BACKGROUND
The events leading up to this lawsuit occurred against a background that was recently discussed by the Supreme Court. We quote from the syllabus:
In response to ongoing natural gas shortages, Congress enacted the Natural Gas Policy Act of 1978 (NGPA), which, *523inter alia, established higher price ceilings for “new” gas in order to encourage production and carried over the pre-exist-ing system of “vintage” price ceilings for “old” gas in order to protect consumers. However, recognizing that some of the vintage ceilings might be too low, Congress, in § 104(b)(2) of the NGPA, authorized the Federal Energy Regulatory Commission to raise them whenever traditional pricing principles under the Natural Gas Act of 1938 (NGA) would dictate a higher price. After the new production incentives resulted in serious market distortions, the Commission issued its Order No. 451, which, among other things, collapsed the existing vintage price categories into a single classification and set forth a single new ceiling that exceeded the then-current market price for old gas; established a “Good Faith Negotiation” (GFN) procedure that producers must follow before they can collect a higher price from current pipeline customers, whereby producers may in certain circumstances abandon their existing obligations if the parties cannot come to terms; and rejected suggestions that the Commission undertake to resolve in the Order No. 451 proceeding the issue of take-or-pay provisions in certain gas contracts. Such provisions obligate a pipeline to purchase a specified volume of gas at a specified price, and, if it is unable to do so, to pay for that volume. They have caused significant hardships for gas purchasers under current market conditions.
Mobil Oil Exploration & Producing Southeast, Inc. v. United Distribution Cos, 498 U.S. 211, -, 111 S.Ct. 615, 617, 112 L.Ed.2d 636 (1991).
FACTS
The named plaintiffs/appellants are the representatives of a class of about 3,000 royalty owners. Their claims derive from oil and gas leases on property located in the Arkoma Basin, in Western Arkansas. Defendant/appellee Arkla, Inc. (Arkla) is a corporation with its principal place of business in Shreveport, Louisiana. Defendant/appellee Arkla Exploration Company (AEC) is likewise a corporation with its principal place of business in Shreveport. At all times relevant, it was a wholly-owned subsidiary of Arkla, Inc., and operated as the exploration and production company of Arkla, Inc. Arkla Energy Resources (AER), while not a named party, is a division of Arkla, Inc, which operates Arkla’s pipeline.
Defendants/appellees Jones and McCoy founded Arkoma as an Arkansas corporation in 1981. Jones owned two-thirds of the stock and McCoy owned one third. Jones was chairman of Arkoma’s board of directors and a corporate officer, and McCoy was Arkoma’s president and its chief geologist and engineer. Arkoma was in the business of natural gas exploration, development and production. They sold their interests in the company to AEC on December 31, 1986. Jones and McCoy were joined as defendants in this action by virtue of this sale and the assignment to Arkoma, prior to that sale, of their interests in various producing wells involved.
The various Arkla entities will be collectively referred to as “the Arkla parties” or as, simply, “Arkla” unless the context otherwise warrants. In such cases they will be designated as “Arkla”, “AER”, “AEC”, or “Arkoma”.
Development in the two primary fields, the Aetna and Cecil Fields, commenced in the 1950’s. Typically, mineral owners gave leases to production companies which provided for the payment of royalty based on the market value of Vs of the gas sold or used off the premises, or Vs of the amount realized from the sale at the wellhead. Many leases in the Cecil Field contained a fixed rate royalty provision which calculated the royalty at Vs of the value fixed at a certain amount per thousand cubic feet (mcf) of gas sold. Those fixed price leases were converted to market value leases in separate litigation in the Chancery Court of Franklin County, Arkansas, in 1990.
On December 31, 1982, Arkoma, then owned by Jones and McCoy, agreed with Arkla, a major developer in the Arkoma Basin, to purchase one-half of Arkla’s *524leasehold interest for $15 million. Arkoma agreed to spend an additional $30 million in a drilling program over a four year period, and to share additional acreage acquired in the Aetna and Cecil Fields from other lease owners. This transaction resulted in Arko-ma and Arkla owning virtually all of the rights to drill new wells in the Aetna and Cecil Fields. Shortly thereafter, Jones became a member of the board of Arkla.
