Southern Nuclear Operating Co. v. United States

77 Fed. Cl. 396, 37 Envtl. L. Rep. (Envtl. Law Inst.) 20190, 65 ERC (BNA) 1713, 2007 U.S. Claims LEXIS 220, 2007 WL 2005164

• Court: United States Court of Federal Claims
• Decided: July 9, 2007
• Docket: No. 98-614C
• Status: Published

Opinion

OPINION

MEROW, Senior Judge.

Two nuclear utilities seek damages for the failure of the United States Department of Energy (“DOE”) to commence performance of its contract to accept, transport and dispose of their spent nuclear fuel (“SNF”).¹ Because of DOE’s delay in commencement of performance, these utilities have incurred enormous expenses to construct additional storage for their SNF, passed on to their customers along with the some $825 million in fees plaintiffs have paid under the contract as of 2004. (Tr. 251 (Cocherell).)

The court has jurisdiction over plaintiffs’ claims. PSEG Nuclear, L.L.C. v. United States, 465 F.3d 1343 (Fed.Cir.2006) (holding that the Nuclear Waste Policy Act (“NWPA”) did not strip the court of its Tucker Act jurisdiction over claims arising out of the Standard Contract). Partial breach has been established. Indiana Michigan Power Co. v. United States, 422 F.3d 1369, 1372-73 (Fed.Cir.2005) (finding DOE liable for breach of contract); Maine Yankee Power Co. v. United States, 225 F.3d 1336, 1342 (Fed.Cir.2000), aff'g Yankee Atomic Elec. Co. v. United States, 42 Fed.Cl. 223 (1998) (DOE’s failure to begin performance by January 31, 1998 was a partial breach and “[t]he breach involved all the utilities that had signed the contract—the entire nuclear electric industry.”). Accordingly, the court granted plaintiffs’ motion for partial summary judgment on liability for partial breach of contract. “There is no dispute concerning the fact that the United States, operating through the DOE, failed to meet the contractual requirement to begin disposition of the nuclear waste covered by the Standard Contracts by no later than January 31, 1998.” (Order, Apr. 7, 2004, Dkt. 234, 5.)

The Federal Circuit held in Indiana Michigan, that while nuclear utilities could not recover their forecasted future costs of storing SNF that DOE contracted to remove, appropriately established and incurred mitigation expenses were recoverable. On September 15, 2005, the parties agreed that trial in this matter would be limited to costs incurred through December 31, 2004. On September 16, 2005, the court ordered that “[t]he scope of the trial proceedings in this matter will comprise damage evidence up to and including December 31, 2004.” (Order, Sept. 16, 2005, Dkt. 304, 2.) Plaintiffs’ Amended and Supplemental Complaint for damages through December 31, 2004 was deemed filed as of October 11, 2005. (Order, Oct. 26, 2005, Dkt. 315.) After a lengthy trial, the parties submitted post-trial briefs.² Oral argument and supplemental briefing followed.

Introduction

Following the enactment of the NWPA, Pub.L. No. 97-425, 96 Stat. 2201 (Jan. 7, 1988) (codified at 42 U.S.C. §§ 10101-10270), plaintiffs, along with all domestic nuclear electrical utilities, signed Standard Contracts with DOE wherein, in return for the utilities’ payment of substantial fees, DOE would accept title to designated SNF at the reactor sites, and transport and dispose of the utilities’ SNF, starting on or before January 31, 1998. DOE did not commence performance by January 31, 1998 as required by the NWPA and the Standard Contracts. While DOE insists there will be performance, the forecasted inauguration continues to recede from 2003, to 2010, to 2017, and to 2018, the latest prognosis.

Standard Contracts were signed by plaintiffs Georgia Power Company (“GPC”) and Alabama Power Company (“APC”). APC owns Plant Farley. GPC holds a majority interest in Plants Hatch and Vogtle.³ Each of the these electrical plants have two nuclear reactors. (Tr. 134 (Long).) Hatch Unit 1 began operation in 1974; Unit 2 in 1978. Farley Units 1 and 2 started in 1977 and 1981, and Vogtle in 1987 and 1989. Plaintiff Southern Nuclear Operating Company (“SNC”) operates the plants and is agent for APC and GPC on matters relating to the Standard Contracts. (Tr. 126-27 (Long).) SNC, APC and GPC are subsidiaries of the Southern Company, a holding company. (Tr. 126 (Long).)

Plaintiffs seek reimbursement of their actual costs spent mitigating DOE’s delays. Rather than allow their spent fuel pools to completely fill with SNF, which would result in shutting down their reactors, replacing that source of electricity at a much higher cost, plaintiffs decided to incur the relatively lesser expense of additional on-site storage. Substantial costs (the amounts of which are mostly not disputed) were incurred to design, engineer, license, construct, install, load, operate and maintain this additional storage. As described in more detail hereinafter, at Plant Hatch, an Independent Spent Fuel Storage Installation (“ISFSI”), consisting of four highly-engineered concrete pads, each with a capacity to hold twelve dry SNF storage casks, was built. By December 31, 2004, twenty-two casks were purchased, loaded with SNF and placed on the pads. Construction of Plant Farley’s ISFSI began in 2000, and as of December 31, 2004, three dry SNF storage casks were purchased but had not been loaded. From 1998 to 2000, Plant Vogtle procured and installed racks to increase the capacity of its spent fuel pool. The actual costs of these mitigation measures are sought in this action.

