
    FIRST NATIONAL BANK IN WEATHERFORD, Texas, Appellant, v. EXXON CORPORATION et al., Appellees.
    No. 6946.
    Court of Civil Appeals of Texas, El Paso.
    March 5, 1980.
    Rehearing Denied April 23, 1980.
    
      Day & Day, Joe Day, Jr., David Ezarik, Marshall Day, Fort Worth, for appellant.
    Baker & Botts, Frank G. Harmon, Stephen M. Hackerman, Carol A. Noel, Walter B. Morgan, Morgan L. Copeland, Houston, for appellees.
    Sanders, Saunders, Brian, Finney & Thomas, Ronald D. Nickum, Amarillo, for amicus curiae Lillian Blanche Brent.
    Brite, Drought, Bobbitt & Halter, Robert Lee Bobbitt, Jr., San Antonio, Miller, Shirley, McMicken & Eckel, Preston Shirley, Galveston, for amicus curiae The Sealy and Smith Foundation for the John Sealy Hospital.
    Dyche & Wright, James T. Wright, Dennis M. Dylewski, John L. Verner, Houston, for amicus curiae Natural Gas Pipeline Company of America.
    Bullock, Scott & Neisig, Tom Scott, Midland, for amicus curiae Jane Baugh Beard, et al.
    David T. Duncan, Brownsville, for amicus curiae Louise Putegnat Sawyer, et al.
   OPINION

STEPHEN F. PRESLAR, Chief Justice.

This is a suit to recover alleged deficiencies in royalty payments to the owner of the soil from March 1, 1974, to April 30, 1979, on gas produced from a well located in Pecos County, Texas, on a section of Relinquishment Act land. Trial was to the Court without a jury, and a take nothing judgment was entered. We affirm.

Appellant, First National Bank of Weath-erford (Bank, Lessor), in its capacity as owner of the soil and agent for the State of Texas leased one-half of the section involved to a predecessor of Appellee, Exxon Corporation (Exxon, Lessee) and the other one-half to Gulf Oil Corporation (Gulf) in 1960. All interests were pooled by unity agreement in 1964 as the Oates Gas Unit No. 1. Exxon obtained a farm-out of Gulf’s lease; therefore, it is Exxon’s conduct that we are here concerned with; that is whom we will refer to as “Lessee.”

Exxon completed a producing gas well on the Unit in 1965. There were no pipeline connections available so shut-in royalties were paid as provided by the lease when “a suitable purchaser was not available.” In 1967, Exxon entered into a twenty-five year contract for sale of the gas to Northern Natural Gas Company (Northern), and secured Federal Power Commission approval of that contract. Bank was not consulted about or notified of the contract with Northern nor of the application for its approval by the Federal Power Commission. However, in November of 1968, Exxon wrote a letter to the Bank transmitting a division order. This cover letter advised the Bank that it should execute the division order if it was claiming the proceeds. On December 2, 1968, the Bank executed the division order which did provide that royalty on gas sold subject to Federal Power Commission jurisdiction shall be based on the net proceeds of the price approved by the Commission. Since that time, and at all times material hereto, Exxon has paid royalties to the Bank calculated as its fractional share of the net proceeds received from the sale of gas to Northern. The Bank accepted these royalty payments for over nine years before notifying Exxon of any dissatisfaction, and it brought this suit in the tenth year of such acceptance of royalty under the twenty-five year contract. The State of Texas and Exxon have reached some form of accord and the State is not a party to this suit.

The parties stipulated there was no market other than the interstate market available for the gas at the time of the contract between Exxon and Northern. The Court made extensive findings that Exxon prudently marketed the gas from the Unit by its sales contract with Northern, and the Bank does not contest those findings; rather, it agrees in its brief that the contract was negotiated on the best terms and conditions available, including price.

The Bank, as Lessor, seeks declaratory judgment construing the oil and gas leases to mean that the provision for payment of royalties based on value of gas contemplates such value will be determined upon prices prevailing in the open market as of the time that gas is run. It contends, then, that during the period of time involved from March, 1974, to April 30, 1979, the market value of its gas was more than it and Exxon were receiving under the Northern contract; therefore, they are entitled to additional royalties.

The royalty clause in the Exxon lease is: To deliver to the credit of the owner of the soil, free of cost, in the tanks or pipelines to which wells may be connected an additional %2nds part of all oil and gas produced and saved from said leased premises or at the option of owner of the soil Three Thirty-Seconds %2nds of the value of all oil and gas produced and saved from said premises.