On February 24, 1983, Arkoma and Arkla executed a gas purchase contract, identified as GPC 5239, covering new wells to be drilled in the Aetna and Cecil Fields, as well as any other acreage to be acquired by Arkoma, and by which Arkla agreed to pay Arkoma the maximum lawful price under §§ 102 and 103 of the NGPA. At the time of the agreement, the §102 price for the gas was $3.83 per mcf. The contract contained a pricing provision which allowed Arkoma to renegotiate the contract price during its term. It provided a 75% minimum take-or-pay provision by which Ark-la was obligated to take 75% of the daily deliverability from Arkoma’s wells, or to pay for a like amount of the gas at the contract rate1. Arkoma committed its working interests together with all royalty interests of the appellant class to the contract.
Arkoma began an aggressive drilling program, achieving a success ratio in excess of 90%, against an industry standard of only approximately 50%. In the process, Arkoma became one of Arkla’s largest suppliers of gas.
In 1985-86, Arkla curtailed the quantities of gas it took from Arkoma, but did not honor the pay provisions of GPC 5239. By March, 1986, the outstanding take-or-pay billings from Arkoma to Arkla were in excess of $36 million, and were accruing at a monthly rate of approximately $3 million. At about that time, Jones resigned from the Arkla board. Arkla then refused to pay for the gas it had not taken. Arkla calculated that it was obligated to buy 40,-000 mcf per day and was taking only 12,000 mcf; that the potential take-or-pay obligation owed to Arkoma could reach $54 million by the end of 1986 and would increase by $40 million during 1987; and it determined that only 10% of the take-or-pay billings were debatable.
Arkla entered into negotiations with Jones and McCoy to resolve the problem. The negotiations for settlement of the take- or-pay obligations were resolved on December 31, 1986, when Arkla simply bought its problem. The tax partnerships, (controlled and primarily owned by Jones and McCoy), which actually owned the producing wells, assigned all of their interests to Arkoma, as did Jones and McCoy. AEC then purchased all of Jones’ and McCoy’s stock in Arkoma, thus acquiring Arkoma Production Company and gaining the ability to renegotiate GPC 5239. Jones and McCoy assigned all drilling interests to Arkoma in exchange for a promissory note in the amount of $35 million, guaranteed by AEC. That note was paid the same day.
“New” Arkoma, that is, Arkoma as it existed after acquisition by AEC, also agreed to furnish Jones and McCoy, free of cost to them, 5.8 billion cubic feet (bcf) of gas over a five year period. AER agreed to purchase this gas at prices beginning at $4.77 per mcf in 1987, and escalating to $6.08 per mcf in 1992. To secure its obligation to purchase this gas, AER gave Jones and McCoy a promissory note in the amount of $24 million, which was the net present value of that gas purchase contract.
“New” Arkoma agreed to pay Jones and McCoy at the rate of $1.62 per mcf for any newly established additional reserves. For the stock in Arkoma, Arkla paid Jones and McCoy, in addition to satisfying the promissory note of $35 million, a cash consider*525ation of $14 million. The total consideration paid by Arkla on December 31, 1986, was $73 million, $35 million for the promissory note, $24 million for the gas purchase contract to buy free gas, and $14 million for the Arkoma stock.
After the sales by Jones and McCoy to Arkoma of their lessee interests, and after the sale of Arkoma to AEC, and during the period of the settlement of the take-or-pay claims and renegotiation of GPC 5239, Ar-koma was wholly owned by AEC (Arkla’s production company). And AER, (the pipeline), was also wholly owned by Arkla.
On February 13, 1987, AER, AEC and Arkoma amended the price provisions and the take-or-pay provisions in GPC 5239. They reduced the contract price for gas from $3.83 per mcf to $2.20 per mcf, and released gas on the spot market for sale at prices less than $1.50 per mcf. Appellants, who knew nothing of the details of these confidential transactions of December 31, 1986, and February 13, 1987, and which the participants concealed from the Arkansas Public Service Commission, did not find out that they would be receiving less money for their royalty interests until they received their January production payments from Arkla in late March, 1987.
After Jones and McCoy directed “New” Arkoma to drill additional wells, which they were entitled to do under the December 31, 1986, transactions, the parties had a new dispute. It concerned additional consideration due to Jones and McCoy for drilling of the new wells. To resolve the dispute AEC paid Jones and McCoy an additional $100 million in 1989, which included payment for reserves, the balance due on free gas, and interest.
On December 31, 1986, the fair market value of gas reserves in the ground was 83$ per mcf. However, Arkla paid Jones and McCoy $1.62 per mcf. The difference in the fair market value of the reserves and the amount paid to Jones and McCoy represented the value paid to Jones and McCoy to settle Arkla’s take or pay dispute under GPC 5239; and to put it in a position to amend the gas purchase contract.
