains that prejudgment interest is appropriate in Mississippi only where the plaintiff's claim was liquidated or where the defendant's denial of the claim was frivolous or in bad faith.
This Court concludes that pursuant to Mississippi law, prejudgment interest is inappropriate in this case. According to Home Insurance Co. v. Olmstead, 355 So. 2d 310, 313-14 (Miss.1978), prejudgment interest may be allowed only in cases where the amount allegedly due was liquidated when the claim is originally made or where the denial of a claim was frivolous or in bad faith. See also, Mitchell v. Aetna Casualty & Surety Co., 579 F.2d 342, 352 (5th Cir. 1978); Dunn v. Koehring Co., 546 F.2d 1193, 1201 (5th Cir.), reh. denied in part, granted in part, 551 F.2d 73 (5th Cir. 1977); Charles Stores, Inc. v. Aetna Insurance Co., 327 F. Supp. 525, 527 (N.D.Miss.1971), aff'd, 490 F.2d 64 (5th Cir. 1974); Commercial Union Insurance Co. v. Byrne, 248 So. 2d 777, 783 (Miss.1971). Since neither situation exists in the present case, prejudgment interest will be denied.
An order in accordance with this opinion shall be submitted by the parties as provided by the Local Rules.
NOTES[1] Exhibit P-6 is a list of members in the plaintiff class as finally certified: Mrs. Henry V. Bailey; A. C. Barton; Roddie C. Berry; Gussie Mae Berry; Black Warrior Minerals, Inc.; R. T. Boteler; H. J. Boyd; Lee Dora Burch; Jack F. Burke; Ralph C. Butler; Agnes Chapman Butler; Colaro Corporation; D'Lo Royalties, Inc.; W. R. Fairchild Const. Co. Ltd. in care of the Merchants National Bank of Mobile; Wiley Fairchild; Albert L. Fairley, Jr.; James V. Fairley; Dorothy H. Gillespie; Georgia L. Jenkins Glissom; Mrs. Zoe P. Hall; Hattiesburg American Publishing Co.; Hayes Petroleum Inc.; H. A. Hedbert; Mrs. Noreen Hogg; Ann Hough Hopkins; Don F. Hugus, Jr.; George D. Hunt; Mary C. Jenkins; Velma R. Jenkins; Lawson Johnson; Louis Johnson; Louise Johnson; Mary Johnson; James E. King, Jr.; Lignum Oil Co.; W. Baldwin Lloyd; Mary C. Lynn; Deposit Guaranty National Bank, Assignee of A. W. Magruder, Jr.; M. H. Marr; E. B. McGehee; H. C. McGehee; Rev. Julius A. McRaney; Kenneth Allen McRaney; Merchants National Bank of Mobile, Assignee of Lester Meng, Jr.; Betty D. Mortimer; Glenn G. Mortimer, Jr.; Aline F. Neal; Walter R. Neill; Deposit Guaranty National Bank, Assignee of John D. Noble; Pachuta Corp.; Edith Perkins Patton; First National Bank of Jackson, Trustee under the Kathryn Susan Parsons Perez Trust; Peoples National Bank of Tyler, Texas, Trustee (Pirtle Trust); Dr. David L. Perkins; The Piney Woods Country Life School; T. S. Price; Louise M. Reese; Ridgway Management, Inc.; L. P. Rush; Citizens Bank of Hattiesburg, Trustee of the L. P. & Eunice H. Rush Trust; Carol H. Ryan; Katherine Westbrook Ryan; Thad J. Ryan; Thad J. Ryan, Jr.; Sabine Royalty Corp.; Ralph V. St. Johns; R. H. Sims; Guy W. Smith; Thomas L. Spengler, Jr., individually, and as Executor and as sole and only heir of the Estate of Maggie Fairley Spengler; G. G. Stanford; Sun Oil Co.; F. M. Tatum; Will S. Tatum; Joe A. Thompson; Robert L. Thomsen; Mrs. Jessie Neal Vaughan; Caroline Neal Vaughan; E. H. Wilkins; Watson W. Wise.
