Summary
In Frankel, the sublessors brought an action against the sublessees, alleging that the sublessees breached the mineral sublease and failed to reassign the mineral lease to them before it terminated. Following a bench trial, the trial court entered judgment for the sublessors and awarded them $799,804.00 for the loss of past and future overriding royalties that they would have received under the lease.
Summary of this case from Hayes Fund v. Kerr-McGee Rocky Mountain, LLCOpinion
No. 2004 CA 1236.
August 10, 2005.
Appeal from the 17th Judicial District Court, Parish of Lafourche, No. 88445, Division "E," F. Hugh Larose, J.
Reginald J. Ringuet, William H. Collier, Ringuet Daniels Collier, APLC, Lafayette, for Plaintiffs-Appellees Russell M. Frankel, et al.
Robert B. McNeal, Mark L. McNamara, Elizabeth F. Pretus, Alex J. Cenac, Frilot, Partridge, Kohnke Clements, L.C., New Orleans, for Defendant-Appellant Exxon Mobil Corporation.
Loulan J. Pitre, Jr., Gordon, Arata, McCollam, Duplantis Eagan, L.L.P., New Orleans, for Defendant-Appellant Taylor Energy Company.
Before: PARRO, KUHN, and WELCH, JJ.
The sublessees under a mineral lease, Exxon Mobil Corporation (Exxon) and Taylor Energy Corporation (Taylor), appeal a judgment concluding they breached the sublease and ordering them to pay damages to the sublessors, who had overriding royalty interests. The sublessors answered the appeal, seeking additional damages for breach of a reassignment clause in the sublease. We affirm.
FACTUAL AND PROCEDURAL BACKGROUND
The mineral lease at issue in this case (the Pool Lease) was executed January 15, 1948, covering land located in the Clovelly oil and gas field in Lafourche parish. The original landowner and lessor was Lafourche Land Company, Incorporated; its successor-in-interest was Allain-LeBreton Company (Allain-LeBreton). The original lessee was Wylmer I. Pool; his interest was later conveyed to Berkshire Oil Co., which assigned it to Jules R. Frankel in 1949. In the assignment to Berkshire Oil Co., Wylmer I. Pool reserved an overriding royalty interest, a portion of which he later assigned to Jules R. Frankel. The plaintiffs in this case are Russell M. Frankel; Sherry Frankel; Monte C. Shalett, individually and as trustee of the Monte Cresap Shalett Trust U/W Mae Frankel Shalett; Jackie McPherson, executrix of the estate of Jay B. Shalett; Madeline Elizabeth Simeon Chastain; Don Stanford; and Sheryl Stanford Overstreet (the Frankels). They are the heirs of and successors to Jules R. Frankel, who on February 13, 1951, granted a sublease of the Pool Lease to Humble Oil Refining Company (Humble), reserving the overriding royalty interest. Humble later assigned a 50 percent working interest to Shell Oil Company (Shell). Exxon is the successor to Humble; Taylor is the successor to Shell.
The lease originally covered more than three thousand acres, but over two thousand acres were released back to the landowners in 1963, leaving one thousand eighteen acres in the Pool Lease.
The Pool Lease provided that after its initial lease term, it would continue in effect as long as there was continuous production. If such production ceased, the lease could be maintained by new drilling or reworking operations, as long as these were commenced within sixty days of cessation of production and continued without any sixty-day gap. It could also be maintained by shut-in royalty payments. A 1966 amendment to the sublease contained a clause obligating the sublessees to reassign the Pool Lease to the Frankels sixty days prior to the expiration of the lease. That clause stated, in pertinent part:
In the event HUMBLE and/or SHELL shall elect not to continue in effect any lease described in Exhibit "A" by any method in said lease permitted, HUMBLE and SHELL shall, not less than sixty (60) days prior to the time when such lease would otherwise expire, deliver to FRANKEL a suitable assignment in recordable form in Frankel's favor of such lease . . ., free and clear of any charges placed thereon by HUMBLE and/or SHELL.
In a previous lawsuit (the first suit) filed by the current lessor, Allain-LeBreton, against the Frankels, Exxon, Taylor, and others, a judgment was rendered canceling the Pool Lease as of January 1992, based on the court's finding that Exxon, the operating partner for the lease, had failed to conduct timely reworking operations to maintain the lease after production had ceased. The parties then settled and dismissed the first suit before that judgment became final. The settlement of the first suit as of November 1, 1997, terminated the Pool Lease, and a new lease (the New Lease) was confected between Allain-LeBreton and the new working interest owners, Flash Gas Oil Northeast, Inc. (Flash) and Ashlawn Corporation (Ashlawn). Flash and Ashlawn then assigned an overriding royalty interest to the Frankels. The Frankels had been receiving overriding royalties of 21.875 percent resulting from the Pool Lease; under the settlement, the Frankels negotiated the continuation of those royalties through October 1997, after which date their overriding royalties were reduced to 10.17187 percent.
In the first suit, the parties to this suit were all defendants and were aligned in defending the lease. Accordingly, they agreed to mount a joint defense of the first suit, but signed a reservation of rights agreement, recognizing and reserving their right to assert any claims they might have against each other.
The judgment in the first suit determined liability only, and the court would not certify it as final for purposes of appeal until an accounting to determine damages was concluded. Before that occurred, the parties settled with no admission of liability. The effective date of the settlement was November 1, 1997.
Production from the Pool Lease was restored in February 1992, when a shut-in well was placed back in production. Later in 1992, years before the termination of the Pool Lease, Exxon and Taylor assigned their working interests to Flash and Ashlawn. Continuous production in paying quantities continued from various wells on the lease after that date.
The total overriding royalties resulting from the Pool Lease were 25 percent, 87.5 percent of which were owned by the Frankels.
The total overriding royalties under the agreement were 11.625 percent, leaving the Frankels with overriding royalties of 10.17187 percent (11.625 × .875 = 10.17187), a difference of 11.70313 percent.
In this lawsuit, the Frankels claim Exxon and Taylor breached the sublease and failed to reassign the Pool Lease to them before it terminated, resulting in lost revenues. All parties agree that three methods of maintaining the lease after its original term — continuous production in paying quantities, new drilling operations, or making shut-in royalty payments — did not occur after production ceased on October 16, 1991. They also agree that Exxon conducted reworking operations until November 12, 1991. Therefore, the issues before the court in this suit were (1) whether activities on the Pool Lease after November 12, 1991, constituted reworking operations without a lapse of more than sixty consecutive days after production ceased until it re-commenced, and (2) whether the sublessees had breached the reassignment clause of the sublease. At trial, the Frankels claimed the breach of the sublease resulted in the termination of the Pool Lease, depriving them of a portion of their overriding royalties after October 1997, and in the alternative, the breach of the reassignment clause in the sublease caused the loss of their potential working-interest share of production revenues after January 1992.
After a three-day trial, the court took the matter under advisement. A judgment was rendered October 10, 2003, and amended February 25, 2004, to include interest and additional expert fees. In reasons for judgment, the court reiterated the factual findings underlying the judgment in the first suit, declaring again that the Pool Lease had expired as of the 61st day following November 12, 1991, and awarding the Frankels $799,804 for the loss of past and future overriding royalties they would have received under the Pool Lease. The court found the reassignment clause of the sublease was breached, but did not award any damages for the Frankels' working interest, finding the evidence on that claim was insufficient. Exxon and Taylor appealed, claiming the court erred in: (1) its conclusion that Exxon's activities were not good faith reworking operations sufficient to maintain the Pool Lease; (2) its interpretation of the reassignment clause in the sublease; and (3) its assessment of damages. Taylor also assigns as error the court's casting it for damages, along with Exxon. The Frankels answered the appeal, seeking recovery of the working interest revenues they lost as a result of the breach of the reassignment clause, which they claimed were $4,055,328.
