
    BASIN EXPLORATION, INC. (DELAWARE), et al. v. TIDEWATER, INC., et al.
    No. CIV.A. 01-2271.
    United States District Court, E.D. Louisiana.
    March 10, 2004.
    
      George Moore Gilly, Evan T. Caffrey, Phelps Dunbar, LLP, New Orleans, LA, for Basin Exploration, Inc. (Delaware), Stone Energy LLC, Stone Energy Corporation, plaintiffs.
    Cliffe Edward Laborde, III, Dean Anderson Cole, Gregory Alan Koury, La-borde & Neuner, Lafayette, LA; for Tidewater Inc, Jackson Marine LLC, in per-sonam, Sara Tide MV, her engines, tackle, apparel, furniture, etc., in rem, defendants.
   FINDINGS OF FACT AND CONCLUSIONS OF LAW

LEMMON, District Judge.

Plaintiffs Basin Exploration, Inc. (Delaware), Stone Energy, L.L.C., and Stone Energy Corporation seek damages from defendants Tidewater, Inc. and Jackson Marine, L.L.C. (collectively “Tidewater”), for damages resulting from a July 26, 2000 albsion between Tidewater’s vessel and plaintiffs’ oil and gas well and fixed platform in the Gulf of Mexico. The non-jury case was tried on May 5-7, 2003, and thereafter submissions were filed into the record.

A. Background.

Plaintiffs’ No. 10 Well and accompanying platform was located in the West Cameron Block 45 field in the Gulf of Mexico off the coast of Louisiana. The well was drilled in 1959 and began producing in 1960. In 1986, the well was shut in, and has not been in production since that date. Basin acquired the well in November 1997.

On July 26, 2000, the MW SARA TIDE, a Tidewater supply vessel, struck the No. 10 Well, knocking over and completely destroying its platform and severely damaging the wellbore. Tidewater admits liability, and the sole issue before the court is the measure of plaintiffs’ damages.

B. Damages.

Under general maritime law, “damages of less than a total loss ... are compensable solely by reference to the costs of repairs.” Bunge Corp. v. American Commercial Barge Line Co., 630 F.2d 1236, 1241 (7th Cir.1980); see also Petrol Indus., Inc. v. Gearhart-Owen Indus., Inc., 424 So.2d 1059, 1062 (La.App. 2d Cir.1982) (“[Wjhere the thing damaged can be adequately repaired, the proper measure of damages is the cost of restoration.”); 2 Thomas J. Schoenbaum, Admiralty and Maritime Law § 14-6, at 311-12 (3d ed. 2001) (“Where the damage [caused by an allision] is repairable, there is liability for reasonable repairs.”).

If “the costs of repairs to damaged property exceed the precasualty value of the property,” it is “considered to be a ‘constructive total loss’; when the property is damaged beyond physical repair, it is considered an ‘actual total loss.’” Pillsbury Co. v. Midland Enters., Inc., 715 F.Supp. 738, 763 (E.D.La.1989); aff'd, 904 F.2d 317 (5th Cir.); cert. denied, 498 U.S. 983, 111 S.Ct. 515, 112 L.Ed.2d 527 (1990). If the property is a total loss, the measure of damages is the market value at the time of destruction. Admiralty and Maritime Law § 14-6, at 311. The Fifth Circuit has held that where a market value cannot be ascertained through recent and comparable sales, “other evidence is admissible touching value such as the opinion of marine surveyors, engineers, the cost of reproduction, less depreciation, the condition of repair which the vessel was in, the uses to which it can be put, the amount of insurance that the underwriters have issued, and the like.” Carl Sawyer, Inc. v. Poor, 180 F.2d 962, 963 (5th Cir.1950); see also Greer v. United States, 505 F.2d 90, 93 (5th Cir.1974) (holding that “[i]n situations where market value cannot readily be established, the court should consider any and all evidence before it to establish a fair valuation.”).

1. Do the proved reserves make the replacement of the thing economically feasible?

Plaintiffs contend that they are entitled to recover the cost of the well because they were deprived of the use of Well No. 10 to access 2.365 billion cubic feet (bcf) of gas reserves in Planulina 4 Sand by sidetracking. Tidewater argues that because plaintiffs cannot demonstrate that the Planulina 4 Sand contained proved reserves, they are not entitled to the replacement of the well, but only to reimbursement of out-of-pocket costs for plugging and abandoning the well and cleanup costs.