[2] A sixth unit, on the Spengler # 1 well located in the Thomasville Field, has begun production since the filing of the instant action.
[3] A list of the leases pooled in each of the five (5) wells appears in evidence as Exhibit P-13. A breakdown of each Plaintiff's fractional royalty interest in each unit and each lease appears in the Title Sheets which are in evidence as Exhibit P-14. A summary of ownership information is provided in Exhibit P-6.
[4] Brackets indicate variations between lease forms (1) and (2) above.
[5] "H2S" is the denotation used in chemistry to represent the compound hydrogen sulfide.
[6] Exhibit No. D-27 contains a chemical breakdown of the production from each of the wells that produces gas processed at the Thomasville Plant.
[7] The transportation fee assessed on gas sold to MisCoa is four and one-half (4½) cents per Mcf. This fee reimburses the cost of the forty-mile pipeline from the tailgate of the Thomasville Plant to MisCoa's plant in Yazoo City and the fee of approximately $41,000.00 a month for management of the pipeline paid to Mustang Fuel.
[8] "Mcf" is defined as "one thousand cubic feet of gas". Williams and Meyers, Oil and Gas Law, "Manual of Terms".
[9] According to the formula, the gathering system cost recovered is the capital investment of the system, together with a return on that investment. The operating cost of the gathering system is included in the operating cost of the plant.
[10] The plant share fraction applied to sulphur revenues is as follows:
Sulphur Plant Sulphur Plant
(Operating ) (Investment ) 0.000728
________
(Cost $/Day ) + ( $ ) ( Day )
------------------------------------------------
(Plant Average Sulphur Sales LT/D) (Plant Netback
Sulphur Price $/LT).
MEANING OF TERMS
Sulphur Plant Operating Cost $/DayThe daily direct operating cost of the sulphur recovery portion of the Thomasville Plant.
Sulphur Plant Investment $The cumulative capital investment in the sulphur recovery portion of the Thomasville Plant.
.000728/DayA daily capital recovery factor designed to produce a maximum 15% return on investment after tax.
Plant Average Sulphur Sales LT/DThe total daily sulphur sales volume from the Thomasville Plant.
Plant Netback Sulphur Price $/LTThe net price per long ton of sulphur sales at Thomasville.
[11] The Sixty Percent Override Limitation provides as follows:
"Notwithstanding the application of the above formulae, except the specific conditions hereinafter described, Buyer shall pay Seller on a monthly basis a minimum of forty percent (40%) of the combined revenue from Adjusted Net Sales Gas and Sulphur. This forty percent (40%) minimum shall no longer be effective if, in order to meet requirement under applicable Federal, State or local environmental laws, rules, regulations, standards or policies for continued operation of the Thomasville Plant, either of the following occurs: (i) for any twelve-month period the total operating costs for both the treating and sulphur recovery portions of the Plant increase by as much as thirty percent (30%) over the average yearly operating costs experienced during the period beginning January 1, 1973 and ending at the start of such twelve-month period, or (ii) additional capital expenditures of more than $2,500,000 are required for modification of the Plant."
[12] Shell's contract with MisCoa is in evidence as Exhibit No. P-18(a)-(f). The Mississippi Power & Light contract is Exhibit No. P-19.
[13] "Off lease" fuel is gas which is produced from one unit but is used to operate facilities on another unit. "On lease" fuel is that part of a unit's production retained by Shell as lessee, to operate lease facilities on the unit at which it is produced. Under the subject leases, as is customarily the case, the lessee is not required to pay royalty on gas used on the unit from which it is produced.
[14] From information available at the time of trial, and set out in Exhibit No. D-11, the Douglas Spread Sheets, sulphur royalty was then being computed on $54.27 per long ton.
[15] See e.g. Gilmore v. Superior Oil Company, 192 Kan. 462, 388 P.2d 602, 607 (1964); Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S.W.2d 989 (1935); Pan American Petroleum Corp. v. Southland Royalty Co., 396 S.W.2d 519 (Tex.Civ.App.1975); Merrill, Covenants Implied in Oil and Gas Leases § 85, 214-15 (2ed. 1940).