APPLICABLE LAW
Lessee's obligation
Louisiana Revised Statute 31:122 sets forth the basic obligations of a mineral lessee to the lessor. It states that the lessee must perform the contract in good faith and develop and operate the leased property as a reasonably prudent operator for the mutual benefit of himself and his lessor. This obligation applies equally to subleases of mineral leases. See Neomar Resources, Inc. v. Amerada Hess Corp., 94-0216 (La.App. 1st Cir.12/22/94), 648 So.2d 1066, 1068, writ denied, 95-0216 (La. 3/17/95), 651 So.2d 277. In any consideration of that general duty, the issue evolves into matters of factual circumstances, reasonable and diligent efforts, industry standards, and prudent operations. McDowell v. PG E Resources Co., 26,321 (La.App. 2nd Cir.6/23/95), 658 So.2d 779, 783, writ denied, 95-1847 (La. 11/3/95), 661 So.2d 1382. The lessee must conform to, and be governed by, what is expected of persons of ordinary prudence under similar circumstances and conditions, having due regard for the interest of both contracting parties. Edmundson Brothers Partnership v. Montex Drilling Co., 98-1564 (La.App. 3rd Cir.5/5/99), 731 So.2d 1049, 1053.
A mineral lease terminates at the expiration of the agreed term or upon the occurrence of an express resolutory condition. LSA-R.S. 31:133. This case involves the alleged termination of the mineral lease upon the occurrence of an express resolutory condition, i.e., the cessation of production for a period of sixty days and the failure to maintain the lease by other available means, such as drilling, reworking operations, or shut-in royalty payments. See Amoco Production Co. v. Carruth, 512 So.2d 571, 573-74 (La.App. 1st Cir. 1987), writ denied, 516 So.2d 366 (La. 1988).
Reworking operations
As noted in the Louisiana jurisprudence, an exact definition of reworking operations is difficult to formulate. The problems associated with producing oil and gas from thousands of feet below the surface are many and varied, as are the procedures for rectifying production that is sluggish or has ceased. O'Neal v. JLH Enterprises, Inc., 37,432 (La.App. 2nd Cir.12/1/03), 862 So.2d 1021, 1027. In Harry Bourg Corp. v. Union Producing Co., 197 So.2d 172 (La.App. 1st Cir.), writ refused, 250 La. 903, 199 So.2d 917 (1967), this court accepted a definition of "rework" commonly used in the oil and gas industry, based on the testimony of three experts who testified at trial. In that case, reworking was defined by the experts as any process or procedure which you may undertake to either regain, increase, or create new production in a well; activity to restore or increase production of a well that has been drilled, usually the second attempt; or to work again on a well. In a well that has produced, it would be an operation when the well came off of production or ceased production, and it would be an operation to maintain, restore, or improve production. Harry Bourg Corp., 197 So.2d at 175-76.
This definition was cited with approval by the Louisiana Supreme Court in Jardell v. Hillin Oil Co., 485 So.2d 919, 923-24 (La. 1986). In Jardell, the court observed:
[T]he prior jurisprudence of this state has provided some guidance for distinguishing reworking operations from routine maintenance. For reworking to occur, it is necessary first that production has ceased or slowed down or has never been achieved. Reworking need not involve additional drilling. It is also clear that reworking operations encompass essential preparatory steps. Furthermore production need not be resumed during the delay. There is also the suggestion that the operations conducted by the lessee must be a good faith effort to resume production as soon as possible.
Jardell, 485 So.2d at 924. Citing cases from other jurisdictions, the Jardell court further stated that:
[A]n activity should be physically associated with the well site and intimately connected with the resolution of the difficulty that caused the well to cease production in order for it to constitute reworking. However, the presence of a workover rig at the well site was not . . . a necessary incident to a reworking operation. . . . And, whatever the activity, it must be done "as an ordinarily competent operator would do in the same or similar circumstances," according to a Texas court.
Jardell, 485 So.2d at 924-25 (citations omitted).
Concerning what constitutes reworking operations, each case must depend upon its own facts, in the light of the opinions of the expert witnesses who testify. House v. Tidewater Oil Co., 219 So.2d 616, 623 (La.App. 3rd Cir.), writ refused, 253 La. 1081, 221 So.2d 516 (1969). The question of whether activities on a lease qualify as reworking operations sufficient to maintain the lease is dependent on factual findings; the jurisprudence does not indicate that certain activities constitute reworking operations as a matter of law. See Allain-LeBreton Co. v. Exxon Corp., 95-1576 (La.App. 1st Cir.4/4/96), 694 So.2d 296, 303. Therefore, the appellate court must apply the manifest error standard to the review of this issue. See Goodrich v. Exxon Co., USA, 608 So.2d 1019, 1028 (La.App. 3rd Cir. 1992), writ denied, 614 So.2d 1241 (La. 1993).
The two-part test for the appellate review of a factual finding is: 1) whether there is a reasonable factual basis in the record for the trial court's finding, and 2) whether the record further establishes that the finding is not manifestly erroneous. Mart v. Hill, 505 So.2d 1120, 1127 (La. 1987). Thus, if there is no reasonable factual basis in the record for the trial court's finding, no additional inquiry is necessary to conclude there was manifest error. However, if a reasonable factual basis exists, an appellate court may set aside a trial court's factual finding only if, after reviewing the record in its entirety, it determines the trial court's finding was clearly wrong. See Stobart v. State, through Dep't of Transp. and Dev., 617 So.2d 880, 882 (La. 1993). Furthermore, when factual findings are based on the credibility of witnesses, the fact finder's decision to credit a witness's testimony must be given "great deference" by the appellate court. Rosell v. ESCO, 549 So.2d 840, 844 (La. 1989). The rule that questions of credibility are for the trier of fact applies to the evaluation of expert testimony, unless the stated reasons of the expert are patently unsound. Sportsman Store of Lake Charles, Inc. v. Sonitrol Sec. Sys. of Calcasieu, Inc., 99-0201 (La. 10/19/99), 748 So.2d 417, 421. Where there are two permissible views of the evidence, the fact finder's choice between them cannot be manifestly erroneous or clearly wrong. Stobart, 617 So.2d at 883; Palace Properties, L.L.C. v. Sizeler Hammond Square Ltd. P'ship, 01-2812 (La.App. 1st Cir.12/30/02), 839 So.2d 82, 89, writ denied, 03-0306 (La. 4/4/03), 840 So.2d 1219.
Interpretation of reassignment clause in sublease
The interpretation of a contract is the determination of the common intent of the parties. LSA-C.C. art. 2045. When the words of a contract are clear and explicit and lead to no absurd consequences, no further interpretation may be made in search of the parties' intent. LSA-C.C. art. 2046. The words of a contract must be given their generally prevailing meaning. LSA-C.C. art. 2047; Crawford v. United Serv. Auto. Ass'n, 03-2117 (La.App. 1st Cir.3/24/05), 899 So.2d 668, 672. Words susceptible of different meanings must be interpreted as having the meaning that best conforms to the object of the contract. LSA-C.C. art. 2048. Intent is an issue of fact which is to be inferred from all of the surrounding circumstances. Whether a contract is ambiguous or not is a question of law. Hampton v. Hampton, Inc., 97-1779 (La.App. 1st Cir.6/29/98), 713 So.2d 1185, 1189. When the terms of a contract are susceptible of more than one interpretation, it is ambiguous. Osborne v. Ladner, 96-0863 (La.App. 1st Cir.2/14/97), 691 So.2d 1245, 1254. Where the terms of the agreement are unclear, ambiguous, or will lead to absurd consequences, the court may go beyond the original agreement to determine the true intent of the parties. Paddison Builders, Inc. v. Turncliff, 95-1753 (La.App. 1st Cir.4/4/96), 672 So.2d 1133, 1136-37, writ denied, 96-1675 (La. 10/4/96), 679 So.2d 1386. A doubtful provision must be interpreted in light of the nature of the contract, equity, usages, the conduct of the parties before and after the formation of the contract, and other contracts of a like nature between the same parties. LSA-C.C. art. 2053; Hampton, 713 So.2d at 1189.