In support of their position that the Planulina 4 Sand has proved reserves, plaintiffs presented evidence that Basin, its auditor Ryder Scott, and Stone each concluded before the allision that there were 2.365 bcf of recoverable gas. Dalton F. Polasek Jr., Basin’s Vice President of Engineering for the Gulf Coast, testified by deposition that Basin carried the reservoir on its books as a “proved undeveloped” location, and that:

Before it goes on your books as a proved undeveloped location, all those questions have to be answered. Can it be drilled, is there a likelihood that the reserves are going to be there and how many are there will have to be answered before they ever get there. I mean, it wouldn’t even show up on our books unless we were able to convince Ryder Scott that, A, it was a viable location, and B, we had intent to do something with it. And if you’ll look through some of Ryder Scott’s [the auditor’s] stuff, my guess is that will be stipulated in one of their letters to us, that all proved undeveloped locations, what in their belief was going to be developed.

Randall A. Young, the Acquisitions Manager of Stone Energy, testified at trial that when Stone was considering buying Basin in 2000, he performed an evaluation of the reservoir to determine its reserves. Young determined that both Basin and Ryder Scott “had done a very reasonable job estimating the amount of oil and gas” in the Planulina 4 Sand. Young himself examined Basin’s files and concluded on September 11, 2001 that “the remaining reserves at this location was 2,918 million cubic feet of gas and approximately 61,000 barrels of condensate.” Young considered this amount as “proved undeveloped reserves.”

Exhibit 29 reflects that on January 25, 1999 and December 30, 2000, Ryder Scott estimated the reserves in the Planulina 4 Sand at 2.365 bcf. Additionally, Exhibit 30 lists economic runs showing that on July 20, 2000, six days prior to the incident, Basin performed a “Reserve and Economic Summary” demonstrating that there was 2.312 bcf of gas in the Planulina 4 Sand, with a discounted net profit value of $4.8 million. On December 31, 2000, Ryder Scott performed an “Estimated Projection of Production and Income” reflecting that the discounted net income of the 2.365 bcf in the field was $14,821,270.00.

After the allision, on January 23, 2002, Stone prepared a “Reserves and Economics” summary sheet indicating there to be 2.365 bcf of gas in the Planulina 4 Sand, and valuing it at $1.88 million. Young testified that even though he believed “with a very high degree of certainty” that there was 2.9 bcf in the field, “2.3 BCF was a little bit more conservative approach and we felt very comfortable with 2.3.”

Judd Hansen, Basin’s Operations Manager for the Gulf Coast Division, testified at trial that prior to the allision Basin had “looked at two possibilities. One was recovering the No. 10 wellbore and sidetracking out of it and the other one was to drill a new well from the jacket and in both cases we were going to use the platform and the existing flowlines.” Hansen indicated that this plan “was a well that we were preparing to do, on short notice, if we had the budget dollars to do. That was a time period when gas prices were going up quite a bit.” Basin intended to do so because “With new technology and a new set of eyes, looking at the field, we had determined there were updip reserves left at the No. 10 location.” In June 1999 Basin attempted to “run a neutron log through the old perforations that would, if we would have been successful doing that, that would establish there was oil and gas at that level.” Hansen believed that if the neutron log “showed there were hydrocarbons that migrated back into the wellbore, that it would make a much easier presentation to Mr. Smith to sidetrack it updip from the reserves that were already on our books.” Additionally, Hansen “asked Tracy Lowery to go to the platform, take a look at it, check it to see if it was in stable, solid condition.” Alton R. Perry, III, Basin’s Production Operations Engineer, testified by deposition that Basin had already successfully reworked the Al and A10 wells, two older, previously shut-in wells in the West Cam 45 field, and both were still producing at the time of his deposition.