[16] See Siefkin, George, "Rights of Lessor and Lessee with Respect to Sale of Gas and as to Gas Royalty Provisions", Southwestern Legal Foundation, Fourth Annual Institute on Oil and Gas Law and Taxation, 181, 201 (1953).
[17] See, lease forms entitled "Producers 88 Revised (11-56)" and "Producers 88 (9/70)" provide: "Lessee covenants and agrees to use reasonable diligence to produce, utilize or market the minerals capable of being produced from said wells, but in the exercise of such diligence, lessee shall not be obligated to install or furnish facilities other than well facilities and ordinary lease facilities of flowlines, separator, and lease tank...." (emphasis added).
[18] Each of the subject royalty provisions contains language to the effect that when royalty is computed on the basis of market value, such computations are of value "at the well" or "at the mouth of the well".
[19] See e.g., Texaco, Inc. v. Pigott, 235 F. Supp. 458, 464 (S.D.Miss.1964), aff'd, 358 F.2d 723 (5th Cir. 1966) (per curiam); Mounger v. Pittman, 235 Miss. 85, 108 So. 2d 565, 566 (1959); Palmer v. Crews, 203 Miss. 806, 35 So. 2d 430, 435 (1948).
[20] Texaco, Inc. v. Pigott, 235 F. Supp. 458, 464 (S.D.Miss.1964), aff'd, 358 F.2d 723 (5th Cir. 1966) (per curiam); Mounger v. Pittman, 235 Miss. 85, 108 So. 2d 565, 566 (1959); Palmer v. Crews, 203 Miss. 806, 35 So. 2d 430, 435 (1948).
[21] See note 19 supra.
[22] Gulf Refining Co. v. Stanford, 202 Miss. 602, 30 So. 2d 516, 517 (1947).
[23] See also, Interstate Gas Co. v. EPC, 331 U.S. 682, 689-91, 67 S. Ct. 1482, 1486-87, 91 L. Ed. 1742 (1947); Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 597-604, 65 S. Ct. 829, 837-840, 89 L. Ed. 1206 (1945).
[24] 3 Williams, Oil and Gas § 645, pp. 591-93 (1977); Aultman, Richard, Kindberg, Charles, "Oil and Gas: Nonoperating Interests Liability" 25 Okla. Law Review 363, 369-76 (1972).
[25] See Williams, note 24 supra at 591-93.
[26] Id. See Also, Aultman, note 24 supra at 369-76.
[27] Id. See also, Holbein v. Austral Oil Co., Inc., 609 F.2d 206, 209 (5th Cir. 1980) (per curiam).
[28] Although Louisiana law was applied in Freeland, the court stated that the solution to the problem of determining royalty was to be found in the lease contract. 277 F.2d at 157. The gas royalty clause considered, identical to Producers 88-D9803 in controversy in the case sub judice, provides:
"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...." Id. (emphasis added).
See also, pages 4-5 supra for lease provisions in evidence. The court interpreted the plain meaning of the contract to that on gas sold or used off the premises, market value is the "market value at the well." This conclusion supports Shell's contention that royalty must be based on wellhead value. See also, Holbein v. Austral Oil Co., Inc., 609 F.2d 206, 209 (5th Cir. 1980) (per curiam).
[29] 277 F.2d at 158-59. See Scott Paper Co. v. Taslog, Inc., 638 F.2d 790, 799 (5th Cir. 1981) (court approved method of determining value of gas by deducting from sales revenue the costs of the transmission, processing and a reasonable return on investment); Holbein v. Austral Oil Co., Inc., 609 F.2d 206, 209 (5th Cir. 1980) (per curiam) (royalty shares proportionately in costs subsequent to production); Ashland Oil, Inc. v. Phillips Petroleum Co., 554 F.2d 381, 384 (10th Cir. 1977) (en banc) (third party processor has the right to recover a return on its investment); Barby v. Caboe Corp., 465 F.2d 11, 15 (10th Cir. 1972) (royalty was precluded from contending an entitlement to royalties on the end product after extraction); Cameron v. Stephenson, 379 F.2d 953, 956 (10th Cir. 1967) (royalty must bear its share of transportation costs); Phillips Petroleum Co. v. Record, 146 F.2d 485 (5th Cir. 1944) (attempt by lessor to base royalty on value of products manufactured rather than on value of gas itself "will not do at all"); Kretni Development Co. v. Consolidated Oil Corp., 74 F.2d 497, 500 (10th Cir. 1934), cert. denied, 295 U.S. 750, 55 S. Ct. 829, 79 L. Ed. 1694 (1935) (lessee's duty to market gas does not extend to providing ninety miles of pipeline facilities); Armstrong v. Skelly Oil Co., 55 F.2d 1066 (5th Cir. 1932) (lessee-operator of a gasoline extracting plant is entitled to recover a fair return on his investment).