Upon careful consideration of testimony, argument, documents and exhibits, the court concludes that plaintiffs incurred substantial costs in mitigating DOE’s acknowledged, continuing and substantial delay in commencement of performance—a partial breach of contract, which was a substantial causal factor in these mitigating storage decisions and of the reasonable costs thereof, and that but for the delay, these expenditures would not have been incurred. The court finds that, in the main, those mitigation decisions and costs were foreseeable and reasonable.

• A brief discussion of the generation of nuclear power provides background for the court’s findings and conclusions. Uranium oxide pellets (little finger-sized) are placed into 12-14 foot metal rods and bundled into assemblies, approximately nine inches square. Assemblies are placed in the reactor core, where fission produces heat, which is converted to steam, which drives turbines and generates electricity. (Tr. 142 (Long).) Nuclear-generated power constitutes 16 percent of the total electricity used by plaintiffs’ some four million customers⁴ and is their most cost efficient and emission-free form of electrical generation. (Tr. 136 (Long).) Louis Long, SNC Vice President, with 35 years of nuclear power generation experience, testified about the importance of these nuclear plants and set the stage for the mitigating decisions discussed herein:⁵

A. [T]he Southern system has a system that’s about 40,000 megawatts total. In that system, power is generated from basically four different sources. One is our coal plant. That’s our largest ... about 69 percent of the power that’s generated by the Southern Company comes from the coal plants. [Sixteen] percent, the second largest generator of electricity in the Southern system is out of our nuclear plants. And then we also have about 12 percent comes from gas and then about 3 percent comes from hydro. So nuclear is the second largest generator of electricity on the Southern system. The importance, though, is really relative to the cost of electricity out of those four sources. And the amount of time that each of these plants will run. Basically, nuclear is the cheapest production cost of any plant out of our system. They are the most valued from an economic viewpoint. We run our nuclear power plants 24 hours a day, seven days a week, as long as we can run them.

[O]ur nuclear plants, because they are the cheapest, run all the time.... The other additional benefit that nuclear has is there are no emissions associated with its generation, no SO2, no nitrous oxide, and no particulates, no mercury---- [N]uclear is quite candidly the ... best source of generation we have both in terms of cost and emission for our system.

(Tr. 135-38 (Long).)

After four to six years, the uranium in the reactor becomes somewhat depleted or “spent,” meaning it becomes relatively inefficient for producing electricity. The reactor is shutdown and assemblies (or rods) containing SNF are removed from the core, replaced with “fresh” fuel. The SNF is placed in basket-like racks in adjacent pools filled with treated water to protect against radioactivity. The pools are monitored with highly sophisticated devices to protect the workers and the environment. With rotational planning, generally about one-third of the core is removed during these scheduled refueling shutdowns.

Plaintiffs’ wet pools are about 30 by 40 feet and 40 feet deep, made of concrete and lined with stainless steel. When SNF is removed from the reactor core, it is still capable of attaining criticality. Transporting rods in or out of the reactor core, or in and out of the wet pool, is a complex, expensive and highly regulated process. See Twp. of Lower Alloways Creek v. Pub. Serv. Elec. & Gas Co., 687 F.2d 732, 737 (3rd Cir.1982). Storage, and most activities in and around the plant, are regulated by the NRC. See generally 10 C.F.R. pts. 72-73 (2007).

The reactor core can hold only a limited number of assemblies. The size and configuration of the spent fuel pool and racks constrain the amount of SNF that can be stored there. Storage need is triggered by the removal of either “spent” fuel or damaged assemblies from the reactor core, in both instances replaced with fresh fuel. Also, repair or inspection of the core requires removal of all the fuel. “Pool capacity” refers to the maximum number of assemblies that can be stored in the pool. “Full core reserve capability” (“FCR”) is the maintenance of sufficient unused space in the pool for all the assemblies in the reactor core. FCR is necessary to accommodate the discharge of the entire reactor core for inspection, maintenance or repair of the reactor. Pool space is also needed to maneuver and store radioactive tools. While the NRC does not require FCR, it is preferred. A reactor with a completely full pool faces shutdown. “Rerack-ing” is the use of higher density racks, with a tighter configuration, allowing more SNF to be stored in the pool. Due to increasing efficiencies in utilizing reactor core uranium, the time between refueling discharges has increased over the years.

The two nuclear reactors at both Plants Hatch and Vogtle share one pool. Each of the two reactors at Farley have their own pool. The shared pool at Plant Hatch contains a rectangular section, referred to as the “bathtub” area, used for the operation and storage of neutron monitoring instruments and tools.

