System Fuels, Inc. v. United States

In the United States Court of Federal Claims

No. 03-2621C

(Filed: February 10, 2016)1

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SYSTEM FUELS, INC., ENTERGY * Spent Nuclear Fuel; Partial

LOUISIANA, INC., and ENTERGY * Breach of Contract; Damages;

LOUISIANA, LLC, * Causation; Reracking Costs;

* Cask Loading Costs; Crane

Plaintiffs, * Upgrade Costs; Fuel Handling

*

Building Modification Costs;

v. *

* General Project Management

THE UNITED STATES, * Costs; NRC Fees; Allegedly

* Unsupported Transactions.

Defendant. *

*

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Alexander D. Tomaszczuk, Pillsbury Winthrop Shaw Pittman LLP, 1650 Tysons

Boulevard, McLean, VA 22102, for Plaintiffs. Jay E. Silberg, Clare M. Cavaliero, and Travis L.

Mullaney, Pillsbury Winthrop Shaw Pittman LLP, 1200 17th Street NW, Washington, D.C.

20036, Of Counsel. L. Jager Smith, Jr., Jager Smith LLC, 1340 Echelon Parkway, Jackson, MS

39213, Of Counsel.

Benjamin C. Mizer, Robert E. Kirschman, Jr., Allison Kidd-Miller, Alexis J. Echols, U.S.

Department of Justice, Civil Division, Commercial Litigation Branch, P.O. Box 480, Ben

Franklin Station, Washington, D.C. 20044, for Defendant. Eric P. Bruskin and Christopher J.

Carney, U.S. Department of Justice, Civil Division, Commercial Litigation Branch, P.O. Box

480, Ben Franklin Station, Washington, D.C. 20044, Of Counsel. Jane K. Taylor, U.S.

Department of Energy, Office of General Counsel, 100 Independence Avenue, SW, Washington,

D.C. 20585, Of Counsel.

1

The Court issued this opinion under seal on January 31, 2016, and ordered the parties to

file proposed redactions by February 12, 2016. The Court publishes this Opinion indicating

redactions and correcting errata. Redactions are indicated by asterisks “[***].”

_________________________________________________________________

OPINION AND ORDER ENTERING JUDGMENT

_________________________________________________________________

WILLIAMS, Judge.

This spent nuclear fuel2 case comes before the Court following a trial on damages.

Because the Government’s liability for partial breach of contract has been established, the only

issue before this Court is the quantum of damages owed to Plaintiffs. Plaintiffs System Fuels,

Inc., Entergy Louisiana, Inc., and Entergy Louisiana LLC (collectively, “Plaintiffs”) seek

$80,795,000 in damages incurred over a 16-year period from January 1, 1996, through June 30,

2012, stemming from the Department of Energy’s (“DOE”) partial breach of the 1983 Standard

Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard

Contract”). The Government challenges $33,688,589 of Plaintiffs’ claim. Based on the record

developed at trial, the Court awards Plaintiffs $49,403,339 in damages.3

2

Congress defined spent nuclear fuel as fuel that “‘has been withdrawn from a nuclear

reactor following irradiation, the constituent elements of which have not been separated by

reprocessing.’” See Sys. Fuels, Inc. v. United States, 120 Fed. Cl. 635, 642 n.2 (2015) (quoting

42 U.S.C. § 10101(23)). “SNF contains toxic uranium and toxic byproducts, such as plutonium,

and ‘remains radioactive after it is removed from a nuclear reactor and must be isolated in safe

disposal facilities for thousands of years.’” Id. (quoting Sacramento Mun. Util. Dist. v. United

States, 63 Fed. Cl. 495, 496 (2005)).

3

Like many spent nuclear fuel (“SNF”) cases, this case was stayed pending appellate

consideration of governing legal issues. The stay was in effect from January 19, 2007 until

January 19, 2010, when it was temporarily lifted to allow Plaintiffs to file an amended complaint.

The stay was continued from March 16, 2010 until November 1, 2011.

This Court held a trial on damages from November 3, 2014 to November 7, 2014, and

November 17, 2014 to November 25, 2014. The Court conducted a site visit of the Waterford

Steam Electric Generating Station, Unit 3 (“Waterford 3”) in Killona, Louisiana on October 29,

2014. After briefing was completed, the Court granted Defendant’s motion to strike the

testimony of Plaintiffs’ expert regarding “Waterford’s reliance upon or consideration of ANO’s

[Arkansas Nuclear One’s] allocation rights and spent fuel storage capacity in the non-breach

world.” Order 1 (Oct. 6, 2015) (internal citation and quotation marks omitted). The Court held

that the testimony at trial regarding the use of these allocations was a new, undisclosed expert

opinion. Id. at 9.

2

Findings of Fact4

The Nuclear Waste Policy Act and the Standard Contract

In 1982, Congress enacted the Nuclear Waste Policy Act (“NWPA” or “the Act”) in

response to safety and environmental concerns about the accumulation of radioactive waste. 42

U.S.C. §§ 10101-270 (2012). The Act authorized the Secretary of Energy “to enter into

contracts with any person who generates or holds title to high-level radioactive waste, or spent

nuclear fuel [SNF] of domestic origin for the acceptance of title, subsequent transportation, and

disposal of such waste or spent fuel.” Id. at § 10222(a)(1), held unconstitutional on other

grounds by Ala. Power Co. v. U.S. Dep’t of Energy, 307 F.3d 1300 (11th Cir. 2002). Pursuant to

section 302 of the NWPA, utilities would enter into a Standard Contract with the United States

Government acting through DOE. In return for fees assessed against the utilities contracting

with DOE for disposal of spent nuclear fuel, Congress imposed on DOE the unconditional

obligation to take title to, transport, and dispose of the spent nuclear fuel generated by these

utilities no later than January 31, 1998. Id. at § 10222(a)(5)(B); JX 1, Art. II. The Act

prohibited the Nuclear Regulatory Commission (“NRC”) from issuing or renewing licenses to

utilities that had not “entered into a [Standard Contract] with the Secretary” or who were not

“actively and in good faith negotiating with the Secretary for a contract,” effectively making

such contracts mandatory for the industry. Me. Yankee Atomic Power Co. v. United States, 225

F.3d 1336, 1337 (Fed. Cir. 2000). As a result, the entire nuclear electric industry entered into

individual contracts with the Government for the disposal of spent nuclear fuel. See NWPA,

Section § 10222(b)(1)(A)(i)-(ii); see also Maine Yankee, 225 F.3d at 1337.

Pursuant to the Standard Contract, DOE is responsible for taking title to the utilities’

spent nuclear fuel and transporting the spent nuclear fuel to its facility, and each utility is

responsible for preparing and loading the spent nuclear fuel for transportation. JX 1, Art. IV.

A.2, B.1-2.; see also Energy Nw. v. United States, 641 F.3d 1300, 1302-03 (Fed. Cir. 2011)

(“Energy Northwest III”). The Standard Contract provides:

The Purchaser [the utility] shall arrange for, and provide, all preparation,

packaging, required inspections, and loading activities necessary for the

transportation of [spent nuclear fuel] and/or [high-level waste] to the DOE

facility.

JX 1, Art. IV.A.2.

The Standard Contract did not set forth the rates at which, or the order in which, DOE

would accept spent nuclear fuel from nuclear facilities. Instead, the contract required DOE to

issue annual capacity reports (“ACRs”) to establish how much fuel DOE was obligated to accept

each year, and annual priority rankings to establish the order in which DOE would allocate the

projected capacity across the nuclear facilities. Id. at Art IV. B.5(b). Pursuant to the Standard

4

These findings of fact are derived from the evidence adduced at trial and stipulations.

The Court uses “PX,” “DX,” and “JX” to designate exhibits admitted during trial and “Tr.” to

cite trial testimony. The cited exhibit page numbers are the last four digits of the Bates number

assigned to a given page or to the document’s internal page numbers or section numbers as

appropriate. Demonstrative exhibits are cited herein as “PDX” and “DDX.”

3

Contract, DOE issued its first report on the acceptance rate in June 1987, and subsequent reports

in June 1988, December 1990, and December 1991. The Federal Circuit later designated the

1987 Annual Capacity Report as the official report on the SNF acceptance rates for calculating

rate commitments and damages because it more accurately depicted the parties’ intent for

complete contract performance. See Yankee Atomic Elec. Co. v. United States, 536 F.3d 1268,

1274 (Fed. Cir. 2008). The 1987 Annual Capacity Report included DOE’s spent nuclear fuel

acceptance rates for the first 10 years of DOE’s SNF acceptance – from 1998 through 2007.

Additionally, as stated in the Standard Contract, the spent nuclear fuel acceptance priority among

contract holders was on an “oldest fuel first” basis – determined by the date of permanent fuel

discharge from a licensee’s nuclear power plant. JX 1, Art. VI. B.1(a).

Under the Standard Contract, each Purchaser was required to submit a delivery

commitment schedule identifying the spent nuclear fuel it wanted to deliver to DOE 63 months

in advance of the delivery year. Id. at Art. V. DOE could approve or disapprove this schedule

within three months of receipt. Id. Additionally, Purchasers were required to submit final

delivery schedules at least one year before the delivery date, and DOE would approve or

disapprove these final schedules within 45 days of receipt. Id. Purchasers had the right to adjust

the quantities of spent nuclear fuel that DOE would receive by plus or minus 20% until the

submission of the final delivery schedule. Id.

The Standard Contract gave Purchasers the right to exchange approved delivery

commitment schedules with “parties to other contracts with DOE,” although DOE reserved the

right to approve or disapprove these exchanges. Id. The exchange provision stated that

Purchasers “shall have the right to determine” which fuel would be delivered to DOE. Id. In

order to exchange DOE delivery dates, a Purchaser had to submit an exchange request to DOE

not less than six months prior to the delivery date set out in the Purchaser’s delivery commitment

schedule. Id.

On February 2, 1984, Plaintiffs entered into a Standard Contract with DOE to collect and

dispose of spent nuclear fuel retained at Waterford 3. Second Am. Compl. ¶ 9; see JX 1. The

Purchaser listed in the Standard Contract was System Fuels, Inc. (“SFI”). According to

Plaintiffs, Waterford 3 is owned by Entergy Louisiana, but SFI “performs all duties of the

Purchaser under the Standard Contract on behalf of Entergy Louisiana, including payment of the

quarterly fee.” Second Am. Compl. ¶ 2, n.3. The NRC issued an operating license to Waterford

3 in 1984. Id. ¶ 2.

DOE’s Partial Breach of the Standard Contract

In 1987, Congress amended the NWPA to require DOE to develop only one permanent

geologic repository for nuclear waste – Yucca Mountain in Nevada – and to forbid DOE from

constructing an interim storage facility until the NRC authorized the permanent facility. Nuclear

Waste Policy Amendments Act of 1987, Pub. L. No. 100-203, §§ 5001-65, 101 Stat. 1330, 1330-

227 (codified at NWPA, 42 U.S.C. § 10172(a)-(b)). On February 17, 1993, DOE issued a

statement asserting that it did not have a legal obligation to accept spent nuclear fuel prior to the

operation of a permanent fuel repository. JX 30 at 0317. At this point, the utilities estimated

that DOE would not have a functioning repository until 2010. Id. On April 28, 1995, DOE

issued its “Final Interpretation” of its obligation under the Standard Contract, and acknowledged

that it would not begin accepting spent nuclear fuel by the January 31, 1998 deadline, but posited

4

that it did not have an unconditional obligation to commence performance on that date. Office of

Civilian Radioactive Waste Mgmt; Nuclear Waste Acceptance Issues, 60 Fed.Reg. 21,793,

21,794-95 (May 3, 1995). Under the judicial review provision of the NWPA, the utilities

challenged this Final Interpretation in the United States Court of Appeals for the District of

Columbia (“D.C. Circuit”). Ind. Mich. Power Co. v. Dep’t of Energy, 88 F.3d 1272, 1274 (D.C.

Cir. 1996). Finding that the NWPA created an unconditional obligation for DOE to commence

acceptance of spent nuclear fuel by 1998, the D.C. Circuit vacated and remanded DOE’s Final

Interpretation. Id. at 1277.

Nevertheless, DOE notified utilities that it would not timely accept spent nuclear fuel

because it was bereft of a permanent or temporary repository. DOE asserted that under Article

IX of the Standard Contract, the “unavoidable delays” clause, its delay in collecting the SNF was

not compensable. Utilities subsequently petitioned the D.C. Circuit for review and a writ of

mandamus to compel the DOE to fulfill its statutory obligation. In Northern States Power Co. v.

United States Department of Energy (“Northern States I”), the D.C. Circuit reaffirmed that DOE

had an unconditional obligation to accept spent nuclear fuel by 1998, and issued a limited writ of

mandamus “precluding DOE from advancing any construction of the Standard Contract that

would excuse its delinquency on the ground that it has not yet established a permanent repository

or an interim storage program.” 128 F.3d 754, 756 (D.C. Cir. 1997). This order did not require

specific performance or impose any contractual remedies, which remained within the purview of

the United States Court of Federal Claims. Neb. Pub. Power Dist. v. United States, 590 F.3d

1357, 1376 (Fed. Cir. 2010) (en banc) (“NPPD”). The Federal Circuit later afforded this ruling

res judicata effect on the issue of liability. Id. at 1363-65, 1376.

On August 31, 2000, the Federal Circuit held that the Government breached every

Standard Contract upon failure to commence the collection of spent nuclear fuel on January 31,

1998. Maine Yankee, 225 F.3d at 1342-43. This failure to begin collecting spent nuclear fuel in

1998 constitutes a partial breach of the Standard Contract. Yankee Atomic, 536 F.3d at 1280.

Nevertheless, the Government has continued to push back the date it would collect and

dispose of spent nuclear fuel, and in the Fiscal Year 2010 federal budget, announced that the

program to construct a federal repository for spent nuclear fuel disposal at Yucca Mountain was

terminated. See Office of Management and Budget, Terminations, Reductions, and Savings,

Budget of the U.S. Gov’t Fiscal Year 2010, 68, www.gpo.fdsys/pkg/BUDGET-2010-

TRS/pdf/BUDGET-2010-TRS.pdf (last visited Sept. 10, 2015). The Government plans to accept

SNF into a repository in 2048. Tr. 99.

The Government continued to collect the fees required by the Standard Contract from the

utilities until November 19, 2013, when the D.C. Circuit ordered the Secretary of Energy to

submit a proposal to Congress to change the fee to zero. See Nat’l Ass’n of Regulatory Util.

Comm’rs v. U.S. Dep’t of Energy, 736 F.3d 517, 521 (D.C. Cir. 2013). Plaintiffs allege that

they paid approximately $217.3 million into the Nuclear Waste Fund as of June 30, 2012.

Second Am. Compl. ¶ 9.

Categories of Challenged Damages

Defendants assert that Plaintiffs’ claimed damages of $80,795,000 should be reduced by

deducting the following allegedly unrecoverable costs:

5

1) $8,490,310 for the reracking performed at Waterford 3

2) $8,505,653 for modifications to the fuel handling building’s cask handling

crane

3) $7,240,114 in other fuel handling building and plant modifications

4) $1,789,227 in general project management

5) $3,966,282 in cask loading costs

6) $266,276 in payroll loader costs for Resource Codes 19 and 60

7) $1,942,000 in Nuclear Regulatory Commission (“NRC”) Part 171 fees

8) $1,488,727 in unsupported transactions.

Waterford 3 Fuel Cycle

The NRC issued an operating license to Waterford 3 on December 18, 1984. PX 1036 at

2546. Waterford 3 is a pressurized water reactor that uses uranium dioxide fuel. Tr. 841. The

uranium dioxide is in the form of pellets, which are loaded into 14-foot long fuel rods by the fuel

supplier. Id. at 55. These rods join together into fuel assemblies, which are placed into the

plant’s reactor core. Id. Waterford 3 uses approximately 217 assemblies. Id. Thus, 217 spaces

are needed to remove all of the fuel from the reactor. Id. at 939. At each refueling, which takes

place generally every 18 months at Waterford 3, one third to one half of the assemblies are

replaced. Id. at 52-53. During a refueling outage, the plant ceases to operate, giving reactor

personnel the opportunity to perform maintenance. Id. at 310. The time in between each

refueling is referred to as a cycle. Id. at 743. Entergy attempts to perform refueling outages in

the fall or spring, when electricity demand is not high. Id. at 2529-30. When the old fuel comes

out of the reactor, it must be stored underwater in the plant’s spent fuel pool because it contains

highly radioactive fission products. Id. at 56.

Plaintiffs’ Operating Philosophy

According to testimony of its employees, Plaintiffs’ plant operating philosophies placed

an emphasis on advance planning. Mr. Clint Alday, a supervisor and reactor engineer, 5 testified

that Waterford 3 coordinated its “system planning” with Entergy headquarters in Jackson,

Mississippi, leading to a practice of evaluating spent fuel storage five years in advance. Id. at

1034.

5

Mr. Clint Alday is employed by Entergy Operations, Inc. and, at the time of trial, was “on

loan to the Institute of Nuclear Power Operations” to serve as a senior evaluator. Tr. 835. After

working as a nuclear engineer at other plants, he became a reactor engineer at Waterford 3 in

1990. Id. at 843. Mr. Alday eventually became the superintendent of reactor nuclear systems

engineering in 1998, the supervisor of reactor engineering and the special nuclear material

custodian in 1999, and the system engineering manager in 2009, and then was again the

supervisor of reactor engineering in 2011. Id. at 847-51. Mr. Alday served as the Plaintiffs’

corporate representative during trial. Id. at 6-7.