Tidewater qontends that it would be economically infeasible to attempt to produce from the Planulina 4 Sand. Tidewater supports this contention with two experts, Joseph Battle and William McKenzie, both of whom were hired for purposes of litigation; in contrast, both Hansen and Young reached their conclusions regarding the feasibility of drilling into the Planulina 4 Sand prior to the allision. Additionally, although Battle and McKenzie disagreed with plaintiffs concerning the amount of recoverable gas in the Planulina 4 Sand and whether it would be economically feasible to attempt to produce it, both of them admitted that there was still some amount of gas remaining in this location.

The court finds the testimony of Hansen and Young to be credible, and that Basin has proved that it was economically feasible to attempt to produce the proved reserves in the Planulina 4 Sand. Therefore, Basin is entitled to either the cost of repair or the replacement costs for the damages caused by the allision.

2. Was Well No. 10 Repairable?

Tidewater contends that because the damages caused by the allision were repairable, the amount recoverable by plaintiffs should not exceed the cost necessary to repair the damages.

Dalton F. Polasek Jr., Basin’s Vice President of Engineering for the Gulf Coast, testified that he made the decision to ask the Mineral Management Service (MMS) for permission to plug and abandon the well. He testified that Basin asked for permission to plug and abandon the well “very soon after” the incident because “the MMS was going to insist you either P & A it or put it back together,” and that even after obtaining MMS approval to plug and abandon the well, it would have been comparatively easy later to have the MMS approve repairing the well for use in future sidetracking if that option became feasible.

Polasek testified that one of the principal factors affecting his consideration of whether to plug and abandon the well or to try to repair it and its platform for use in sidetracking operations was that “the well was laying over at an extremely high degree angle to the vertical, the platform was knocked over, and that it was — [I] was told that when we stood it up it was probably going to break.” He indicated that, from past experience working with the MMS, Basin would not be allowed simply to straighten the structure above the water line that had been knocked over, and “with a boat hitting a structure of this magnitude, you are going to have to put either a new or a refurbished structure out there. The MMS was not going to let you put the same structure out there. It would have had to have passed a mechanical.... [T]he first inclination when a well is knocked over like that is you’re going to plug it, because there’s nothing left. It was broken off at the mudline for all practical purposes.”

Polasek also testified about the safety factors that contributed to his quick decision to plug and abandon the well:

One of the primary — the primary aspect of anything like this that happens is the safety factor involved.
In this particular instance, you had tubing that was sheered off or virtually sheered at the mudline that had active completions underneath it and only plugs in the tubing.
The number one concern on that has to be taking care of that. It can’t be can I fiddle around with this well for two weeks and get any of this thing straightened out. If one of those plugs let loose, you’ve got a situation on your hand that’s magnified itself a hundred times above what you have at that point in time.
At that point in time, the well is relatively stable. But if something lets go, there is nothing connected to stop it and no way to control it. And that’s the primary thing that drives you to a lot of the decisions, are the safety aspects of it.
There may be a lot of things that you would like to do with a particular well. But from a safety and environmental consideration standpoint, you just can’t do it.
The time doesn’t allow you or you don’t have the luxury to sit there and try to plan something out for two weeks. You’ve got to act immediately because of the problems that could occur if something let go.

Polasek emphasized that safety was really the prime consideration in Basin’s decision to plug and abandon the well after the allision, regardless of whether the well could conceivably have been used in a sidetrack operation after repairs:

I don’t necessarily have to make the determination that I can’t sidetrack it. That really didn’t enter my mind in a large degree at that point in time.
What entered my mind at that point in time was I’ve got two live well strings sitting down here that if they let go, we’re in a heap of trouble and no way to stop it. And the only logical solution at that point in time in my opinion was to plug that well.
* :|: * * * *
You had about the worst condition you could ask for in the Gulf of Mexico. You had a well open with safety valves or plugs holding the two tubing strings and no casing protecting it. There’s not much worse situation you can be in than that.

Polasek testified that the cost of repairing the damages and then sidetracking would have at least matched the cost to plug and abandon and then drilling a new well:

Yeah, in the grossest sense, we could have evaluated that sidetrack. The problem was, at that point in time in order to stabilize the well sufficiently, we almost got to the point where we couldn’t sidetrack anymore, and there was no way we could get around that.
I mean, we had to stabilize the well to make sure that that well didn’t come in on us. And to do that, you have to put something solid, i.e., cement or something down in those tubing strings.
Once you do that, you’ve got yourself to the point where it becomes very, very expensive to sidetrack. Yes, we could have went and sidetracked that wellbore if we would have spent all the money to put it back, to put a structure around it, and to go and cut and try to pull those tubing strings, but we would have been into it for so' much we could have drilled another well at that point in time.