Historically, the disposal of SNF and high-level waste (“HLW”) from the commercial production of nuclear power has been a federal responsibility. See Florida Power & Light Co. v. Westinghouse Elec. Corp., 826 F.2d 239, 244 (4th Cir.1987) (discussing President Eisenhower’s Atoms-for-Peace Program, the passage of the Atomic Energy Act and other pre-NWPA history). During the 1970s, when these plants were licensed (for a base term of 20 years with the possibility of renewals) and constructed, SNF was “reprocessed” off-site. See Yankee Atomic Elec. Co. v. United States, 73 Fed.Cl. 249, 253-55 (2006) (summarizing history in this regard). As a result, wet pools constructed prior to 1977 were not designed to store all SNF generated during the life of the plant. In 1977, President Carter effectively halted reprocessing. Id. Absent removal and reprocessing for another use off-site, wet pools were the only existing place for plaintiffs to store their SNF. Lack of capacity in the Plant Hatch and Plant Farley wet pools mandated the construction of dry storage facilities as the wet pools approached their limits. The Vogtle Plant reactors were licensed and constructed after reprocessing was banned and after the implementation of the NWPA. Accordingly, the Plant Vogtle wet pool has larger storage capacity.

The 1983 passage of the NWPA reaffirmed federal responsibility “to provide for the permanent disposal of high-level radioactive waste and such spent nuclear fuel as may be disposed of in order to protect the public health and safety and the environment.” 42 U.S.C. § 10131(a); Indiana Michigan, 422 F.3d at 1372. The NWPA contained a series of milestones prior to DOE’s mandated commencement of performance no later than January 31, 1998. The NWPA directed the Secretary of Energy to find an appropriate repository site, 42 U.S.C. §§ 10132-10133, and following Presidential and Congressional approval of that selection, proceed with construction authorization through the NRC. Id. §§ 10134-10135. A 1987 amendment directed the Secretary to select Yucca Mountain in Nevada as the repository site. 42 U.S.C. § 10172. In the event Yucca Mountain proved unsuitable, DOE was directed to terminate site-specific activities and report to Congress. 42 U.S.C. § 10133(e)(3).

The NWPA authorized DOE to enter into contracts with nuclear utilities for the acceptance, transportation and disposal of SNF. Indiana Michigan, 422 F.3d at 1372 (citing 42 U.S.C. § 10222 (2000)). The Act required that the contracts provide that:

(A) following commencement of operation of a repository, the Secretary shall take title to high-level radioactive waste or spent nuclear fuel involved as expeditiously as practicable upon the request of the generator or owner of such waste or spent fuel; and

(B) in return for the payment of fees established by this section, the Secretary, beginning not later than January 31, 1998, will dispose of the high-level radioactive waste or spent nuclear fuel involved as provided in this subehapter.

42 U.S.C. § 10222(a)(5).

Under the Standard Contract, fees paid by the utilities were deposited into the Nuclear Waste Fund (“NWF”).⁶ Entry into contracts was effectively mandatory. “Nuclear plant operators and utilities were mandated by Congress to enter into Standard Contracts, the terms of which are presented at 10 C.F.R. § 961.11, as a prerequisite to obtaining renewal of their operating licenses.” Indiana Michigan, 422 F.3d at 1372 (citing 42 U.S.C. § 10222(a)(1)); Maine Yankee, 225 F.3d at 1337 (“The [NWPA] effectively made entry into such contracts mandatory for the utilities.”); Tr. 461-62 (Hunt).

Plaintiffs have paid approximately $850 million in fees into the NWF as of December 31, 2004 and payments continue. (Tr. 251 (Cocherell).) In the aggregate, nuclear utilities have paid over $20 billion into the NWF. Yankee Atomic Elec. Co. v. United States, 73 Fed.Cl. 249, 256 n. 8 (2006). In the end, “DOE was exclusively responsible for SNF collection and disposal in the United States, thereby prohibiting Indiana Michigan or any other nuclear utility from seeking alternative disposal means.” Indiana Michigan, 422 F.3d at 1374 (citing 42 U.S.C. § 10131(a)(4), (b)(2)).

Notwithstanding the foregoing, the repository at Yucca Mountain remains unbuilt and commencement of contract performance is further out on the horizon. The “best-achievable” date is 2017. Statement of Edward P. Sproat III, Director, Office of Civilian Radioactive Waste Management (“OCRWM”), before the Subcommittee on Energy and Air Quality, Committee on Energy and Commerce, United States House of Representatives, July 19, 2006, available at www.ocrwm.doe/gov/infoJibrary/program_ does/testimonies/July_19_Sproat-testimony. pdf (last visited May 17, 2007). That date may slip to 2018. Sproat Statement before the Senate Appropriations Subcommittee on Energy and Water Development, March 7, 2007, available at www.ocrwm.doe.gov/ welcome/index.shtml (last visited May 17, 2007). See also Def.’s Ans. to Second Am. Compl. and Supplemental Compl. 11 in System Fuels, Inc. v. United States, No. 03-2624 (Fed.Cl.), Dkt. 125, filed Jan. 30, 2007 (citing Statement of OCRWM Director Sproat before Subcommittee Clean Air, Climate Change and Nuclear Safety, Committee on Environment and Public Works, United States Senate, September 14, 2006, that DOE planned to initiate repository operations in 2017).