The Gulf royalty clause provides:

To deliver to the credit of Lessor as the owner of the soil, free of cost, in the pipe lines to which wells may be connected, an additional equal ⅜2 part of all oil and gas produced and saved from said leased premises or at the option of Lessee to pay Lessor ⅜2 of the value of all oil and gas produced and saved from said leased premises.

The question is not before us as to whether this is a “proceeds” lease or a “value” lease; it was tried simply as a value lease. In affirming the judgment of the trial Court, we hold that Appellant did not prove that the value of the gas was greater than that received.

To prove market value of this gas, Appellant, through its expert witness, presented evidence of gas sold in the intrastate market. We do not consider these as comparable sales for purposes of arriving at market value of this gas; the intrastate gas was unregulated as to price while this gas was regulated during the five years involved. The use of this gas was restricted and its marketability thereby affected; it could not be sold in the intrastate market so its value in that market was zero. As held in Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944):

There was no market for appellee’s gas for light and fuel purposes. For such uses it would bring nothing. The price of a thing is what it will bring,

Sales in intrastate market were based on what willing buyers and willing sellers agreed to, while sellers and buyers of this gas could not contract for a price above the regulated price. They could not lawfully contract for a price above that allowed by federal regulation. Evidence of a price arrived at above the federally regulated price would not be admissible as a comparable. City of Austin v. Cannizzo, 153 Tex. 324, 267 S.W.2d 808 (1954). Recognizing those facts, Appellant argues for fixing of a “theoretical market value.” That’s not the question here, for that’s not the lawsuit before us. Appellant by this suit seeks a real, actual monetary award and not a theoretical determination of its rights. The market value to be found, then, must be the actual real value which the product would in fact bring and for which Exxon is in default under the oil and gas lease for not in fact obtaining or paying to Appellant.

No appellate court in Texas has yet made a determination of market value of gas sold in the interstate market. But, in Exxon Corporation v. Middleton, 571 S.W.2d 349 (Tex.Civ.App.—Houston [14th Dist.] 1978, writ granted), the use of a field price which included interstate sales was held not to be the appropriate measure in determining the value of intrastate gas; this is the principle applicable here, that a sale in a regulated market is not comparable to open market sales and vice versa. In the field of eminent domain, where, as here, comparables are used to determine market value, Texas law excludes evidence of sales of unrestricted property as comparable in finding the value of property which is burdened with restrictions. City of Austin v. Cannizzo, supra. It follows that recent federal court decisions are in accord with Texas law in excluding unrestricted intrastate sales of gas as not being comparable to interstate sales burdened with federal regulations. Brent v. Natural Gas Pipeline Company of America, 457 F.Supp. 155 (N.D.Tex.1978) appeal docketed, 5th Cir.; Hemus & Company v. Hawkins, 452 F.Supp. 861 (S.D.Tex.1978). Those two cases enunciate Texas law as concerns this phase of oil and gas law.

Appellant’s evidence fails in another area. Its cause of action is for value as though the gas were sold when run from day to day. Texas Oil & Gas Corporation v. Vela, 429 S.W.2d 866 (Tex.1968). Appellant offered no evidence of any gas which was sold on a day by day basis; its evidence was from contract sales and there was no evidence of lessees or producers selling their gas in the open market or on a day to day basis. Appellant seeks recovery for the gas sold in that manner, but offers no evidence of what gas would bring when marketed in that manner.

Appellant offered evidence of other gas sales within the regulated market as an alternative to its basic contention that intrastate sales are comparables. It would seem that, within the regulated field, there can be no comparables, for the regulating agency classifies and divides the gas into various categories and fixes the price for each category. With all prices fixed, we fail to see how one could be comparable to the other to make either the “market value.”

Texas Oil & Gas Corporation v. Vela, supra, sets the test for determining market value of gas to be by sales of gas comparable in time, quality and availability of market. That case did not involve price-regulated gas; in the case before us, it was stipulated that such a regulated market was the only one available at the time lessee was obligated to sell the gas. That fact must be taken into account and given consideration under the element of marketability in the Vela test. That, we have done. We have paid our respects to Vela.

As noted earlier, this case is treated by all parties as a value case. Both leases are State form leases so the State is the author, so far as any rules of construction are involved. As is seen by the royalty clause, these are “in kind” leases fixing the lessee’s royalty obligation to be to deliver the lessor’s share of the gas to it. Exxon’s lease gives the Lessor the option to accept the gas in kind or the value. The Gulf lease gives such option to the Lessee but Gulf has sought to exercise it and offered the gas in kind to Lessor but Lessor has rejected it so in effect the option in both leases now rests with the Lessor/Appellant. Under the facts of this case, Appellant has elected to waive receipt of its gas in kind. By such waiver action, it placed title to the gas in the Lessee without restrictions and fettered only by Lessee’s obligation to market it with prudence. It concedes in its brief that has been done.