6

A key concept used in making fuel storage decisions at Waterford 3 was maintaining full

core reserve or full core discharge capability. This “important planning concept” meant

maintaining enough space in the spent fuel pool to discharge all the fuel assemblies from the

reactor core – 217 assemblies at Waterford 3. Id. at 100. The purpose of maintaining full core

reserve was to ensure that all of the fuel could be removed from the reactor to allow for

inspection or maintenance. Id. at 101. Waterford 3 attempted to have full core reserve “at all

times.” Id. at 100. Waterford 3 occasionally infringed on full core reserve, but the plant would

“work hard” to avoid this state. Id. 101-02, 194. Maintaining full core reserve was not a

regulatory or an operating requirement, but “a target” and an example of “prudent planning”

because there might be times when the reactor had to be completely emptied of fuel. Id. at 102-

03. Without being able to perform unscheduled repairs or inspections, the plant could not be

restarted, which would cause between $500,000 to $1 million a day in replacement power costs.

Id. at 103-04. Additionally, if there were no room in the spent fuel pool to unload old fuel from

the reactor, the reactor could not be refueled and would be unable to operate. Id. at 105-06.

Because they were running a “multi-billion-dollar asset” that generates hundreds of

thousands of dollars per day, Waterford 3 personnel strove to make economically efficient

decisions. See id. at 105-06. As a fleet, the Entergy plants sought to arrange the most economic

fuel services at the least cost, including the “front-end” purchase of fuel and the “back-end” of

storage. Id. at 95-96; JX 3 at 9047-48. At each of its sites, the company desired to do what was

most efficient economically and to meet regulatory requirements. Tr. 150.

Safety was also extremely important at Waterford 3. As a nuclear power plant,

Waterford 3 had to comply with a variety of NRC safety regulations. Id. at 762. Waterford 3’s

NRC license required compliance with mandatory technical specifications, that were part of

Waterford 3’s Final Safety Analysis Report (“FSAR”), which delineated the parameters of

operations. Id. at 185-86, 1637. As the Court observed during its site visit, Waterford 3

personnel had a safety-conscious corporate culture and strove to avoid potential safety hazards,

including exposure to radiation. As stated by Mr. Laque, “one of the principles for working in

nuclear power is to try to keep the dose that each individual receives as low as possible.” 6 Id. at

329. This principle is called “ALARA,” or “as low as reasonably achievable.” Id. at 329, 1655.

When dealing with potential radiological contamination, Entergy’s practice was to assume there

was contamination unless proven otherwise. Id. at 362-63. This practice was part of Waterford

3’s general “conservative decision-making.” Id. at 363.

Spent Fuel Pool Rerack

On February 26, 1993, some 13 years before DOE was scheduled to pick up SNF from

Waterford 3, Mr. Frank Rives authored a revised “Strategic and Tactical Plans for Nuclear Fuel

6

Mr. Jason Laque is currently employed by Sid Munshi, Inc. as a contract senior engineer

at Waterford 3. Id. at 178. Prior to February 2014, he was employed by Entergy Operations

working as senior project manager for dry fuel storage at Waterford 3. Id. Mr. Laque has

worked in several different capacities at Waterford 3 and other Entergy plants since 1986. Prior

to becoming senior project manager, he worked as a maintenance manager. Id. at 179-81.

7

Management.”7 JX 3 at 9403. The purpose of the Strategic Plan was “to provide guidelines for

nuclear fuel management for the System which will assist in minimizing the cost of operation of

the Entergy System.” 8 Id. at 9048. In addition to plans regarding the purchasing of fuel, one of

the components of the Strategic Plan was the “provision for back end fuel cycle services with a

sufficient lead time to prevent loss of discharge capability . . . at any of the System’s reactors.”

Id. Mr. Alday testified that it was “a good practice” to “have plenty of planning time” when

planning to implement a fuel storage project, such as the rerack. Tr. 1031.

In discussing spent fuel services at Entergy’s fleet of utilities, Mr. Rives explained how

critical it was to remove spent nuclear fuel, but that at the time, availability of pick up services

was “highly uncertain,” and the “DOE program and the status of the System’s nuclear units

[would] have to be monitored . . . .” JX 3 at 9055. He continued:

Assurance of supply of spent fuel services is an important consideration. Failure

to provide at least one of these services when needed would prevent a reactor

from discharging spent fuel, and thereby prevent refueling and further operation.

The System should arrange for the most economic service, or mix of services, in a

timely manner so that spent fuel services are provided at the least cost. Onsite

storage should be maximized to the extent that it is physically, economically, and

legally practical. Each of the System’s nuclear units will lose full-core discharge

capability between the mid-1990s and the mid-2000s. About five years prior to

the time that this capability is lost at each nuclear site, an evaluation should be

performed to implement one of the available options. Such a process has been

initiated for ANO-1 and 2. (Dry cask storage has been selected.) The status of

storage options should be monitored to ensure that as many feasible alternatives

as possible may be considered for application in the System.

Id.

In the Tactical Plan, Mr. Rives discussed the situation at the Arkansas Nuclear One

(“ANO”) plant, the Entergy plant that was going to lose full core reserve first, in 1995, and that

decided to implement on-site dry storage. Id. at 9072, 9089. The Tactical Plan included charts

indicating when each Entergy plant would lose full core reserve. The chart indicated that

Waterford 3 would lose full core reserve in 2000, at the end of fuel cycle 10. Id. at 9092.

Another chart showed that Waterford 3 would begin fuel cycle 10 on October 9, 1998, and that

fuel cycle 10 would last 548 days, i.e. until April 9, 2000. Id. at 9075.

7

Mr. Frank Rives is employed by Entergy Services, Inc. as the Director of Nuclear Fuels

and has worked in this position since 1987. Id. at 51, 60. Mr. Rives is the contract manager for

Entergy’s contracts with DOE. Id. at 52.

8

The Strategic Plan’s guidelines were designed to have a five-year time horizon, while the

Tactical Plan provided detail for the first two years of the Strategic Plan. JX 3 at 9049. The

Strategic Plan and the Tactical Plan were generally updated annually and semi-annually,

respectively. Id. at 9043.

8

Mr. Richard Finch testified that Waterford 3 began evaluating spent fuel storage options

in 1994. 9 Tr. 2518-19. In 1994, Mr. Rives sent an email to another Entergy staff member about

starting to “kick off the Waterford 3 spent fuel project.” Id. at 159-60; DX 21 at 7869. Mr.

Rives’ handwritten notes on this email indicated that after he sent the email, he received a call

from the recipient about forming a team at Waterford 3 to begin the spent fuel project, with an

objective of providing additional storage by January 1999. DX 21 at 7869.

Waterford 3 made a decision to rerack the spent fuel pool to add capacity in 1996. The

spent fuel pool is located in the fuel handling building. The spent fuel pool originally contained

16 Wachter Associates brand storage racks, which contained 1,088 fuel assembly storage spaces.

Tr. 471; PX 1036 at 2544. Inside the fuel handling building, to the west of the spent fuel pool, is

the cask storage area, which is separated from the spent fuel pool by Gate 1. PX 1023 at 2544.

As seen in the following diagram, to the west of the cask storage area is the refueling canal.

Gate 2 separates the cask storage area and the refueling canal. To the north of the cask storage

area is the cask decontamination area. Gates 3A and 3B, located parallel to each other, separate

the cask storage area from the cask decontamination area. Gate 4 separates the cask

decontamination area from the fuel handling building’s train bay. Id. at 2545; PX 1 at 14.

PX 1 at 14.

In January 1996, Mr. Finch authored a revised position paper on spent fuel storage. JX 6

at 7843. After noting that Waterford 3 would lose full core reserve in 2000 and represented “the

next Entergy decision regarding additional storage,” he stated that “Waterford-3’s decision-

9

Mr. Richard Finch has been retired since 2004, and began working for Entergy

companies in 1974. Tr. 2474-76. Mr. Finch was a senior staff engineer in the engineering

design department at the time of his retirement, a job he had held since 1990. Id. at 2476-77.

9

making process to provide that capacity has been initiated.” Id. at 7844. Mr. Finch continued

that the Design Engineering staff had prepared a “scoping review” of options for increasing

Waterford 3’s storage capacity, including shipping the spent fuel to DOE, dry fuel storage at

another Entergy plant, dry fuel storage at an Indian reservation, on-site dry fuel storage, and

rereacking. Id. The evaluation also considered “a review of the ANO project,” an unsolicited

proposal from the company that worked on dry storage at ANO to provide additional dry storage

at other Entergy sites, and an unofficial estimate from reracking vendors. Id. The “only feasible

options” were determined to be on-site dry storage and reracking. Id.

Mr. Finch concluded that it appeared that it might be appropriate for Waterford 3 to only

take bids on reracking. Id. at 7845. Mr. Finch noted specific benefits of reracking, namely the

provision of an additional 18 years of storage capacity at a lower cost than dry storage, a shorter

project scope, less exposure to delays, and the removal of “the existing boroflex neutron absorber

(boroflex degredation is a potential concern).” Id.10 Furthermore, reracking increased the

chances that there could be an off-site storage or disposal facility in operation by the time

additional action was needed, such that reracking would be the only capacity addition required

by the plant. Id. Mr. Finch also stated that Waterford 3’s situation was different from that of the

ANO plants, which had chosen on-site dry storage, as reracking at ANO would have only

provided a much shorter extension of the date that additional capacity was required. Id.

Additionally, Waterford 3’s geography, soil conditions, and flooding potential made dry storage

less attractive. Id. at 7846. Mr. Finch concluded by stating that the present plan was for

Waterford 3 to obtain reracking bids “in the second quarter of 1996.” Id.

On September 16, 1996, Mr. Finch prepared the Technical Evaluation Report on

reracking proposals the company had received in response to a May 1996 request for bids. JX 30

at 0315, 0321. This document reviewed the options discussed in the January 1996 position

paper, confirmed that Waterford decided to first pursue the reracking option, and listed the

“favorable considerations associated” with reracking as:

1. The expense is estimated at approximately $12,000 per stored fuel assembly.

2. The existing Boroflex could be replaced to preclude any future problems.

3. It is a much smaller scope project than the on site dry spent fuel storage project.

A reracking can be accomplished in approximately two years. It is also not a very

visible project. It should not raise any political concerns.

4. The technology associated with reracking is mature.

5. An increase of 800-1000 storage spaces would provide Waterford 3 with spent

fuel storage capacity until approximately the year 2018. This would give DOE

time to place a spent fuel repository into operation.

10

Boroflex was a boron carbide material that was used as a neutron poison to keep neutrons

from being absorbed by the spent fuel and thus to prevent criticality in the spent fuel pool. Id. at

890, 1044. The boron carbide was part of a rubber compound that was in removable inserts

between cells in the spent fuel pool. Id. at 892.

10

Id. at 0320-21. The “unfavorable considerations associated with reracking” were that a license

amendment was required, the fuel handling building load bearing capacity would have to be

reanalyzed, the spent fuel pool cooling system would have to be reanalyzed, and all of the spent

fuel in the pool would have to be reshuffled to allow the existing racks to be removed. Id. at

0321. The proposal evaluation team recommended that Holtec International (“Holtec”) be

awarded the reracking contract. Id. at 0324.

The reracking contract was signed in October 1996. Tr. 2518. In order for Holtec to

complete the reracking project, it was necessary for Waterford 3 to amend its NRC license. JX

30 at 0321. On March 27, 1997, Entergy submitted a proposed amendment in its technical

specifications to the NRC and requested that the amendment be issued “no later than January 8,

1998.” JX 8 at 1. This approval date was necessary to support both a rerack completion date of

July 1998, when cycle 10 fuel would be arriving on site, and to support “the expeditious removal

of the existing Boroflex racks.” Id. Mr. Finch explained that cycle 10 fuel would have arrived at

the plant 2-3 months before the next refueling outage to give the plant the opportunity to make

sure nothing was wrong with the fuel before taking the plant offline to complete the refueling

process. Tr. 2541.

The rerack was planned to begin at the end of fuel cycle 9, in October 1998. Id. at 2528.

On July 10, 1998, the NRC approved Waterford 3’s license amendment. Id. at 2536. On July

23, 1998, Entergy’s configuration management group approved a design change package to

allow changes to be made at the Waterford 3 plant. Id. at 459; PX 1036 at 2540. The July 1998

design change package stated that the rerack needed to occur during cycle 9 prior to the receipt

of new fuel because after cycle 9 there would be too many assemblies in the spent fuel pool to

allow the reracking to be completed using divers and maintain safe heavy load paths. PX 1036 at

2553-54. Mr. Frederick Smith11 testified that the end of fuel cycle 9 was November 1998. Tr.

2228. Referring to his 1996 Technical Evaluation Report, which contained a table showing the

historical and projected end dates of each fuel cycle, Mr. Finch testified that fuel cycle 9 was

projected to end on October 15, 1998.12 Id. at 2528-29; JX 30 at 0318. The authors of this

document noted that loss of full core discharge capability would occur at Waterford 3 at the end

of fuel cycle 10 in 2000. PX 1036 at 2546. While two additional fuel cycles could occur

without full core discharge capability, the plant would have had to shut down in 2004, if no

additional storage was added. Id.; Tr. 465.

The installation of new Holtec racks was completed in November 1998. Tr. 2518. This

work involved removing the old Wachter Associates racks and adding new racks to the spent

fuel pool and the cask storage area. The racks were put in the cask storage area. PX 1036 at

11

Mr. Frederick Smith is the senior manager of fuel for Entergy Services, and has

responsibility “for all of the fuel for the Southern fleet.” Id. at 2145. Mr. Smith joined Entergy

in 1982, in the corporate Nuclear Analysis Department and became manager of Entergy’s fuel

program in 2008. Id. at 2144-45. Mr. Smith took on his current role in November 2013. Id. at

2145.

12

Due to the rerack work, fuel cycle 9 actually ended in 1999. Id. at 2528-29. Specifically,

because new works were still being installed in the spent fuel pool, the plant was “not in the

outage at that time.” Id. at 2528.

11

2549. Preparing the cask storage area to receive racks involved sealing a drain in the cask

storage area, cutting gussets off Gate 3A, and installing platforms in the bottom of the cask

storage area. Id.; Tr. 471-73. Additional work involved modifying the spent fuel pool spargers,

piping, underwater lighting, and return lines so that they did not interfere with the new racks, and

moving a limit switch on the fuel handling building crane. PX 1036 at 2549-50; Tr. 473-75.

Finally, Waterford 3’s Spent Fuel Handling Machine had to be reprogrammed to access all of the

new spaces, and it was planned that Holtec would supply a new Offset Handling Tool to access

spaces that were inaccessible with the current tool. PX 1036 at 2550; Tr. 2494.

Holtec’s reracking contract guaranteed to increase storage capacity to 2,104 usable

spaces. Tr. 2500. This consisted of 1,849 spaces in the spent fuel pool and 255 in the cask

storage area. PX 1036 at 2548. Waterford 3 was also licensed to place racks in the refueling

canal, but these would not be used until the plant permanently shut down. JX 8 at 5. Because of

reserved cells, restricted cells, and inaccessible cells, only 1,659 spaces were available in the

spent fuel pool as of October 2004. PX 810 at 6812. Furthermore, the cask storage area racks

had certain limitations as to use, leaving only 140 spaces available in that area to temporarily

store spent fuel. Id. at 6813.

The new Offset Handling Tool proved to be unacceptable, as it apparently failed several

usage tests. Tr. 2477-78. Eventually, in 2012, the Offset Handling Tool was completed and

allowed access to all but 20 of the 209 previously inaccessible spaces. Id. at 931.

Boroflex Issues

The old Wachter Associates racks contained Boroflex, a neutron poison material. The

new Holtec racks contained Boral. Boral is a neutron poison material that is fixed into the racks,

as opposed to removable Boroflex inserts. Id. at 892. In the early 1990s, the nuclear industry

made efforts to deal with Boroflex problems. Id. at 2150-51. When Boroflex is bombarded with

gamma radiation from the spent fuel, the rubber molecules can disintegrate, causing shrinkage

and tears. Id. Over time, this will cause the loss of neutron-absorbing material, which impacts

the criticality analyses that nuclear plants perform on the spent fuel pool to ensure that the spent

fuel does not start a critical reaction. Id. at 2151-52. Additionally, the Boroflex material can

degrade and dissolve into the water of the spent fuel pool. Id. at 2154. When this dissolution

occurs, silica is released into the spent fuel pool, and if silica is able to enter the reactor, it can

potentially damage the reactor fuel. Id. at 2157.

At Waterford 3, the Boroflex was tested with a process called blackness testing. Id. at

852. Blackness testing was conducted by placing a neutron source in a selected cell and

determining how many neutrons could pass through, which allowed analysis of gaps in the

rubber compound. Id. at 853-54. A software program called RACKLIFE, which predicts

neutrons absorbed or lost in the spent fuel pool, was used to ascertain how many panels are

needed to test the condition of the Boroflex. Id. at 1052-53, 2167. BADGER testing is the

current standard for Boroflex testing. Id. at 2160-61. BADGER testing is similar to blackness

testing, but requires more resources to test a panel than blackness testing. Id. at 2164.

The NRC issued a generic letter in 1996, requesting a response about how to manage

Boroflex degradation from plants using Boroflex. Id. at 1042. Waterford 3 responded in

October 1996, describing how Boroflex monitoring had been occurring since 1992, and stating

12

that it would continue its surveillance program and would conduct a silica analysis of the spent

fuel pool. PX 803 at 613-14, 617.

On October 23, 1997, Waterford 3 completed its silica analysis, which showed that the

racks had “high silica loss and a correspondingly high [boron carbide] loss.” DX 39 at 0796.