Damages:

Faced with DOE’s impending delay in commencement of performance detailed hereinafter, and mindful of long lead times for approval and implementation of storage options required to continue operations, plaintiffs assert their decisions to increase storage, the implementation of those decisions and the reasonable costs thereof were necessary, foreseeable and caused by DOE’s partial breach, and are accordingly, recoverable. Plaintiffs also contend defendant did not meet its burden to establish either that these decisions, their implementation or cost, were unreasonable.

In addition to asserting plaintiffs did not meet their burden of establishing foreseeability, causation and reasonable certainty in amounts, defendant argues plaintiffs have another burden—to establish that their mitigation costs would not have been incurred if DOE had performed in the so-called non-breach world. Otherwise plaintiffs would have a windfall, defendant insists. In that nonbreach world, defendant asserts DOE would have performed at an annual rate of around 900 metric tons of uranium (“MTU”), and at that rate, plaintiffs would have incurred some, but not all, of the costs sought in damages here; consequently, it is argued, that an award of the damages claimed would put plaintiffs in a better position than if DOE had commenced performance.

Plaintiffs urge the court to find that DOE would or should have performed in the non-breach world at an annual rate of 3000 MTU. At that level, there would not be a windfall— DOE would have removed more SNF than plaintiffs have actually placed in storage; accordingly, by reimbursing the costs as sought herein, plaintiffs would not be better off than if DOE had performed. Plaintiffs also contend they need not establish precisely how much SNF DOE would have removed and when. Rather, plaintiffs assert their decisions to construct dry storage at Plants Hatch and Farley, and rerack at Plant Vog-tle, were reasonably foreseeable, caused by DOE’s acknowledged breach and were reasonable mitigating reactions, the costs of which were shown with reasonable certainty.

“The remedy for breach of contract is 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, 422 F.3d at 1373 (citing San Carlos Irrigation & Drainage Dist. v. United States, 111 F.3d 1557, 1562 (Fed.Cir. 1997)). “ ‘The general principle is that all losses, however described, are recoverable.’ ” Id. (quoting Restatement (Second) of Contracts § 347 cmt. c).

Mitigation was required. As the Federal Circuit made clear in Indiana Michigan, by 1994 when DOE formally and publicly announced it was not going to initiate performance by January 31, 1998, nuclear utilities were obligated to mitigate.

In 1994, DOE announced that it would not begin SNF collection until 2010 because its planned storage repository would not be ready until then. Notice of Inquiry, Office of Civilian Radioactive Waste Management: Waste Acceptance Issues, 59 Fed. Reg. 27,007-27,008 (May 25, 1994). One year later, DOE asserted that it had neither a statutory nor contractual obligation to accept the utilities’ nuclear waste in the absence of such repository or temporary storage facility. Maine Yankee, 225 F.3d at 1338 (citing Final Interpretation of Nuclear Waste Acceptance, 50 Fed.Reg. 21,-793 (1995)).

422 F.3d at 1372. Accordingly, “[i]t is beyond debate that because the government unequivocally announced in 1994 that it would not meet its contractual obligations beginning in 1998, the utilities were in fact obligated to take mitigatory steps.” Id. at 1375. Indiana Michigan’s determination that mitigation was required by 1994 was based on DOE’s public and formal announcement of delay. “ ‘[0]nce a party has reason to know that performance by the other party will not be forthcoming, ... he is expected to take such affirmative steps as are appropriate in the circumstances to avoid loss by making substitute arrangements or otherwise.’” Id. (quoting Restatement (Second) of Contracts § 350 cmt. b). “Mitigation is appropriate where a reasonable person, in light of the known facts and circumstances, would have taken steps to avoid damage.” Id. (citing Robinson v. United States, 305 F.3d 1330, 1334 (Fed.Cir.2002)).

Generally mitigation, or more precisely, the failure to mitigate, reduces consequential damages awarded to a nonbreaching party. “The amount of loss that [the non-breaching party] could reasonably have avoided by ... making substitute arrangements or otherwise is simply subtracted from the amount that would otherwise have been recoverable as damages.” Restatement (Second) of Contracts § 350 cmt. b. Similarly, “ ‘mitigation damages’... are intended to reimburse a non-breaching party to a contract for the expenses it incurred in attempting to rectify the injury the breach caused it.” Citizens Fed. Bank v. United States, 474 F.3d 1314, 1320 (Fed.Cir.2007) (citing Restatement (Second) of Contracts § 347 cmt. c). “[W]e see no reason why efforts to avoid damages in contemplation of a partial breach should not also be recoverable.” Indiana Michigan, 422 F.3d at 1375.

The admitted obligation to mitigate DOE’s delays does not, however, end the inquiry. “The presence of a duty to mitigate does not perforce make the pre-breach costs incurred by Indiana Michigan to store its SNF recom-pensable; [Indiana Michigan] must prove foreseeability, causation, and reasonableness.” Indiana Michigan, 422 F.3d at 1376. Accordingly, “damages are recoverable where: (1) the damages were reasonably foreseeable by the breaching party at the time of contracting; (2) the breach was a substantial causal factor in the damages; and (3) the damages are shown with reasonable certainty.” Id. at 1373 (citing Energy Capital Corp. v. United States, 302 F.3d 1314, 1320 (Fed.Cir.2002)).