Plaintiffs/appellants assert, and defendants/appellees do not contest, that except for the fixed rate leases, the royalty provisions took the following basic form:
Lessee shall pay Lessor as royalty on gas, casinghead gas, distillate, condensate, and other gaseous substance produced from said land and sold or used by Lessee off of the land or in the manufacture of gasoline or other products, the market value at the mouth of the wells of one-eighth (Vs) of such products so sold or used. On all gas, casinghead gas, condensate and distillate sold at the wells by the Lessee the royalty shall be one-eighth (Vs) of the amount realized from such sales.
The fixed rate royalty provisions took the following form:
The Lessee shall pay Lessor as royalty for gas the equal one-eighth (Vs) of the value of such gas calculated at the rate of Four (4$) cents per thousand cubic feet corrected to two pounds above atmospheric pressure while the same is being sold or used off the premises.
Corporate Appellees’ Appendix at 132 (emphasis added). As previously noted, in separate litigation the fixed rate leases were converted to market value leases. The fixed rate leases were:
Converted into leases providing for the payment of royalties based on the proceeds received at the wellhead from the sale of the produced gas. ... As to the production from and after [July 1, 1990], all such royalties shall be paid by the lessees according to the proceeds, net of lawful taxes or assessments and other proper charges authorized by law or the lease agreements, if any, received by the lessees at the well for all gas produced from the leased premises.... Arkla warrants that the royalty payment level on its converted proceeds leases will be no less than the royalty payment level applicable to the market value leases as to which Arkla is a lessee in the Cecil Gas Field Settlement Area.
Glen Morris, et al. v. Arkansas Louisiana Gas Company, et al., In the Chancery Court of Franklin County, Arkansas, *526Charleston District, No. E-86-40, Final Order, Filed on May 21, 1990 (Exhibit 1 at 5).
While the briefs and the arguments refer frequently to contracts and agreements among developers and distributors — marketers of oil and gas — these plaintiffs/appellants claim as royalty owners and under leases between royalty owners and developers. And the plaintiffs/appellants’ rights in these matters must arise out of the oil and gas leases executed by the royalty owners.
PROCEDURE
The lawsuit was filed February 23, 1990. Plaintiffs/Appellees Jones and McCoy filed a motion for summary judgment January 1, 1991. The Arkla defendants/appellees filed a motion for summary judgment January 18, 1991. Each group filed its Statement of Material Facts and, on March 4, 1991 the trial court, ruling from the bench during a hearing on a motion for summary judgment, dismissed all claims against Jones and McCoy and all claims against the other defendants, except the claim based on a breach of the implied covenant to market gas. After a bench trial that lasted seven days, the court found that the action was time barred and, on April 21, 1991 entered its order dismissing the entire action. At the request of the appellants, on May 7, 1991, the court entered an order affirming the previous dismissals.
DISCUSSION
While the statements of the issues vary among the parties), the areas of concern expressed by the trial judge covered all the issues, and that outline will be followed here.
Further, in review of these issues this court will be guided by the standard that the appellate court views the case in the same manner as the trial court, Western Casualty & Surety Co. v. National Union Fire Insurance Co., 677 F.2d 789 (10th Cir.1982); and we review the trial court’s rulings on the applicable state law de novo. Salve Regina College v. Russell, — U.S. -, 111 S.Ct. 1217, 113 L.Ed.2d 190 (1991). We will turn, therefore, to the bench discussion of the trial court at the hearing on March 4, 1991.
Turning now to the specific counts or claims made by plaintiffs:
1. General Breach of Duty of Fair Dealing Arising from a Fiduciary Relationship.
In Amoco Production Co. v. Ware, 269 Ark 313, 602 S.W.2d 620 (1980), the Arkansas Supreme Court carefully reviewed the relationship of a developer to a lessor among a group of lessors and recited the five implied warranties arising out of the lessor-lessee relationship. It found no fiduciary relationship and it found no implied breach of fiduciary duty by lessee. Instead, it defined the duty owed each lessor, and to the lessors as a group, to act for the mutual advantage of both. It held that the lessee must act in a reasonable and prudent manner, using reasonable judgment, and not act arbitrarily.
In this case the take-or-pay elements in the developers contracts with the pipeline/marketer were, because of Federal Energy Regulatory Commission intervention, literally bankrupting the pipeline, and those facts must be considered in evaluating the reasonableness of defendants’ actions. We find it reasonable for the defendants to make some effort to liquidate the take-or-pay obligations of AEC.