Waterford 3’s October 1996 response to the NRC’s generic letter noted:

Waterford 3 has evaluated options to replace the existing spent fuel pool storage

racks in order to increase the number of storage locations. The replacement is

currently planned to occur during the Summer of 1998. The replacement racks

will use Boral, instead of Boraflex, as the neutron absorber.

PX 803 at 6714. Further, the response stated that monitoring would continue until the Waterford

3 racks were replaced. Id. at 6717. Mr. Alday testified that the Waterford 3 spent fuel pool

never had high enough silica levels to cause concern about it impacting the reactor and that the

pool’s normal filtration system removed any silica from the degraded Boroflex. Tr. 898-99. As

Boroflex degrades, it releases silica into the spent fuel pool. Id. at 898. However, Mr. Alday

testified that Waterford’s spent fuel pool filtration removed any silica from the water in the spent

fuel pool. Id. Mr. Alday explained that the system “pump[ed] the water through filters and ion

exchanges to clean the impurities out of the water,” and that this system was so effective at

trapping any silica that may have escaped from the degraded Boroflex, that to his knowledge,

Waterford “never took any additional actions other than the normal cleanup system.” Id. at 899.

Boroflex is still used at several Entergy plants. The NRC requires plants that still use

Boroflex to maintain a monitoring program. Id. at 2165. Continuing to use Boroflex may

require the plant to take mitigation measures such as checkerboarding, or locating two fuel

assemblies diagonally in the pool instead of side by side, which results in a loss of useable cells.

Id. at 1052, 2156, 2211. Although no checkerboarding has occurred at the Pilgrim plant,

checkerboarding is currently used at Grand Gulf. Id. at 2156. Furthermore, continued

degradation of Boroflex could result in a plant needing to perform a silica cleanup campaign. Id.

at 1052. Other mitigation strategies for dealing with Boroflex degradation are avoiding placing

recently discharged fuel into cells that have been subjected to high levels of radiation exposure

and creating separate pool regions. Id. at 2274-75. Both of these methods increase the

complexity of controlling the spent fuel pool. Id.

The removal of Boroflex was listed as a benefit of reracking in contemporaneous

Waterford 3 documents, including in Mr. Finch’s January 1996 position paper. JX 6 at 7845.

Mr. Finch’s September 1996 Technical Evaluation Report outlining reracking proposals also

mentioned this advantage. JX 30 at 0320.

The Court finds that removing the degraded Boroflex was not the primary reason for

conducting the rerack, but was an additional incentive to reracking beyond gaining more storage

space. Reracking allowed Waterford 3 to avoid monitoring Boroflex beyond 1998, and also to

avoid eventually taking measures, such as checkerboarding, that would have further reduced the

amount of space in the spent fuel pool.

13

Plaintiffs’ Claimed Reracking Damages and Model of Non-Breach World

In the breach world, Waterford 3 reracked in November 1998. The rerack permitted

Entergy to keep storing fuel in the pool until 2011. The parties agree that in the non-breach

world, Waterford 3 would not have had DOE acceptance rights under the Standard Contract until

2006. Tr. 1733-34, 2399-2400. The parties do not dispute that Plaintiffs would have lost full

core reserve in 2000 - - six years before DOE was scheduled to pick up SNF - - had they not

done the rerack project. However, Plaintiffs claim damages of $9,814,067 for the rerack project,

asserting that this project would not have been necessary in the non-breach world.13 Plaintiffs’

economic damages expert, Kenneth Metcalfe,14 created a model, working with Entergy personnel

and using the report of fuel discharges prepared by Ms. Eileen Supko,15 Plaintiffs’ expert in

13

Prior to trial, the parties stipulated to the amounts claimed by Plaintiffs for the various

elements of their damages claim. The amount stipulated for the rerack was $8,490,310,

exclusive of the $1,253,893 the Government challenges as unsupported costs and the $69,864 the

Government challenges as unrecoverable payroll loaders that are both associated with the rerack

project. In addition to the $8,490,310 figure, Plaintiffs also confusingly use $10,563,000 as the

amount they incurred in reracking costs due to DOE’s breach. Compare Pls.’ Post-Trial Br. 14

(“Plaintiffs’ claim related to the purchase and installation of additional spent fuel storage racks

totals approximately $10,563,000 through June 30, 2012.”) with 37 (“The following chart

identifies the issues, and the amounts associated therewith, that remain in dispute between the

parties: 1. Spent Fuel Pool Re-rack: $8,490,310 . . . .”). This $10,563,000 amount was derived

by Mr. Metcalfe and represents a total of $11,563,000 minus a $1 million Holtec credit for the

non-functional offset fuel handling tool. Tr. 1784. The Court will use the stipulated figures in

this opinion.

14

Mr. Metcalfe was qualified as an expert in “economic damages, cost, and regulatory

accounting in the public utility industry.” Id. at 1702. Mr. Metcalfe is the President and co-

founder of the Kenrich Group, which was formed in 2004. Id. at 1676-77. Mr. Metcalfe has a

bachelor of science in business administration from Georgetown University, is a certified public

accountant in Virginia, a certified valuation analyst with the National Association of Certified

Valuators and Analysts, and is an “associate certified fraud examiner.” Id. at 1677. Mr.

Metcalfe is a member of several professional organizations and has worked in business

management and litigation consulting since 1982. Id. at 1679, 1682.

15

Ms. Supko is currently employed as the president of Energy Resources International

(“ERI”), a nuclear fuel cycle consulting company. Id. at 1453. She received a bachelor of

science in nuclear engineering from Pennsylvania State University in 1985, and worked as a fuel

projects engineer and in-core analysis engineer for the Carolina Power & Light Company. Id. at

1453-54. Ms. Supko began working for ERI in 1990 as a consultant. Id. at 1456.

Ms. Supko provides consulting services associated with nuclear fuel management, spent

nuclear fuel management, radioactive materials and spent fuel transportation, and radioactive

materials and spent fuel disposal. Id. Her clients “include nuclear power plant operating

companies, a foreign government, industry organizations, private companies, and a private [spent

nuclear fuel] management organization.” PX 1 at 4. From 1990 to 2004, Ms. Supko “was a

14

nuclear waste management, storage, and transportation and associated plant modifications, to

explain why Waterford 3 would not have reracked in 1998 had the Government subsequently

started to accept spent nuclear fuel as required by the Standard Contract in 2006.

Mr. Metcalfe’s fuel management model applied available acceptance rights of two other

plants Entergy later acquired, Pilgrim and Indian Point 3. He applied all of Pilgrim’s rights to

Waterford 3 in the year 2000 and all of Indian Point 3’s acceptance rights to Waterford 3 for the

years 2001-05, using exchanges. PDX 7 at 14; PX 357; Tr. 1737, 1755-56. After the rerack

occurred, Entergy acquired two new nuclear plants, the Pilgrim plant in July 1999 and the Indian

Point 3 plant in November 2000. Joint Stip. ¶¶ 7-8. Pilgrim was the first nuclear plant to be sold

through a competitive bidding process. Tr. 166. Mr. Rives testified that prior to closing on both

new plants, there was a due diligence period that went on for several years and that Entergy was

aware of the number of DOE spent fuel pickup allocations that each plant had prior to the official

sale of the plant. Id. at 129-30. However, no testimony was provided on the exact parameters of

this due diligence and when, definitively, Waterford 3 began to consider purchasing both plants.

Mr. Rives was asked if it was correct that the Pilgrim plant was offered for sale in June 1998, but

he did not know this date or the details of when work began on the purchase of the plant. Id. at

165.

In 1995-96, when Plaintiffs were anticipating running out of space in the spent fuel pool

in 2000, they did not know that they would own these plants. The DOE acceptance allocations

would not have been available for Entergy to use until the plants were officially purchased in

1999 and 2000. Id. at 167-68. In Mr. Metcalfe’s non-breach world scenario, Plaintiffs would

have used exchanges to obtain Pilgrim and Indian Point 3’s acceptance rights, and DOE would

have removed spent nuclear fuel from Waterford 3 in the years 2000-05, instead of from Pilgrim

and Indian Point 3. Waterford 3 would have used its own acceptance rights from the year 2006

onward. PX 357. This model would allow Waterford 3 to maintain its full core reserve in all

years, so that no additional mitigation activities, particularly reracking and dry storage, would

have been necessary. Tr. 1742.16

direct participant as an industry consultant in technical exchanges between the nuclear industry

and DOE . . . .” Id. At the recommendation of DOE, Ms. Supko served as a U.S. technical

expert to the International Atomic Energy Agency. Id. Since 2002, Ms. Supko has served as the

“Principal North American Representative to the World Nuclear Transport Institute.” Id. at 6.

Ms. Supko has “authored more than 50 reports, presentations, and publications in leading nuclear

energy journals and [has] been an invited speaker at over two dozen conferences sponsored by

leaders in the nuclear industry.” Id.

Ms. Supko was also qualified in regulatory requirements, including “modeling

acceptance rate scenarios including [greater than class C] waste, allocation of acceptance rates

including [greater than class C] waste, and the effects of the acceptance rate scenarios on the

reactor storage spent fuel acceptance.” Tr. 1509.

16

On October 6, 2015, the Court granted Defendant’s motion to strike Mr. Metcalfe’s

testimony regarding “Waterford’s reliance upon or consideration of ANO’s [Arkansas Nuclear

One’s] allocation rights and spent fuel storage capacity in the non-breach world.” Order 1 (Oct.

15

Defendant’s Expert Testimony on Plaintiffs’ Model of Non-Breach World

Both Mr. Gregory Maret17 and Dr. Jonathan Neuberger18 asserted that Mr. Metcalfe’s

fuel management model was unreliable and unrealistic. Dr. Neuberger emphasized that while

6, 2015) (internal citation and quotation marks omitted). The Court held that the testimony at

trial regarding the use of these allocations was a new and undisclosed expert opinion and should

be stricken from the record. Id. at 9. Given the Court’s order, there is no probative evidence that

Plaintiffs were able to consider ANO’s allocation rights as a stop-gap measure or a place holder

for potential exchanges prior to the purchase of the Pilgrim and Indian Point 3 plants. Tr. 1756-

57. This need for a stop-gap arose because in 1995-96, when Waterford 3 was evaluating its

spent fuel storage options, it did not know that Entergy would later own Pilgrim and Indian Point

3. Id. at 1991. In the stricken testimony, Mr. Metcalfe posited that in 1995-96, in the non-breach

world, Waterford 3 would have planned for additional spent fuel storage, but instead of deciding

to rerack as occurred in the breach world, would have planned to use some of ANO’s acceptance

rights in 1999. Id. at 2110; PDX 7 at 25. The Court also struck the parts of Dr. Neuberger’s

testimony that discussed Mr. Metcalfe’s ANO opinion. Dr. Neuberger, in his expert report,

opined that Mr. Metcalfe’s model was flawed because the allocations from Pilgrim and Indian

Point 3 were not available in the mid-1990s when Waterford 3 was making its fuel storage

decisions and hence could not have been used for planning purposes by Waterford 3. DX 187 at

17-18. Dr. Neuberger also noted that Mr. Metcalfe had not attempted to create a fleet-wide

model of how allocations would be used across Entergy plants, and as a consequence, in other

spent nuclear fuel litigation, inconsistently testified that the Pilgrim and Indian Point 3

allocations would be used differently than he has modeled in this case. Id. at 21-22.

17

Mr. Gregory Maret was admitted as an expert in “nuclear power plant operations and

management.” Tr. 2616. At the time of trial, Mr. Maret was employed by Sequoia Consulting

Group, although when he produced his expert report, in December 2012, he was “an independent

consultant contracted with ABZ, Incorporated, an engineering consulting company performing

work related to the commercial nuclear power industry.” Id. at 2576; DX 177 at 2. Mr. Maret

received a bachelor of science degree in nuclear engineering, a master of engineering in nuclear

engineering, and a master of engineering in electric power engineering from Rensselaer

Polytechnic Institute. Tr. 2576. After receiving his graduate degrees in 1981, Mr. Maret worked

in the nuclear industry until 1999. Mr. Maret has “experience in design, construction, testing and

operation of nuclear reactors and reactor systems.” Id. at 2580-81, 2601; DX 177 at 2. Mr.

Maret has provided consulting services “for international nuclear regulatory agencies and

operators, as well as domestic utilities and suppliers.” DX 177 at 2. Mr. Maret has provided

expert reports and/or testimony in 10 other spent nuclear fuel cases. Id. at 3.

18

Dr. Jonathan Neuberger was admitted as an expert in “economic modeling and the

quantification of economic harm.” Tr. 2358. Dr. Neuberger is a principal in the economic

consulting firm Economists Incorporated and has a bachelor of science in international relations

from Georgetown University, a master’s degree in economics from Johns Hopkins University,

and a Ph.D in economics from Johns Hopkins University. DX 187 at 2-3. Dr. Neuberger has

worked as an economist for several different firms and as a Visiting Assistant Professor of

Economics at Mills College, in Oakland, California. Id. at 3. Dr. Neuberger has provided expert

16

Mr. Metcalfe hypothesized that Waterford 3 could have used inter-utility exchanges or the

Standard Contract’s plus-or-minus 20% allocation, Mr. Metcalfe had not analyzed the

plausibility or potential costs of these options, rendering their use purely speculative. DX 187 at

24-29. Dr. Neuberger believed that Mr. Metcalfe’s model left out costs, as he did not think it

plausible that Waterford 3 would not have incurred any costs for dealing with spent fuel storage

in the non-breach world, such as “planning, analyses, engineering studies, negotiations over

inter-utility exchanges, arrangements between affiliated entities to - - acquire or confirm the

existence of additional capacity.” Tr. 2404.

Mr. Maret also analyzed Mr. Metcalfe’s spent fuel management model and concluded

that Waterford 3 would have reracked in 1998 even with DOE performance. DX 177 at 8. Mr.

Maret asserted that two to three years were required to implement the reracking. Id. at 11. Mr.

Maret opined, based on the October 12, 2012 deposition testimony of Mr. Finch, that Waterford

3 would have lost sufficient space in the spent fuel pool to allow reracking “at the end of 1998.”

Id. Mr. Maret stated that Mr. Metcalfe’s presumption that, instead of making a decision to rerack

in 1996, Waterford 3’s management would have relied on the allocations of plants that had not

yet been acquired, was “clearly flawed.” Id. Mr. Maret testified that Waterford 3 needed to

rerack in the non-breach world because of its need for additional space, benefited from

“resolving the Boraflex issue, and because “[i]t’s easier to manage the entire on-site fuel

management cycle, to receive fuel, to discharge fuel, and to handle fuel with the new, larger-

capacity spent fuel pool compared to the lower-capacity original spent fuel pool.” Tr. 2906.

Elements of Plaintiffs’ Claim for Dry Fuel Storage

After completing the rerack in 1998, Waterford 3 eventually implemented an on-site dry

fuel storage system. Plaintiffs’ claim for damages for implementing dry fuel storage is based on

nine work orders:

1) Dry Fuel Storage (Work Order N66105) - $10,153,377

2) Dry Fuel Storage Crane Upgrade (Work Order N66737) - $8,938,50619

3) Dry Fuel Storage Storage Pad (Work Order N66738) - $14,601,000

4) Haul Path Improvements (Work Order N66739) - $6,528,000

5) Dry Fuel Storage Security Modifications (Work Order N66740) - $1,245,000

6) Overpack Construction Pad (Work Order N66741) - $2,648,000

trial testimony on 23 previous occasions, and has testified in 16 spent nuclear fuel cases. Id. at 4.

Dr. Neuberger has also published extensively in economics and banking. Id. at Ex. 1 at 8-10.

19

While Plaintiffs charged $8,938,506 to this work order, the parties have stipulated that

Plaintiffs claim $8,505,653 for the fuel handling building crane upgrade, exclusive of $7,600 in

allegedly unsupported costs and $8,413 in allegedly unrecoverable payroll loaders. Joint Stip. ¶

6(b).

17

7) Fuel Handling Building and Plant Modifications (Work Order N66742) - $8,081,00020

8) Cask Systems (Work Order N66743) - $6,997,000

9) Dry Fuel Storage Campaign 2012 (Work Order N66920) - $8,033,000

Pls.’ Post-Trial Br. 15-24; PDX 2. At trial, Mr. Greg Ferguson21 testified that all of these work

orders were issued due to Waterford 3’s need for additional storage space as a result of DOE’s

failure to perform under the Standard Contract. Tr. 442-48. Mr. Laque testified that these costs

would not have been incurred had Waterford 3 not implemented dry storage. Id. at 190-92.

The Process of Loading SNF for Storage Using the Holtec Cask System

Waterford 3 loaded its first three dry fuel storage casks in October 2011, and six more

casks in 2012. Id. at 192-93. These casks are located near the plant buildings on an independent

spent fuel storage installation (“ISFSI”). The ISFSI is a 14-inch thick concrete pad built on top

of 1,044 60-foot long wooden piles, which were used to address the soil conditions at the plant,

as it is located on the banks of the Mississippi River.22 Id. at 632-33. Waterford 3 uses a Holtec

HI-STORM 100S system for dry fuel storage. Id. at 194-95. There are three major components

of this system – the HI-STORM overpack, the Multi-Purpose Canister, and a HI-TRAC transfer

canister. Id. at 196-98; PDX 3 at 1.

The HI-STORM overpack is a steel shell filled with concrete that holds the Multi-

Purpose Canister, providing radiation shielding and protection, when placed on the ISFSI. Tr.