Judd Hansen, Basin’s Operations Manager for the Gulf Coast Division, testified at trial that he participated in the decision by Polasek to plug and abandon the well instead of repairing it. Hansen confirmed that initially “You have to permit the worst case. If at some point in time we had discovered that the damage was minimal and we could easily have repaired the well, we could have changed that opinion and repaired the well.” Hansen recalled that the well was bent over 70 degrees, almost completely to the mud line, and the pipeline connections were destroyed. The two outermost layers of casing of the well, designed to prevent oil and gas from escaping into the atmosphere, were broken and cracked. The two layers of casing and a layer of tubing were severely bent, and their integrity compromised. The well was buried under the wreckage of the six legged platform. On a ten-point scale measuring the seriousness of the well’s condition (with a “10” representing a “raging blow out”), Hansen rated the No. 10 Well as an “8,” indicating:

Because of the way the well had been bent over, i.e. at 70 degrees, I did not have any idea nor did Basin have any idea what had happened to the internal integrity of the tubulars, the packer, the casing, the wellhead. At any point in time, if there was oil and gas underneath the plugs that were set in the tubing, if they gave away, it could possibly come to the surface and end up on the beach.

Hansen recalled that “the only thing we were really saving, if we would have recovered the well was what we could save by sidetracking as opposed to drilling a new well.” He testified that Basin decided to plug and abandon the well because he and his coworkers “discussed the value of the well, now that we didn’t have the platform and the flowlines access to us. We talked about the additional costs to drill a new well versus a sidetrack, if we tried to repair this well. And everybody within our company came to the conclusion that we needed to plug this well and redrill it.” Hansen indicated that “from a mechanical standpoint,” the well was repairable; but it was not feasible to do so “[b]e-cause we had lost the structure and lost the flowlines. All those would have had to be reinstalled again if we had saved the well.” Additionally, both Hansen and Polasek pointed out the navigational hazard posed by the wreckage which needed immediate attention because although the platform was knocked completely underwater, it was not very far underwater.

Alton R. Perry, III, Basin’s Production Operations Engineer, testified that he did not know if anyone at Basin specifically decided that Well No. 10 could not be repaired, but “[w]e had the potential for leaking hydrocarbons, and so a decision was made to P & A the well, to stop the possibility that this could become a hazardous situation.” Perry indicated that “the wellbore was destroyed beyond unrepairable stage,” and that “anybody with knowledge of the mechanics of oil and gas wells would know that the damage was so extensive that it was beyond repair.” Perry-elaborated:

[The wellbore] had the 30-inch conductor that was, I believe, cracked at the mud line around there. I think you had the 20-inch conductor that was cracked at the mud line, and then you had — -just all this stuff was cracked. You can’t repair this stuff, I don’t think. Just all these tubulars were — I don’t know how to verbalize it, but it was in an unrepairable state. This could never be — this wellbore could never have integrity again, due to the damage from the accident.

Perry said it would have been “technically unfeasible” to even attempt to repair the well because “[t]here was so much wrong with it that it would be difficult to go about to even try to repair it, if it could be repaired at all.” He testified that “it’s just a foregone conclusion that anybody else in the business knows that the well got run over. It’s torn up pretty bad. We’d better plug it before it starts leaking hydrocarbons and really exposes our butts.”

Plaintiffs also introduced the testimony of Jim Wilkinson, an expert in petroleum engineering, exploration, and production. Wilkinson testified that Basin’s response to the incident was prudent, and that it would not have made sense to try to repair the well after the accident. Wilkinson opined that as a result of the allision, the well developed an “S curve,” and that in order to adequately repair the well, Basin would have had to sever the casing of the well at least 20 feet below the mudline. Wilkinson believed that the cost of attempting to repair the well would have exceeded the cost of drilling a new well.