2. Third Party Beneficiaries.
Plaintiffs also sought relief as third party beneficiaries of GPC 5239. The Restatement defines third party beneficiaries as follows:
(1) Unless otherwise agreed between promisor and promisee, a beneficiary of a promise is an intended beneficiary if recognition of a right to performance in the beneficiary is appropriate to effectuate the intention of the parties and either
(a) the performance of the promise will satisfy an obligation of the promisee to pay money to the beneficiary; or
(b) the circumstances indicate that the promisee intends to give the beneficia*527ry the benefit of the promised performance.
(2) An incidental beneficiary is a beneficiary who is not an intended beneficiary.
Restatement (Second) of Contracts, § 302 (1981). The comments to this section provide no examples dealing with oil and gas leases.
Under the lease, the lessee’s failure to perform will defeat the lessee’s interest, so it follows that there is not a continuing obligation of performance, i.e. the lessee can abandon the lease. Nor does the lessee indicate by assignment of the lease that he intended to give the beneficiary any further benefit of promised performance. Therefore, it follows that the lessors are only, at the most, incidental beneficiaries and we affirm the trial court’s dismissal of this claim.
3. Tortious Interference with a Contractual Relationship.
The next claim made is that of tor-tious interference with a contractual relationship between the lessor and the lessee. But, the leases are admittedly assignable, and the original lessee and transferor committed no unlawful act in exercising the right to assign. We affirm the trial court’s dismissal of this claim.
4. Unjust Enrichment
This court’s power extends to the equity aspects of this problem. U.S. Const. Art. Ill, § 2, cl. 1. The doctrine of unjust enrichment, that a person shall not be allowed to profit or enrich himself inequitably at another’s expense is not contractual, but is equitable in nature. Black’s Law Dictionary 1705 (4th ed. 1968).
“Take-or-pay” provisions in a lease are nothing new. See Southwestern Legal Foundation, Fourth Annual Institute on Oil and Gas Law and Taxation, 151, 170 (1953). It cannot be claimed by the defendant that the parties to this lease could reasonably foresee that, under the Natural Gas Policy Act of 1978, lessors would find their market shattered by the service of mandates issued by the Federal Energy Regulatory Commission. In the course of those mandates, the market price of gas was determined not by the commercially logical principle of fitness of the gas for the purpose for which it was intended, but rather by an illogical principle related to the age of the wells.
The resulting market distortions forced the pipeline (AER) to take only the old gas, at a price level which the Federal Energy Regulatory Commission felt the customer would accept. The problems of lessor/royalty owners which arise with reference to take-or-pay clauses are generating substantial litigation as lessee/developers and marketer/pipeline owners, seek to resolve marketing problems created in the course of administration of the National Gas Policy Act of 1978 (NGPA), 15 U.S.C. §§ 3301-3432, which allowed gas price increases through supervised deregulation.
Three factors cry for equity intervention in this situation:
1. As shown by the legislative history of the NGPA, at no time during the development of the Act did Congress concern itself with the impact of the Act on the rights of lessor/royalty owners. See Legislative History, P.L. 95-621, 1978, 95th Cong., 2d Sess., reprinted in U.S.C.C.A.N. 7, 7659, 8800.
2. The artificial market distortion forced the pipeline, AER, to take the “old” gas and sell it at an artificial price to the consumers, and to abandon its efforts to honor the pay obligations.
3. Where before the purchase of Arko-ma, its interest was consistent with that of the lessors, after AEC bought Arkoma its primary interest was with the pipeline, AER, because both were wholly owned by Arkla. Thus the lessors no longer had a representative dealing at arms-length with the pipeline. And lessors/royalty owners had no direct input into the making of the take-or-pay contracts since take-or-pay is a part of the developer /pipeline contract.
By its nature, gas can pass from one collection point in a reservoir to another, so a well, once opened, should be constantly tapped; and at the same time since gas is difficult and dangerous to store on the *528surface, and its users normally demand reliable, constant, access to it, both the developer and the pipeline want a constant flow.
As a result of the policies of the NGPA and the high demand for gas in the 1980’s, and the inherent nature of gas, developers could, and did, get favorable take-or-pay provisions in their contracts. See, Kirk J. Brily, Comment, Royalty on Take-or-Pay Payments and Related Consideration Accruing to Producers, 27 Hous.L.Rev. 105 (1990).