196. The HI-STORM lid is also made of steel and concrete and is bolted to the body of the HI-

STORM. Id. at 199. The Multi-Purpose Canister is a steel enclosure with a welded lid that

holds 32 spent fuel assemblies in an internal basket. Id. at 196-97, 206-07. The HI-TRAC is

used inside the fuel handling building to move and protect the Multi-Purpose Canister while it is

being moved into the cask storage area to be loaded with fuel and is also used to transfer the

Multi-Purpose Canister into the HI-STORM. Id. at 197-98. The HI-TRAC has lifting trunnions

that attach to a device called a lift yoke, which itself can be attached to the fuel handling building

crane. Id. at 209. Another feature of the HI-TRAC is a removable “pool lid” bottom that allows

the Multi-Purpose Canister to be moved out of the HI-TRAC and into the HI-STORM. Id. at

210-11.

The HI-STORM cask is moved in and out of the fuel handling building by a “low profile

transporter.” Id. at 213; PDX 3 at 14. The low profile transporter is a device with six Hilman

rollers that is pushed by another device called a “prime mover.” Tr. 213-14. After being loaded

20

The parties have stipulated that Plaintiffs claim $7,240,114 for these items, exclusive of

$16,277 the Government challenges as unrecoverable payroll loaders. Id. at ¶ 6(c).

21

Mr. Ferguson currently works as an independent contractor at Waterford 3. Tr. 426.

Prior to July 2013, he was employed by Entergy Operations as senior lead engineer. Mr.

Ferguson began working at Waterford 3 in 1992 as a senior engineer. Id. at 426-27.

22

Mr. Ferguson noted that 1,045 piles were actually used because one was broken during

installation. Id. at 633.

18

with fuel and taken out of the fuel handling building on the low profile transporter, a wheeled

vertical cask transporter is used to move the HI-STORM along a specially engineered pathway

called the heavy haul path to the ISFSI pad. Id. at 215-16; PDX 3 at 16. The heavy haul path,

which includes a turning pad that was put in place to allow the vertical cask transporter to make a

45 degree turn, was created so that Waterford 3 could use the Holtec cask system. Tr. 278-79.

Removing spent fuel from the spent fuel pool and eventually placing it on the ISFSI is a

multi-step process. A HI-STORM is delivered by truck and concrete is poured between the inner

and outer shells. Id. at 200; PDX 3 at 4-5. The concrete pouring is performed on site near the

ISFSI. Tr. 234. When a loading campaign is ready to start, the vertical cask transporter is used

to bring a HI-STORM containing an empty Multi-Purpose Canister via the heavy haul path to the

fuel handling building. Id. Workers unbolt the HI-STORM lid and remove it, then open the

doors to the fuel handling building rail bay and use the low profile transporter to push the HI-

STORM and Multi-Purpose Canister into the fuel handling building. Id. at 234-35. The Multi-

Purpose Canister is moved from the HI-STORM into the HI-TRAC, prepped, and partially filled

with borated water. Id. at 235; PDX 3 at 27. The area between the HI-TRAC and the Multi-

Purpose Canister is filled with demineralized water. Tr. 282.

Inside the cask storage area, which is filled with water, is the variable elevation cask

support pedestal (“VECASP”). The VECASP is a two-elevation platform that is unique to the

Holtec system. Id. at 219. The very bottom of the cask storage area is at elevation 0.5 feet. The

lower VECASP level is at 4.25 feet, while the upper position is at 18.52 feet. The elevation of

the floor of the fuel handling building is 46.25 feet. DDX 5 at 9. Therefore, the cask storage

area is over 40 feet deep.

The lift yoke is attached to the HI-TRAC lift trunnions, then attached to the main hook of

the fuel handling building crane, lifted, and placed on the upper position of the VECASP in the

cask storage area. Tr. 236-37. Workers add a lift yoke extension to the lift yoke to give more

reach so that the crane hook does not enter the spent fuel pool water. Id. at 237. As Mr. Laque

explained, Waterford 3 does not want the crane hook to go into the water because of “very high

concentration[s] of boric acid in the spent fuel pool,” which degrades the carbon steel of the

hook. Id. After the lift yoke extension is added, the HI-TRAC, containing the Multi-Purpose

Canister, is rotated and inserted into the cask storage area to rest on the lower level of the

VECASP. Id.

Using the spent fuel handling machine underwater, the operator places fuel assemblies

inside the Multi-Purpose Canister. PDX 3 at 29. Workers then move the HI-TRAC from the

lower to the upper position of the VECASP, remove the lift yoke extension, and use the crane

and lift yoke to bring the Multi-Purpose Canister lid over and lower it onto the Multi-Purpose

Canister inside the HI-TRAC. Id. at 31; Tr. 242. Then, the entire HI-TRAC and Multi-Purpose

Canister are removed from the water of the cask storage area, the radiation dose is monitored,

and the HI-TRAC and lift yoke are sprayed down to remove contamination. Tr. 255.

The HI-TRAC and Multi-Purpose Canister are lifted out of the cask storage area and

moved into the cask decontamination area. Id. at 255-56; PDX 3 at 36. The cask

decontamination area contains a work platform and pedestal that allows workers to comfortably

access the HI-TRAC containing the Multi-Purpose Canister. Tr. 220. The work platform in the

cask decontamination area was designed for the unique dimensions of the Holtec HI-TRAC. Id.

19

at 694-95. The crane operator places the HI-TRAC onto the cask decontamination pit platform

and, using the work platform, workers decontaminate the area to prepare to weld the MPC lid.

Id. at 257; PDX 3 at 32. An automatic welding machine is brought in and the operator welds the

lid onto the MPC. Tr. 259; PDX 3 at 38. The welding is then tested for flaws. Tr. 261-62.

After the welding, the water is removed from the inside of the MPC by hooking up a helium

system using hoses to the Multi-Purpose Canister’s internal drain line. Id. at 262-63; PDX 3 at

39. The inside of the Multi-Purpose Canister is further dried with a vacuum drying system. Tr.

262. Using the helium system, helium is then injected into the MPC. Id. at 263.

During this loading process, the HI-STORM has remained in the rail bay. A device

called the mating device is placed on top of the HI-STORM. Id. at 264. The HI-TRAC, still

containing the Multi-Purpose Canister, is placed on top of the mating device and the HI-STORM

– a configuration known as the stack-up position. Id. at 266; PDX 3 at 41. Workers use the

mating device to remove the HI-TRAC’s lower pool lid. Using downloader slings, the Multi-

Purpose Canister is lowered from the HI-TRAC into the HI-STORM. Tr. 267-68; PDX 3 at 42.

The slings are then removed, the pool lid is replaced onto the HI-TRAC, and the HI-TRAC is

removed from the stack-up and placed back into the cask decontamination area to await the next

canister. Tr. 269-70. The mating device is removed from the HI-STORM, the low profile

transporter is used to take the loaded HI-STORM out of the fuel handling building, and the

vertical cask transporter moves the HI-STORM along the heavy haul path to the ISFSI pad. Id.

at 272. The HI-STORM lid is installed and bolted on. Id. at 276. The HI-STORM containing

the loaded Multi-Purpose Canister will sit on the ISFSI pad for the foreseeable future, as no DOE

repository is in place.

Challenged Site Modifications Needed for Dry Storage Activities

In order to implement dry storage, Plaintiffs made certain modifications to the plant

equipment and fuel handling building. Plaintiffs claim damages of $8,505,653 for upgrading the

crane in the fuel handling building to be single-failure-proof. Single-failure-proof means that the

crane is made so that no single component could fail and allow the load to drop. Id. at 607-08.

The load capacity of the crane remained at 125 tons before and after the upgrade. Id. at 670-71.

If a crane is not single-failure-proof, a cask could potentially be dropped, and the cask cannot be

lifted beyond the bounds of an applicable cask drop analysis. A cask drop analysis analyzes the

effect of a drop on the cask, the cask contents, and the plant structure, such as the floor. Id. at

1647.

In addition to potentially causing a dangerous release of spent fuel, performing a lift that

goes beyond the parameters of the cask drop analysis would violate Waterford 3’s safety

requirements. Waterford 3’s FSAR for its license included a cask drop analysis of a Fort Saint

Vrain-1 (“FSV-1”) cask, which weighs 47,000 pounds, from a height of 43.25 feet. Id. at 1577.

This analysis was done to understand the potential damage to the building structure from this

type of drop. Id. at 825. Waterford 3 did not review this cask drop analysis in order to use the

Holtec system, because the Holtec casks are much heavier. Id. at 805. It was necessary to

upgrade the crane to single-failure-proof because the HI-TRAC “is not designed for cask drop,”

meaning there was “no analysis showing that the [Multi-Purpose Canister] would survive a

20

drop.”23 Id. at 671. Mr. Ferguson credibly testified that the crane was upgraded to allow for use

of the Holtec system, not to save on costs or reduce personnel exposure. Id. at 672.

Implementing dry cask storage required Plaintiffs to remove the racks and support

platform that had been located in the cask storage area. Id. at 692-93. Additionally, Plaintiffs

purchased the work platform that is currently used in the cask decontamination area. Id. at 694.

Waterford 3 had a structural and seismic analysis done to ensure that the Holtec cask equipment

would not damage the building structure during a seismic event and performed 3D modeling of

the cask handling path and other locations within the fuel handling building. Id. at 667, 2127,

2678; PX 850 at 7676. Plaintiffs also had to request a license amendment from the NRC to

change the plant’s technical specifications to allow the handling of the 10,000 pound Multi-

Purpose Canister lid over the spent fuel. Tr. 428-29. The parties also dispute whether Plaintiffs

should receive damages for the purchase of the VECASP, lift yoke extension, and lift yoke stand,

which is used to store the lift yoke.

Plaintiffs’ Model of the Non-Breach World Using DOE Transportation Casks

Under the Standard Contract, DOE was required to provide a suitable transportation cask.

This provision stated:

DOE shall arrange for, and provide, a cask(s) and all necessary transportation of

the SNF and/or [high-level waste] from the Purchaser’s site to the DOE facility.

Such cask(s) shall be furnished sufficiently in advance to accommodate scheduled

deliveries. Such cask(s) shall be suitable for use at the Purchaser’s site, meet

applicable regulatory requirements, and be accompanied by pertinent information,

including, but not limited to, the following:

(a) written procedures for cask handling and loading, including

specifications on Purchaser-furnished cannisters [sic] for containment of failed

fuel;

(b) training for Purchaser’s personnel in cask handling and loading, as

may be necessary;

(c) technical information, special tools, equipment, lifting trunnions, spare

parts and consumables needed to use and perform incidental maintenance on the

cask(s); and

(d) sufficient documentation on the equipment supplied by DOE.

JX 1 at Art. IV.B.2. In accordance with the delivery commitment schedule and final delivery

schedule forms, the Purchaser was to select the shipping mode – either truck, rail, or barge.

The regulations at 10 C.F.R Part 71 govern the transportation of nuclear fuel, while Part

72 governs the storage of spent fuel. Tr. 298-99, 676-77. The Holtec HI-TRAC, HI-STORM,

23

Mr. Ferguson testified that Entergy was able to have impact limiters “with their building

set up,” i.e. that the River Bend plant had a building set-up that allowed it to use load limiters to

absorb the load of a potential drop, instead of single-failure-proofing the crane. Id. at 672.

21

and Multi-Purpose Canister are not licensed for shipment but are licensed for storage under Part

72. Id. at 675, 862. The Multi-Purpose Canister is a dual-purpose canister that can be used for

storage and is compatible with another Holtec item called the HI-STAR, which can be used, with

the proper licensing, for transportation of spent fuel. Id. at 298-99. However, in order to use the

Multi-Purpose Canister for transportation, a Part 71 license must be obtained. Id. at 864-65.

A cask licensed under Part 71 for transportation must be able to survive a 30-foot drop

and have been analyzed to ensure that it can withstand such a drop. Id. at 680, 797. There are

two types of transportation casks – truck casks and rail/barge casks. Id. at 1561. A truck cask is

smaller and can be transported on highways because the “gross vehicle weight, including the

loaded cask does not exceed 80,000 pounds.” Id. at 2627; PX 1 at 21, n.40. A rail cask is larger

and can hold more fuel assemblies. Tr. 1636.

Ms. Eileen Supko was asked to develop a plausible description of DOE performance for

spent fuel acceptance and transportation from Waterford 3, assuming that DOE had begun

performance in 1998. Id. at 1477. The purpose of this analysis was to determine what plant

modifications and actions would have been necessary in the non-breach world. Ms. Supko

identified the actions and modifications that were made at Waterford 3 in order to use the Holtec

system in the breach world, identified “the general features of a plausible DOE transportation

cask for acceptance of spent fuel from Waterford,” and then identified the actions and

modifications that would have been necessary for Waterford 3 to handle this plausible DOE

cask. Id. at 1477-78.

In order to determine what a plausible DOE transportation cask would have been, Ms.

Supko analyzed the physical features at Waterford 3 and compared these to the known features

of DOE casks that were under development and casks that were in use for transport in the 1990s.

Id. at 1478. Ms. Supko also reviewed the Waterford 3-specific Facility Interface Capability

Assessment (“FICA”), a report created by DOE for each nuclear plant that discussed the plant’s

cask handling capability and the ability to handle the various casks under development. Id. at

1479. Finally, Ms. Supko reviewed Waterford 3’s final safety analysis report, the FSV-1 cask

drop analysis, and plant drawings, and spoke with Entergy personnel regarding cask handling.

Id. at 1480-81.

Ms. Supko concluded that “had DOE begun performance in 1998 . . . , Entergy could

have, and plausibly would have, selected truck shipment for acceptance of [spent nuclear fuel]

from the Waterford site.” PX 1 at 9. Ms. Supko only analyzed legal weight truck casks, instead

of heavier rail casks, “because the only cask drop analysis performed for Waterford was for a

legal weight truck cask, and because the use of a legal weight truck cask was a plausible choice.”

Id. at 18. Based on conversations with Entergy personnel and a review of the Waterford 3-

specific Facility Interface Capability Assessment report, Ms. Supko determined that Waterford 3

could handle a DOE transportation cask with a maximum diameter of 11 feet, 1 inch, and a

maximum length of approximately 18 feet. Id. at 10.

Although it was not possible to identify the specific transportation cask design that would

have been provided by DOE for use at Waterford 3, Ms. Supko found it plausible that DOE

would have brought a truck cask with similar dimensions to five casks that were developed by

22

DOE or were certified for transportation in the 1990s.24 Id. at 18-22. These casks weigh

between 23 and 27.1 tons, have lengths between 188 and 208 inches (without impact limiters),25

diameters between 28 and 48.31 inches, and can hold 1 to 4 spent nuclear fuel assemblies. Id. at

22. Ms. Supko noted that the Waterford 3 cask drop analysis was performed assuming a 23.5 ton

(47,000 pound) FSV-1 cask dropped from a height of 43.25 feet. Id. at 24. Additionally, a Part

71 transportation cask must be designed to withstand a 30-foot drop on to an unyielding surface.

Id. Ms. Supko concluded that this cask drop analysis would still cover the use of an

approximately 30-ton DOE cask, such that another cask drop analysis would not need to be

performed, because in handling a DOE cask, Waterford 3 would only have had to perform a 20-

foot lift. Id. at 24.

Ms. Supko modeled how Waterford 3 would have loaded a DOE-supplied cask in the

non-breach world. The DOE cask would have arrived via a DOE transport vehicle at the fuel

handling building rail bay. Id. at 25. Ms. Supko asserted that DOE would have supplied a cask

lift yoke, slings, and other equipment pursuant to the Standard Contract, which specified that

DOE would provide “technical information, special tools, equipment, lifting trunnions, spare

parts and consumables needed to use and perform incidental maintenance on the cask(s).” Id.;

JX 1 at Art. IV.B.2.26 The DOE cask would have been brought into the fuel handling building

through Gate 4 and placed in the cask decontamination area to be washed down. PX 1 at 25.

The DOE cask lid would have been removed with the crane auxiliary hook, which has a 15-ton

capacity, and set aside. Id.

Before moving the DOE cask to the cask storage area, the cask storage area “would have

been drained of water and bulkhead Gates 3A and 3B . . . would have been removed to facilitate

transfer of the DOE cask from the [cask decontamination area] to the [cask storage area].” Id.

The DOE cask would then have been moved into the cask storage area using the crane. Id.

Gates 3A and 3B would have been reinstalled, the interior of the DOE cask filled with borated

water, and the cask storage area would have been refilled. Id. Gate 1, between the cask storage

area and the spent fuel pool, would have been removed to allow spent nuclear fuel assemblies to

be placed into the DOE cask. Then, the DOE cask lid would have been lifted by the crane

auxiliary hook and lowered into place on the DOE cask.

24

These five casks were the General Atomics GA-4 and FSV-1, the NAC International

NAC-LWT and NLI 1/2, and the Westinghouse Titan. Very few of these casks ever existed.

General Atomics has completed NRC certification of the GA-4, but has never fabricated any of

these casks. NRC regulations did not allow for fabrication of the NLI 1/2 and the FSV-1 after

August 31, 1986. NAC International owns five NLI 1/2 casks and eight LWT casks. Three

FSV-1 casks were fabricated. The FSV-1 was not certified to transport fuel from pressurized

water reactors like Waterford 3.

25

Impact limiters are “removable external protective structures” “that reduce the

mechanical forces imposed on the package under accident conditions.” PX 1 at 23.

26

In their post-trial briefs, Plaintiffs do not assert that the lift yoke would have been

provided by DOE and instead argue that purchasing it would not have been necessary in the non-

breach world because the cask storage area would have been drained. See Pls.’ Post-Trial Reply

Br. 20.