Damages
If a mineral lease is violated, an aggrieved party is entitled to any appropriate relief provided by law. LSA-R.S. 31:134. An obligor is liable for the damages caused by his failure to perform a conventional obligation. A failure to perform results from nonperformance, defective performance, or delay in performance. LSA-C.C. art. 1994. Damages are measured by the loss sustained by the obligee and the profit of which he has been deprived. LSA-C.C. art. 1995. The measure of damages that the lessor (obligee) sustains because of a breach by the mineral lessee (obligor) of its implied obligation to act as a prudent administrator is the value of the minerals or royalties the lessor would have received had the lessee complied with his obligation under the lease. See Williams v. Humble Oil Ref. Co., 290 F.Supp. 408, 422 (E.D.La. 1968), aff'd and remanded for further proceedings, 432 F.2d 165 (5th Cir. 1970), cert. denied sub nom. Humble Oil Ref. Co. v. Price, 402 U.S. 934, 91 S.Ct. 1526, 28 L.Ed.2d 868 (1971). Damages for lost profits must be proven to a reasonable certainty and must not be based on evidence that is speculative or conjectural. See Pelts Skins Exp., Ltd. v. State, 97-2300 (La.App. 1st Cir.4/1/99), 735 So.2d 116, 126-28, writs denied, 99-2036 2042 (La. 10/29/99), 748 So.2d 1167 1168.
ANALYSIS
Keeping the above principles in mind, we examine the factual situation revealed by the evidence in this case. The record indicates that at the end of 1991, Exxon was faced with a difficult situation involving the Pool Lease. The Clovelly field was a depletion-type reservoir that had been producing oil and gas for over forty years. The reservoir pressure in the field was declining, making it more difficult and expensive to maintain production from the wells in the field. In addition, regulations imposed by the Louisiana Department of Conservation required Exxon to install an approved salt water disposal (SWD) facility at the site by September 1992. Mark R. Agnew, the Exxon reservoir engineer with supervisory authority over the Clovelly field, participated in an evaluation of the wells to assist Exxon in making a decision concerning the Pool Lease. He said that after estimating the value of the potential remaining reserves from the wells on the Pool Lease and balancing that against the expense of the SWD facility and eventual "plug and abandon" costs, Exxon concluded in December 1991 that the SWD facility could not be economically justified and decided to either sell or abandon its interest in the lease by the end of 1992. Therefore, Exxon put together a bid proposal, began marketing efforts, and focused its field activity on obtaining sufficient production to sell its interest in the Pool Lease. Barry Ellis, Exxon's field engineering technician on site, testified at the trial that any time Exxon had a property they were "fixing to sell," he would be brought to the field to increase production and cash flow in order to enhance sale opportunities.
This department is now called the Louisiana Department of Natural Resources, Office of Conservation. See LSA-R.S. 36:359(A) (D).
Agnew's deposition in the first suit was submitted as a joint exhibit in this case.
At the end of 1991, there were only four wells still producing or thought to be capable of production in paying quantities on the Pool Lease — LLC Nos. 1, 12, 13, and 20. LLC No. 1, a gas well, had been producing until March 1991, when it shut down automatically due to excessive sand production; it was still shut in eight months later. LLC No. 12, an oil well, had been producing somewhat intermittently, but quit altogether on October 15 or 16, 1991. LLC No. 13 was a formerly productive oil well that had been shut in since the mid-1980's due to an extensive sand "bridge" blocking the tubing. LLC No. 20, a gas well, produced until October 11, 1991, when it quit, apparently due to low reservoir pressure. When LLC No. 12 quit producing in mid-October, Ellis notified his superiors that since all production on the Pool Lease had ceased, the lease expiration clock was ticking, requiring either reinstatement of production or reworking operations within the applicable time period. Following this notification, on October 30, 1991, Dania Baldwin, an Exxon attorney, prepared a document entitled "Lease Maintenance Opinion" which stated:
These wells could potentially produce without major workovers. There were other inactive wells on the lease premises or in the unit that included the lease premises, but Exxon did not do anything to bring these wells back into production during the time period involved in this case.
[I]n order to maintain the captioned mineral leases, additional reworking or drilling operations must be commenced on the LLC No. 12 on or before December 15, 1991. Once commenced, said operations must be continuously prosecuted with no delays in on site activity in excess of 60 consecutive days until [production] is restored.
Exxon had already approved plans and funding for capital expenditures (AFEs) to do some work on LLC Nos. 1, 12, and 13. Aware of the deadline, Ellis continued the field work and reported his progress to Agnew.
LLC No. 1 activity
A barge with well-testing equipment arrived at the Clovelly field around November 4, 1991. John Duplantis, an oil and gas engineer and expert in reworking operations, explained that well records showed LLC No. 1 had initially produced in a low pressure system, but sometime early in 1991, "it kicked into the high pressure system for some reason," resulting in the production of sand and the automatic shut-down. From November 4 through 7, testing was performed on LLC No. 1 — running it at different flow rates with gas going to the test barge — to establish the rate at which the well could produce sand free. According to Agnew, the tests indicated an appropriate rate at which the well could be produced. On November 13, a wireline was inserted to see if the testing process had resulted in sand in the well. The absence of a safety valve was noted during this procedure, and a safety valve was installed on November 20. Ellis testified that from an engineering standpoint, LLC No. 1 was ready to produce at this time, and some gas from the well was used to conduct pressure tests on other wells. However, LLC No. 1 was not brought back into production until February 4, 1992, at which time its gas was used to attempt a gas-lift operation on LLC Nos. 12 and 13.
Duplantis was an expert who testified on behalf of Exxon and the other defendants in the first suit; his testimony at that trial was part of the record in this case.
LLC No. 12 activity
Exxon had known for some months that holes in the well tubing of LLC No. 12 were allowing fluid to leak into the casing, and it had approved an AFE for curative work. From November 6 through 12, down-hole wireline work was performed on the well in an effort to repair it and bring it back into production. A wireline was used to remove "dummy" gas-lift valves from the tubing, to install actual gas-lift valves that could be used once the holes were repaired, to locate the holes in the tubing, and to repair them with pressure packing. The well had to be plugged with an "S" tool or check valve in order to remove the "dummy" gas-lift valves and install the actual valves. The gas-lift valves were successfully installed and a number of holes in the tubing were located. However, during this work, the check valve became stuck in the bottom of the well, and about three feet of sand and other debris accumulated on top of it. The packing could not be inserted to repair the holes in the tubing until the check valve had been pulled out of the well, because the packing would restrict the inner diameter of the tubing and prevent removal of the valve. Exxon's efforts to dislodge the sand and retrieve the valve using the wireline were unsuccessful, and on November 12, 1991, the wireline work was discontinued. From that date until February 4, 1992, Exxon made no further efforts to retrieve the valve from the bottom of LLC No. 12, to conduct any repair work to seal the leaks in the tubing, or to clear the sand.
All of the experts and fact witnesses agreed that this activity constituted reworking operations.
Jerry Raggio, a professional mechanical engineer with a specialty in gas-lift operations, explained that before starting such repairs, fluids had to be loaded into the well to equalize the pressure inside the tubing with the pressure around it from fluids in the casing and thereby "avoid being blown up the hole" when the "dummy" gas-lift valves were removed from the tubing. Therefore, a check valve had to be installed in the bottom of the tubing to hold the "foreign fluids" in the tubing and keep them from seeping back into the formation.