But the NGPA developed the concept of “vintagizing” (i.e. classifying by the age of the wells), gas for purposes of producer price regulation that arose under the NGPA. “Old flowing gas” was held to price ceilings far below the market clearing price of gas. This pool of artificially low-priced gas has produced “horrendous” distortions of the gas market.2 And it was this distortion of market conditions, and efforts to adapt gas production contracts between developers and pipelines which generated the litigation before us now. See Richard J. Pierce, Jr., Lessor/Lessee Relations in a Turbulent Gas Market, 38th Oil and Gas Inst. § 8.04 (Matthew Bender 1987).
It is inevitable that as developers and pipeline marketers attempted to resolve problems of take-or-pay liabilities between themselves, the claims of royalty owners would arise.
In Mesa Petroleum Co. v. U.S. Dept. of Int., 647 F.Supp. 1350 (W.D.La.1986), the Department of Interior, the royalty owner, claimed royalty on a take-or-pay payment that Mesa, the developer, had received from the pipeline. The court denied recovery, pointing out that the lease required “production” and the “pay” arose in an absence of production.
In Diamond Shamrock Exploration Co. v. Hodel, 86-536, slip op. (E.D.La.1986), the United States District Court reasoned that the take-or-pay payments are intended to compensate the developer for costs necessary to keep the well functioning, so they fall within the definition of “production” as activities which take place after the successful completion of the well, such as operations, monitoring, and maintenance.
The case was appealed and reviewed in Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159 (5th Cir.1988). The Circuit court rejected the Shamrock decision and held flatly that “[f]or purposes of royalty calculation and payment, production does not occur until the minerals are physically severed from the earth.” Id. at 1168.
However, in January of 1988 the Outer Continental Shelf Lands Act (OCSLA) as administered by the Minerals Management Service, (MMS), revised its gas royalty evaluation regulation to provide:
“The value of gas ... sold pursuant to an arm’s-length contract shall be the gross proceeds accruing to the lessee.” “Gross proceeds” are defined as “[t]he total monies and other consideration accruing to an oil and gas lessee ... including] but ... not limited to: Take-or-pay payments; ... and other reimbursements_” 30 C.F.R. 206.151 as quoted in Brily, supra3. The author of that comment concludes, as to MMS’ position that:
The likelihood remains remote that a court will find that the MMS overstepped its bounds by declaring that take-or-pay receipts and other consideration accruing to the lessee give rise to a royalty obligation. The MMS’s [sic] position appears neither arbitrary nor capricious. The most reasonable projection is that royalties will be due on federal lease take-or-pay payments in the future.
Brily, supra, at 122.
Wyoming, as to leases where the state is the lessor, has held, by analyzing the meaning of “production”, that royalties are only payable when the oil or gas is severed from the earth. State v. Pennzoil Co., 752 P.2d 975 (Wyo.1988).
*529In Louisiana, as to state leases, the State Mineral Board has adopted a resolution addressed to the take-or-pay issue and announced that all sums “attributable to gas contracts ... should be paid to the state along with other royalties due.”
Against this background of undertakings by governmental bodies to expand the scope of “royalty” by special definitions and concepts of “constructive” production, we turn back to the problem of leases between private parties, and an equitable analysis of the meaning of “royalty” and its impact on “take” funds under a take-or-pay contract.
The Louisiana mineral code, Article 213 provides that:
“Royalty” as used in connection with mineral leases, means any interest in production, or its value, from or attributable to land subject to a mineral lease, that is deliverable or payable to the lessor or others entitled to share therein.... “Royalty” also includes sums payable to the lessor that are classified by the lease as constructive production.
La.Rev.Stat.Ann. § 31-213(5) (West 1992).
Arkansas statutory law has also addressed this problem of a fair distribution of the developers/lessees recoveries in performance of its duty to market. See Ark. Code Ann. § 15-74-705 (Michie 1987). Arkansas law states:
It shall be the duty of both the lessee, or his assignee, and any pipeline company, corporation, or individual contracting for the purchase of oil or gas under any oil, gas, or mineral lease to protect the royalty of the lessor’s interest by paying to the lessor or his assignees the same price including premiums, steaming charges, and bonuses of whatsoever name for royalty oil or gas that is paid the operator or lessee under the lease for the working interest thereunder.
Ark.Code Ann. § 15-74-705 (Michie 1987).'