23

Gate 1 would have been replaced and the water in the cask storage area would have been

drained again. Id. The DOE cask would have been prepared for shipping, by draining the

borated water, backfilling the cask interior with helium, and installing and tightening all

remaining cask lid bolts for transport. Id. Using the crane, the DOE cask would have been

moved into the cask decontamination area through Gates 3A and 3B and decontaminated. Id. at

26. Finally, the DOE cask would have been lifted through Gate 4 into the rail bay and loaded

onto a DOE transport vehicle. Id.

Based on this opinion of how a DOE cask would have been loaded in the non-breach

world, Ms. Supko concluded that Waterford 3 would not have had to make modifications to the

fuel handling building or take other actions it had to take in the breach world. Ms. Supko found

that Waterford 3 would not have had to upgrade the crane to single-failure-proof because the

height of the lift envisioned by her model coupled with the use of a 30-ton DOE cask fell within

the parameters of Waterford 3’s existing cask drop analysis using the FSV-1 cask. Additionally,

because the 30-ton weight of the DOE cask is not close to 25% of the 125-ton capacity of the

crane, according to Mr. Ferguson, there would be an “additional margin in the [crane] safety

factors.” Id. at 28. Furthermore, because the DOE cask lid would have been bolted in place and

fully torqued while the cask was in the cask storage area, if the cask were dropped while being

moved to the cask decontamination area, it would be leak-tight with no possible release of

radiation. Id.

Ms. Supko also found that Waterford 3 would not have had to obtain an NRC license

amendment to lift heavy loads, i.e. the cask lids, over the spent fuel pool, as the weight of the

truck cask lid would have been less than 2,000 pounds. Id. at 27-28.27 Ms. Supko testified that

the truck casks she examined had lid weights from 860-1510 pounds and thus, even when

combined with the weight of the auxiliary hook and load block, this weight would remain under

27

The NRC regulates the movement of heavy loads over certain areas at nuclear power

plants, including areas where the spent fuel is located. Tr. 768. An NRC regulation, NUREG

612, governed control of heavy loads at nuclear power plants. Id. at 608. During the

implementation of its dry cask storage project, Waterford 3 obtained a license amendment to lift

heavy loads over the spent fuel assemblies, specifically “over the HI-TRAC transfer cask as it

sits in the cask storage area, and specifically the HI-TRAC transfer cask lid.” Id. at 1638-39.

Prior to this amendment, loads in excess of the 2,000 pound limit could not be lifted over spent

fuel, as this limit was part of Waterford 3’s operating license. Id. Waterford 3’s administrative

or procedural definition of a heavy load is 1,500 pounds. Id. at 815. Waterford 3’s Final Safety

Analysis Report (“FSAR”) has a higher definition of heavy load – 2,000 pounds. Id. at 815-16.

Waterford 3’s July 23, 1998 design change package, which was created to gain approval from

management to make changes to the plant for the rerack project, specified that a heavy load was

defined as 1,500 pounds, including the block, load, rigging, and hook. Id. at 754-55. The crane

has an auxiliary hook, weighing 625 pounds, which includes the weight of the crane load block,

that is rated for 15 tons. Id. at 815. The main hook of the crane is rated for 125 tons. Id. at 670.

Mr. Ferguson testified that the total weight of the auxiliary hook and block is 400 pounds.

However, Ms. Supko, quoting from Waterford 3’s heavy load procedures, noted that the weight

of these two items combined is 625 pounds. Id. at 1640.

24

2,000 pounds. Tr. 1595. She also stated that it was plausible that a truck cask could have been

used that had a lid weight that fell under both the 2,000 pound limit in Waterford 3’s technical

specifications and its 1,500 pound procedural limit. Id.

Ms. Supko also opined that the VECASP, lift yoke, lift yoke extension, and lift yoke

storage hangar would not have been needed because there would have been no issue with

potentially dipping the hook and other crane parts into borated water, as her model had the cask

storage area water drained. PX 1 at 29. Ms. Supko posited that the work platform would not

have been necessary because DOE had a bolted cask lid and thus no access to the top of the cask

for inspection and welding would have been necessary. Id. Ms. Supko stated that “Entergy

could have utilized scaffolding to support closure operations of the DOE cask in the [cask

storage area], such as the scaffolding used in the [fuel handling building] [r]ail [b]ay during stack

up operations.” Id.

Ms. Supko was instructed by counsel not to consider cask loading costs in her

comparison of the breach and non-breach world. PX 1 at 1. Ms. Supko did not attempt to

identify “the number of assemblies that would have been transported in the DOE cask in this

non-breach scenario” because this “would only be important if it were necessary to quantify

differences in cask loading costs between the non-breach and breach worlds.” Id. at 29. Ms.

Supko also did not consider worker radiation dose or the amount of time it would take to load a

cask in her model. Tr. 1622.

Ms. Supko’s model of the non-breach world required operational gates, particularly Gates

3A and 3B. However, in the breach world, Gate 3A is welded closed to stop leaking. Id. at 308.

Mr. Ferguson testified that Gate 3A was welded in the beginning of plant operations because

plant personnel were never able to get the leakage below 30 gallons per hour. Id. at 611-12, 750.

Multiple unsuccessful attempts were made to stop the leaking. Id. at 750-51. Additionally,

Gates 1 and 2 leaked. Id. at 703, 752. Mr. Ferguson had never seen Gates 1 and 2 installed or

Gates 3A and 3B removed. Id. at 696, 747. Ms. Supko concluded, based upon discussions with

Mr. Ferguson, that Entergy would have repaired Gate 3A by removing the welds and replacing

the gate seals. Id. at 695; PX 1 at 29.

Mr. Laque estimated that removal of Gates 3A and 3B would take approximately 1.5-2

hours per gate.28 Tr. 371. This estimate did not include the time to deflate and reinflate the seals

around the gates. Id. at 372. It would also take approximately 1.5-2 hours, possibly longer, to

reinstall the gates. Id. at 372-73. Mr. Laque further estimated it would take 4-6 hours to remove

Gate 4 using a six-man crew. Id. at 376.

Based on Ms. Supko’s conclusion that Gate 3A would necessarily have been repaired to

comport with her model of the non-breach world, Mr. Metcalfe computed an offset for gate

repair of $660,338. He stated that this offset was based on facts provided by Mr. Ferguson about

the amount of manpower, contractor personnel, days needed, and other information. Id. at 1875-

76. Therefore, based on Ms. Supko’s opinion, Plaintiffs claim damages of $8,505,653 for the

28

Mr. Laque’s estimates were based on each gate being a separate section. Mr. Ferguson

testified that Gate 3A is made out of two pieces on top of each other with a horizontal seam.

25

crane upgrade and $7,240,114 for the other fuel handling building modifications and actions,

minus the gate offset.

Defendant’s Expert Opinion on Ms. Supko’s Non-Breach World Model

According to Gregory Maret, Defendant’s expert in nuclear power plant operations and

management,29 Plaintiffs would have upgraded the crane in the non-breach world as well as in

the actual world, and would also have performed the other modifications and actions, such as

obtaining the NRC license amendment for heavy loads. Id. at 2616, 2674-78. Mr. Maret had

several overall objections to Ms. Supko’s analysis. Mr. Maret opined that Plaintiffs’

representation of the non-breach world would have led to “potentially risky behaviors” and had

“significant gaps” that were not consistent with Entergy’s business practices reflected in its

cost/benefit analyses, safety values, and risk management. Id. at 2620-21. In Mr. Maret’s

opinion, Ms. Supko’s analysis was overly constrained to try to fit within Waterford’s FSAR

[Final Safety Analysis Report] documentation, meaning that her analyses only “considered what

activities could have been performed at Waterford while limiting modifications, not what

modifications Waterford would have implemented.” Id. at 2624; DDX 5 at 4. Additionally, Ms.

Supko did not consider the benefits of modifications over the life of the plant. Tr. 2623-24.

One of the major problems that Mr. Maret found in Ms. Supko’s model was her use of a

low-capacity truck cask. Mr. Maret concluded that the only cask that could have been used at

Waterford 3 under Ms. Supko’s model had the capacity of one fuel assembly, because Ms. Supko

did not consider “the licensing effort that would be necessary to qualify casks with heavier lids,”

and this one-assembly cask was the only one with a lid that could meet the non-heavy load

criterion of being under 1,500 pounds. Id. at 2622. Mr. Maret testified that using a cask with

this low capacity instead of a larger rail cask created costs that Ms. Supko did not take into

account. Id. at 2622-23. Mr. Maret opined that using a one-assembly cask required shipping two

casks per week to keep up with the discharge of spent fuel from the reactor, creating scheduling

problems with the other activities conducted in the fuel handling building. Id. at 2629. Mr.

Maret testified that Waterford 3 appeared to have been designed for the handling of large casks,

as there was rail access to the site and the crane was rated for 125 tons. Id. at 2630. Mr.

Ferguson also testified that the plant’s design basis allowed for rail loading. Id. at 606.

Mr. Maret found that Ms. Supko’s model of draining the cask storage area and

conducting cask closure activities in the drained cask storage area created serious problems that

she did not take into account. Mr. Maret concluded that Ms. Supko did not address concerns

about reversing the welding on Gate 3A and opined that it would be difficult to “convince the

plant operations review committee and plant management that removing the seal weld [would

be] a safe and appropriate thing to do at that nuclear power plant.” 30 Id. at 2639-40. Removing

29

Mr. Maret’s expertise included plant modifications, management of spent nuclear fuel,

regulatory compliance, and transfer of fuels from wet to dry storage.

30

Mr. Maret had served as the vice chairman of the plant operations and review committee

at the Yankee Rowe plant. Id. at 2586-87. According to Mr. Maret, the plant operations review

committee “is the body that reviews proposed changes to the design of the nuclear facility and

makes recommendations to the senior manager” whether to approve or disapprove changes based

on their “risk and safety merits.” Id. at 2587.

26

the weld and still not being able to fix the leaks would risk an “uncontrolled release of

radioactive material” and would be a “violation of the license for operating” the plant, something

the plant managers would “do everything they can to make sure” never happened. Id. at 2640.

Furthermore, this model required workers to enter the dry cask storage area, which was hot,

confined, not intended for people to work in, and did not have any means of access. Id. at 2643-

44. Second, the walls of the cask storage area and the cask itself would have been radiologically

contaminated, requiring ventilation or supplied air for workers. Id. at 2644. Mr. Maret stated

that Ms. Supko did not address the water transfer time of pumping 50,000 gallons of water out of

the cask storage area and the cost of operating these pumps. Id. at 2647. According to Mr.

Maret, Ms. Supko did not discuss leakage from Gate 1, was not clear whether the cask storage

area would be fully or partially drained, and did not address increased radiation exposure from

the loaded fuel resulting from lowering the water level above the cask. Id. at 2634-37.

Mr. Maret further stated that whether or not the hypothetical DOE cask had impact

limiters was something that should have been considered by Ms. Supko, but was not. Id. at

2638-39. For example, the GA-4 cask, one of the casks Ms. Supko stated could plausibly have

been used at Waterford 3, had impact limiters that prevented access to its lift trunnions, which

are needed to move the cask from a horizontal to a vertical position. Id. at 2638. However, Ms.

Supko did not analyze how impact limiters would have been handled in the non-breach world.

Based on these stated problems with Ms. Supko’s model, Mr. Maret concluded that,

assuming operation through 2024, approximately 600 truck cask loading evolutions would have

had to have been performed and the gates would have had been moved an equal amount of times.

DX 177 at 6-7.31 Mr. Maret determined that Waterford 3 would have chosen to make the

upgrades that it did in the breach world because it would avoid the costs created by not taking

these actions and because this choice offered reduced risk and increased personnel safety. Id.

Mr. Maret opined that using Ms. Supko’s non-breach world scenario would not have been

consistent with prudent plant decision-making. Id. at 6.

Mr. Maret asserted that Waterford 3 would have upgraded its crane to single-failure-

proof had DOE timely performed. Mr. Maret believed that the existing Waterford 3 cask drop

analysis using the FSV-1 cask would not have covered the potential drop of a DOE cask. Tr.

2625-26. Mr. Maret noted that Ms. Supko “essentially credit[ed] the impact limiters in her

adoption of a population of casks in her work, because they all require impact limiters to satisfy

the analyses required in 10 C.F.R. Part 71, but she never address[ed] how those impact limiters

are going to be handled inside the Waterford [p]lant.” Id. at 2626. Therefore, Mr. Maret

concluded that upgrading the crane in the non-breach world allowed Waterford 3 to avoid

performing drop analyses and taking mitigation measures such as redundant rigging. DX 177 at

14. Upgrading the crane would have allowed Waterford 3 to use a large-capacity rail cask,

which was possible at the site. Furthermore, even assuming the use of a DOE truck cask,

upgrading the crane would have been a prudent decision to avoid all of the costs and safety

issues that would have been incurred by fixing, maintaining, and moving the gates during cask

loading, draining the cask storage area, constructing and moving scaffolding in the cask storage

area, and having workers enter the drained and contaminated cask storage area. Id. at 14-17.

31

These numbers increased to 1,000 if the plant’s license was extended to 2044. DX 177 at

7.

27

Mr. Maret also opined that Waterford 3 would have needed the VECASP [variable

elevation cask support pedestal] or similar device and lift yoke items to load DOE-supplied

transportation casks. Id. at 18. Without the VECASP and lift yoke, it would not be possible to

lower a cask to the bottom of the cask storage area without submerging the steel crane

components. Id. Ms. Supko’s approach avoided the use of these items by draining the cask

storage area. However, Mr. Maret opined this approach came with the significant costs

associated with the gate removal and the time and manpower to drain the water, and thus was not

a reasonable alternative to using a platform and lift yoke. Id. at 18-19. Mr. Maret further

concluded that the following modifications and actions would have taken place to load any cask

at Waterford 3, including a DOE-supplied cask: removal of the racks and associated platform in

the cask storage area, the use of a work platform in the cask decontamination area, the structural

and seismic evaluations of the fuel handling building, 3D modeling of the cask handling path and

fuel handling building, and the license amendments to move heavy loads over the spent fuel and

loaded cask and to load spent fuel into a cask. Id. at 24.

Mr. Maret acknowledged that if DOE had performed and Waterford 3 had chosen not to

rerack, there would have been no racks in the cask storage area that needed to be removed in the

non-breach world. Tr. 2802. He also acknowledged that had DOE performed, the same

VECASP would not have been used, and that Holtec had provided lift yoke items that were

designed to connect to the HI-TRAC. Id. at 2803-04. Mr. Maret did not know whether the

Holtec lift yoke would work with a DOE cask. Furthermore, Mr. Maret accepted that the work

platform in the cask decontamination area was designed to accommodate the specific diameter of

the Holtec HI-TRAC and that a new platform would have to be procured or modifications made

to the Holtec platform to match up with the DOE cask when DOE performs. Id. at 2808.

Similarly, Mr. Maret acknowledged that the seismic and structural evaluations and the 3D

modeling that had been performed had considered the specific weight, dimensions, and center of

gravity of the Holtec system components and that these analyses might have to be redone to use

DOE cask parameters when DOE performs. Id. at 2809-10, 2812-13. Mr. Maret stated that

Waterford 3 may have to make a claim for damages from the Government to pay for a second

version of these analyses when DOE performs and they have to be redone. Id. at 2811, 2813.

Mr. Maret did not know the weight of the lid of the cask that DOE would bring to Waterford 3

and conceded that if the lid, along with the hook and rigging, did not qualify as a heavy load, no

license amendment would be needed. Id. at 2814-15.

Fact Witness Testimony Addressing Characteristics of the Cask Storage Area

Mr. Laque testified regarding Entergy’s confined space program, which is designed to

protect employees from actual or potential hazards when entering “permit-required confined

spaces” and provide guidance “for entry into spaces other than permit-required confined spaces.”

Id. at 318. The program defined “confined space” as “any area which may be occupied by

personnel which have all of the following characteristics:”

(a) large enough and so configured that an employee can bodily enter and

perform assigned work;

(b) limited or restricted means of entry or exit; and

(c) not designed for continuous human occupancy.

28

Id. at 367; JX 19 at 5402. Additionally, the program defined “permit-required confined spaces”

as those which had all of the characteristics of a confined space and one or more of the following

characteristics:

(a) Contains or has the potential to contain a hazardous atmosphere

(b) Contains material that has the potential for engulfing an entrant

(c) Has an internal configuration such that an entrant could be trapped or

asphyxiated by inwardly converging walls or by a floor which slopes downward and

tapers to a smaller cross-section, or

(d) Contains any other recognized serious safety or health hazard.

JX 19 at 5404-05. Mr. Laque stated that entry into a confined space required atmospheric

sampling and a pre-job brief, while entry into a permit-required confined space was more

restrictive and required requesting entry from supervisors. Id. at 5412; Tr. 404. Mr. Laque

testified that it appeared that the drained cask storage area would meet the definition of a

confined space but not a permit-required confined space. Tr. 405.

Mr. Laque also testified regarding radiological contamination of the walls of the drained

cask storage area. The practice of the plant would be to assume that the surface of the cask

storage area was radiologically contaminated because assuming otherwise could result in

unintentionally exposing people to radiation. Id. at 362-63. Mr. Laque stated that the gates that

had come into contact with the water of the spent fuel pool would be considered contaminated

until surveyed and proven not to be contaminated. Id. If the gates were going to be removed

from the contaminated area, they would have to be decontaminated or wrapped up to stop the

contamination from spreading. Id. at 373-74.