Exxon was prudent and diligent in attempting to find a purchaser for gas from the Unit. The only possible purchasers at this time were interstate pipeline companies. The gas sales contract entered into was an arm’s length, prudently negotiated contract with the best terms and conditions available, including the best price which could be obtained at the time.

The right of the Lessee to place the gas into a long term contract is not questioned. The fact that it chose a regulated market is not' questioned, nor is its right to chose such a market questioned. As was its right, Appellant has elected not to take its gas in kind and market it for such value as existed under its theory of recovery; it has brought this action to recover such value from its Lessee. The trial Court has held, and we have sustained its finding, that it failed in its proof of such value. We see no further questions as to the correctness of the trial Court’s judgment. All points of error have been considered, and all are overruled. The judgment of the trial Court is affirmed.

OSBORN, Justice,

dissenting.

I respectfully dissent. This case involves the basic question as to whether prices paid for gas sold in the intrastate market may be considered in deciding the value of a royalty owner’s gas sold in the interstate market on a long term contract where the lease contains a “value” gas royalty clause.

BACKGROUND

The basic issue of deciding the value of a royalty owner’s gas was first considered in Texas Oil & Gas Corporation v. Vela, 429 S.W.2d 866 (Tex.1968). In that case, the issue arose out of a contract for gas sold at 2.3c per Mcf and produced and delivered at a time when the market price was 13.047c per Mcf. Now, we are faced with a case where the original contract price was 16.5c per Mcf and gas in the area has now exceeded $2.10 per Mcf. The rapid increase in the price of natural gas in the intrastate market has resulted in substantial litigation between royalty owners and producers. And, the issue in those cases involving the intrastate sales of gas has now spread into the area of interstate sales of gas. Again, the litigation is substantial and increasing rapidly.

FACTS

The basic facts upon which this case is to be decided are not in dispute. The Bank, as owner of the surface and for the State of Texas as owner of the minerals, executed an oil and gas lease covering a half-section of land in Pecos County to Humble Oil and Refining Company, a predecessor in interest of Exxon, and another oil and gas lease covering an adjoining half-section of land to Gulf Oil Corporation, each lease being executed under the provisions of the Relinquishment Act. These leases were pooled to form the Oates Gas Company Unit No. 1. In July, 1965, a producing well was completed. Shut-in gas royalties were paid as provided for in the leases because there was no available purchaser for the gas at the time the well was completed. In 1967, a twenty-five year gas sales contract was executed with Northern Natural Gas Company, an interstate pipeline company, to sell the gas from the Oates Gas Unit. Thereafter, the Federal Power Commission issued a certificate, and deliveries began in October, 1968. The Bank was not a party to, and had no knowledge of, the sale of the gas to an interstate pipeline company. But, it is agreed that Exxon was prudent and diligent in entering into the contract with an interstate carrier on the best terms and conditions then available.

The case was tried to the Court without a jury, and each side used an expert witness to establish what it considered to be the value of the gas under the leases in question during the period in dispute from March 1, 1974, to April 30, 1979.

Mr. William S. Hudson, testifying as an expert for the Bank, identified an exhibit which he had prepared, which showed the amount of gas sold each quarter during the period in question, the price paid under the contract, the highest price paid in the field, the average of the three highest prices paid in the county, the average of the three highest prices paid in the county and adjacent counties, the average of the three highest prices paid in Railroad Commission District 8, the average of the three highest prices paid in Railroad Commission Districts 7C and 8, and the price for new gas controlled by the FERC (Federal Energy Regulatory Commission, successor to the Federal Power Commission). Due to amendments to the sales contract, which provided for an escalation of the price of gas equal to that permitted by the Regulatory Commission for gas of the same vintage, the actual price paid by Northern to Exxon ranged from 17.63$ per Mcf to 29.52$ per Mcf during the period in question. In this field, the highest price ranged from 37$ per Mcf to $1.95 per Mcf. In Pecos County, sales ranged from 69$ per Mcf to $2,074 per Mcf. In Pecos and adjacent counties, it ranged from 79.8$ per Mcf to $2,107 per Mcf. New FERC controlled gas ranged from 35$ to $2,156. Gas sold within Railroad Commission District 8 ranged from 79.8$ per Mcf to $2,108. Gas sold in Railroad Commission Districts 7C and 8 ranged from 79.8$ per Mcf to $2,108 per Mcf. Because of the quality of the gas, each of the prices were adjusted lower because of the Btu rating of the gas in this area.