LLC No. 13 activity
Ellis had participated in the original drilling of this oil well many years earlier and was convinced it could be brought back into production despite its long shut-in period. Based on his recommendation, Exxon had approved an AFE for some down-hole work and an eventual gas-lift operation on the well. On November 7 and 8, the barge tested LLC No. 13 to see if it might have sufficient potential to justify repairing an old, ruptured, gas-lift line leading to it. Duplantis stated he saw nothing in those test results to justify repair of the gas-lift line at that point. However, Ellis said he believed a gas-lift operation might loosen the sand bridge. On November 14, Exxon probed LLC No. 13 with a wireline to check the nature and depth of the sand fill blocking the well; no attempt was made to dislodge the sand or open the well at this time. Nothing further was done until February 4, 1992, when a gas-lift operation was attempted without success. Ellis testified that he eventually concluded the well had collapsed casings at the perforations and could not be brought back into production without re-drilling, which was not economically justifiable. LLC No. 13 never produced again.
LLC No. 20 activity
According to Ellis, LLC No. 20 was a gas depletion well; the reservoir pressure had depleted to the point that it did not produce consistently. It would flow for a short period and then would shut down and would have to remain idle while pressure built up again. On November 13 and 14, a wireline was inserted into LLC No. 20 to check the well and measure the bottom hole pressure. On November 19 and 20, LLC No. 20 achieved twenty-four hours of production to the test barge, which showed it was still capable of significant production without any rework. However, production was not continued, because Agnew feared the well might be nearing the end of its capacity and did not want to exhaust it. Therefore, LLC No. 20 was shut in. On November 20, 1991, a memo from Agnew to Joseph B. Elam, an Exxon attorney in the office responsible for making decisions regarding shut-in payments, stated:
The Lafourche Land Co. # 20 in Clovelly field has been flowing over 24 hours at a test rate of 0.686 kcfd. As you have advised, the well is now capable. The well will be shut in today, so please proceed with SI royalty payments within the critical date.
Agnew testified there was a typographical error in this message, in that the flow was actually 686,000 cubic feet, which is what he had verbally communicated to Elam.
Elam testified in a deposition that he told Agnew that before a well could be shut in for the purpose of making shut-in payments, it had to be capable of production in paying quantities, a determination that would have to be made by the engineers. In a letter to Agnew on November 27, 1991, Elam confirmed the information concerning the well's capability of production in paying quantities and said Exxon's records would be adjusted to tender the necessary shut-in payments. Ellis testified at trial that once he learned shut-in payments would be made on LLC No. 20, this eased the time pressure for other work in the field to reinstate production from another well.
Under LSA-R.S. 31:124, production is considered to be in paying quantities when the lessee's share of such production under the lease is sufficient to induce a reasonably prudent operator to continue production in an effort to secure a return on his investment or to minimize any loss.
Elam's deposition was taken in connection with the first suit and was submitted as a joint exhibit in this case. On this point, Elam's testimony conflicted with Agnew's, who said he did not make that determination. Agnew said that after he told Elam about the 24-hour production levels on LLC No. 20, Elam told him this meant the well was capable of production in paying quantities.
In a follow-up letter to Agnew on January 22, 1992, Elam stated shut-in payments would commence on February 18, 1992. However, on February 11, Agnew advised Elam that repair work was proceeding on LLC No. 12, so the shut-in payment could be eliminated. Elam also concluded that under Louisiana jurisprudence, any field activity would be sufficient to hold the Pool Lease; therefore, shut-in payments were not needed. In a letter to Agnew dated February 27, 1992, Elam noted this and stated, "Should these operations cease, an additional monthly payment of $1,375 will become necessary to maintain that lease." Exxon did not make shut-in payments to maintain the Pool Lease, and LLC No. 20 remained shut in until Flash turned it back on in October 1992. At the time of trial in February 2003, LLC No. 20 was still producing.
In the Pool Lease, the critical time period for payment of shut-in payments was 90 days after gas sales ceased from a gas well capable of production in paying quantities. Elam admitted that upon further review of the lease terms and the factual situation on this lease, the test production from LLC No. 20 on November 20, 1991, which was not sold, may not have been the correct trigger date for such payments. However, since no payments were made, the correctness of Elam's deadline is not relevant.
However, their communications indicate that neither Elam nor Agnew considered the timing of those activities or whether a sixty-day lapse had already occurred before those repairs began in February 1992.
Other activity in the Clovelly field
There was no direct work on any well to correct production problems after Exxon discontinued the wireline repair efforts on LLC No. 12 on November 12, 1991. A safety valve was installed on LLC No. 1 on November 20, and a twenty-four hour test run of LLC No. 20 was conducted to the barge on November 19 and 20. The only activities in the field after that date were the transportation of pipe to the site from another Exxon operation, welding to repair and upgrade flowlines, and gas-lift line installation. According to Ellis, the same kind of pipe was used for flowlines and gas-lift lines. Ellis said a flowline servicing LLC No. 1 had ruptured and needed to be repaired. Because suitable pipe was lying unused at another Exxon field, the decision was made to replace the flowline, rather than just repair it. Ellis said the work on the LLC No. 1 flowline was done between January 27 and February 3, 1992. The only other work between November 12, 1991, and February 4, 1992, was repair and installation of gas-lift lines leading to LLC Nos. 12 and 13. Ellis said he decided not to do any further work on the wells until the gas-lift procedure could be tried. Therefore, all other activity was suspended for over two months while the gas-lift lines were being prepared for this attempt.
On a timeline of Clovelly field activity prepared by petroleum engineering expert Bill Hise, gas-lift line work is shown during late November and early December 1991, while pipeline welding work is shown intermittently from January 3, 1992, through January 31, 1992. However, Hise said most of the contractor's work tickets did not show exactly what was being welded on any given date, so these were not precise descriptions. The only clarification in the record identifying the timing of work done only for the LLC No. 1 flowline was the testimony from Ellis and an entry on another Clovelly Field History stating, "LLC # 1: 01/27, 28, 30, and 31/92 installing new flowline." All other work during January — including manufacturing a canal crossing during the week of January 20 — was preparation for the gas-lift attempt.
Were these activities reworking operations?
A gas-lift operation involves pumping gas into a well through a gas-lift line in order to aerate the contents, thereby reducing the density of the fluid in the well and lowering the bottom-hole pressure needed to generate the upward flow. According to Hise and Raggio, the effect of a gas-lift operation is similar to shaking a carbonated soft drink. On February 4, 1992, LLC No. 1 was brought back into production, and gas from it was used in an attempt to gas-lift LLC Nos. 12 and 13. Ellis stated that repairing and installing gas-lift lines were essential steps in achieving production, because he believed the gas-lift procedure might dislodge some of the sand from the plugged wells and allow production to be reinstated. Ellis said he believed the activities conducted in the Clovelly field after production ceased in October 1991 were reworking operations that would maintain the Pool Lease.
Hise testified in the first trial on behalf of Allain-LeBreton as an expert in petroleum engineering; his testimony from the first trial was included as a joint exhibit in this case.
In the first suit, Raggio testified on behalf of Allain-LeBreton; his testimony from that trial was included as a joint exhibit in this case.
However, Hise stated Ellis's expectation concerning the gas-lift operation was not reasonable, because both LLC Nos. 12 and 13 obviously needed significant down-hole work before any gas-lift process could succeed. Concerning LLC No. 12, Hise explained:
Well, these [gas-lift] valves are designed so when you pressure up and activate them, they unload the liquid out of the tubing down to a point where, you know, depending on what the pressure is in the well, you may have to move [to] successively lower depths to aerate the column to get it to flow. And this is not going to work. A gas lift valve is a precision instrument that opens at a certain pressure and then closes and then you go to the next one down in the well. You're going to have a whole series of them, normally. And if you have a hole in the tubing, it just defeats this sequential opening of the gas lift system.