[30] See note 27 supra.
[31] See Exhibit P-63.
[32] Craig v. Champlin Petroleum Co., 300 F. Supp. 119 (W.D.Okl.1969), aff'd, 421 F.2d 236 (10th Cir. 1970); Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex. Civ.App.1979).
[33] Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84, 93 (5th Cir. 1966); Waechter v. Amoco Production Co., 217 Kan. 489, 537 P.2d 228 (1975).
[34] Southwest Gas Producing Co. v. Seale, 191 So. 2d 115, 119-20 (Miss.1966).
[35] See, e.g., Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84, 93 (5th Cir. 1966); Newell v. Phillips Petroleum Co., 144 F.2d 338 (Okl. 1944); Foster v. Atlantic Refining Co., 329 F.2d 485, 489 (5th Cir. 1964); Craig v. Champlin Petroleum Co., 300 F. Supp. 119 (W.D.Okl. 1969), aff'd, 421 F.2d 236 (10th Cir. 1970); Nordan-Lawton Oil & Gas Corp. of Texas v. Miller, 272 F. Supp. 125, 135 (W.D.La.1967); Harding v. Cameron, 220 F. Supp. 466, 470 (W.D.Okl. 1963); 2 Summers, The Law of Oil & Gas § 400 (1959).
[36] Craig v. Champlin Petroleum Co., 300 F. Supp. 119 (W.D.Okl.1969), aff'd, 421 F.2d 236 (10th Cir. 1979); Nordan-Lawton Oil & Gas Corp. of Texas v. Miller, 272 F. Supp. 125, 135 (W.D.La.1967); Harding v. Cameron, 220 F. Supp. 466, 470 (W.D.Okla.1963); Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex.Civ.App.1979); Southwest Gas Producing Co. v. Seale, 191 So. 2d 115, 119-20 (Miss.1966).
[37] Nordan-Lawton Oil & Gas Corp. of Texas v. Miller, 272 F. Supp. 125, 135 (W.D.La.1967); 2 Summers, The Law of Oil & Gas §§ 400, 415 (1959).
[38] 2 Summers at § 415.
[39] 300 F. Supp. at 122, 124.
[40] See Exhibits P-18(a) §§ 6.1, 1.1(i); P-19 §§ 6.1, 1.1(g).
[41] See e.g., Barby v. Cabot Corp., 465 F.2d 11 (10th Cir. 1972); Waechter v. Amoco Production Co., 217 Kan. 489, 537 P.2d 228 (1975); Stanolind Oil & Gas Co. v. Cities Service Gas Co., 178 Kan. 202, 284 P.2d 608 (1955).
[42] Miss.Code Ann. §§ 75-1-10111-108 (1972), particularly Miss.Code Ann. §§ 75-2-101725 (1972).
[43] The Uniform Sales Act (Codes 1942, § 41A:2-105; Laws, 1966, Ch. 316 § 2-105, eff. Mar. 31, 1968) provided that if the contract for sale allowed the buyer an opportunity to inspect and reject the goods once delivered, then title did not pass until the buyer had a reasonable opportunity to inspect.
[44] Pursuant to the contract, royalty owners agreed to a price of 2.3 cents per Mcf. Plaintiffs instituted suit to recover alleged deficiencies predicated on a 13.047 cents per Mcf current market price. 429 S.W.2d at 869.