Mr. Hudson concluded that market value was represented by the average of the three highest prices paid for gas in Railroad Commission Districts 7C and 8. Using those figures, he concluded that the additional royalty due the Bank was $1,155,453.00. He also noted that if value was calculated on the price of new gas in interstate commerce at the price set by the FERC, the royalty due the Bank would be $575,519.00. He readily acknowledged that the sales which he used to arrive at the first figure did not include any sales in the interstate market because he did not consider those sales to reflect market value. He said he used the same basic method in arriving at the market value of gas in this case as in the Middleton case where he testified for the royalty owners.

Mr. Frank C. Bolton, Jr., testified as an expert witness for Exxon. He concluded that the only comparable sales were those of gas in the interstate market and of the same vintage as the gas involved in this case. He used four comparable sales and arrived at a weighted average price ranging from 14.4$ in March, 1974, to 22.6$ in April, 1979. He concluded that the price actually paid by Northern, and which ranged from 17.6$ to 29.5$, was market value for this vintage gas which had been committed to the interstate market.

Testimony was also offered from Exxon and Northern officials to establish that the sales contract was made in good faith, and that Exxon had made diligent efforts to obtain certain increases for the price of this gas. At the time this contract was executed, there were no intrastate lines into this field and no contracts were being executed with a “most favored nations” clause.

FINDINGS AND CONCLUSIONS

The trial Court filed extensive findings of fact and conclusions of law and denied recovery to the Bank. The Court’s controlling conclusion was that “[t]he only gas sales which may be comparable to the sale involved in this case are sales to the interstate market of gas of the same vintage as the gas involved in this case made by a similar producer. All other sales, and specifically intrastate sales, are not comparable to the sale involved in this case and are therefore not relevant to the market price of the gas involved in this case.” It thereby accepted the testimony and opinion of Mr. Bolton and rejected the testimony and opinion of Mr. Hudson.

MARKET VALUE

This case has been tried and appealed with an apparent agreement between the parties that the royalty clause is a “market value” provision. Quite obviously, it is not a “proceeds” clause as appears in some oil and gas leases. See Kunz, The Law of Oil and Gas, Vol. 3 sec. 40.4 (1967). Neither do we face the issue upon which the dissent was based in the Vela case that market price was to be based upon the market at the time of “sale” which the minority concluded was when the long term contract was made. In our case, value is determined not at the time the gas is “sold” but at the time it is “produced and saved.”

In Vela, the Court concluded that “the market price of gas is to be determined by sales of gas comparable in time, quality and availability to marketing outlets.” In doing so, the Court rejected the contention that market price was “the price contracted for in good faith by the lessee in pursuance of its duty to market gas from the premises.” The Court in its opinion said: “The royalties to which they [the royalty owners] are entitled must be determined from the provisions of the oil and gas lease, which was executed prior to and is wholly independent of the gas sales contracts.” (Emphasis added). To hold otherwise would mean that the gas sales contract becomes a unilateral amendment to the oil and gas lease, and thereby requires that value be based on a regulated market for gas of a particular vintage and not value as determined by a free or fair market.

Applying a fair market value, unfettered by federal controls, I would reach the same result as did the Kansas Supreme Court as to the Maupin case in Lightcap v. Mobil Oil Corporation, 221 Kan. 448, 562 P.2d 1 (1977) cert. denied 434 U.S. 876, 98 S.Ct. 228, 54 L.Ed.2d 156 (1977). A similar result has been reached by the trial Court in Kingery v. Continental Oil Company, 434 F.Supp. 349 (W.D.Tex.1977) appeal docketed No. 781015 (5th Cir.)

I recognize this decision can result in some producers paying more for royalty than they might receive for the contract price for the gas being sold. That was a consideration before the Court in Foster v. Atlantic Refining Company, 329 F.2d 485 (5th Cir. 1964), and there the Court said: “The fact that increases in market prices have made the lease obligations financially burdensome is no defense.” The Court in Vela adopted that same position.