Mr. Laque was not sure if the cask storage area could be drained and had never seen this

done since the plant began operations. Id. at 308. Mr. Ferguson did not know how long it would

take to drain the cask storage area and acknowledged that the cask storage area did not have

built-in features to allow workers to access the bottom. Id. at 753. Mr. Ferguson stated that he

was not sure where Entergy would put the water drained from the cask storage area, but that this

water could be put back into the spent fuel pool and the spent fuel pool could be drained down to

make room for the water from the cask storage area. Id. at 818.

In Mr. Maret’s opinion, it did not make sense for Waterford 3 to have used low-capacity

truck casks in the non-breach world because the plant had the infrastructure to allow for the use

of large rail casks. DX 177 at 14. Mr. Ferguson testified that rail access had existed during the

original construction, but there had not been rail access since he had started working at

Waterford 3 in 1992. Tr. 606. Waterford 3 currently does not have usable rail access. Mr.

Maret, however, opined that this rail access could have been reestablished. Id. at 2630. In

October 2004, Waterford 3, in a “dry fuel storage overview” document, evaluated three options

for further fuel storage to maintain full core reserve – additional reracking, building an ISFSI,

29

and shipping the spent fuel to another plant. PX 810 at 6814. 32 The author of this document

noted that if Waterford 3 chose to ship its spent fuel elsewhere by rail, “considerable work on the

rail spur from the plant [would] be necessary” because “[t]he current rail spur has not been used

since the early 1980s” and “[t]he railroad ties along the 0.5 mile path to the site boundary have

seriously degraded and [were] probably unfit for use.” Id. Assuming the rails and rail bed were

still acceptable for use, the cost to repair the rail line to the site boundary was estimated to be

$250,000, using a metric of $1 million per mile. Id. Additionally, although there was a rail head

one mile from the plant, the condition of the rail line between the site boundary and the rail head

was also assumed to be in a degraded condition. Id. at 6814-15.

Cask Loading Costs

The Government challenges $3,966,282 in costs Plaintiffs incurred for loading the spent

nuclear fuel into dry storage canisters. This amount was derived from work orders N66920,

N09518, and N09588. DX 177 at 28. Under the Standard Contract, “[t]he Purchaser shall

arrange for, and provide, all preparation, packaging, required inspections, and loading activities

necessary for the transportation of [spent nuclear fuel] . . . to the DOE facility.” JX 1, Art.

IV.A.2(a). The Standard Contract thus required utilities to pay for cask loading costs.

The Government has admitted that in order to accept canistered fuel from Waterford 3,

an amendment to the Standard Contract will be necessary “to define the terms and conditions for

the acceptance of [spent nuclear fuel] in the canisters in which it is stored.” PX 1066 at 13.

With respect to its knowledge of the terms of such an amendment, the Government stated:

While precise terms of any amendment to the Standard Contract for DOE

acceptance of [spent nuclear fuel] that has been loaded into interim dry storage at

Waterford 3 are unknown, the general parameters of such an amendment are

known. The terms of the contract amendment would deem canistered fuel

acceptable and determine the schedule for acceptance based upon the waste

acceptance capability of the [spent nuclear fuel] storage and disposal facilities to

be considered pursuant to the NWPA and applicable licensing requirements. No

financial consideration beyond that which is required pursuant to the Standard

Contract would be required per the terms of the amendment. The final design of

the storage and disposal facilities to be constructed pursuant to the NWPA may

require additional terms that cannot be defined at the present time.

Id. at 14. Additionally, the Government admitted that without an amendment to the Standard

Contract, DOE could not accept canistered fuel for transport and disposal, but “DOE expects

that, before DOE beings performance, it will execute a contract amendment to be able to accept

canistered fuel for transport and disposal from Waterford 3.” Id. at 15.

The Contracting Officer for all Standard Contracts, Mr. Zabransky, testified that the fuel

on the Waterford 3 ISFSI was stored in multi-element sealed canisters and that “the Department

of Energy’s position has been since 1992 that the [S]tandard [C]ontract does not cover the

32

Mr. Ferguson testified that he reviewed this document when he started working on the

dry fuel storage project in 2006, and that the project manager at the time would have been the

lead drafter. The document does not contain an author’s name. Tr. 598-99.

30

acceptance of spent fuel while stored in multi-element sealed canisters.” Tr. 1102. Furthermore,

in the absence of an amendment to the Standard Contract, the utility would have to unload its

spent fuel and reload it into DOE-provided transportation casks when DOE performs. Id. at

1102-03.

Plaintiffs argue that if they are not awarded cask loading costs, they will be forced to pay

twice for loading fuel, once to put it into the canisters and then again to recanister it when DOE

arrives. Mr. Maret opined that by loading its spent fuel into dual-purpose canisters, Waterford 3

has packaged the spent fuel for transfer to DOE. Id. at 2680; DDX 5 at 19. Mr. Maret stated that

the multi-purpose canisters are ready to be put into a transportation package, instead of the

storage package, and shipped to DOE. Tr. 2680-81. In his expert report, Mr. Maret clarified that

the multi-purpose canisters can be transported under the existing license for the Holtec HI-STAR

transportation package. DX 177 at 26.

Mr. Maret acknowledged, however, that while the canisters were designed to be dual-

purpose, they were not currently licensed for shipment of the Waterford 3 fuel. Tr. 2831.

Furthermore, Mr. Maret testified that not all of the loading activities for the Holtec canisters

would have been the same as required to load a DOE cask and that there would be “a number of

differences.” Id. at 2878-79. Mr. Maret agreed that the costs to load a DOE bolted cask and a

Holtec welded cask would not be identical and that a DOE cask would not require the stack-up

operation. Id. at 2879, 2883.

Neither party’s expert quantified cask loading costs in the non-breach world. Mr. Maret

did not offer an opinion about what it would have cost to load, close, and handle DOE casks. Id.

at 2884. Ms. Supko was instructed by counsel not to consider cask loading costs in comparing

the breach and non-breach world cask loading operations. PX 1 at 29.

Mr. Maret testified that it was reasonable to expect that the loaded canisters would be

accepted by DOE because it made “practical sense” that DOE would not force the utilities to

reopen their canistered fuel. Tr. 2681-82. Mr. Maret stated that this opinion was based on his

review of Entergy documents regarding the decision to fund the dry fuel storage project, which

indicated that one of the benefits of using the Holtec dual-purpose system was that the fuel

would not have to be repackaged and could be sent directly from the ISFSI to DOE. 33 Id. at

2682-83. Mr. Maret also believed that the actions of the nuclear industry support his view. For

example, he relied on a 2008 Electric Power Research Institute report stating its view of DOE’s

plans that dual-purpose canisters would be shipped to Yucca Mountain, where DOE would open

them for repackaging and storage. DX 177 at 26; DDX 5 at 19. Furthermore, Mr. Maret

reviewed submissions that different plants have made to the NRC documenting their estimated

costs of decommissioning. Tr. 2686; DX 177 at 26-27. Because these estimates have not

included the costs of unloading the canisters and repackaging the spent fuel, Mr. Maret

concluded that the utilities have assumed that DOE will pick up canistered fuel from their

ISFSIs.34

33

Mr. Maret also relied on a 1990 Entergy Spent Fuel Storage Study. Id. at 2684.

34

Mr. Maret also noted that the actions of prematurely shut down plants also demonstrated

their assumption that DOE will accept their canistered fuel, as these plants have placed all of

31

However, the canisters may not meet the Part 71 transportation licensing requirements or

may not be transportable by the time DOE performs. Tr. 864-89. The spent fuel cannot remain

on the ISFSI forever, as the multi-purpose canister steel cladding will degrade over time. Id. at

865. There are specific requirements for fuel that can be placed into a Part 71 canister, and fuel

selected to be placed into a Part 72 storage canister may not meet Part 71 requirements. Id. at

864-65. Waterford 3 has not made sure that all the fuel in the canisters meets both requirements

because the canisters are not licensed for transport. Id. at 864. The Government admitted that

“whether or not canistered fuel at Waterford may or may not be transportable when DOE begins

[spent nuclear fuel] acceptance from Waterford will be determined by applicable NRC

regulations and cask certificates of compliance at the time of transport.” PX 1066 at 16. Mr.

Maret agreed that DOE did not know whether the canisters would be transportable in the future,

and stated that some canisters could be degraded by the time DOE performs. Tr. 2847.

DOE has not identified the dimensions of any cask or how many assemblies a DOE

supplied cask could hold. Id. at 2820-21. The Government has admitted that “it would have

supplied transportation casks with bolted closures, pursuant to the terms of the Standard

Contract, had it begun performance in 1998,” but also that it “does not know the specific cask(s)

that would have been selected and supplied to Waterford 3” had it begun performance in 1998.

Id. at 1125; PX 1066 at 10-11.

General Project Management Costs

Plaintiffs’ claim includes dry storage and maintenance costs, including project

management costs, associated with Work Order N66105. Pls.’ Post-Trial Br. 67. Plaintiffs

contend that the costs associated with this Work Order would not have been incurred absent

DOE’s breach, as Waterford would not have undertaken the dry fuel storage project. Id. at 68.

The Government challenges $1,789,227 of Waterford 3’s Work Order N66105, which

encompassed costs relating to dry fuel storage project management, claiming that “a large

portion of the costs charged to this work order included costs related to generic dry fuel storage

management of activities recorded to all work orders” in Plaintiffs’ claim. Def.’s Post-Trial Br.

44.

Mr. Maret “identified sub-projects within the dry fuel storage effort that [he believed]

would have been implemented with timely DOE performances,” making these costs

unrecoverable. Id. Mr. Maret did not elaborate on how he identified these sub-projects. In order

to calculate which portion of the N66105 general project management costs related to the sub-

projects Mr. Maret claimed were unallowable, the Government’s damages expert, Mr. Robert

Peterson, 35 “allocated the generic project management costs recorded to N66105 among all the

their spent fuel on ISFSIs and dismantled their spent fuel pools, leaving no way to remove the

fuel from the canisters and repackage it. DX 177 at 27.

35

Mr. Robert Peterson was accepted by the Court as an expert in the “quantification of

money damages.” Tr. 2934. Mr. Peterson is a managing director of LitCon Group, LLC, has a

bachelor of science degree in mechanical engineering from Rensselaer Polytechnic Institute and

a master of business administration from the University of North Carolina at Chapel Hill. Id. at

2933; DX 185 at 1, App. A at 1. Mr. Peterson “has more than twenty years of engineering and

consulting experience” and “has analyzed damages associated with delay, acceleration,

32

specific activities charged to the work order.” Id. He then “calculated the portion of the general

management charges” associated with Mr. Maret’s sub-projects. Id.

Mr. Maret determined that work order N66105 was for general management costs and

attempted to categorize these costs based on the documentation underlying the line items. Tr.

2887-88. Mr. Maret classified any costs with a heading referencing this work order as a general

management cost and assigned them to categories if he could. Id. Mr. Maret went through a

spreadsheet prepared by Mr. Peterson’s employees. Id. at 2885. If he could not assign the line

item to a specific category based on the underlying documentation, he applied a proportionate

distribution “based on the relative costs compared to the total costs for the individual projects.”

Id. at 2887-88.

Mr. Maret determined that some costs were supervisory and applied to multiple projects

and made a recommendation for how he “thought those uncategorized costs should be

distributed.” Id. at 2885-86. In practical terms, Mr. Maret made this distribution by populating a

column labeled “Technical Review.” If Mr. Maret left this column blank, this indicated that the

cost was required to load DOE casks or was indeterminate. Id. at 2888; DX 177 at C2-17. Mr.

Maret acknowledged that some of the items that he left blank were for welding the Holtec casks

closed and other activities that would not have been required to load a bolted DOE cask. Tr.

2890. Mr. Maret did not dispute that this work order contained engineering, supervision, and

technical support costs that would be necessary for dry fuel storage. Id. at 2896. Nor did Mr.

Maret dispute that the costs for projects that would have been implemented with timely DOE

performance were legitimately part of the claim. Id. at 2897. When asked how he decided to

employ a standard that all indeterminate items would be categorized as disallowed loading costs,

he stated “[t]hat’s just the way that the indeterminate items were treated.” Id. at 2893-94.

Mr. Peterson used Mr. Maret’s work to apportion the amounts that Mr. Maret could not

categorize as pertaining to the items charged to this work order. Any line item that Mr. Maret

left blank was then questioned by Mr. Peterson and disallowed. When asked what his

understanding was as to why Mr. Maret proposed that this subset of the general management

costs be disallowed, Mr. Peterson testified: “Well, he’s proposing that the management in that

work order is managing something, and so what are they managing? They’re managing the other

activities that are taking place. And so to the extent that he has questioned one of those other

activities, there’s some management that would go with it, and it’s been apportioned.” Id. at

3117. He described this apportionment as follows:

There was a particular work order that had some elements of specific work going

on but more of it was related to overall general management of the dry fuel

storage work, and we weren’t really sure how to initially capture any relationship

between the costs recorded there and any of the other adjustments that we were

making. So, there were discussions between I’m sure members of my staff and

members of Mr. Maret’s staff to determine what would be an appropriate

methodology.

disruption, changes in scope of work, productivity losses, and contract termination, among

others.” DX 185 App. A at 1. Mr. Peterson has “lectured on the topic of identifying and pricing

damages” and has testified in several spent nuclear fuel cases. Id. at 2, App. B at 1-6.

33

Mr. Maret suggested that these could be reasonably allocated, these being the

costs recorded for the management components within work order 66105, could

be appropriately allocated out to all the other activities that were not general in

nature. So, we concurred that seemed to be a reasonable approach, and so that

was the mechanism we went through in our work papers to allocate out the --

again, the amounts that through analysis were determined to be general

management in nature within that work order.

Id. at 3019-20. Mr. Peterson further described his apportionment as “attaching management” to

activities that Mr. Maret questioned. Id. at 3116. This methodology resulted in Mr. Peterson

calculating a percentage per quarter that should be disallowed based on the amount that Mr.

Maret identified divided by the net amount of costs in that quarter. Mr. Peterson then reduced

the line item costs for each quarter of the damages period by the percentage that he had

calculated. Mr. Peterson disallowed 93.8% of the costs questioned by Mr. Maret, yielding a net

adjustment for general project management of $1,784,995.

Payroll Loaders

The Government challenges $266,276 in Entergy payroll loaders associated with

Resource Codes 19 and 60. At trial, Plaintiffs supported their claim with the testimony of Ms.

Stephanie Barras.36 As Ms. Barras testified, payroll loaders are used to burden internal labor

costs and are applied using an automated software system. 37 Id. at 499-501. Ms. Barras’ team

and other Entergy accountant teams created the loader rates. Id. at 510-11. A resource code

designates a type of cost and is used to assign appropriate loaders to transactions. Id. at 503.

Entergy has six resource codes for payroll loaders: 2 for incentive compensation, 18 and 19 for

benefits, 60 for stock options, 810 for payroll taxes, and 890 for non-productive time. Id.

Resource Code 60 was introduced in 2010, as stock options were previously captured under

Resource Code 19. Id. at 508-09. Entergy computes and charges these payroll loaders according

to generally accepted accounting principles (“GAAP”) and Federal Energy Regulatory

Commission (“FERC”) regulations. Id. at 511.

While Resource Code 18 is associated with “current year costs,” such as medical, life,

and dental, as well as current year service costs for employee pension and other post-

employment benefits, Resource Code 19 is associated with benefits that are not considered

“current year service cost based.” Id. at 508. Rather, Resource Code 19 includes “things such as

gains and losses on the pension trust,” “changes in interest costs . . . as well as different

amortization and differences in accounting . . . .” Id. at 512. Resource Code 19 includes prior

36

Ms. Stephanie Barras is employed by Entergy Services, Inc. as manager of property

accounting. Tr. 492. She has a bachelor of science degree in accounting from the University of

New Orleans and is a certified public accountant licensed in Louisiana. Id. at 495. Ms. Barras

began working for Entergy in 1996 as an entry level accountant and worked her way up to the

management level. Id. at 495-96.

37

Capital suspense is another type of loader that is applied to capital project work, and

materials loaders are also used to assign indirect costs of materials to projects. Id. at 517-18,

529. The methodology of computing these two loaders and the payroll loaders are “very

similar.” Id. at 527.

34

period costs and non-current benefit costs as well as amortized transition costs due to Entergy’s

implementation of different accounting standards during the claim period. Id. at 542, 551. Ms.

Barras stated that costs attributable to current, past, and retired employees are part of Resource

Code 19 and are not specific to any type of employee. Id. at 513.

Ms. Barras explained that Resource Code 19 costs were included in Plaintiffs’ claim

because

they are a cost that’s incurred by the company and it’s an ongoing cost that the

company has been paying for years and will continue to pay for years. [. . .] There

are costs that are generated today that are part of the loader that may have been

attributable – attributed to employees past.

Id. at 513-14. Resource Code 19 costs can be attributed to economic conditions, interest rates,

regulations, and other similar things outside of Entergy’s control. Id. at 543. Entergy’s increases

or decreases in contributions to this trust during the period at issue would cause increases or

decreases in the Resource Code 19 payroll loader rate in the future. Id. at 544-45. Variables in

the trust funding due to interest rates and gains and losses are attributed to Resource Code 19.

Id. at 545.

Plaintiffs argue that charges associated with Resource Code 60 are included in their

damages claim because “they are indirect costs associated with labor and represent the actual

costs of doing business incurred by Entergy.” Pls.’ Post-Trial Br. 26. Defendant challenged the

inclusion of Resource Code 60 within Plaintiffs’ claim because “Entergy did not introduce any

evidence at trial to establish that the costs allocated through [this] payroll loader[] [was] incurred

as a result of DOE’s delay in performance.” Def.’s Post-Trial Br. 47. With regard to Resource

Code 60, Ms. Barras testified that stock options are only available to certain levels of Entergy

management and she did not know whether individuals who worked on the dry fuel storage

project at Waterford 3 received stock options. Tr. 555-56.