Hise said that the successive steps Exxon should have attempted in order to reinstate production in LLC No. 12 would have been: (1) to continue wireline-type efforts with stronger, braided line; (2) to use a coil tubing unit — like a steel garden hose — to circulate water and wash out the sand; or (3) If all else failed, to put a workover rig on the well, remove the tubing and stuck check valve, and make the repairs. Because the installation of a gas-lift line to LLC No. 12 was not a logical next step to restore production from the well, Hise concluded that such activity did not constitute a reworking operation in these factual circumstances.
Flash eventually performed a complete rework of this well with a workover rig in October 1992, as a result of which, LLC No. 12 began producing again.
For much the same reasons, Hise concluded the gas-lift line installation and gas-lift attempt on LLC No. 13 did not constitute reworking operations. In addition to a sand plug blocking the tubing, that well also had a standing valve that had been stuck in the bottom of the hole under the sand for a number of years. LLC No. 13 already had one old gas-lift valve in it; Exxon had installed additional gas-lift valves in August 1991, and had approved an AFE for work consisting of successive steps similar to those outlined by Hise before attempting the gas-lift. However, instead of following that plan and clearing the well before trying to gas-lift it, Ellis delayed all further work until the unsuccessful gas-lift attempt on February 4, 1992. Since this attempt was virtually doomed to failure, Hise did not consider it to be a bona fide reworking operation. He also noted that the wireline test on November 14 was not a reworking operation, stating that in his view, well tests are conducted routinely and are never considered reworking operations.
After reviewing all of the Exxon records, its employees' deposition testimony, and records kept by Flash after it took over the working interest, Hise constructed a Clovelly field timeline showing the nature of the activity on each well, the date it started, and the date it concluded. The flowline and gas-lift line installation on site was also shown. Based on his review of this factual information, Hise concluded that although Exxon had started a reworking operation on the lease with its wireline work on LLC No. 12, that work was discontinued on November 12, following which there was a period in excess of sixty days when there were no reworking operations, no new drilling, and no production. He observed that during the critical period, the only work done was well testing, repair and replacement of flowlines, and installation of gas-lift lines, work which could not be considered reworking operations in the context of this case.
See footnote 18. The accuracy of the times and activities shown on the Hise timeline of Clovelly field activity was not contradicted by any of the fact witnesses or documentary evidence in the record.
Raggio expressed much the same opinion, indicating that even if all flowlines and gas-lift lines had been in place and ready to use on November 12, Exxon could not have successfully gas-lifted LLC Nos. 12 and 13 to bring them back into production. He said LLC No. 12 was still loaded with water after the wireline procedures, and the spacing of the gas-lift valves in it was such that the water could not have been unloaded using a gas-lift operation. Also, with all this water in the tubing, it was not realistic to expect the gas-lift operation to remove sand covering the check valve. Before the well could flow — with or without gas-lifting — the water had to be drained, the sand had to be removed, and the check valve had to be retrieved from the bottom of the hole. Concerning LLC No. 13, Raggio said the well records indicated it had been shut in for many years, had a sand bridge "cemented" in the tubing over 1,000 feet above the perforations, and had a standing valve stuck in the bottom of the hole. He did not believe the gas-lift design for the well could accomplish removal of such entrenched sand, nor could it unload the fluid that had been loaded into the well. Therefore, Raggio agreed with Hise that the gas-lift line installation and gas-lift operation were not calculated to produce any results as far as getting LLC Nos. 12 and 13 back into production.
Exxon and Taylor contend, however, that well tests and the installation and repair of the flowlines and gas-lift lines were essential preparatory steps to resuming production from the wells. Duplantis testified that when a well is producing sand or has a sand blockage of some kind, the testing of that well to determine the degree of sand production or the nature, location, and extent of the blockage would be considered a reworking operation. He also said it appeared the flowline installation for the LLC No. 1 well was a necessary prerequisite to getting the well back into production, because the low-pressure flowline in place before the well shut down in March 1991 needed to be replaced by a high-pressure flowline. In his opinion, reworking operations in this case would also include obtaining permits to lay flowlines across a canal in the marsh and installing the safety valve in LLC No. 1. However, Duplantis agreed with Hise and Raggio that the attempt to gas-lift LLC Nos. 12 and 13 could not be considered an essential step toward putting those wells back into production and said he could not say it was logical to stop wireline operations on those blocked wells and begin laying gas-lift lines. Duplantis said it appeared Exxon was just testing the gas-lift systems, noting that "it's a cheap, inexpensive way to see if their idea of gas lifting would work on the 12 and 13 Well[s]."
After reviewing the activities being conducted by Exxon on the Pool Lease, Duplantis concluded there was no time period in excess of sixty days after production ceased during which no reworking operations occurred. However, he admitted on cross examination that if the entire flowline and gas-lift line activities were determined not to be reworking operations, there would have been sixty consecutive days without reworking operations. He also acknowledged that he did not know if any permits were required or applied for at this time in order to perform the flowline or gas-lift line work on this lease; he did not know if it was actually necessary to install a higher-pressure flowline for LLC No. 1, rather than simply repair the existing flowline; and he did not know why it would have taken so long to begin repair or replacement of that flowline.
Agnew described the following activities to maintain the lease after October 1, 1991: wireline work, well testing, and flowline on LLC No. 1; wireline work and gas-lift line work on LLC No. 12; testing, wireline work, flowline and gas-lift line work on LLC No. 13; and testing and wireline work on LLC No. 20. However, he admitted he did not calendar the sixty-day deadline or the timing of the work being done, relying on Ellis to advise him about whether the work and its timing were sufficient to maintain the lease.
In apparent contradiction to Exxon's argument concerning whether the installation and repair of flowlines and gas-lift lines were reworking operations is the deposition testimony of Exxon's retired Senior Field Superintendent, Thomas R. Stringer, whose production responsibilities in 1991 and 1992 included the Clovelly field. He had no supervisory authority over any down-hole work that might be required to reinstate production, but he was involved in the decisions concerning flowlines and gas-lift lines. Stringer testified that it just "seemed good business" to take care of those lines, using pipe that was lying idle at another Exxon field not far away. He said he considered the work done on the Clovelly field flowlines and gas-lift lines during this time period to be routine maintenance.
Stringer's deposition was taken in connection with the first suit and is a joint exhibit in this case.
Although Ellis believed the flowline and gas-lift line work constituted reworking operations, he agreed that routine maintenance did not require authorization for a capital expenditure and that there were no AFEs for this work, whereas there were AFEs for the down-hole work. Ellis also confirmed that the availability of pipe at a nearby Exxon field provided a resource that Stringer could use and prompted the decision to replace flowlines at this time.
In reasons for judgment, the court observed the wells were "plagued by down-hole problems," that had to be corrected before production could be resumed, concluding:
During the time in question, no down-hole work was undertaken, no wireline operations were performed, no workover rigs were brought on location. In short, the only attempts at "reworking" by Exxon [were] the delivery of, and installation of flow lines to repair existing damaged flow lines as well as some new gas lift flow lines. However, even with the addition of the new gas flow lines intending to gas lift the No. 12 and No. 13, it is clear that neither the No. 12 nor the No. 13 were properly equipped or prepared to accept the gas lift operation and that this would require further down-hole work. Based upon these facts, it is found that the lease with the Allain-Lebreton Company was in fact breached by failure to perform reworking activity in excess of 60 days.
Based on our review of all the evidence in the record, we conclude there was reasonable factual support and credible expert opinion underlying the court's finding that the only reworking operations in the Clovelly field after production ceased in mid-October were the wireline efforts on LLC No. 12, and that the Pool Lease terminated by its own terms sixty-one days after those efforts were discontinued on November 12, 1991.