Two more recent cases have reached a different result. In Hemus & Company v. Hawkins, 452 F.Supp. 861 (S.D.Tex.1978), the Court concluded that where gas was dedicated to an interstate sale, market value was required to be determined by what a willing seller and willing buyer would agree upon as a price with the governmental restriction placed on the commodity being sold. That decision is based largely upon the holding in Weymouth v. Colorado Interstate Gas Company, 367 F.2d 84 (5th Cir. 1966). In Brent v. Natural Gas Pipeline Company of America, 457 F.Supp. 155 (N.D.Tex.1978) appeal docketed, No. 78-3245 (5th Cir.), the Court reached the same result and said the decision was mandated by the holding in Weymouth. Judge Woodward’s decision in Brent also is based upon the fact that the lease permitted the gas to be sold interstate, and that the royalty owners did not object when the gas was sold in the interstate, market. In our case, the lessor had no right to control the sale of gas and knew nothing of the sale until after it had been completed, and therefore could not have objected.

These cases attempt to distinguish the opinion in Kingery because in that case Judge Sessions noted that the lease was executed before the holding in Phillips Petroleum Company v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1953), which gave the Federal Power Commission authority to regulate interstate sales of gas.

I would agree with Judge Cowan in the Hawkins case that the parties did not foresee and did not contemplate the effect an interstate sale might have on the market value of gas some years later, as opposed to a sale made for delivery in the intrastate market. But, had they contemplated such issue, it seems only reasonable that they would have concluded, as did the Courts in Foster and later in Vela, that the lessee had a perfect right to sell gas without any interference by the lessor, but it “took [a] calculated risk of that contract producing royalties satisfactory to the” lessor. Certainly, the lessor had a right to contemplate and expect that no unilateral act by the lessee would rob it of that which could have been expected when the lease was executed. To use the definition suggested in Weymouth makes the Court a party to a unilateral amendment to the oil and gas lease, so that “value” or “market value” is amended without consent of the lessor to mean “regulated value” or “regulated market value.” The language in Foster, which was quoted in Vela, makes it clear that the Court cannot “rewrite the lease to [the lessee’s] satisfaction.”

But, the results are not totally devastating for the producer who has sold to an interstate carrier. Under the holding in Federal Energy Regulatory Commission v. Pennzoil Producing Company, 439 U.S. 508, 99 S.Ct. 765, 58 L.Ed.2d 773 (1979), the Commission may and should provide special relief when a producer’s out-of-pocket expenses in connection with the operation of a particular well exceeds its revenue from the well under the applicable area price. One of the factors of production costs and return on investment to be considered by the Commission, in arriving at a just and reasonable rate producers may charge, includes royalty expense. See Lightcap v. Mobil Corporation, supra, 562 P.2d at 20. In Pennzoil, the attempted “pass through” for additional royalty was denied because it was an additional royalty “agreed to” by Pennzoil without an actual determination of its liability for this additional expense. That is not so under cases like Lightcap, where the producer is ordered to pay additional royalty under a “market value” lease.

The result I would reach is certainly consistent with the holding by the Supreme Court of Montana in Montana Power Company v. Kravik, 586 P.2d 298 (1978). In that case, the Court was concerned with the price of royalty gas sold intrastate, but it considered and discussed those cases involving interstate sales as well. In considering the effect of federal regulation on interstate sales as they relate to a royalty owner’s interest, the Court said:

Further, as stated in Lightcap v. Mobil Oil Corp. (1977), 221 Kan. 448, 562 P.2d 1, 8, cert. den., 434 U.S. 876, 98 S.Ct. 228, 54 L.Ed.2d 156, to limit royalty payments to the FPC ceiling price is to analyze the problem backward:
‘. . . [T]he process begins at the other end. The royalties to be paid are first to be determined under state law, based on the terms of the lease. The royalties so determined then become a component cost, to be considered by the FPC in determining the rates it will permit Mobil to charge.’
If, as subsequent events develop, the producers are put in a bind by their royalty obligations, they may petition the FPC for individual relief. Mobil Oil Corp. v. FPC (1974), 417 U.S. 283, 328, 94 S.Ct. 2328, 2355, 41 L.Ed.2d 72, 106 aff'g, Placid Oil Co. v. FPC (5th Cir. 1973), 483 F.2d 880, 911.
The impact of these decisions is that the FPC price regulations are of no relevance in setting the amount of royalty to be paid under a market price lease. Mobil Oil Corp. v. FPC, 463 F.2d [256] at 264; J. M. Huber Corp. v. Denman, 367 F.2d [104] at 109. The existence of federal regulation over the rates which a gas producer may receive is no obstacle to the fixing of a higher rate as the market value of the gas it sells for the purpose of computing royalties. Lightcap v. Mobil Oil Corp., 562 P.2d at 8. The possibility that a royalty base might in fact exceed the FPC ceiling has been clearly recognized. Mobil Oil Corp. v. FPC, 417 U.S. at 328, 94 S.Ct. at 2355, 41 L.Ed.2d at 106; Lightcap, 562 P.2d at 7. Neither does the collection of royalties at a rate in excess of that established by the FPC subvert the purpose of the Natural Gas Act nor undercut the federal regulatory system. Mobil Oil Corp. v. FPC, 463 F.2d at 265; Kingery v. Continental Oil Co. (W.D.Tex.1977), 434 F.Supp. 349, 355.
The above cases deal with lessors whose lessees sell the gas in interstate commerce, so that the prices for which the lessees can in turn sell the gas are regulated by the FPC. 15 U.S.C. § 717c; Lightcap, 562 P.2d at 7. Despite this nexus between lessee and FPC, regulation, the lessor is not bound to accept the FPC regulated price as the market price.
Under the type of market price lease here, even an FPC regulated gas company would have to pay royalties based on actual market price of gas, regardless of FPC regulations. Mobil Oil Corp. v. FPC, 463 F.2d at 263, 149 U.S.App.D.C. at 317; J. M. Huber Corp. v. Denman, 367 F.2d at 109-10; Kingery v. Continental Oil Co., 434 F.Supp. at 354-55; Lightcap, 562 P.2d at 11. Clearly, a non-FPC regulated company and lessor are not to be bound by these regulations.