Mitigation costs must have been “reasonably foreseeable by the breaching party at the time of contracting.” Indiana Michigan, 422 F.3d at 1373. That plaintiffs would generally incur storage expenses of the nature and magnitude sought here was foreseeable. 422 F.3d at 1375 (“Having been placed in a position where they are required to find alternate storage for SNF, the utilities must de facto accept responsibility to guard against the environmental impact of improperly-disposed and maintained SNF, a situation which the NWPA was enacted to avoid.”). “ ‘[T]he intent of the NWPA and the parties [to the Standard Contract] was to avoid the construction by utilities of additional at-reactor storage [after January 31, 1998].’ DOE’s failure to perform under the Standard Contract thus has led to the very thing the NWPA and the Standard Contract were designed to forestall, ie., the construction of dry storage facilities for spent nuclear fuel at nuclear power electricity generating plants throughout the United States.” Tennessee Valley Auth. v. U.S., 60 Fed.Cl. 665, 674 n. 10 (2004) (citing Commonwealth Edison Co. v. United States, 56 Fed.Cl. 652, 667 (2003)) (alterations in original); Tennessee Valley Auth. v. United States, 69 Fed.Cl. 515, 528 (2006) (“DOE also recognized that utilities might be forced to build additional on-site storage facilities if DOE were not successful in performing under its contracts for SNF disposal, as reflected by the fact that one of DOE’s goals was to preclude the utilities’ need to provide storage outside then-spent fuel pools.... In short, the court finds that it was entirely foreseeable to DOE that failure to perform under the contract would result in damages of the nature and magnitude that [plaintiff] claims.”).

Since before the NWPA, or the formulation of the Standard Contract, DOE was aware that utilities faced enormous storage costs. Indeed, avoidance of these costs was an impetus for, and objective of, the NWPA. From the inception of the SNF program, DOE planning documents cited avoidance of these costs as a program goal. Whether aspirational objectives, goals or contractual requirements, the court relies on these statements for foreseeability as well as what would have been reasonable or unreasonable performance by DOE, discussed infra. Tennessee Valley Auth., 69 Fed.Cl. at 519 (discussing NWPA goals of precluding any need for SNF storage other than in existing wet pools and for reducing accumulated backlogs). See generally Federal Group, Inc. v. United States, 67 Fed.Cl. 87, 103-04 (2005) (discussing aspirational goals vice contractual requirements).

Generally, foreseeability is determined at the time of contracting. Indiana Michigan, 422 F.3d at 1373 (affirming the trial court’s finding on the evidence that Private Fuel Storage was not foreseeable to the DOE at the time of contracting). However, there may be situations where foreseeability is more appropriately measured at the time of the breach, because that is when the breaching party should be on notice of the ramifications of its actions or failures to act. “There may even be valid reason to fix the foreseeability at the time of the breach rather than at the time of the agreement, for it is at the breach time that the consequences of wrongdoing are more apparent and assessable, and the deterrent accordingly greater.” Gardner Displays v. United States, 171 Ct.Cl. 497, 505, 346 F.2d 585, 589 (1965). “Compensation for the plaintiffs losses is to be made with reference to the conditions existing at the time when performance is due and the contract is broken.” Pacific Gas & Elec. Co. v. United States, 73 Fed.Cl. 333, 395 (2006) (citing 11 Arthur L. Corbin, Corbin on Contracts § 1005 (Interim ed.1993), quoted in Indiana Michigan, 422 F.3d at 1375-76).

While the general response to a breach must be foreseen, the particular way that a mitigating decision is implemented need not.

[A] breaching party should not be liable for damages that “it did not at the time of contracting have reason to foresee as a probable result of such a breach.” If it was foreseeable that the breach would cause the other party to obtain additional capital, there is no requirement that the particular method used to raise that capital or its consequences also be foreseeable. “What is required is merely that the injury actually suffered must be one of a kind that the defendant had reason to foresee and of an amount that is not beyond the bounds of reasonable prediction.”

Citizens Fed., 474 F.3d at 1321 (emphasis supplied) (quoting Restatement (Second) of Contracts § 351 cmt. a (1981) and Joseph M. Perillo, 11 Corbin on Contracts § 56.7 at 108 (2005 rev. ed.)). See also Old Stone Corp. v. United States, 450 F.3d 1360, 1377-78 (Fed.Cir.2006) (rejecting attenuated causation), cert. denied, — U.S.-, 127 S.Ct. 1831, 167 L.Ed.2d 319 (2007). In this regard, “what must be foreseeable is only that the loss would result if the breach occurred. There is no requirement that the breach itself or the particular way that the loss came about be foreseeable.” 3 Farnsworth on Contracts § 12.15, at 260-61 (3d ed.2004).

Particularly here, where performance is delayed for decades during which technology advances, there may be tension between what may have been foreseeable consequences in the 1980s, vice what may be commercially reasonable mitigation measures when the upcoming delay(s) were announced and when mitigation measures were required, or at the time of the breach. “[M]iti-gation in a contract that spans the ages is not limited to decades-old technology____[Plain-tiffs] were required to mitigate and their selection of these containers was commercially reasonable and defendant did not establish that it was unreasonable.” Yankee Atomic, 73 Fed.Cl. 249, 286 (2006).