The next line of cases involve four decisions arising out of the same case. For simplicity these cases will be cited as follows. The first decision, Frey v. Amoco Production Co., 708 F.Supp. 783 (E.D.La.1989) will be referred to as Frey 1. The next in this group of cases, Frey v. Amoco Production Co., 943 F.2d 578 (5th Cir.1991), will be referred to as Frey 2. The third, Frey v. Amoco Production Co., 951 F.2d 67 (5th Cir.1992) will be referred to as Frey 3. The fourth decision, Frey v. Amoco Production Co., 603 So.2d 166 (La.1992) will be referred to as Frey 4-
In Frey 1, Amoco, the lessee/developer, sold gas from wells of Frey and others to Columbia, the pipeline/marketer. Columbia defaulted on its “pay” obligation. Amoco had sued Columbia in Louisiana state court; and the case was settled by Columbia’s payment to Amoco of:
1. Approximately $21 million as non-re-coupable take-or-pay.
2. Approximately $45 million as recou-pable payment.
The Royalty owner-lessors then sued Amoco in the United States District Court for a share of the settlement. Both sides moved for summary judgment. The court denied Amoco’s motion and granted Columbia’s motion. The court found that Amoco had paid royalty to Frey on all gas produced and sold. Amoco paid no royalty on payments made in settlement of Columbia’s failure to keep up its take-or-pay payments. And, as to the recoupment taken by Columbia, Amoco had paid royalty at its standard rate, presumably below the contract value of the recouped gas. The court held that as to the non-recoupable payment, Frey, et al., had no claim because no gas had been produced and sold. And it held that Frey, et al., had no claim as to the recouped gas because they got the market value under the long term contract of sale and therefore had suffered no injury.
The case was appealed, Frey 2. The Fifth Circuit Court first distinguished Frey from Diamond Shamrock Exploration Co. using the lease language. In Shamrock the lessor received as royalty a fraction of the “amount or value of production saved, removed or sold.” Diamond Shamrock Exploration Corp., 853 F.2d at 1163. But, in Frey 2 the lessor received a fraction of the “amount realized at the well from the sale of gas.” See Frey 2, at 581. Also, in Shamrock the court applied federal law *530to determine the meaning of the Department of Interior’s lease then at issue; but in Frey 2 the court applied the law of Louisiana, and the Louisiana Supreme Court had not spoken to the issue.
The court then held that under the language “amount realized at the well from the sale of gas”, production was not required under Louisiana law. The court further held, inter alia, take-or-pay payments are part of the “amount realized” from the sale of gas under the lease, and thus such payments received by the lessee in settlement of the take-or-pay dispute with its pipeline purchaser for gas not taken, are subject to the lessor’s royalty. Frey 2 at 580-84. The court, relying on Louisiana law, reasoned that the payments “constitute economic benefits that Amoco received from granting Columbia the right to take gas from the leased premises, a right Amoco got through the lease. Id. at 584. It determined “it would be contrary to the nature of the lease as a cooperative venture to allow a benefit, by any name, that is attributable to the gas under the leased premises to inure exclusively to the lessee.” Id.
The court also held that since the market value would vary during the period of re-coupment, and the lessor’s royalty share would vary with it, and since $45 million was paid for the recoupable gas, the volume of gas rather than the price per each thousand cubic feet (mcf) varied; and there was no problem of computing the amount due the lessor’s royalty interests.
On the take-or-pay issue the circuit court reversed the district court's summary judgment for Amoco and held the plaintiffs were entitled to their share of one-fifth of all take-or-pay payments received by Amoco. Id. at 586.
On a petition for rehearing, the circuit court in Frey 3 withdrew that portion of its opinion as to Frey’s entitlement to a royalty interest on the take-or-pay settlement, and certified to the Louisiana Supreme Court this question:
Whether under Louisiana law and the facts concerning the Lease executed by Amoco and Frey, the Lease’s clause that provides Frey a ‘royalty on gas sold by the Lessee of one-fifth (Vs) of the amount realized at the well from such sales’ requires Amoco to pay Frey a royalty share of the take-or-pay payments that Amoco earns as a result of having executed the Lease and under the terms of a gas sales contract with a pipeline-purchaser.
Frey 3 at 68.
The Supreme Court of Louisiana accepted the certification in Frey 4 after writing that:
The controversy centers around Frey’s alleged entitlement to a royalty share of the $66.5 million in take-or-pay amounts paid by Columbia to Amoco under the Settlement Agreement. The parties characterized $45.6 million of the total as a “recoupable take-or-pay payment” and the remaining $20.9 million as a “non-recoupable take-or-pay payment.”
Frey 4 at 170.