I recognize that the Vela decision has received much criticism, but so far the court has not retreated from the position it took in 1968. An editorial note following the Kingery case suggests that the Erie doctrine probably compelled the result reached in that ease. 58 Oil and Gas Reporter 415 (1978). In the editorial comment following the Hawkins case in 61 Oil and Gas Reporter 243 to 244 (1979), the discussion note says:

While this writer did not agree with the Texas Supreme Court majority’s decision ... in the Vela case . he cannot agree that Vela left the matter open to be disposed of as in this Texas diversity federal case. Vela required accounting in terms of current contemporary sales contract values despite that about a 500% price disparity had developed between contract market values at the 1935 time of long-term contracting and then current 1960 contract prices, While no doubt there are instances of even greater spreads, that much disparity abundantly demonstrates the Texas rule for accounting due royalty owners. The inferior Texas state courts, and even more particularly federal courts dealing with Texas diversity cases, should follow the plain thrust of the Vela precedent until and unless it is changed.

I agree with that comment and feel, as I did in the Butler case that, until the rule in Vela is changed, I am compelled to follow that decision.

If Vela does not compel the results set forth in this dissent, there is yet another reason why the same results should be reached. From the opinions by the highest courts in Kansas and Montana, royalty owners in those states are permitted in “market value” leases the right to recover their royalty based upon a price paid in a free or fair market on gas committed to a regulated interstate market. (Under the Pennzoil case, that cost should then be passed on to the consumers). It is hard for me to believe that the courts of the largest producing state in the nation will say to its royalty owners that they are not entitled to the same payments as those in Kansas and Montana and perhaps other states yet to pass on this issue. Certainly all royalty owners should be treated alike. Since we do not write on a clean slate, the preferable choice is to follow those states which have previously said market value in an oil and gas lease means “market value” not “regulated market value.”

Clearly, City of Austin v. Cannizzo, 153 Tex. 324, 267 S.W.2d 808 (1954), has no application to this case. We are concerned with a contractual obligation to pay value made in a 1960 lease when no gas had been committed to the interstate regulated market.

I cannot agree that the evidence fails because of some question about day to day sales. These royalty owners were paid monthly, not daily; the figures used by Mr. Hudson were based on sales at various days each month and averaged to set a price for gas sold each quarter.

I would sustain Appellant’s points of error 1 through 4, 7 and 11.

One last comment must be made with regard to market value. Even if “availability of market” means that if gas can only be sold in an interstate market and only gas sales in such market may be considered in arriving at market value, we know from Vela that “comparable in time” means time of delivery and time of sale and the Bank in this case would at least recover $575,519.00 under the calculations made by Mr. Hudson on interstate sales of gas.

DIVISION ORDER

After the completion of the well and the execution of the gas contract with Northern, a division order was signed by the president of the Bank on December 2,1968. It provides in part:

Settlements for gas sold at wells or at a central point in or near the field where produced shall be based on the net proceeds at the wells. If the gas is processed in or near the field where produced, settlements shall be based on net value at the wells with such net value being determined as provided in the agreement between the producer and the processor, or in the absence of such an agreement, on the same basis as settlements to other producers of gas of like kind and quality processed at the same plant. Where gas is sold subject to regulation by the Federal Power Commission or other governmental authority, the price applicable to such sale as approved by order of such authority shall be used as a basis for determining the net proceeds at the wells or the net value at the wells. For all other gas sold or used off the premises, settlements shall be based on the market value at the wells.