[45] 429 S.W.2d at 871. See also, J. M. Huber v. Denman, 367 F.2d 104, 109 (5th Cir. 1966) (market value not synonymous with actual proceeds); Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84 (5th Cir. 1966) (same); Lightcap v. Mobil Oil Corp., 221 Kan. 448, 562 P.2d 1, 2, 5 (1977) (same).
[46] 288 S.W. at 433. Accord, Foster v. Atlantic Refining Co., 329 F.2d 485, 489 (5th Cir. 1964); Kingery v. Continental Oil Co., 434 F. Supp. 349, 352, 354 (W.D.Tex.1977), rev'd, 626 F.2d 1261 (5th Cir. 1980); Exxon Corp. v. Jefferson Land Co., Inc., 573 S.W.2d 829, 832 (Tex.Civ. App.1970); Exxon Corp. v. Middleton, 571 S.W.2d 349, 354 (Tex.Civ.App.1978), rev'd, 613 S.W.2d 240 (Tex.1981); Butler v. Exxon Corp., 559 S.W.2d 410, 416 (Tex.Civ.App.1977). See Also, J. M. Huber Corp. v. Denman, 367 F.2d 104, 113-14 (5th Cir. 1966).
[47] See Montana Power Co. v. Kravik, 586 P.2d 298, 302 (Mont. 1978); Exxon Corp. v. Middleton, 571 S.W.2d 349, 354 (Tex.Civ.App.1978), rev'd, 613 S.W.2d 240 (Tex.1981); Sartor v. United Gas Public Service Co., 186 La. 555, 173 So. 103, 105 (1937); Sartor v. United Carbon Co., 183 La. 287, 163 So. 103, 103 (1935).
[48] 329 F.2d at 489.
[49] Id. at 489-90.
[50] Defendant relies upon Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S. Ct. 794, 98 L. Ed. 1035 (1964) and United Gas Improvement Co. v. Continental Oil Co., 381 U.S. 392, 85 S. Ct. 1517, 14 L. Ed. 2d 466 (1965) for the proposition that a total, completed sale takes place upon signing the initial contract. However, the court in Kingery stated that these rulings were merely determinations that such contracts were to be regulated by the Natural Gas Act and not that such contracts constituted a complete sale upon execution. 434 F. Supp. at 354.
[51] 434 F. Supp. at 353.
[52] 173 So. at 105.
[53] 367 F.2d at 90.
[54] Id. at 91, n.26.
[55] 562 P.2d at 6.
[56] See Kingery v. Continental Oil Co., 434 F. Supp. 349, 356 (W.D.Tex.1977), rev'd on other grounds, 626 F.2d 1261 (5th Cir. 1980) (division orders executed in 1951 and 1952 may bar plaintiff's claims for additional royalties under those contracts). But see, Craig v. Champlin Petroleum Co., 300 F. Supp. 119, 125 (W.D.Okl. 1969), aff'd, 421 F.2d 236 (10th Cir. 1970) (lessors are not estopped from claiming higher royalties based on market price by division orders); Butler v. Exxon Corp., 559 S.W.2d 410, 417 (Tex.Civ.App.1977) (same); J. M. Huber Corp. v. Denman, 367 F.2d 104, 110 (5th Cir. 1966) (division orders constitute a definite basis for payment so that payments made in accordance therewith are final and binding, although they may be withdrawn as to future payments); Phillips Petroleum Co. v. Williams, 158 F.2d 723, 727 (5th Cir. 1947) (same).
[57] Defendant-Shell also relies on two Oklahoma cases, Pierce v. Texas Pacific Oil Co. Inc., 547 F.2d 519 (10th Cir. 1976) and Apache Gas Products Corp. v. Oklahoma Tax Commission, 509 P.2d 109 (Okl.1973). We find these two cases clearly distinguishable in that both were resolved on the basis of the construction of a particular Oklahoma tax and communitization statute. Therefore, these cases have no bearing on the issue at hand.