After recognizing the “fundamental principle that the lease contract is the law between the parties defining their respective legal rights and obligations” it observed that “disinclined to write a mineral lease in pursuit of equity, we are nonetheless cognizant [that] the terms of a mineral lease are neither intended to, nor capable of, accommodating every eventuality.” Frey 4 at 172. Further, the court observed:
When the parties made no provision for a particular situation, it must be assumed that they intended to bind themselves not only to the express provisions of the contract, but also to whatever law, equity, or usage regards as implied in a contract of that kind or necessary for the contract to achieve its purpose.
Frey 4 at 172.
The court also pointed out that it cannot realistically be claimed that the lessor/royalty interest shares none of the costs or risks of development, and noted the risks of drainage and defective market forecasts are, for example, risks shared by the lessor/royalty interest. Id. at 178.
*531After finding that the Louisiana Mineral Code was not dispositive of lessor’s right to take-or-pay payments, and that “... the terms of a mineral lease are neither intended to, nor capable of, accommodating every eventuality,” it looked to the leasehold parties’ general intent, i.e. that the lessor supplied the land and the lessor the capital and expertise necessary to develop the land for the mutual benefit of both parties. Id at 172-73. In so doing it looked to 1) the function of the royalty clause and 2) to the lessor’s implied obligation to market diligently the gas produced. Id.
The court adopted the principle that: [A]ny determination of the market value of gas which admits the lessee’s arrangements to market were prudently arrived at consistent with the lessee’s obligation, but which at the same time permits either the lessor or the lessee to receive a part of the gross revenues from the property greater than the fractional division contemplated by the lease, should be considered inherently contrary to the basic nature of the lease and be sustained only in the clearest of cases.
Henry v. Ballard & Cordell Corp., 418 So.2d 1334, 1338 n. 10 (La.1982) (citing Thomas Harrell, Developments in Non-regulatory Oil & Gas Law, 30 Inst. on Oil & Gas L. & Tax’n, 311, 336 (1979)).4
In further support of the proposition that royalty owners were entitled to share in take-or-pay monies and that the basic policy of the lease required a division of the total benefits, it observed that under a lease, as a bargained for exchange, the lessor would not relinquish a valuable right without receiving something in return. The take-or-pay contract gave the pipeline (AER) the right not to take gas as well as the right to take gas; and such a right had its price. Id. at 173. Further, almost invariably where take-or-pay claims are settled, there are amendments to other provisions of the (sale) agreement, particularly pricing and quantity provisions, for example, a'lowering of the take obligations, even though the settlement agreement clearly allocates settlement payments between take-or-pay payments and modification of pricing provisions. {See 23 Tulsa L.J. No. 4 1988). The lessee’s action has relinquished a valuable right and the lessor is entitled to receive something in return.
[Further, i]f producers are allowed to retain all of one part of the settlement (the lump sum payment), but must share with the royalty owners another part of the settlement (proceeds from future sales under the contract), producers have an artificial incentive to maximize the lump sum settlement and minimize future price.
Richard J. Pierce, Lessor/Lessee Relations in a Turbulent Gas Market, 38 Inst. on Oil & Gas Law & Tax’n 8-1, 8-20 (1987).
The court in Frey 4 also found that the “amount realized” encompassed the contracted sale price of the gas per mcf, the amount paid in recoupable take-or-pay payment and in non-recoupable take-or-pay payments, and in settlement and release of the take-or-pay agreement. Id. at 179-80.
The writings in reference to this problem show a strong, developing recognition that a restrictive interpretation of the royalties clause in a conventional lease can be inconsistent with its basic purpose, and can produce results that are unintended by the parties, and unfair to the lessor. It is hornbook law that oil and gas leases are construed in favor of the lessor, if for no other reason than that the lessor is the uninformed and inexpert party to the bargain. Summer’s Oil & Gas Perm Edition Yol. 2 at 372.
We also recognize the Harrell rule, that a lease arrangement is in the nature of a cooperative venture in which the lessor contributes the land and the lessee the capital and experience necessary to develop the minerals for the mutual benefit of both parties. And it follows from that rule that:
[A]ny determination[s] of the market value of gas which admits the lessee’s ar*532rangements to market were prudently arrived at consistent with the lessee’s obligation, but which at the same time permits either the lessor or lessee to receive a part of the gross revenues from the property greater than the fractional division contemplated by the lease, should be considered inherently contrary to the basic nature of the lease and be sustained only in the clearest of cases.
Harrell, supra, at 336.