Our review of the record as a whole for manifest error does not demonstrate that the trial court's conclusion was clearly wrong. According to two experts, Hise and Raggio, November 12 was the last day on which any activity occurred that was logically connected with the resolution of the difficulties that had caused one of the wells to cease production. They, along with Duplantis, concluded that gas-lift line installation was not an essential preparatory step toward reinstating production from any of the wells in the field. Nothing in the record indicates that the opinions of these experts were patently unsound. On the contrary, the facts of this case fully support their conclusions. The activity associated with the gas-lift lines did not address the difficulties that were preventing production from LLC Nos. 12 and 13, nor did it have any effect on LLC Nos. 1 or 20, other than to delay the start-up of LLC No. 1 until the gas-lift lines were in place. Therefore, we find no error in the court's conclusion that these activities were not reworking operations under the factual circumstances of this case.
Looking at the remaining activities, we note that even if the work on November 20, 1991 — the installation of a safety valve on LLC No. 1 and the 24-hour well test on LLC No. 20 — were considered essential to bring those wells back into production, a sixty-day gap in activities on the wells occurred following that date, during which time nothing was done to bring them or any other well back into production. The only other activity arguably related to reinstating production from any well was the replacement of the broken flowline for LLC No. 1. However, by November 13, the well tests on LLC No. 1 had demonstrated there was a lower flow rate at which this well could produce sand-free. The LLC No. 1 flowline could have been repaired or replaced immediately and production could have resumed from this well while other field work continued. Instead, Exxon opted to leave LLC No. 1 shut in until the gas-lift lines were installed. According to Ellis, the LLC No. 1 flowline work did not begin until January 27, 1992, by which time a sixty-day lapse in reworking operations had already occurred, no matter which starting date is used.
Therefore, although there was testimonial and documentary evidence from which the trial court might have reached other factual findings concerning the commencement date for the sixty-day time period or the qualification of certain activities on the lease as reworking operations, the evidence in this case presented the court with two permissible views of the facts. When the evidence as a whole is plausible and there are two permissible views of the evidence, the court's choice between them cannot be manifestly erroneous or clearly wrong. Unless the trial court's judgment is manifestly erroneous, this court cannot substitute its judgment for that of the trial court, even if it might have evaluated the facts differently or reached a different conclusion. Accordingly, we accept the court's conclusion that there were no reworking operations sufficient to maintain the Pool Lease after November 12, 1991. With no production, no new drilling, no reworking operations, and no shut-in payments within the critical time periods, the lease lapsed.
Breach of the sublease and reassignment clause
Under the sublease, the Frankels stood in the position of lessors to Exxon and Taylor. As such, Exxon and Taylor were bound to perform the contract in good faith and develop and operate the leased property as reasonably prudent operators for the mutual benefit of themselves and the Frankels. See LSA-R.S. 31:122. As noted by Judge Alvin Rubin in the Williams case:
The fundamental purpose of the mineral lease — "the use for which it was intended by the lease" — is the production of minerals. Once production commences, the lessor is paid rent for the leased premises only by the royalty reserved in the lease. It is therefore the duty of the lessee, necessarily implied in the lease, to develop the leased premises properly and to prevent drainage of oil and gas from beneath it, not at all hazards and all costs, but "as a good administrator," just as it is the obligation of a lessee enjoying a store under a percentage rental to operate the store with regard to the lessor's interests as well as its own. (footnotes and citations omitted).
Williams, 290 F.Supp. at 415. Obviously, this case does not involve the lessee's implied obligation to prevent drainage of minerals from leased property, but it does involve the implied obligation underlying every lease to operate the leased property as a good administrator with due regard for the lessor's interests. The trial court found this obligation was breached by the defendants in this case. Based on our review of the evidence, we find no manifest error in this conclusion, which is supported by the record as a whole.
Despite the fact that Exxon employees with key roles and responsibilities in this situation, namely Ellis, Agnew, and Elam, were aware of the ticking clock after production ceased on October 15, 1991, their testimony indicates none of them actually calendared the work as it was being done to be sure there was no sixty-day lapse in the activities in the field. During much of the critical period, Agnew and Ellis apparently relied on the fact that LLC No. 20 had been found capable of production in paying quantities and had been shut in, thus making it possible to maintain the lease by making shut-in payments. Therefore, as Ellis testified, he felt no urgency to do the repair work on the other wells within the sixty-day period. Then in February 1992, when the time approached for making those shut-in payments of $1375 per month, Elam checked back with Agnew and learned that, according to Ellis, repair work was being done on LLC No. 12. However, because no one was keeping track of the timing of the work, by that time sixty days without genuine reworking operations had already passed. The prudent decision at that point would have been to make these de minimis shut-in payments, which could have maintained the Pool Lease for up to five years. Instead, Agnew and/or Elam made a considered decision not to pay shut-in royalties, and ultimately, the lease was extinguished by the occurrence of the resolutory condition — cessation of production and a sixty-day lapse without new drilling or reworking operations — and without shut-in payments. We find no error in the trial court's conclusion that the sublessees in this case did not perform the contract in good faith and did not operate the lease property as a reasonably prudent operator.
"For the want of a nail, the shoe was lost; for the want of a shoe, the horse was lost; for the want of the horse, the rider was lost . . . all for the want of a horse shoe nail." Benjamin Franklin, Poor Richard's Almanac (1758).
The trial court also concluded that Exxon's actions and decisions constituted an election on behalf of the sublessees not to continue the Pool Lease in effect by any of the methods permitted by the lease. Therefore, the sublessees were obligated to reassign the lease to the Frankels sixty days before it would otherwise expire, so they could protect their interests. Exxon contends the court erred in this interpretation of the reassignment clause, because a plain reading of the provision requires a conscious choice to discontinue the lease, which it claims it did not make.
Taylor did not address any of these issues in its briefs, but adopted Exxon's arguments as its own.
We agree that the word "elect" connotes a conscious decision. We also agree with the statement of the trial court, that "Exxon as operating partner of the lease in question made a business decision to not undertake any expensive down-hole reworking operations in light of the fact that they had already made the decision to sell their interest in the sub-lease." The record established a series of decisions made by the operating partner affecting the sublease at this time. Exxon had concluded it would either sell or abandon its interest in the lease before the end of 1992. All of its actions during this period were motivated by that specific intention. Therefore, when production ceased in mid-October 1991, it never considered doing any new drilling in the field. Also, instead of completing the down-hole work its own AFEs described to bring some of the wells back into production, which would have been reworking operations, Exxon chose to do only routine flowline maintenance and installation for a gas-lift operation that was a futile exercise when it was undertaken, however beneficial it might have proven after the wells were cleaned out. Additionally, Exxon opted to delay production from LLC No. 1 until flowline replacement and gas-lift line installations were finished. Exxon also decided on November 20 not to turn LLC No. 20 back on, although there was no physical obstacle preventing this well's production, because it did not want to jeopardize the well's production potential while trying to sell its working interests. And finally, as the trial court also noted, Exxon also made a conscious decision not to pay "inconsequential" shut-in royalties of $1375 per month, an alternative it knew would maintain the lease for up to five years. Each of these decisions was an "election" under the clear meaning of the word.
Taylor had obviously reached a similar conclusion; it sold its interest to Flash on May 6, 1992.
However, the reassignment clause is more than just one word; it also includes the phrase, "by any method in said lease permitted." When read in pari materia, ambiguity creeps into the clause. If, as Exxon and Taylor contend, the reassignment clause could only be triggered if the sublessee(s) chose to abandon or give up the lease, then this additional phrase would be superfluous. This court cannot simply ignore a phrase because it is inconvenient or "muddies the waters," when we would prefer clarity. We conclude, therefore, that when the complete text of the reassignment clause is considered, the clause is ambiguous.