The court notes that, to hold otherwise would be to provide a perverse incentive to non-breaching parties attempting to mitigate their foreseeable damages from a breach of contract through reasonable and appropriate methods. If the most reasonable and appropriate method of mitigating a non-breaching party’s foreseeable damages happens to be one that was not available at the time of contracting, and courts were to deny recovery because of this, non-breaching parties to contracts would have a significant disincentive to taking reasonable and appropriate steps to mitigate a breach of contract.

Pacific Gas & Elec., 73 Fed Cl. at 419 n. 71.

The breach must be a “substantial causal factor” in the mitigation decisions. In Citizens Federal Bank v. United States, 474 F.3d 1314, 1318 (Fed.Cir.2007), the Federal Circuit affirmed application of the substantial factor causation standard in an award of mitigating damages, surveying authority, that “may appear superficially somewhat inconsistent in applying the ‘substantial factor’ and ‘but for’ theories,” but finding as a “common thread [that] ... the selection of an appropriate causation standard depends upon the facts of the particular ease and lies largely within the trial court’s discretion.” Analysis included the Federal Circuit’s prior decision in Indiana Michigan applying the substantial causal factor standard to a mitigation award under the Standard Contract. See also Southern California Fed. Sav. & Loan Ass’n v. United States, 422 F.3d 1319, 1337 (Fed.Cir.2005), cert. denied, — U.S. -, 126 S.Ct. 2967, 165 L.Ed.2d 950 (2006) (affirming the finding that “FIRREA was the principal cause of [the thrift’s] recapitalization and was the substantial factor in [the thrift] incurring higher costs of funds after the breach”); Pacific Gas & Elec., 73 Fed.Cl. at 405, 415 (applying substantial factor standard); Sacramento Mun. Util. Dist., 70 Fed.Cl. 332, 362-65 (2006) (awarding mitigation costs substantially caused by DOE’s impending breach); Tennessee Valley Auth., 69 Fed. Cl. at 523 (applying substantial causal factor in awarding mitigation costs of constructing and operating dry storage), appeal dismissed, 188 Fed.Appx. 1004 (2006).

The Federal Circuit in Indiana Michigan upheld the trial court’s finding that DOE’s partial breach was not the cause of the utility’s decision to rerack its spent fuel pool. Rather, the utility’s decision, made six years before DOE formally announced delay, was for independent business reasons.

Indiana Michigan’s pre-breach costs were not caused by any anticipated DOE delay in performance. It authorized the expenditure for its reracking projects in 1989, in the normal course of business, six years before the 1994 Notice of Inquiry announced DOE’s inability to begin timely SNF collection. In light of that fact, the trial court found that Indiana Michigan’s rerack schedule was not affected by 1987 and 1989 DOE announcements projecting delays in the scheduled January 1998 acceptance start date. And [Indiana Michigan’s] decision to perform a full instead of a partial, rerack in 1995 was purely a business judgment which it would have had to pursue irrespective of DOE’s partial breach.

422 F.3d at 1376.

Mitigating decisions are constrained by commercial reasonableness. Citizens Fed., 474 F.3d at 1321 (stating that the nonbreach-ing “[thrift’s] strategy of raising capital through various types of financing was a commercially reasonable effort to maintain its debt-to-equity ratio, and fair and reasonable efforts to mitigate are all that the law requires” (emphasis supplied)). The “guiding principle” is whether plaintiff acted with “reasonable commercial judgment.” N. He-lex Co. v. United States, 207 Ct.Cl. 862, 883, 524 F.2d 707, 718 (1975) (internal quotation marks omitted). The mitigating party “must only make those efforts that are fair and reasonable under the circumstances.” Home Sav. of Am. v. United States, 399 F.3d 1341, 1353 (Fed.Cir.2005) (upholding “commercially reasonable effort,” quoting from Robinson v. United States, 305 F.3d 1330, 1333 (Fed.Cir. 2002)). Efforts need not necessarily be successful when viewed in hindsight because “fair and reasonable efforts to mitigate are all that the law requires.” Id.; accord Old Stone Corp. v. United States, 450 F.3d 1360, 1368 (Fed.Cir.2006) (“A non-breaching party may generally recover its mitigation costs incurred in a reasonable effort to avoid loss caused by a breach, even if its efforts prove unsuccessful.”); Hughes Commc’n Galaxy, Inc., 271 F.3d at 1067 (“As the victim of the breach, Hughes was within its rights to obtain commercially reasonable substitute launch services ____”) (cited with approval for recovery of mitigation costs in Old Stone, 450 F.3d at 1368); Sacramento Mun. Util., 70 Fed.Cl. at 366; Tennessee Valley Auth., 69 Fed.Cl. at 522-23. See also Anchor Sav. Bank v. United States, 59 Fed.Cl. 126, 149 (2003) (referring to “cover” concepts under the Uniform Commercial Code as closely-related to mitigation, deemed by the Federal Circuit to provide “useful guidance” in applying general contract principles).