The Government’s damages expert, Mr. Peterson, challenged the inclusion of Resource

Codes 19 and 60 in Plaintiffs’ claim. Mr. Peterson did not challenge any other payroll loaders.

Id. at 2996. Mr. Peterson testified that the “biggest issue” with Resource Code 19 was that it

included costs from prior periods that became recognized when a change in accounting standards

required Entergy to change how it accounted for pension adjustment and post-employment

adjustment in its books. Id. at 2999-3001. As this change in standards created a “large,

unrecognized expense” for Entergy and other types of companies, they were allowed to amortize

this cost over a 20-year window. Id. at 3000. Mr. Peterson did not know when the new

accounting standards were implemented, but believed that they were put in place in the late

1980s or early 1990s and “there were a few years grace period and then approximately a 20-year

window over which they were amortized.” Id. at 3003. Entergy was thus “most certainly”

claiming costs allocated to Resource Code 19 that it incurred before the claim period of this suit.

Id. at 3003-04.

In Mr. Peterson’s view, while this amortized expense was included over the claim period,

it was not “tied to or driven by anything associated with the work happening on-site” and would

not be repeated. Id. at 3001. Mr. Peterson related a similar concern regarding other costs

included in Resource Code 19, as the change in the value of pension plans was not tied to work

35

at the plant and did not increase or decrease because of any dry fuel storage activities. Id. at

3001-02. With regard to Resource Code 60, Mr. Peterson was concerned because only high-

level executives received stock options and this resource code may not have been connected to

the dry fuel storage project. Id. at 3002-03. According to Ms. Barras, Resource Code 60 “is a

cost that the company incurs in its normal course of business.” Id. at 514.

NRC Fees

Plaintiffs’ claim includes $1,942,000 in fees assessed by the NRC under 10 C.F.R. Part

171 (“Part 171”). The NRC “has long recovered a substantial portion of its operating budget

through fees levied on those that it regulates.” PX 1005 at 5. The NRC uses two categories of

fees – fees for specific benefits it provides to licensees, which fall under 10 C.F.R. Part 170, and

since 1986, annual fees under 10 C.F.R. Part 171 to recover other generic costs. Id. Site-specific

fees are license and inspection fees charged directly to the applicant or licensee involved. See 10

C.F.R. § 170.12 (2015). Examples of site-specific fees include fees associated with the review of

applications for new licenses, the review of renewal applications, the review of license

amendment requests, and inspections of licensees. Id.

In 1991, Congress passed the Omnibus Budget Reconciliation Act (“OBRA-90”),

requiring the NRC to recover 100% of its annual budget through fees assessed to license

applicants and license holders, less amounts appropriated from the Nuclear Waste Fund. PX

1005 at 5. OBRA-90 also required the NRC to establish a schedule of annual charges that “fairly

and equitably” allocated the total annual amount among licensees and had “a reasonable

relationship to the cost of providing regulatory services,” “to the maximum extent practicable.”

Id.; 42 U.S.C. § 2214(c)(3) (2012).

Prior to 1999, the NRC recovered its generic costs associated with spent fuel stored

outside a spent fuel pool through an annual fee assessed under Part 171, but only on licensees

that held a Part 72 license to store spent fuel outside of the spent fuel pool. PX 1005 at 6. The

NRC charged a fee for its generic costs associated with spent fuel pools and a separate fee for

generic decommissioning activities to all operating Part 50 licensees, but not on Part 50

possession-only licensees that decided to forgo dry fuel storage in favor of wet storage. Id.; Tr.

1451. Thus, all operating licensees paid to cover the NRC’s generic fees associated with

regulating spent fuel pools, but only licensees that had Part 72 dry storage paid a fee to cover the

NRC’s generic costs associated with this dry storage.

However, in 1999, the NRC established a new fee under Part 171, the Spent Fuel

Storage/Reactor Decommissioning Fee (“SFS/RD fee”).38 PX 1005 at 7. In the proposed

rulemaking, the NRC observed that the existing policy raised the following concerns about the

equitable allocation of generic fees:

(a) [t]he fee structure could create a disincentive for licensees to pursue dry

storage; (b) [t]he fairness of assessing multiple annual fees if a licensee holds

multiple [dry storage] licenses for different designs; and (c) [n]ot all affected

38

NRC rules are issued by a five-person Commission, including the NRC Chairman. 42

U.S.C. § 5841(a) (2012). The Commission members are appointed by the President and

confirmed by the United States Senate. Id. at § 5841(b).

36

licensees are being assessed the costs of NRC’s generic decommissioning

activities.

Revision of Fee Schedules; 100% Fee Recovery, FY 1999, 64 Fed. Reg. 15,876, 15,881 (Apr. 1,

1999).

During the notice-and-comment rulemaking process, one commenter observed that a fee

change would be unnecessary had the DOE honored its obligations under the Standard Contract.

The NRC responded in the Final Rule:

The NRC recognizes that sites will be required to continue to store spent fuel

onsite until another solution becomes available. The fact that DOE has not taken

possession of the spent fuel does not relieve NRC of the OBRA-90 [Omnibus

Budget Reconciliation Act of 1990] requirement to recover approximately 100

percent of its budget authority through fees, including those costs associated with

generic spent fuel storage activities . . . . The current policy has raised concerns

that the fee structure could create a disincentive for licensees to pursue dry

storage. The spent fuel storage/reactor decommissioning annual fee will give

equivalent fee treatment to both storage options [wet storage and dry storage].

Revision of Fee Schedules; 100% Fee Recovery, FY 1999, 64 Fed. Reg. 31,448, 31,455 (June

10, 1995). The NRC assessed a fee on all Part 50 licensees and on licensees with Part 72 storage

licenses but without Part 50 licenses, a Spent Fuel Storage/Reactor Decommissioning Fee, which

levied a generic fee on all licensees, regardless of whether they used wet or dry storage.

Plaintiffs proffered Mr. Jesse L. Funches to provide an expert opinion to support their

claim for these fees. Mr. Funches joined the NRC in 1978, as an advisor to Commissioner John

Ahearne and continued this role when Mr. Ahearne was appointed Chairman, providing advice

on budgetary and other financial and administrative matters. PX 1005 at 3. Mr. Funches then

served as the Director of Planning and Program Analysis Staff in the NRC’s Office of Nuclear

Reactor Regulation from 1981 to 1987, and in the NRC’s Office of Nuclear Materials and

Safeguards from 1987-90. Id. at 4. In both roles, Mr. Funches managed a staff of approximately

30 and “defined the programs, program elements, and planned accomplishments for the NRC’s

annual budgets.” Id.; Tr. 1143. From 1990 to 1997, Mr. Funches held the position of Deputy

Controller of the NRC. Mr. Funches “was assigned the lead responsibility for developing the

first 10 CFR Part 170 and 10 CFR Part 171 fee rules” to implement the new OBRA-90

requirements. PX 1005 at 4. He also participated in the development and justification of the

NRC’s annual budget. Id.

In 1997, Mr. Funches was appointed Chief Financial Officer (“CFO”) of the NRC and

reported directly to the NRC Chairman. Tr. 1145. He held this position until his retirement in

2007. PX 1005 at 4. In October 1998, in response to the Commission’s request, Mr. Funches’

staff provided a Spent Fuel Storage and Decommissioning Fee Study. Id. at 7. Mr. Funches

reviewed and approved this study, but did not author it and was not a member of the study team.

Tr. 1409. Based on the October 1998 study, Mr. Funches recommended the establishment of the

Spent Fuel Storage/Reactor Decommissioning Fee. PX 1005 at 7. In his role as CFO, Mr.

Funches met each morning with the NRC’s Chairman and other senior managers, and typically

37

met with the other Commissioners about once a month, and would brief the Commission “maybe

once or twice a year.” Tr. 1147.

Mr. Funches was admitted as an expert in NRC annual fee assessment, including the

Spent Fuel Storage/Reactor Decommissioning Fee (“SFS/RD fee”) adopted in 1999. Id. at 1178-

79. Mr. Funches opined that,

[i]n establishing the SFS/RD Fee, the NRC concluded . . . that beginning in

FY1999, the NRC’s costs associated with generic spent fuel storage activities

should be included in the cost of providing services to all power reactors. The

underpinning for this finding was the fact that DOE was not accepting spent fuel

from utilities beginning in 1998 as provided in the Standard Contract, and

therefore the NRC’s generic activities for reactor spent fuel pool storage and dry

spent fuel storage would benefit all power reactors, the majority of which would

eventually require additional storage due to DOE’s breach. If DOE had not

breached the Standard Contract, and DOE would have begun accepting the spent

fuel in 1998, the number of Part 50 licensees that required storage beyond their

existing spent fuel pool would have been minimized. In that circumstance, the

NRC would not have assessed the SFS portion of the SFS/RD Fee on the power

reactor class of licensees . . . because those activities would have benefited only

the much smaller class of licensees that would have required additional storage

outside of their existing spent fuel pools.

PX 1005 at 7-8. Mr. Funches indicated that the NRC would not have been complying with

OBRA-90 if it had changed the fee structure in the non-breach world, because most reactors

would not have needed dry fuel storage had DOE picked up the spent nuclear fuel. Tr. 1436.

In providing this opinion, Mr. Funches relied on several documents:

 Excerpts of the March 1995 Congressional testimony of former NRC Chairman Ivan

Selin concerning the assessment of annual fees. PX 998;

 A February 2, 1998 memorandum from NRC Secretary John Hoyle to NRC Chairman

Shirley Jackson and NRC Commissioner Edward McGaffigan, Jr. (“Feb 1998

Memorandum”), on which Mr. Funches was copied. JX 9;

 Mr. Funches’ February 27, 1998 “Policy Issue” memorandum to the NRC

Commissioners (“Sec’y 98-034”), which requests that the Commissioners consider

whether to use rebaselining or a percent change as the methodology for calculating fiscal

year 1998 annual fees. JX 10;

 A March 9, 1998 Staff Requirements Memorandum (“SRM”)39 from NRC Secretary Mr.

Hoyle to Mr. Funches and Executive Director for Operations, L. Joseph Callan

(COMSAJ-98-001). DX 218;

39

A SRM reflects a Commission decision that requests the NRC staff to perform a specified

task. Tr. 1292.

38

 Mr. Funches’ November 5, 1998 “Policy Issue” memorandum to the NRC

Commissioners (“Sec’y 98-260”), which included the October 1998 Spent Fuel Storage

and Decommissioning Study. DX 224;

 Commissioner Merrifield’s December 4, 1998 Comments on Sec’y 98-260 (FY 1999 Fee

Rulemaking). JX 12;

 Commissioner McGaffigan’s December 14, 1998 Comments on Sec’y 98-260 (FY 1999

Fee Rulemaking). JX 13;

 A February 2, 1999 SRM – drafted in response to Sec’y 98-260 – from NRC Secretary

Annette Vietti-Cook to Mr. Funches and General Counsel Karen Cyr, with all five

Commissioners copied on the memorandum. JX 14;

 The 10 C.F.R. Parts 170 and 171 June 1999 final fee rule, containing a comment from a

nuclear utility about the SFS/RD fee and the NRC’s response. DX 61.

Mr. Funches acknowledged that the NRC is composed of four Commissioners and a

Chairman, and that he had never served in any of these roles. Tr. 1333. He further

acknowledged that the 1999 fee rule change was a policy decision that required the approval of

the Commissioners. Id. at 1335-36. While Mr. Funches had the responsibility to respond to

questions in his role as CFO, he was never delegated authority to be a spokesperson for the

Commission. Id. at 1338-39. Mr. Funches did not recall any specific conversations he had with

the Commissioners in which they told him that the reason for the reassessment of Part 171 was

DOE’s delay in performance under the Standard Contract. Id. at 1172. He also did not

remember any specific oral statement by any of the Commissioners to the effect that they were

approving the SFS/RD fee because of DOE’s breach of the Standard Contract. Id. at 1174.

Mr. Metcalfe offered an opinion on the “economic implications, if any, of NRC’s

adoption of a revised methodology for charging utilities like Waterford Part 171 fees in 1999.”

Id. at 1842-43. Mr. Metcalfe opined that “[h]ad DOE performed in accordance with its

contractual obligation, the NRC would not have had to change its fee structure in 1999.” PX 116

at 27. Mr. Metcalfe relied on the 10 C.F.R. Parts 170 and 171 June 1999 final fee rule,

containing a comment from a nuclear utility about the SFS/RD fee and the NRC’s response,

Sec’y-98-260, the October 1998 Spent Fuel Storage and Decommissioning Fee Study,

Commissioner Merrifield’s and Commissioner McGaffigan’s December 1998 comments, and the

February 2, 1999 SRM from NRC Secretary Annette Vietti-Cook to Mr. Funches and General

Counsel Karen Cyr, with the five Commissioners copied. PDX 7 at 62-71.

For each year between 1999 and 2012, Mr. Funches created a breakdown, in the form of

percentages, of the portion of the SFS/RD fee he determined was allocated to NRC generic

activities in the categories of dry spent fuel storage, reactor spent fuel storage, and reactor

decommissioning. PX 1005 at 9-15. Mr. Metcalfe then used these percentages to calculate

Waterford 3’s alleged damages, using the percentage of the SFS/RD fee for each year that Mr.

Funches had determined was used for dry spent fuel storage generic activities. Tr. 1857-58.

39

Allegedly Unsupported Transactions

Defendant challenges $1,488,727 of Plaintiffs’ claimed damages on the grounds that they

are “unsupported by adequate contemporaneous documentation . . . .” Joint Stip. ¶ 2. Mr.

Peterson separated these charges into three categories –

1. Transactions missing documentation,

2. Transactions missing capital suspense rate information, and

3. Invoices for which Plaintiffs did not provide discovery responses.

DDX 6 at 5-6.40

Both Mr. Metcalfe and Mr. Peterson testified about the invoices encompassing the first

and third categories. The first category consists of allegedly incomplete invoices and missing

accounting system transactions. Id. at 5. Mr. Metcalfe did not agree that any of the transactions

in the first category were unsupported and determined, after reviewing the documents and

supporting material and discussing them with plant staff, that all of the challenged invoices had

been paid and were properly included in the claim. Tr. 1912-45. Mr. Metcalfe also testified that

all of the charges in the third category were properly included in the claim and paid. Id. at 1959-

67.

However, Mr. Peterson testified that he had not challenged any invoice on the basis of

whether or not it was paid. Rather, Mr. Peterson’s exclusions resulted from other information he

believed was lacking. Id. at 2944-45. Mr. Peterson testified as to what documents he determined

were missing for the first category of invoices. Id. at 2958-75; DDX 6 at 7-14. For example,

Mr. Peterson noted that certain invoices referred to other documents, such as attached letters, that

had never been provided. DDX 6 at 10. Mr. Peterson also testified that he was not able to tie all

invoices to Entergy’s accounting data and that certain transactions had been assigned a resource

code that Mr. Metcalfe had previously determined should not be part of Plaintiffs’ damages. Tr.

2982-83. In regard to the third category of challenged damages, Mr. Peterson described how Mr.

Maret’s company had requested “information on a wide variety of different work orders and

individual invoices” from Plaintiffs. Id. at 2988-90. After receiving discovery responses, Mr.

Maret and his staff could not “understand the connection to the particular overall work order to

which it was charged or they had a document that did not provide sufficient description of the

work” for four particular invoices, so Mr. Peterson disallowed these damages. Id. at 2992.

As to the second category of challenged damages, Plaintiffs and Defendant agree that

documentation of the actual percentage rate that Entergy used as a capital suspense loader was

not available for the time period of 1996 through June 1998. Id. at 1955, 2985; DDX 6 at 16.

Mr. Peterson challenged capital suspense costs for the first half of 1998 because he could not

determine that the rate was properly applied. Tr. 2987-88. Before this time, the rate was

apparently 0%. Id. at 2988.

40

The total amount of allegedly unsupported transactions consists of $1,039,261 in

transactions missing documentation, $164,267 in transactions missing capital suspense rate

information, and $285,198 in transactions with missing discovery responses. DDX 6 at 6.

40

Discussion

Damages for Partial Breach of Contract

The remedy for breach of contract is an award of “damages sufficient to place the injured

party in as good a position as it would have been had the breaching party fully performed.”

Indiana Michigan Power Co., 422 F.3d at 1373. Mitigation damages are intended to reimburse a

non-breaching party to a contract for the expenses it incurred in attempting to rectify the injury

caused by the breach. In particular, mitigation damages are available to compensate plaintiffs for

“efforts to avoid damages in contemplation of a partial breach.” Id. at 1375 (“Mitigation is

appropriate where a reasonable person, in light of the known facts and circumstances, would

have taken steps to avoid damage.”); see generally Restatement (Second) of Contracts § 347 cmt.

c (Am. Law Inst. 1981) (“[T]he injured party is entitled to recover for all loss actually suffered . .

. includ[ing] costs incurred in a reasonable effort, whether successful or not, to avoid loss.”).

Damages should not place the non-breaching party “in a better position . . . than if there had been

no breach.” Bluebonnet Sav. Bank, FSB v. United States, 339 F.3d 1341, 1345 (Fed. Cir. 2003)

(per curiam) (“Bluebonnet II”); see also San Carlos Irrigation & Drainage Dist. v. United States,

111 F.3d 1557, 1563 (Fed. Cir. 1997). Damages for a breach of contract are recoverable if they

were reasonably foreseeable, were substantially caused by the breach, and are shown with

reasonable certainty. Indiana Michigan Power Co., 422 F.3d at 1373.