Determining the intent of the parties is difficult in this situation, because the current parties were not involved in confecting and drafting the lease, sublease, or amendment. If anything is clear about their agreements, it is that the current parties do not share a common intent with respect to the reassignment clause. However, there is testimony in the record concerning the generally understood purpose and intent of such provisions in the oil and gas industry. Monte C. Shalett testified as the representative of the Frankels; he was the owner of three corporations involved in the oil industry and had worked in the family business of oil and gas production and exploration during all of his adult life — over thirty years at the time of trial. Shalett stated the general understanding in the industry was that the purpose of such a clause is to require the sublessee to maintain the lease in full force and effect or reassign it to the sublessors. Shalett said the Frankels had to rely on Exxon to take whatever steps were necessary to maintain the lease. If Exxon chose not to do what was required to maintain the lease, it had to offer the Frankels the opportunity to save the lease. Michael F. McKenzie, an expert in petroleum engineering and petroleum reservoir engineering, also confirmed that the generally accepted meaning in the oil and gas industry is that the sublessee's obligation under such a clause is "to either maintain the lease in effect and force, or reassign it in a timely manner." Even Calvin Boudreaux, a landman who testified as an expert on behalf of Exxon, agreed that the purpose of a reassignment clause is to make sure the sublessor has the chance to get the lease back before it expires. We note that such a clause is the only realistic protection for the non-working-interest owners, who otherwise are totally at the mercy of the working-interest owners to conduct operations in the field for their mutual benefit.
The purpose and importance of such a provision was emphasized by the court in Amoco Production Co. v. Texaco, Inc., 02-0240 (La.App. 3rd Cir.1/29/03), 838 So.2d 821, 830, writs denied, 03-1102 1104 (La. 6/6/03), 845 So.2d 1096, as follows:
The reassignment clause in Amoco Production stated:
In the event that the Assignee should elect to surrender, let expire, abandon or release any or all rights in said lease acreage, or any part thereof, the Assignee shall notify the Assignor not less than sixty (60) days in advance of such surrender, expiration, abandonment or release, and if requested to do so by the Assignor, the Assignee Immediately shall reassign such rights in said lease acreage, or such part thereof, to the Assignor. (Emphasis added.)
Amoco Production, 838 So.2d at 826.
[I]t is impossible to determine precisely when assigned leases may be lost. Unlike obligations that arise on a certain date, no exact date can be set when a lease may expire. Also, leases may be continued in a number of ways, including redrilling operations, productions from different units in the same field or the granting of extensions. The record establishes reliance on the lease reassignment provisions is the primary vehicle by which an assignor learns that his lease is in danger of being lost. All the experts admitted it is customary for oil and gas companies to honor reassignment clauses. However, in this case neither IMC nor Texaco provided Amoco with notice as required by the reassignment clause.
Similarly, in this case, when production ceased, Exxon made no effort to advise the Frankels of the situation, much less tell them about the decision not to make shut-in payments that would have held the lease or offer to reassign the lease to them.
Like the trial court, we are also influenced by the decision in Huggs, Inc. v. LPC Energy, Inc., 889 F.2d 649 (5th Cir. 1989), which, applying Louisiana law, also interpreted a reassignment clause with language similar to the reassignment clause in this case. That clause stated:
In the event [LPC] elects not to maintain any lease within a proposed unit in effect by payment of delay rentals or drilling operations or to renew or extend to such lease then on or before 60 days of the earliest lease expiration or delay rental date on any lease on any unit, [LPC] shall relinquish and assign, free of liens and encumbrances, to Huggs all of such leases within such unit area and any leases therein and any wells drilled or caused to be drilled thereon shall no longer be subject to this agreement. (emphasis added).
Huggs, 889 F.2d at 653. The court described the duty under that clause as an alternative obligation, either to maintain the lease by delay rentals or drilling operations or relinquish and assign all the leases within a unit area sixty days before the lease expired. As a prudent operator, LPC was required to keep current with the facts so that it could make a responsible decision concerning the election. The court concluded, "When LPC failed to maintain the lease by delay rentals or drilling operations, it was thereby required to relinquish and assign the leases; failure to do so constituted a breach of contract." Huggs, 889 F.2d at 654.
Exxon distinguishes the Huggs case, because there the operator was simply not paying attention to what was happening, whereas Exxon claims it knew exactly what was going on with the Pool Lease. We believe this militates against Exxon, since it did know that production had ceased and made a series of decisions not to use the several alternatives open to it under the lease to ensure it was maintained. We note also that Exxon has not cited to this court any Louisiana jurisprudence agreeing with its interpretation of reassignment clauses including "election" language similar to that at issue in this case, nor did our research reveal any such cases. Although Exxon suggests in its brief to this court that a later Fifth Circuit case, Avatar Exploration, Inc. v. Chevron, U.S.A., Inc., 933 F.2d 314 (5th Cir. 1991), was a "correction" to what it considers an incorrect decision in Huggs, the Avatar reassignment clause addressed only the payment of delay rentals. If the assignee "elected" not to pay delay rentals, the reassignment clause was triggered. However, the court found the assignee had paid all delay rentals, so the clause had not been breached, stating, "Nothing in the clause indicated an intent of the parties to expand the right to reassignment beyond the occurrence of that one event." Avatar, 933 F.2d at 318. Unlike the Avatar reassignment clause, the phrase in this case "by any method in said lease permitted," does indicate a more expansive intent.
We conclude, therefore, that the reassignment clause in this case was triggered by the choices made not to continue the Pool Lease by any of the permitted methods. Therefore, the sublessees breached that clause by failing to reassign the lease to the Frankels before it expired. We find no error in the trial court's conclusion on this issue.
Damages — lost overriding royalties
The amount of damages awarded to the Frankels was compensation for the diminution of their past and future overriding royalties after the settlement in 1997. See LSA-C.C. arts. 1994 1995. The award was based on the assumption that the Frankels would have continued to receive overriding royalties at the same percentage rate resulting from the Pool Lease, regardless of who held the working interest, and was computed from the actual sales records for wells on the Pool Lease — or in the unit in which the lease property was included — that were put back into production after February 4, 1992. The amounts the Frankels had already been paid during this time — their full overriding royalties through October 1997 and lower overriding royalties after the settlement of the first suit — were not included in this total, recognizing the mitigation of their damages. See LSA-C.C. art. 2002. The overriding royalty computations were done by McKenzie, who reviewed field and well operations reports and actual payment records from January 1992 forward. In computing the future overriding royalties, the historical annual decline was charted for each well, and the future royalties attributable to the projected remaining life of each well were discounted 10%. The wells on which production was reinstated included LLC No. 20, LLC No. 27, and Exxon B-4 — a unitized well on adjoining property for a unit that included the Pool Lease property. McKenzie's report indicated $799,804 was the total loss the Frankels suffered due to having their overriding royalties reduced as a result of the termination of the Pool Lease. His methodology and computations were confirmed by Ron Gaubert, an oil and gas accounting expert who also testified on behalf of the Frankels.
Charles C. Theriot, a certified public accountant with expertise in oil and gas matters and business valuations, testified on behalf of Exxon and Taylor. He questioned the reliability of McKenzie's data, but did not offer a more accurate compilation. Theriot confirmed the basic mathematical computation for the diminished overriding royalty and agreed on cross-examination that "but for" the termination of the Pool Lease, the Frankels would have continued to receive the full 21.875 percent overriding royalties on production from all of the wells contributing production under the lease, no matter who held the working interest. Therefore, we conclude, as did the trial court, that the losses attributable to the diminished overriding royalties were an appropriate measure of the Frankels' damages in this case.
Most of his testimony criticized the computation of the working interest losses, as those were compiled by McKenzie and Gaubert.