[58] The "comparability" test announced in Vela was borrowed from Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 199 (5th Cir.), cert. denied, 329 U.S. 714, 67 S. Ct. 44, 91 L. Ed. 620 (1946), wherein the Fifth Circuit stated that "the test is what do such producers pay for gas similar in quantity, quality, and availability to market."
[59] 429 S.W.2d at 873.
[60] The expert noted that reserves are not a significant factor when there are existing pipelines in the field.
[61] The Texas Supreme Court considered the issue of whether the sales of gas occurred "at the well" or "off the premises" to be more important; thus overruling the decision in Butler v. Exxon Corp., 559 S.W.2d 410 (Tex.Civ. App.1977), regarding this point.
[62] See, Holliman, Exxon Corp. v. Middleton: Some Answers But Additional Confusion in the Volatile Area of Market Value Gas Royalty Litigation, 13 St. Mary's L.J. 1, 43 (1981).
[63] 613 S.W.2d at 246. Compare Kingery v. Continental Oil Co., 434 F. Supp. 349, 355 (W.D. Tex.1977), rev'd, 626 F.2d 1261 (1980) (comparability as to time depended on the date of delivery, regardless of the contract date) with Butler v. Exxon Corp. 559 S.W.2d 410, 413 (Tex.Civ.App.1977) (court accepted expert's opinion of market value which admittedly was based upon new gas coming into the market under current market conditions).
[64] The expert testifying in Vela, 429 S.W.2d 866, 872 (Tex.1968), adjusted the computed market price for differences in well pressure for some of the sales included in the computations.
[65] See Kingery v. Continental Oil Co., 626 F.2d 1261, 1264 (5th Cir. 1966) (comparable sales are those derived solely from the interstate or intrastate markets); Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84, 88-93 (5th Cir. 1966) (interstate sales); Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 199 (5th Cir.), cert. denied, 329 U.S. 714, 67 S. Ct. 44, 91 L. Ed. 620 (1946) (testimony regarding interstate sales is incompetent); Domatti v. Exxon Corp. 494 F. Supp. 306, 309 (W.D.La.1980) (intrastate sales are not comparable for determining the market value of regulated gas); Brent v. Natural Gas Pipeline Co., 457 F. Supp. 155, 162 (N.D. Tex.1978), aff'd, 626 F.2d 1261 (5th Cir. 1980) (only interstate sales are admissible to determine market value of regulated gas); Hemus & Co. v. Hawkins, 452 F. Supp. 861, 864-65 (S.D. Tex.1978) (same); First National Bank in Weatherford v. Exxon Corp., 597 S.W.2d 783, 785 (Tex.Civ.App.1981) (same); Exxon Corp. v. Jefferson Land Co., 573 S.W.2d 829, 831 (Tex. Civ.App.1978); Butler v. Exxon Corp., 559 S.W.2d 410 (Tex.Civ.App.1977); Amoco Prod. Co. v. First Baptist Church of Pyote, 579 S.W.2d 280, 288-89 (Tex.Civ.App.1979); Sartor v. United Gas Public Service Co., 186 La. 555, 559, 173 So. 103, 105 (1937); Wall v. United Gas Public Service Co., 179 La. 908, 918, 152 So. 561, 565 (1934). But see, Lightcap v. Mobil Oil Co., 221 Kan. 448, 562 P.2d 1, 8, cert. denied, 434 U.S. 876, 98 S. Ct. 228, 54 L. Ed. 2d 156 (1977) (intrastate and interstate sales are comparable).
[66] Note that the Vela decision omitted the requirement that comparable sales be of similar volumes. 429 S.W.2d 866, 872 (Tex.1968). Plaintiffs' expert testified that reserves were unimportant in valuation of market value when pipelines have already been laid in the field. Id. Cf. Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 199 (5th Cir.), cert. denied, 329 U.S. 714, 67 S. Ct. 44, 91 L. Ed. 620 (1946) (the court, construing Texas law, stated that the test for market value is what do producers pay for gas similar in quantity, quality, and availability to market).
[67] Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 198 (5th Cir. 1946) (the court stated that the question was not what happened in the county where the gas was produced, but whether or not there have been recent, substantial and comparable sales of like gas from wells in the area whose availability for marketing is reasonably or substantially similar to that of the gas involved).