The Federal Circuit in Indiana Michigan confirmed the application of these bedrock principles:

Section 350, comment b of the Restatement of Contracts advises that “[o]nce a party has reason to know that performance by the other party will not be forthcoming, ... he is expected to take such affirmative steps as are appropriate in the circumstances to avoid loss by making substitute arrangements or otherwise.” Indiana Michigan is “not precluded from recovery ... to the extent that [it] has made reasonable but unsuccessful efforts to avoid loss.”

422 F.3d at 1375 (alterations in original). See also 3 Dan B. Dobbs, Law of Remedies § 12.6(1)(6), at 127 (2d ed. 1993) (“[T]he plaintiffs damages are adjusted upwards to reflect all the reasonable costs he incurs in attempting to avoid losses, whether or not he was successful in doing so.”); Cienega Gardens v. United States, 38 Fed.Cl. 64, 79 (1997) (“Whether or not an attempt to mitigate damages is successful, the non-breaching party may recover for injury incurred during such mitigation as long as the attempt was reasonable.”), vacated on other grounds, 194 F.3d at 1231 (Fed.Cir.1998).

“[T]he established standard for evaluating the reasonableness of mitigation efforts is ‘from the perspective of one viewing the situation at the time the problem was presented.’ ” Franconia Assocs. v. United States, 61 Fed.Cl. 718, 744 (2004) (quoting Koby v. United States, 53 Fed.Cl. at 498); Tampa Elec. Co. v. Nashville Coal Co., 214 F.Supp. (D.Tenn.1963) (“The critical factor in determining ... a plaintiffs duty to mitigate is whether the method which he employed to avoid consequential injury was reasonable under the circumstances existing at the time.”) (cited in Corbin on Contracts § 57.16 at 349 (rev. ed.2005)).

Generally, the breaching party may not complain that one of several reasonable courses of action were taken. “ ‘The rule of mitigation of damages may not be invoked by a contract breaker as a basis for hypercritical examination of the conduct of the injured party, or merely for the purpose of showing that the injured person might have taken steps which seemed wiser or would have been more advantageous to the defaulter.’ ” Sacramento Mun. Util., 70 Fed.Cl. at 367 (quoting Koby v. United States, 53 Fed.Cl. 493, 497 (2002)) (citing In re Kellett Aircraft, 186 F.2d 197, 198-99 (3d Cir.1950)).

Although defendant disagrees, plaintiffs assert that defendant bears the burden of establishing that mitigating decisions or expenditures were unreasonable. Plaintiffs are correct. In Old Stone, the government breached its contract with the thrift by eliminating regulatory capital. The Federal Circuit rejected the government’s claimed error in the trial court’s award of the cost of replacement capital in excess of the required regulatory minimum, concluding the government did not prove that the thrift’s mitigation efforts were unreasonable.

In Home Savings, we recognized that “[w]hen mitigating damages from a breach, a party ‘must only make those efforts that are fair and reasonable under the circumstances.’ ” 399 F.3d at 1353 (quoting Robinson v. United States, 305 F.3d 1330, 1333 (Fed.Cir.2002)); see also 11 Corbin on Contracts § 57.11, at 311 (2005 ed.) (“The doctrine of avoidable consequences merely requires reasonable efforts to mitigate damages.”); 3 Dobbs: Law of Remedies § 12.6(1), at 127 (2d ed. 1993) (“[T]he damage recovery is reduced to the extent that the plaintiff could reasonably have avoided damages he claims and is otherwise entitled to.”). The government has not shown that it was unreasonable for [the thrift] to replace the entire amount of regulatory capital that was eliminated by FIRREA ... so that the thrift had a cushion against future losses.

450 F.3d at 1370 (all but last alteration in original). See also Pacific Gas & Elec., 73 Fed.Cl. at 406; Sacramento Mun. Util., 70 Fed.Cl. at 367 (2006); Tennessee Valley Auth., 69 Fed.Cl. at 523; Yankee Atomic, 73 Fed.Cl. at 264. Once plaintiffs have met their tripartite burdens of foreseeability, substantial causal factor, and reasonable certainty in amount, “[t]o eliminate or reduce [plaintiffs’] mitigation-related damages, the government bears the burden of showing that [plaintiffs’] mitigation efforts were unreasonable.” Tennessee Valley Auth., 69 Fed.Cl. at 523 (extensive citations omitted).