Plaintiffs may recover damages for partial breach of the Standard Contract if they can

show that “but for the breach, the alleged damages would not have been suffered.” San Carlos

Irrigation & Drainage Dist., 111 F.3d at 1563. The Federal Circuit has expressed a preference

for the traditional “but-for” test in spent nuclear fuel cases. See Yankee Atomic, 536 F.3d at

1272-73. Although a plaintiff must show that the claimed losses “would not have occurred but

for the breach,” the breach need not be the sole cause of the incurred damages. Cal. Fed. Bank v.

United States, 395 F.3d 1263, 1268 (Fed. Cir. 2005); Anchor Sav. Bank, FSB v. United States,

81 Fed. Cl. 1, 60 (2008).

Plaintiffs must present a “comparison between the breach and non-breach worlds.”

Yankee Atomic, 536 F.3d at 1273. The plaintiff bears the burden of proving “the extent to which

his incurred costs differ from the costs he would have incurred in the non-breach world.” Energy

Northwest III, 641 F.3d at 1306. Therefore, “a plaintiff seeking damages must submit a

hypothetical model establishing what its costs would have been in the absence of breach.” Id. at

1305 (citing Glendale Fed. Bank, FSB v. United States, 239 F.3d 1374, 1380 (Fed. Cir. 2001)

(“Glendale I”)). “It is only by comparing this hypothetical ‘but-for’ scenario with the parties’

actual conduct that a court can determine what costs were actually caused by the breach, as

opposed to costs that would have been incurred anyway.” Id. (citing Glendale I, 239 F.3d at

1380); see also Yankee Atomic, 536 F.3d at 1273.

To show damages with reasonable certainty “it is not essential that the amount [of

damages] be ascertainable with absolute exactness or mathematical precision: ‘It is enough if the

evidence adduced is sufficient to enable a court or jury to make a fair and reasonable

approximation.’” Bluebonnet Sav. Bank, FSB v. United States, 266 F.3d 1348, 1355 (Fed. Cir.

2001) (“Bluebonnet I”) (quoting Elec. & Missile Facilities, Inc. v. United States, 189 Ct. Cl. 237

(1969)). A recovery for speculative damages is precluded. Indiana Michigan Power Co., 422

41

F.3d at 1373; see also Glendale Fed. Bank, FSB v. United States, 378 F.3d 1308, 1313 (Fed. Cir.

2004) (“Glendale II”).

“[T]the defendant may eliminate or reduce the alleged damages by showing either that

the ‘[p]laintiffs did not undertake reasonable mitigation efforts, or that the efforts they did

undertake were unreasonable.’” Entergy Nuclear Vt. Yankee, LLC v. United States, 95 Fed. Cl.

160, 184 (2010), aff’d in part, rev’d in part on other grounds sub nom. Vt. Yankee Nuclear

Power Co. v. Entergy Nuclear Vt. Yankee, LLC, 683 F.3d 1330 (Fed. Cir. 2012) (citing Carolina

Power & Light Co. v. United States, 82 Fed. Cl. 23, 44 (2008)) (alteration in original).

Reracking Costs

Plaintiffs claim $8,490,310 in mitigation damages for the spent fuel pool rerack,

exclusive of the associated payroll loaders for Resource Codes 19 and 60 and allegedly

unsupported transactions. Plaintiffs began planning for the rerack in 1995-96, and the rerack was

accomplished in November 1998, and prevented loss of full core reserve in 2000. Plaintiffs

argue that Defendant’s breach caused them to rerack because in the non-breach world, they

would have avoided infringing on full core reserve in 2000, by using allocations from Pilgrim

and Indian Point 3 from 2000 until 2006, when DOE would have picked up fuel from Waterford

3. The Court rejects this argument, finding that the breach was not the but-for cause or even a

substantial factor in Entergy’s decision to rerack. Although Entergy knew that DOE would not

likely perform as early as 1993, DOE was not scheduled to pick up spent nuclear fuel from

Waterford 3 until 2006. Entergy had a much more pressing need to rerack well in advance of

2006, due to its loss of full core reserve in 2000.

Consistent with their philosophy and conduct in the actual world, the Waterford 3

employees would have been prudent planners, who would have started considering whether a

rerack was necessary five years in advance of losing full core reserve. Waterford 3 would have

needed to produce Strategic and Tactical Plans for overall management of the front and back end

of the fuel cycle, even with DOE performance. The Court finds that in the 1995-96 timeframe,

Entergy would have analyzed how to deal with spent fuel at Waterford 3, in exactly the same

way in the non-breach world as it did in the breach world – the plant management would have

determined that reracking was the most economical and beneficial solution, as opposed to

shipping fuel to DOE, using dry fuel storage at another Entergy plant or at an Indian reservation,

or constructing a dry fuel storage facility at Waterford. JX 6 at 7844.

The record reflects that a key concept used in making fuel storage decisions at Waterford

was maintaining full core reserve or full core discharge capability. This “important planning

concept” meant maintaining enough space in the spent fuel pool to discharge all the fuel

assemblies from the reactor core – 217 assemblies at Waterford. Tr. 100. The purpose of

maintaining full core reserve was to ensure that all of the fuel could be removed from the reactor

to allow for inspection or maintenance. Id. at 101. Waterford attempted to have full core reserve

“at all times.” Id. at 100. Waterford occasionally infringed on full core reserve, but the plant

would work hard to avoid this state. Id. 101-02, 194. Maintaining full core reserve was not a

regulatory or an operating requirement, but “a target” and “prudent planning” because there

might be times when the reactor had to be completely emptied of fuel. Id. at 102-03. Without

being able to perform unscheduled repairs or inspections, the plant could not be restarted, which

would cost between $500,000 to $1 million a day in replacement power costs. Id. at 103-04.

42

Additionally, if there were no room in the spent fuel pool to unload old fuel from the reactor, the

reactor could not be refueled and would be unable to operate. Id. at 105-06.

Given this key concept, the plant managers would not have wanted to lose full core

reserve in the non-breach world. In the mid-1990s, the plant managers recognized that after

2000, two additional fuel cycles could occur without full discharge capability, but the plant

would have to shut down in 2004, because it would run out of space in the spent fuel pool. Id. at

465. As seen in a September 1996 chart, Waterford 3 had projected its discharges and space in

the spent fuel pool until the end of the reactor’s license in 2024. JX 30 at 0318. The plant could

thus predict that when cycle 10 ended in July 2000, there would be 892 assemblies in the spent

fuel pool, impinging on full core reserve. Id. By the end of 2004, the total number of assemblies

would be over the 1,088 space upper limit. At the end of cycle 11 in April 2002, there would be

992 assemblies in the pool and by the end of cycle 12 in April 2004, 116 assemblies would need

to be discharged, taking up the remaining space in the pool and preventing the plant from

continuing operations. Id.

The Court finds that this rerack would have been implemented as soon as practicable to

avoid the loss of full core reserve in 2000, even in the non-breach world. In the breach world,

the plant managers started to consider the rerack project in 1993, and began to plan it in earnest

in 1995-96. In January 1996, the plant decided to take bids on reracking, eliminating other

options such as dry fuel storage, both on site and in other locations, and transporting spent fuel

directly to DOE. JX 6 at 7845. In May 1996, the plant put out a request for bids for the rerack

project and reviewed those bids in September 1996. JX 30 at 0315, 0321. Waterford 3 signed a

contract with Holtec in 1996 and anticipated the rerack work being completed in July 1998 based

on the schedule put forth by Holtec. Tr. 2518. In the breach world, the plant managers were

aware that an NRC license amendment would be needed and would take one year to be

approved. JX 30 at 0321. They also anticipated that a rerack would take two years to be

completed. Id. at 0320. Entergy submitted its license amendment in March 1997, and requested

that it be approved by January 1998, to support a rerack completion date of July 1998. JX 8 at 1.

However, it was not approved until July 10, 1998, and Entergy’s management approved the

design change package for the rerack to allow changes to be made to the Waterford 3 plant on

July 23, 1998. Tr. 459, 2536; PX 1036 at 2540. This design change package stated that the

rerack needed to occur before the end of fuel cycle 9, scheduled for October/November 1998,

because otherwise there would be too many assemblies in the pool to permit reracking to be done

using divers - - a significant cost benefit over using a remotely operated tool. PX 1036 at 2553-

54; Tr. 2519. The installation of the new Holtec racks was completed in November 1998. Thus,

the rerack project from initial planning until completion, spanned two years and eleven months,

from December 1995 until November 1998.

Additionally, reracking would have helped the plant to deal with its boroflex degradation

issue. While not the sole reason for the rerack, removing the boroflex would have been a useful

benefit that would have militated in favor of reracking, as it did in the breach world. Therefore,

given the known constraints that would still have been applicable in the non-breach world – the

2000 full core reserve loss, the 2006 DOE pickup date, the boroflex issue, and the awareness that

a rerack needed to be started well ahead of time – the Court finds that the rerack would have

occurred in the non-breach world and was not caused by the Government’s partial breach.

43

Plaintiffs creatively attempt to eliminate the fact of Waterford 3’s 2000 loss of full core

reserve by arguing that they would have avoided infringing on full core reserve by using

allocations from Pilgrim and Indian Point 3 from 2000 until the DOE pick up in 2006. Plaintiffs’

exchange allocation construct is squarely defeated by the chronology here. In 1995-96,

Waterford had to plan how to deal with its upcoming loss of full core reserve as of 2000, whether

via rerack or another strategy. At that time, the Pilgrim and Indian Point 3 acquisitions were not

yet on the horizon. Therefore, Mr. Metcalfe testified that Waterford would have considered

obtaining allocation rights from ANO as a temporary placeholder in his hypothetical non-breach

world. Tr. 1196-97. The Court, however, struck Mr. Metcalfe’s testimony that Plaintiffs would

have relied upon ANO’s allocations as being a surprise, and also noted that it was bereft of the

detail that would have made this aspect of Mr. Metcalfe’s but-for world plausible - - what plans

Waterford and ANO would have made, what ANO’s plans for a rerack or ISFSI were, what the

costs would have been, and why projecting to use ANO’s allocations was a plausible choice

given Waterford’s other options.

Even considering Mr. Metcalfe’s testimony on using ANO’s allocations, the Court does

not credit Mr. Metcalfe’s opinion that Waterford 3 could have avoided the rerack by using

allocations from Pilgrim and Indian Point 3 starting in 2000. To prove causation, it is incumbent

upon plaintiffs to establish a plausible but-for world. See Yankee Atomic, 536 F.3d at 1273

(citing Bluebonnet Sav. Bank FSB v. United States, 67 Fed. Cl. 231, 238 (2005)). Simply put,

Waterford 3 decision-makers would not have been aware that Entergy would later own these

plants when Waterford 3 would have been making its reracking decision in 1995-96. Any

reliance on these allocations is thus not plausible. The sale of Pilgrim, the plant needed for

allocations in 2000, was competitively bid and hence Entergy could not have counted on owning

the plant ahead of the sale. Tr. 166. Even if some “due diligence” might have occurred prior to

July 1999, when Entergy acquired Pilgrim, Waterford 3 could not have reasonably planned to

use those allocations. Under the Standard Contract, the necessary forms for exchanges had to be

submitted to DOE not less than six months prior to the delivery date, to use Pilgrim’s allocations

until Entergy actually owned Pilgrim.

Although DOE would be performing in the non-breach world, the spent fuel would have

been collecting inside the spent fuel pool prior to DOE’s first scheduled pick up at Waterford 3

in 2006. The Court does not find it plausible, as Plaintiffs suggest, that Waterford 3 would have

taken a “wait and see” approach, doing nothing but hoping to obtain some allocations from other

Entergy plants or other utilities before losing full core reserve in 2000, or waiting beyond 2000

to make a decision. Pls.’ Post-Trial Reply Br. 13.

The Court Denies Plaintiffs’ Cask Loading Costs

Plaintiffs claim $3,966,282 in costs incurred to load spent nuclear fuel into dry storage

casks at Waterford 3. Defendant asserts that Plaintiffs cannot recover these costs because they

would have paid these costs in the non-breach world and because they have not proven how the

non-breach world loading costs would differ from the breach world costs. Def.’s Post-Trial Br.

35-42. In response, Plaintiffs contend that Defendant seeks an “offset” to Plaintiffs’ damages

under an “avoided cost” theory. However, the Government emphasizes that it is not arguing that

Plaintiffs avoided the cask loading costs due to DOE’s breach and hence is not seeking an offset,

for which it must shoulder the burden of proof. Id. at 41.

44

Plaintiffs rely on Carolina Power & Light Co. v. United States, 573 F.3d 1271 (Fed. Cir.

2009) (“Carolina Power”). In that case, the Government argued that Plaintiffs’ claim should be

reduced by cask loading costs that they had avoided due to the Government’s breach. Carolina

Power, 573 F.3d at 1277. However, the Federal Circuit disagreed and held that the Government

was not entitled to offset Plaintiffs’ damages with cask loading costs because Plaintiffs had not

actually avoided these costs due to the Government’s breach. Rather, the Court found that

Plaintiffs will not incur these costs until DOE picks up the spent nuclear fuel. Id. The Federal

Circuit rejected the Government’s “avoided cost” theory because “‘[j]ust as the utilities cannot

now collect damages not yet incurred under the ongoing contract, the [G]overnment cannot

prematurely claim a payment that has not become due.’” Id. (quoting Yankee Atomic, 536 F.3d

at 1281).

As the Federal Circuit explained in Energy Northwest III:

Carolina Power addresses the separate circumstance where a breaching party

seeks to offset an award by proving that the non-breaching party has achieved

some cost savings because the breach permitted it to avoid—not just defer—some

aspect of performance. Carolina Power properly urges caution when speculating

about the future in a case of partial breach—usually, the proper approach is to

wait for those events to actually occur, and to resist premature conclusions.

641 F.3d at 1306-07 (citing Carolina Power, 573 F.3d at 1277). The Government was not

seeking an offset for avoided costs in Energy Northwest III, but instead argued that the plaintiff

had not proven that certain site modification costs differed from those in the non-breach world.

The Federal Circuit found that the plaintiff was entitled to recover the cost of those modifications

only to the extent that it could prove “to a reasonable certainty, that but for the [G]overnment’s

breach they would not have been incurred.” Id. at 1305-07.

Plaintiffs attempt to distinguish Energy Northwest III on the basis that it discussed plant

modifications instead of cask loading costs. Pls.’ Post-Trial Br. 50-51. However, Plaintiffs do

not point to any case exempting cask loading costs from the Federal Circuit’s well established

requirement that a utility present a “comparison between the breach and non-breach worlds.”

Yankee Atomic, 536 F.3d at 1273. Here, as in a subsequent Energy Northwest case, “the Court

has no principled basis (nor have plaintiffs offered one) for treating ‘cask loading’ differently

from the ‘plant modification costs’ at issue in [Energy Northwest III] . . . .” Energy Nw. v.

United States, 115 Fed. Cl. 69, 76 (2014); see also Ala. Power Co. v. United States, 119 Fed. Cl.

615, 629 (2014) (holding that because plaintiffs failed to prove that their incurred fuel

characterization and loading costs would not have been incurred in the non-breach world,

plaintiffs were not entitled to recovery for these costs); Sys. Fuels, Inc. v. United States, 120 Fed.

Cl. 635, 660-62 (2015) (“Grand Gulf II”) (denying plaintiffs’ cask loading costs because

plaintiffs failed to establish the costs of using DOE casks and acknowledged that these costs

would have been incurred even with DOE performance).

Similarly, in the instant case, the Government is not seeking an offset, it is claiming that

Plaintiffs failed to their meet their burden of proving what their cask loading costs would have

been in the non-breach world. As with their other claimed damages, Plaintiffs must prove the

extent to which their incurred costs differ from the costs they would have incurred in the non-

breach world. See Energy Northwest III, 641 F.3d at 1306. Plaintiffs here have proffered no

45

evidence, however, as to how their incurred costs differ from the cask loading costs they would

have incurred in the non-breach world.

Plaintiffs’ technical expert, Ms. Supko, did not identify any cask loading costs that would

have been incurred had DOE picked up the spent nuclear fuel as scheduled. As Ms. Supko stated

in her expert report:

At counsel’s direction, I have not attempted to assess any costs that may have

been incurred by Entergy to load DOE transportation casks in the non-breach

world. I further understand from counsel that consideration of such non-breach

world loading costs has been foreclosed as a matter of law by the U.S. Court of

Appeals for the Federal Circuit in Carolina Power & Light Co. v. United States,

573 F.3d 1271 (Fed. Cir. 2009).

PX 1 at 1. Although Ms. Supko identified several plausible DOE transportation casks that

allegedly could have been used at Waterford 3, and presented a detailed scenario of how such

casks could have been loaded, she did not perform any analysis of the costs to load any of these

plausible DOE transportation casks. Id. at 29-30; Tr. 1622.

Plaintiffs argue that any failure to construct a model of the non-breach world was caused

by the Government’s failure to provide useful information in discovery about the type of cask

that DOE would have used. The Court, however, does not find that DOE obstructed Plaintiffs’

discovery efforts. As Ms. Supko noted in her expert report, DOE at first planned in the 1980s to

develop its own fleet of transportation casks, but stopped obligating funds to this development

program in 1993, without ever submitting a cask to the NRC for certification. PX 1 at 19. Even

without additional information about a cask that DOE would have used in the non-breach world,

Ms. Supko was able to describe, in detail, several plausible casks that could have been used at

Waterford 3, including their height, weight, and capacity. Id. at

This text is long and has been trimmed here. Open the source document for the complete record.