Nor is the Harrell analysis new or surprising. See Brily, supra, at 135. “... decisions that lessee owe royalties on non-recoupable payments ... are legally and equitably sound.” Id. The author supports the proposition that the royalty on recoupable payments should not be paid until gas is delivered at the well head. There the author recognizes the Harrell rule but seeks to follow the lease provision for capture where possible. See also, Pierce, supra, at § 8.03; John S. Lowe, Current Lease and Royalty Problems in the Gas Industry, 23 Tulsa L.J. 561; and Royalty Issues, Take or Pay Claims, and Division Orders, 24 Tulsa L.J. 511 et seq. Two cases applying the concept that all benefits grounded on the existence of a lease must be shared in accordance with the lease are Amoco Production Co. v. First Baptist Church, 579 S.W.2d 280 (Tex.Civ.App.1979) and Henry v. Ballard & Cordell Corp., 418 So.2d 1334 (La.1982) where Harrell is cited favorably, see 1335 n. 10.
5. Implied Covenant to Market Gas and Statute of Limitations.
An implied covenant to market is discussed in Summer’s, Oil and Gas, § 400 (1959). The writer’s thesis is that, whether by specific language in the lease or by implied covenant, lessees have a clear duty to market oil and gas produced. In Ware, the Arkansas Supreme Court found five implied covenants in oil and gas leases. They are:
[1.] A covenant to drill wells within a reasonable time, testing the land for oil and gas;
[2.] a covenant to drill test wells within a reasonable time after notice;
[3.] a covenant, if oil and gas be found in paying quantities, to proceed with reasonable diligence in drilling sufficient number of wells to reasonably develop the premises;
[4.] a covenant to protect the land from drainage through wells on adjoining lands, by drilling offset wells; and [5.] a covenant to market the produce of producing wells.
Ware, 602 S.W.2d at 624 (citing Summers, The Law of Oil & Gas, ch. 13, § 395 (vol. 2, 1959).
The test of compliance with an implied covenant is that of a reasonable developer. In this case, the trial court found that a valid claim of failure to market had been asserted, but that it was lost as time barred under Ark.Code Ann. § 16-56-105 (1987), the three year statute of limitations. However, based on the facts, we hold that the action is not time barred.
Ark.Code Ann. § 16-56-105 provides: The following actions shall be commenced within three years after the cause of action accrues:
3. All actions founded on any contract or liability, express or implied;
The novation agreement between Arko-ma and Arkla was formally executed on February 13, 1987. This action was brought by the filing of a complaint on February 23, 1990, three years and ten days later. The trial court held the three year statute applicable, found that the statute started to run when the novation occurred, and dismissed the suit as time barred by ten days. Appellants claim that it was not until March, 1987, when they received their January royalty checks, that they were put on notice of the change in their share. Appellees admit that they attempted to complete the novation of the take-or-pay contract as secretly as possible.
We recognize that the clear language of § 16-56-105 encompasses the oil and gas leases of appellants, including the *533implied covenant which is an integral part of such lease. The precise statutory language is “all actions founded on any contract or liability expressed or implied;”. In Scroggin Farms Corp. v. Howell, 216 Ark. 569, 226 S.W.2d 562 (1950), the Arkansas Supreme Court observed that, “if the plaintiff, by reasonable diligence, might have detected the fraud he is presumed to have reasonable knowledge of it.”
Appellants claim the statute did not begin to run until they had or, by the exercise of due diligence, should have known, the facts that gave rise to their cause of action. We agree. The statute did not begin to run until late March, 1991, and the action is not time barred.
Summary judgment in favor of Jerral W. Jones and Michael V. McCoy on all issues is reversed. The denial of dismissal as to the issue of breach of the covenant to market is sustained. The dismissal of the action on the grounds that the action is barred by the statute of limitations is reversed, and the case is remanded to the trial court for further proceedings consistent with this opinion.
. Take or pay clause
A clause in a gas purchase contract requiring the purchaser to take, or failing to take, to pay for the minimum annual contract volume of gas under which the producer-seller has available for delivery. Under such clause the purchaser usually has the right to take gas paid for (but undelivered) in succeeding years. Such gas is called makeup gas. See Howard R. Williams and Charles J. Meyers, Oil and Gas Terms, 249 (1959), citing Howell, Gas Purchase Contracts, Southwest Legal Foundation, Fourth Annual Institute on Oil and Gas Law and Taxation, 150, 170 (1953).
. Lessor Lessee Relations in a Turbulent Gas Market, 38th Oil & Gas Institute, 8.04 (Mathew Bender 1987).
. .The 1992 CFR omits the words "take-or-pay payments”.
. Professor Thomas Harrell, Professor of Oil and Gas Law, Louisiana State University Law Center, Baton Rouge, La.