However, Exxon contends some of the amounts included in the court's damage award were not justified. It argues that because LLC No. 27 was totally inactive when the lease terminated and was eventually transferred back to the landowner by Flash and Ashlawn, the Frankels would not have received any royalties attributable to that well, because it had been released from the lease by the time the production occurred. However, the transfer of this well occurred in connection with the settlement of the first suit and confection of the New Lease — which would not have occurred "but for" the sublessees' failure to maintain the Pool Lease. Shalett explained that a "Pugh clause" in the New Lease, a provision not included in the Pool Lease, ultimately resulted in this well reverting back to the landowner. Had the Pool Lease still been in place, the Frankels would have gotten overriding royalties on the production attributable to LLC No. 27, because it was included in the Pool Lease. When questioned about this, Theriot admitted that under this scenario, the Frankels would have received overriding royalties under the Pool Lease for this well's production. The court commented during this testimony that the "but for" analysis had several layers, "like an onion," and ultimately chose to include the overriding royalties attributable to LLC No. 27 in its award of damages. We find that the award for overriding royalties attributable to production by LLC No. 27 was within the trial court's discretion.
The general rule with respect to the maintenance of oil, gas, and mineral leases is that the drilling of a well on the premises covered by the lease during the primary term of the lease, assuming such well produces in paying quantities, maintains the lease as to all of the lands covered by the lease. See LSA-R.S. 31:114. The inclusion of a Pugh clause has the result that if there is unitization and production is obtained from the unit, the lease is maintained only as to that portion of the leased premises within that unit. See Will-Drill Resources, Inc. v. Huggs Inc., 32,179 (La.App. 2nd Cir.8/18/99), 738 So.2d 1196, 1199, writ denied, 99-2957 (La. 12/17/99), 751 So.2d 885. According to Shalett, the LLC No. 27 well was outside the unitized area that included the LLC No. 20 and the Exxon B-4. Because the New Lease had a Pugh clause and a short primary term, the Frankels did not receive any overriding royalties from production attributable to the LLC No. 27 well.
Exxon also argued that an award for overriding royalties attributable to production from the Exxon B-4 well was inappropriate. That well was not located on the Pool Lease property, but was a unitized well on adjoining property, with 60% of the unit consisting of Pool Lease property. Because of these proportions of ownership, Exxon contends it was mere conjecture to think a rational operator not involved in the Pool Lease would invest 100% of the capital needed to rework a well when it would be entitled to only 40% of its production. However, Exxon sold its working interest in the Pool Lease and its ownership interest in the Exxon B-4 to Flash and Ashlawn as part of the total sale package in 1992. That sale, unlike the transfer of LLC No. 27, preceded by a number of years and was totally independent of the settlement of the first suit. Flash and Ashlawn ultimately re-completed the Exxon B-4 well several years later and brought it back into production. Had it not been allowed to expire, the Pool Lease would have been extant, and the Frankels would have been entitled to overriding royalties attributable to production from that well. Therefore, we reject Exxon's argument on this portion of the damage award. We find the damages awarded by the court for lost overriding royalties are legally and factually justified.
Damages — lost working-interest revenues
Despite the trial court's finding that the reassignment clause was breached, the court also found there was "no reliable evidence" that the Frankels could have undertaken the role of an active operating partner and matched the sophistication, financial resources, and expertise possessed by Exxon and the successor operating partners to obtain comparable continued production in paying quantities from the field. Therefore, the court declined to award any damages for the loss of working-interest revenues the Frankels could have received if that clause had not been breached and the lease had been reassigned to them. In their answer to the appeal, the Frankels contend the court erred in failing to award damages for lost working-interest revenues.
Based on our review of the record, we find the trial court was within its discretion in determining that an award for the potential lost working-interest revenues was not justified by the evidence presented. While we are impressed with Shalett's credentials, experience, and overall knowledge of the oil and gas industry, the premise underlying the Frankels' working-interest claim was that they could have achieved the same results as did the subsequent operators. To some extent, this is inherently speculative. The projections presented to the court by Gaubert and McKenzie were based on the actual results achieved by the subsequent operators, which is the only basis on which they could be computed. However, those projections ignored the fact that some of the realities enabling the successor operators to achieve those results were different from what would have existed for the Frankels. For instance, in late 1991, much of the infrastructure needed for operations in the Clovelly field was not on Pool Lease property, but was located off the lease premises and would not have been included in any reassignment. These processing facilities and equipment were owned by Exxon and were included in the transfer to Flash and Ashlawn, who used them in developing and maintaining production and sales from the Clovelly field. However, it is pure conjecture to predict Exxon would have transferred or leased this equipment to the Frankels. Moreover, there was nothing in the Frankels' projections to account for the expenses they would have incurred to build, purchase, or lease these or comparable facilities.
The evidence also showed that Shalett, individually or through his corporations, did not have the manpower to maintain operations in the field without contracting out the actual work. Yet the projections presented by the Frankels in support of this claim did not include any expenses for contractors. Also, although Shalett testified concerning the net worth of his companies, there was no financial information other than this very brief testimony to show the court the Frankels could have matched the long-term investment put into the Clovelly field by the successor operators in order to maintain production. These projections also did not include any "plug and abandon" costs that would eventually be incurred for the field, which Exxon had estimated would exceed $1.5 million. Also, despite Gaubert and McKenzie's best efforts to accumulate all the revenue and expense data for the post-1992 production, there were significant gaps in some of the information on which their projections were based, particularly on the expense side.
We note also that the production revenue attributable to the Exxon B-4 well, $2,185,939, forms over half of the projected working-interest revenue the Frankels claim they would have received if the lease had been reassigned. Yet, as noted above, that production was achieved only after and because the working-interest owners obtained a 100% interest in that well as a result of the 1992 sale from Exxon and Taylor to Flash and Ashlawn. Had the lease been reassigned to the Frankels in 1991, that sale would not have occurred. If the working interest had not been sold, the development of the Exxon B-4 may not have occurred. Therefore, unlike the overriding royalties, which the Frankels would still have received despite the 1992 sale, the premise underlying their working-interest-revenue claim is undermined by the reality that the sale helped make this well's development economically justifiable. Thus, a major portion of their working-interest claim is speculative and conjectural.
Because of these and other discrepancies in the estimates of the working-interest revenue the Frankels might have been able to generate, we agree with the trial court that such damages were not proven to a reasonable certainty. Therefore, the court did not err or abuse its discretion in refusing to award damages for this claim.
Taylor's obligation
Because Exxon, as the operating partner, was the entity actually making the choices concerning the sublease, Taylor, the non-operating partner, now claims there is no evidence it made any election at all, and it cannot be held responsible for Exxon's decisions. We find this argument interesting, but specious. The parties entered a joint stipulation into the record, stating, in pertinent part:
Exxon and Shell became jointly, and not solidarily, liable for the obligations arising under the Sublease, with each being responsible for only, and not more than, its 50% of such obligations.
Both Exxon and Taylor were subject to the prudent operator standard and were bound by the reassignment clause in the sublease. The record established that, as between the two of them, Exxon had been designated as the operating partner to make choices in the field affecting the sublease. As such, Taylor conferred on Exxon, at the very least, the apparent authority to act on its behalf, and the Frankels justifiably relied on that authority. See LSA-C.C. arts. 3020 3021. Taylor failed to submit any evidence of its joint operating agreement with Exxon to establish what is, in essence, its affirmative defense or cross-claim to show that Exxon acted outside of its operating authority in making the choices it did concerning the Pool Lease. Therefore, we find no merit in this contention.
CONCLUSION
For these reasons, we affirm the judgment of October 10, 2003, as amended February 25, 2004. Each party is to bear its own costs for the appeal.
AFFIRMED.