In support of its position that it would have been more prudent to repair the No. 10 Well, defendants offered the testimony of William A. Bruha, an expert petroleum engineer. Bruha disagreed with Wilkinson’s opinion that the No. 10 Well had experienced an “S curve” effect, and indicated that, from an engineering and mechanical perspective, the well was capable of being repaired. Bruha estimated that it would have cost $900,000.00 to repair the well, which “[wjould have put the well back in the same utility that it had before.” On cross-examination, however, Bruha refused to categorize Basin’s decision to plug and abandon the well as unreasonable:

Q: Is it your position today it was unreasonable for Basin to plug the well?
A: To me the well could have been saved. That is all I said, could have been and it depended on what the utility, future utility was, which I had no indication what the future utility was. So, I’m not criticizing what they did. I don’t have all the facts. So I am just reporting what they did. And then I showed my concern that the well could have been tied back, if they had future utility for it. That is my only comment.
Q: As we sit here, you haven’t reached an opinion whether the decision was reasonable or unreasonable; is that fair?
A: That’s correct.

The court finds that Well No. 10 and its accompanying platform were constructive total losses after being struck by the SARA TIDE. It is clear that after the allision Basin had a very brief period of time to definitively determine whether to attempt to repair the well or to plug and abandon it. The court accepts the testimony of Polasek and Hansen that repairing the damages would have met or exceeded the cost of drilling a new well, and Wilkinson’s testimony that it would not have been economically feasible to repair the damages.

3. What is the measure of Basin’s damages?

Plaintiffs argue that as a matter of law, no deduction for depreciation should be allowed because repair or replacement would not extend the useful life of the destroyed items. Defendants presented no evidence of what credit for depreciation should be allowed. Additionally, Hansen testified that prior to the allision, “the platform was in good shape to be drilled from” and had received no incidents of noncompliance from the MMS. Reginald T. Lowry, Basin’s Production Superintendent, testified:

The platform was structurally sound. It was an old platform, sure, it was, you know. But as far as being structurally sound, yeah, it was structurally sound.
It was a — it would have worked for another — I mean, if you could have removed it and put it off somewhere else and drill another well off of it — -you could have drilled a well off of it where it was at and produced off of it, if you had wanted to. There is no doubt about that. I mean, it wasn’t something that was fixing to fall into the water the next day.

Hansen also confirmed that the wellbore was in a good enough condition for sidetrack operations. Additionally, he indicated that the pipeline connections were very valuable:

Q: [D]id the pipelines that were connected to the No. 10 jacket give it any particular value?
A: Yes, very much so. This field had been owned by, I think, four other operators and been redeveloped several times. Each time they would lay new lines and at the A platform it was just a nest of flow-lines coming up on that platform. There was no — virtually no access to come up there. So existing flow-lines were quite valuable to us.

Hansen testified that the well had a useful life that extended through the termination of production in the West Cam 45 field, which he estimated would occur some ten years in the future. Wilkinson confirmed that the well would not need to be plugged and abandoned for ten or more years:

Q: ... Mr. Wilkinson, can anyone say, based on your experience in the oil field, when the No. 10 well would have needed to be plugged and abandoned in the normal course of the events with any degree of certainty?
A: No.
Q: Did you listen to Mr. Hansen’s testimony yesterday where he stated he believed it could be ten years or more before the well would otherwise needed to be plugged and abandoned?
A: I did.
Q: Do you agree with that testimony?
A: I certainly do. I think he stated that it was really based on the life of the field. The life of that lease. And I believe that to be correct.
Q: And how long have you seen some leases stay alive through continued oil and gas production?
A: Well, this particular field is approaching 50 years. So, you know, we don’t know how much time there is in the future.

Basin contends that it is entitled to the following damages:

Platform replacement: Pipeline hookups: Replacement of wellbore: $780,000.00 $530,000.00 $458,630.00

Wilkinson testified to the accuracy of each of these figures. He indicated that $780,000.00 was the value of a caisson style platform, which is a “less expensive structure and a less expensive design. It would not have had the capability of the original structure but it was adequate for the needs of the water depth and the single well.” $530,000.00 represented the cost to hook up the replacement platform to the production system with new pipelines. Finally, $458,630.00 was “the difference between the straight hole cost” of a new well and “the sidetrack cost” that Basin would have incurred if it had sidetracked from the No. 10 Well if there had been no allision. Plaintiffs are entitled to recover these amounts.