On October 7, 1977, counsel for the Bank wrote to both Exxon and Gulf, expressing dissatisfaction with the method in which royalties were being calculated. Subsequently, this suit was filed on February 27, 1978. The Bank contends it is not bound by the division order, and it also asserts the division order has been cancelled. The trial Court made an alternative conclusion with regard to the division order as follows:

This Court has previously found that the Plaintiff executed a division order which provides for payment of royalty on the basis of the proceeds from the sale of the gas and that Exxon specifically advised Plaintiff to execute the division order if plaintiff was claiming proceeds. The Court concludes that the division order is a binding agreement until can-celled, requiring payment and receipt of royalty on the basis of the proceeds received by Exxon for the sale of the gas involved in this case.

The trial Court found the division order had not been cancelled, and also that no new or additional consideration was received by the Bank for executing the division order. I agree that the division order has never been cancelled. Although the October 1978 letter expressed dissatisfaction .about the manner in which royalty payments were being made, the letter never mentioned the division order and certainly did not state it was cancelled. Although the plaintiff’s first amended original petition said the Bank’s rights to be paid fair market value are unaffected by any gas division order, there was no allegation or prayer that the division order be cancelled.

Since it has not been cancelled, it is necessary to decide whether it has been effective to change the lease requirement of payment based on value of the gas produced and saved to a requirement to pay only on the basis of “proceeds” received by the producer. We discussed the basis for and our opinion as to the effect of a division order in both Butler v. Exxon Corporation, supra, and Amoco Production Company v. First Baptist Church of Pyote, supra. They were also considered by the Court in Middleton v. Exxon Corporation, supra.

In Butler, we concluded that the division order did not bar payment as provided for in the Veterans Land Board lease. On remand, such payment was recovered. Exxon Corporation v. Butler, 585 S.W.2d 881 (Tex.Civ.App.—San Antonio 1979, writ pending). In the Amoco case, we followed the holding in LeCuno Oil Company v. Smith, 306 S.W.2d 190 (Tex.Civ.App.—Texarkana 1957, writ ref’d n. r. e.) cert. denied, 356 U.S. 974, 78 S.Ct. 1137, 2 L.Ed.2d 1147 (1958) and again concluded that the division order did not bar recovery of amounts provided for in the lease. In the Middleton case, the Court found there was a new and additional consideration as to the Sun division orders, and thus concluded that such division orders could not be unilaterally revoked. In its opinion, the Court noted that there is a statutory presumption that all written contracts are supported by consideration and the burden was on the appellees to prove otherwise. But, where an original agreement or contract is to be changed or amended, particularly to the detriment of the one against whom the change is asserted, the law requires proof of a new and additional consideration. Travelers Indemnity Company v. Edwards, 462 S.W.2d 533 (Tex.1970). In our case, the Court found there was no consideration for the division order. Thus, I conclude the division order does not bar the Bank’s recovery under the terms of its lease.

ATTORNEY FEES

Although the parties stipulated as to the amount of reasonable attorney fees in this case, the trial Court concluded alternatively that no recovery could be had because the contract on which suit was brought was executed prior to the effective date of the amendment of Article 2226, Tex.Rev.Civ. Stat.Ann., allowing recovery on contractual action.

I believe that the controlling issue is when did the cause of action accrue. The Bank only seeks to recover attorney fees for that portion of its cause of action accruing after August 29, 1977, when the amendment became effective. In Government Personnel Mut. Life Ins. Co. v. Wear, 151 Tex. 454, 251 S.W.2d 525 (1952), the Court held it could not give effect to an amendment to the attorney fees statute as it related to a cause of action which arose after the amendment. In this case, the controlling date is not when the lease was made, but when the cause of action arose. Part of it arose after the amendment to the statute, and the Bank is entitled to recover attorney fees in accordance with the stipulation of the parties. I would sustain the Appellant’s point of error 15.

GULF’S APPEAL

In addition to adopting the position of Exxon on each of the issues heretofore discussed, Gulf presents one additional point which relates only to its position in this case. Under the Exxon lease, royalties are to be delivered in kind if the lessor so elects. But, under the Gulf lease, royalties are to be delivered in kind if the lessee so elects. Gulf asserts that it has exercised that election as to all gas produced after February 28, 1978, and that, if any additional royalties are due, Gulf owes no additional royalty on gas produced after that date. With regard to this particular issue, it should be noted that Humble, who had a lease covering the S/2 of the particular section in question, secured a farm-out from Gulf covering the N/2 of the section in 1964, and all interest in the two leases were pooled. The well was subsequently drilled on the S/2 of the section. In 1967, Humble entered into the gas sales contract with Northern covering all gas from this particular section which was known as the Oates Gas Unit No. 1. At the time deliveries began, Exxon owned all of the working interest in the Unit and Gulf held ½ of a Vmth overriding royalty interest in the Unit. Effective July 1, 1971, Humble reassigned ½ of the working interest in the N/2 of the section to Gulf, and the two of them entered into an operating agreement.