[68] "Btu" is the abbreviation for British thermal unit, the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit. Williams and Meyers, Oil and Gas Law, "Manual of Terms".
[69] The court noted that this weighted average market price was appropriate only for gas produced after January 1, 1973. 573 S.W.2d at 831. Accordingly, the weighted average market price was that price at which all gas produced in the area by all producers was sold under contracts entered into after January 1, 1973. Id. The court stated that much of the gas sold was under contracts made before January 1, 1972. Id. However, no mention was made of the treatment these sales received in determining market value.
[70] See Exxon Corp. v. Middleton, 613 S.W.2d 240, 247 (Tex.1981) (size of the market area depends upon the facts in the case; in this instance, Texas Railroad Commission Districts Nos. 2, 3, 4 were utilized which included most of the Texas Gulf Coast); Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 872 (Tex.1968) (the "field" comprised the relevant market area); Amoco Prod. Co. v. First Baptist Church of Pyote, 579 S.W.2d 280, 287 (Tex.Civ.App. 1979) (field); Exxon Corp. v. Jefferson Land Co., 573 S.W.2d 829, 831 (Tex.Civ.App.1978) (Railroad Commission District No. 3 plus seven other east Texas counties); Butler v. Exxon Corp. 559 S.W.2d 410, 413, 417 n.2 (Tex.Civ. App.1977) (expert began with a seven-county area and ultimately concentrated on a two-county area). See also, Phillips Petroleum Co. v. Bynum, 155 F.2d 196, 198 (5th Cir.), cert. denied, 329 U.S. 714, 67 S. Ct. 44, 91 L. Ed. 620 (1946) ("wells in the area"); Brent v. Natural Gas Pipeline Co. of America, 457 F. Supp. 155, 160 (N.D.Tex.1978), aff'd, sub nom. Kingery v. Continental Oil Co., 626 F.2d 1261 (5th Cir. 1980) (market area defined as "the geographical area in which the wells producing such gas were located"); Kingery v. Continental Oil Co., 434 F. Supp. 349, 351 (W.D.Tex.1977), rev'd, 626 F.2d 1261 (5th Cir. 1980) (relevant market area described as the "immediate vicinity").
[71] Exxon Corp. v. Middleton, 613 S.W.2d 240, 249 (Tex.1981) quoting Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84, 91 (5th Cir. 1966).
[72] 613 S.W.2d at 249.
[73] Id. See also, Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 869, 874 (Tex.1968).
[74] In good faith we cannot follow Butler v. Exxon Corp., 559 S.W.2d 410 (Tex.Civ.App. 1977), wherein the court accepted the testimony of Max Powell due to the failure of defendant to refute his testimony.
[75] After deductions for processing, etc., royalty for the subject gas is paid on the "wellhead value", or its sour gas value. Such payment is of no consequence in comparison of sales prices of sweet and sour gas.
[76] The Court does not decide at this point whether market value computations will be made monthly or quarterly.
[77] 421 U.S. at 247-259, 95 S. Ct. at 1616-1622. F. D. Rich Co., Inc. v. United States ex rel. Industrial Lumber Co. Inc., 417 U.S. 116, 129, 94 S. Ct. 2157, 2165, 40 L. Ed. 2d 703 (1974); Vaughn v. Atkinson, 369 U.S. 527, 82 S. Ct. 997, 8 L. Ed. 2d 88 (1962). See also, Hall v. Cole, 412 U.S. 1, 93 S. Ct. 1943, 36 L. Ed. 2d 702 (1973); Newman v. Piggie Park Enterprises, Inc., 390 U.S. 400, 88 S. Ct. 964, 19 L. Ed. 2d 1263 (1968); Knights of Ku Klux Klan, Realm of Louisiana v. East Baton Rouge Parish School Board, 643 F.2d 1034, 1036-37, n.1 (5th Cir. 1981); Blue v. Bureau of Prisons, 570 F.2d 529, 531-32 (5th Cir. 1978).
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