4. Out-of-pocket costs incurred by plaintiffs.

“Out of pocket costs incidental to a marine casualty loss are ... fully recoverable if reasonably incurred.” Admiralty and Mantime Law § 16-6, at 311. According to Hansen, Basin incurred significant out-of-pocket costs due to the nature of the accident:

We had to first go out there with a lift boat to establish a local presence to work from. And jump divers to review what had happened and what the current situation was. At that point in time a firm plan was decided on how to attack the situation, in which Alton Perry and Twatchman, Snyder and Byrd were on day to day contact on how to do that. And that included a lot of support, vessels, dock space, a lot of rental items. At that time we, like I said, we needed to get the structure removed from the well where we could try to repair the well or plug the well, as the situation required.
* * * * * *
We had numerous problems. The well, where it was bent, was actually bent below the mudline. So we had to jet out around it below the mudline to get to an area where we could work [while] the casing integrity was still intact and [had] not been mechanically deformed.

Hansen testified that the work required to clean away the debris left from the incident and to plug and abandon the well cost Basin $2,079,r72.00. Additionally, Wilkinson testified at trial that he had reviewed the morning reports of the on site supervisor and a sampling of the contractor invoices, and concluded that Basin “acted prudently. And that the work was carried out in a workmanlike manner.”

Bruha testified that $42,000.00 in work appearing on two invoices was unrelated to the allision. Bruha opined that the issue had been “resolved” with Basin, and did not state for the record why he concluded that these sums were unrelated. Bruha provided no support for his conclusion, and did not specifically identify what work was allegedly performed by Basin that was unrelated to the incident. The court accordingly finds that Basin’s total out-of-pocket costs were $2,079,172.00.

Tidewater argues that because Basin would have had to plug and abandon the Well No. 10 at some point in the future, Basin’s recovery should be reduced by the amount of its actual out-of-pocket costs attributable to plugging and abandoning the well (which it calls “non-accident-related costs”). Alternatively, Tidewater argues that Basin’s recovery should be reduced by the amount of a normal non-accident related plug and abandon operation, namely $820,000.00.

Plaintiffs will have the obligation to plug and abandon any replacement well. Allowing Tidewater a credit would result in reducing plaintiffs’ damages by the cost to plug and abandon the damaged well, while it simultaneously has the obligation to plug and abandon any replacement well. Plaintiffs would have to pay to plug and abandon twice. Tidewater is not entitled to a plug and abandonment credit.

5. Prejudgment interest.

Although not automatic, “[i]n maritime cases, an award of pre-judgment interest is the rule rather than the exception.” Koch Refining Co. v. Jennifer L. Boudreaux, 85 F.3d 1178, 1183 (5th Cir.1996). Whether prejudgment interest should be allowed is a fact specific inquiry:

The Supreme Court has explained that “the allowance of interest on damages is not an absolute right. Whether it ought or ought not to be allowed depends upon the circumstances of each case, and rests very much in the discretion of the tribunal which has to pass upon the subject, whether it be a court or a jury.” Nevertheless, a court has the discretion to deny pre-judgment interest “only when there are ‘peculiar circumstances’ that would make it inequitable for the losing party to be forced to pay prejudgment interest.”

Id. at 1183.

The Fifth Circuit has clarified that prejudgment interest may be denied “where plaintiff improperly delayed resolution of the action, where a genuine dispute over a good faith claim exists in a mutual fault setting, where some equitable doctrine cautions against the award, or where the damages award was substantially less than the amount claimed by plaintiff.” Reeled Tubing, Inc. v. M/V CHAD G, 794 F.2d 1026, 1028 (5th Cir.1986). However, the Fifth Circuit has limited the trial court’s discretion to deny prejudgment interest, finding that “the existence of a good faith dispute as to liability” does “not justify denying prejudgment interest to the date of loss.” Id. at 1029.