Gulf attempted to exercise its election by a letter written from its attorney to the attorney for the Bank on February 28,1978, advising that “Gulf Oil Corporation hereby terminates its option to pay to the lessor the proceeds from the sale of 3/32nds of Gulf Oil Corporation’s proportionate interest of the gas produced and saved from the captioned land (being the north half of the section in question).On such date, The First National Bank in Weather-ford shall be the successor-in-interest to Gulf Oil Corporation with respect to a 3/32nd part of Gulf Oil Corporation’s proportionate interest of the gas produced from captioned land . .

The trial Court denied Gulf’s request for additional findings of fact and conclusions of law with regard to its position on this issue. No cross-point is presented complaining about the trial Court’s failure to make the requested findings and conclusions.

I conclude that there was no error, and that Gulf’s contention cannot be sustained. As noted above, Gulf’s interest had been pooled and Humble entered into a gas sales contract covering all gas produced from the leases pooled to form the Oates Gas Unit No. 1. In 1971, when Humble reassigned ½ of the working interest in the lease covering the N/2 of the section to Gulf, Humble was operator under the operating agreement covering the Unit. By reason of these transactions, I would hold that Gulf lost its right to elect to deliver gas in kind to the Bank. Phillips Petroleum Company v. Ham, 228 F.2d 217 (5th Cir. 1955).

JUDGMENT

Having concluded that the trial Court erred in entering judgment denying the claim of the Bank, it is necessary to determine what judgment should be entered. The trial Court found that the exhibit prepared by Mr. Hudson correctly states the additional royalties to which the Bank would be entitled if the market value of the gas produced from the Oates Gas Unit No. 1 is to be determined on the basis of

(1) the highest, or average of the three highest prices paid for intrastate gas of pipeline quality redetermined each quarter, in Pecos and/or surrounding counties, or Railroad District 8, or Railroad Districts 7C and 8,
(2) the highest price paid from time to time for pipeline quality gas sold in the intrastate market from a well in the Northeast Oates Field,
(3) the highest price allowed by the Federal Power Commission (now FERC) for new gas produced, except emergency sales.

This exhibit does not reflect the deduction of the amount of severance taxes from any additional royalty claimed to be due. I agree with Mr. Hudson that the average of the three highest prices paid for gas in Railroad Commission Districts 7C and 8 represent market value. I would reverse the judgment of the trial Court, and direct that judgment be entered for the Bank in accordance with the dissent. 
      
      . Mcf is a measuring unit of 1,000 cubic feet of gas. See William and Meyers, Oil and Gas Law, Vol. 7 p. 337; Exxon Corporation v. Jefferson Land Company, Inc., 573 S.W.2d 829 at 831 (Tex.Civ.App.—Beaumont 1978, writ pending). It has sometimes been mistakenly referred to as a million cubic feet. See Exxon Corporation v. Middleton, 571 S.W.2d 349 at 358 (Tex.Civ.App.—Houston [14th Dist.] 1978, writ granted); and What Price, Gas?, 7 St. Mary’s .L.J. 333 at 333 (1975).
     
      
      . Butler v. Exxon Corporation, 559 S.W.2d 410 (Tex.Civ.App.—El Paso 1977, writ ref'd n. r. e.); Exxon Corporation v. Middleton, supra note 1; Exxon Corporation v. Jefferson Land Company, Inc., supra note 1; Amoco Production Company v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex.Civ.App.—El Paso 1979, writ pending).
     
      
      
        . Lightcap v. Mobil Oil Corporation, 221 Kan. 448, 562 P.2d 1 (1977), cert. denied 434 U.S. 876, 98 S.Ct. 228, 54 L.Ed.2d 156 (1977); Kingery v. Continental Oil Company, 434 F.Supp. 349 (W.D.Tex.1977, appealed 5th Cir.); Hemus & Company v. Hawkins, 452 F.Supp. 861 (S.D.Tex.1978); Brent v. Natural Gas Pipeline Company of America, 457 F.Supp. 155 (N.D.Tex.1978, appealed 5th Cir.).
     