Tidewater has not disputed liability in this case, and argues only that the court should deny prejudgment interest because plaintiffs’ claim is inflated. The court’s damages award to plaintiffs is not substantially less than the amount they claimed, and the court finds that “peculiar circumstances” do not exist making it inequitable for Tidewater to pay prejudgment interest. The court awards plaintiffs prejudgment interest from the date of loss, at the rate established by 28 U.S.C. § 1961 that was in effect on the date of loss. See Reeled Tubing, 794 F.2d at 1028 (noting that “[i]n this circuit, prejudgment interest is ordinarily awarded from the date of loss.”).

C. Conclusions.

The court finds that plaintiffs proved by a preponderance of the evidence that they are entitled to the following:

1. Out-of-pocket cleanup costs: $2,079,172.00

2. Replacement Well $3,274,030.00

Less: Ordinary Cost of Sidetrack Well ($2,815,400.00)

3. Replacement Jacket $ 780,000.00

4. Replacement Flow Line $ 530,000.00

Total: $3,847,802.00

The court accordingly awards plaintiffs the sum of $3,847,802.00, plus prejudgment interest from the date of loss at the rate established by 28 U.S.C. § 1961 that was in effect on the date of loss. 
      
      . The factors set forth in Carl Sawyer have been embraced in numerous other cases. E.g., E.I. DuPont de Nemours & Co., Inc. v. Robin Hood Shifting & Fleeting Serv., Inc., 899 F.2d 377, 379-80 (5th Cir.1990); King Fisher Marine Serv., Inc. v. NP Sunbonnet, 724 F.2d 1181, 1185 (5th Cir.1984).
     
      
      . At the time of his deposition, Polasek was employed by Mariner Energy and no longer worked for Basin.
     
      
      . Depo. Polasek at 87-88.
     
      
      . Trial Transcript at 169.
     
      
      . Trial Transcript at 170. Walter B. McDonald, a Stone Energy geologist, confirmed at trial that he felt "pretty confident" that Stone's booked reserves were accurate, and that he would be comfortable drilling a well to reach the reserves at the Planulina 4 sand. Trial Transcript at 133.
     
      
      . Trial Transcript at 175. Exhibit 29 contains Young's analysis of the reserves in the Planu-lina 4 Sand.
     
      
      . Trial Transcript at 176.
     
      
      . Basin's and Stone's figures for the net present value of the gas in the Planulina 4 Sand changed over ’time because the underlying assumptions varied (including the price of gas).
     
      
      . Exhibit 30.
     
      
      . Trial Transcript at 185.
     
      
      . Trial Transcript at 23.
     
      
      . Trial Transcript at 24. Polasek confirmed that at the time Basin merged with Stone in 2001, “we were actually drilling one of these type wells in West Cameron/' and Well No. 10 “would have moved up fairly rapidly on the — with the success that we had out there at the time.” Polasek depo. at 57.
     
      
      . Trial Transcript at 25.
     
      
      . Trial Transcript at 26. Exhibit 9 consists of the results of the neutron log test. Perry also recalled that the neutron log was run because Basin was “looking at some potential zones down here.” Depo. Perry at 41. Although the attempt to run the neutron log was unsuccessful, Hansen testified that this "had no negative impact to me whatsoever” in deciding whether to use the No. 10 wellbore, because "[i]t had nothing to do with the mechanical status of the well as far as it being able to be sidetracked.” Trial Transcript at 27; see also Polasek depo. at 99 (“The fact that we couldn't get the gamma ray neutron tool down is of not much relevance to the risk factor in the well because that’s basically inside a tubing. It doesn’t speak at all to what the condition of the casing is.”).
     
      
      . Trial Transcript at 77. Mr. Smith was Basin’s President.
     
      
      . Trial Transcript at 26.
     
      
      . Depo. Perry at 49.
     
      
      . Trial Testimony at 370-71; Trial Testimony at 480-81. McKenzie opined that the remaining reserve in the Planulina 4 Sand was between 483 and 816 million cubic feet (mcf) of gas, and agreed that "a lot of people” would have a fair degree of confidence that good reserves existed. Trial Testimony at 439, 481.
     
      
      . Depo. Polasek at 40-42.
     
      
      . Depo. Polasek at 41.
     
      
      . Depo. Polasek at 42, 67.
     
      
      . Depo. Polasek at 69-70.
     
      
      . Depo. Polasek at 116-119.
     
      
      . Depo. Polasek at 121.
     
      
      . Trial Transcript at 41-42.
     
      
      . Trial Transcript at 37-38. Exhibit 10 consists of drawings of the well depicting its condition after it had been struck. .
     
      
      . Trial Transcript at 39-40.
     
      
      . Trial Transcript at 110.
     
      
      . Trial Transcript at 41. Hansen indicated that no written economic analysis was performed regarding the cost of repair because "Basin was a very small but very experienced technical company in the Houston office. Numerous times we would have technical discussions and make a decision. There would be no documentation to what the decision was.” Trial Transcript at 42; see also Trial Transcript at 57 ("The people that were discussing it have 25 or 30 years experience in this business” and "would not necessarily have to do a detailed analysis to come to a conclusion.”).
     
      
      . Trial Transcript at 60.
     
      
      . Depo. Perry at 60.
     
      
      . Depo. Perry at 58, 169-70; see also Depo. Perry at 57 ("[Tjhis well needed to be P & A'd. It was totally destroyed.”).
     
      
      . Depo. Perry at 59; see also Depo. Perry at 80 (noting that there no discussions with the MMS about saving the wellbore because "[i]t was unsaveable.”).
     
      
      . Depo. Perry at 60.
     
      
      . Depo. Perry at 171-72.
     
      
      . Trial Transcript at 224-225.
     
      
      . Wilkinson indicated that it would have cost roughly $460,000.00 more to drill a new well than to sidetrack from the No. 10 Well, and that this amount represented only a week's worth of the total work that would have needed to have been done to repair the well. Trial Transcript at 226; see also Trial Transcript at 253 (noting that repairing the well "would have cost as much as and not be as secure as a new well.”).
     
      
      . Trial Transcript at 502, 533.
     
      
      . Trial Transcript at 525.
     
      
      . Trial Transcript at 559.
     
      
      . See, e.g., Plaintiffs' Pretrial Memorandum at 11.
     
      
      . Trial Transcript at 27; Trial Transcript at 30-31; see also Polasek depo. at 49 ("As long as it [the platform] was in reasonable shape, i.e., through MMS inspections every year, it would have supported putting a well alongside of it and running it across the platform. It wasn’t that we were necessarily going to drill through the platform. That water depth was such that we could set a wellbore right beside it and attach it to the platform and flow it across the platform.”). Exhibit 7 are the MMS inspection reports for the platform. Exhibit 2 consists of photographs depicting the condition of the platform on September 28, 1999 during a "Level 2” MMS inspection.
     
      
      . Depo. Reginald T. Lowry at 21-22. At the time of his deposition, Lowry was no longer employed by Basin and did consulting work for himself.
     
      
      . Trial Transcript at 31-34.
     
      
      . Trial Transcript at 18-19.
     
      
      . Trial Transcript at 48.
     
      
      . Trial Transcript at 229-30.
     
      
      . Trial Transcript at 236. Plaintiffs do not argue entitlement to replace the old platform with a similar new platform, which would be more expensive than the caisson style platform.
     
      
      . Trial Transcript at 236.
     
      
      . Trial Transcript at 237; see also Trial Transcript at 238 (noting that the cost of replacement well would be $3,274,030.00, and the cost of a sidetrack well would have been $2,815,400.00).
     
      
      . Trial Transcript at 42-43.
     
      
      . Trial Transcript at 44; see also Trial Exhibit 12 (daily reports of work performed to clean site and plug and abandon well); Trial Exhibit 14 (spreadsheet summarizing all of Basin's out-of-pocket costs).
     
      
      . Trial Transcript at 221.
     
      
      . Trial Transcript at 514-15.
     
      
      . Quoting City of Milwaukee v. Cement Division, National Gypsum Co., 515 U.S. 189, 115 S.Ct. 2091, 132 L.Ed.2d 148 (1995) and Noritake Co. v. M/V HELLENIC CHAMPION, 627 F.2d 724 (5th Cir.1980).
     