The court’s findings on reasonableness and substantial causation are also informed by Hughes Communications Galaxy, Inc. v. United States, 271 F.3d 1060, 1066-68 (Fed.Cir.2001) which affirmed an award of the nonbreaching party’s pre-breach mitigation costs. By contract, the National Aeronautics and Space Administration (“NASA”) was to use its “best efforts” to launch ten of Hughes’ satellites on future Space Shuttle missions no later than September 30, 1994. Before that date (pre-breach), following the tragic explosion of the Space Shuttle Challenger in January of 1986, shuttle operations were suspended. President Reagan then announced there would be no more commercial satellite launches. In pre-breach mitigation, Hughes launched five satellites,⁷ three on private expendable launch vehicles (“ELVs”) (which apparently were reasonably similar to what would have been on a shuttle launch), and two more on the HS-601 satellite which was better suited for Hughes’ commercial use, but more expensive. Hughes sued for damages for the increased costs of both types of alternative launches. The government’s defense in Hughes, not unlike the defense here, was that the costs of launching the two satellites on the HS-601 were motivated/caused by commercial concerns, not by NASA’s announced future breach. The Court of Federal Claims modified damage theories presented by the experts, determining that using its “best efforts” in the non-breach world, NASA would have launched only five of the maximum ten satellites. The court awarded the actual costs of three ELV launches, took the average of those costs to determine what the “reasonable” cost of launch four and five would have been, and added that extrapolated sum to the mitigation cost award. Affirming, the Federal Circuit cited bedrock contract principles. Damages are to place the nonbreaching party in “ ‘as good a position as he or she would have been had the breaching party fully performed.’ ” 271 F.3d at 1066 (citing San Carlos Irrigation & Drainage Dist. v. United States, 111 F.3d 1557, 1562-63 (Fed.Cir. 1997)).⁸ The Federal Circuit found no abuse of discretion in the Court of Federal Claims’: (1) determination that in the nonbreaeh world, using “best efforts,” NASA would have launched five of the ten Hughes satellites; (2) calculation of the average cost of the three actual launches and application of that average to the remaining two in lieu of an expert’s calculation; or (3) selection of parameters for calculating cost escalation other than those used by an expert. 271 F.3d at 1065.

Another instructive case is Chain Belt Co. v. United States, 127 Ct.Cl. 38, 115 F.Supp. 701 (1953). There, prior to, but in anticipation of the government’s announced impending breach, the nonbreaching party mitigated, a response the court endorsed as not only appropriate, but obligatory, bounded again by reasonableness.

[P]laintiff was under an obligation to avoid by a reasonable effort any damages which it should have foreseen and, having done so, it may recover as damages the expense incurred in such reasonable effort to avoid harm.... It makes no difference whether the breach has already occurred, or where ... it is merely impending under circumstances such that it was not reasonable for plaintiff to expect defendant to prevent the harm.

127 Ct.Cl. at 57-58,115 F.Supp. at 714.

Plaintiffs must establish the amount of their recoverable costs with reasonable certainty. Indiana Michigan, 422 F.3d at 1373 (citing Energy Capital, 302 F.3d at 1320 (Fed.Cir.2002)). “While the amount of damages need not be ‘ascertainable with absolute exactness or mathematical precision[,]’ recovery for speculative damages is precluded.” Id. (alteration in original) (quoting San Carlos Irrigation, 111 F.3d at 1563); Southern California Fed., 422 F.3d at 1336 (citing as the threshold evidentiary standard for a damage award, “sufficient evidence from which the court could ‘make a fair and reasonable approximation of the damages ....’”) (citing Bluebonnet Sav. Bank v. United States, 266 F.3d 1348, 1357 (Fed.Cir. 2001)).

Development of the Standard Contract

As background for the court’s findings herein, the development of the Standard Contract and the evolution of performance planning by DOE and monitoring by nuclear utilities is summarized.

The NWPA authorized DOE to enter into contracts for the acceptance, transportation and disposal of SNF.⁹ 42 U.S.C. § 10222(a)(1). Performance was to be as expeditious as practicable beginning no later than January 31,1998.

On February 4, 1983, after receiving preliminary comments from nuclear industry groups, DOE published a proposed Standard Contract. 48 Fed.Reg. 5458-71 (Feb. 4, 1983). The Federal Register Notice stated that “[the NWPA] directs DOE to begin repository operations no later than January 31, 1998.” Id. at 5458. There was a 30-day comment period. In a letter to Robert Morgan, DOE’s interim director, noting that the proposed contract did not contain a rate or a performance standard, APC and GPC requested a performance rate equal to at least the annual rate of SNF production, plus some to work off accumulated backlog, and urged the contract contain language that DOE should take title to SNF “as expeditiously as practicable,” a phrase that was not in the published proposal.

[W]e would like to emphasize the importance of the annual receipt rate of the disposal facility being designed, to the extent practicable, to be commensurate with the levels of spent nuclear fuel being generated annually and the need to also reduce the back-log of spent fuel as expeditiously as possible. Consistent with section 302(a)(5) of the Act, the contract should express the intent of DOE to take title to spent nuclear fuel as expeditiously as practicable upon request of the generator or owner.

(PX 46, 47.) Industry groups and other utilities also complained of the lack of an acceptance rate in the proposed contract. (PX 48 (comments from Edison Electric Institute (“EEI”), an association of investor-owned utilities and the Utility Nuclear Waste Management Group (“UNWMG”), a consortium of 43 utilities).)

Bruce Hunt,¹⁰ manager of nuclear fuel for Southern Company, participated in the events and discussions surrounding the development of the Standard Contract and testified that utilities and DOE understood that, consistent with the NWPA, “expeditiously as practicable” meant the removal of enough SNF from reactor sites such that the utilities would not have to add additional at-reactor storage after January 31, 1998. (Tr. 447, 454-55 (Hunt).)

On April 18, 1983 DOE issued the final Standard Contract. 48 Fed.Reg. 16,590-01. The “expeditiously as practicable” phrase from plaintiffs’ (and others) comments was added as a preamble. “Whereas, the DOE has the responsibility, following commencement of operation of a repository, to take title to the spent nuclear fuel or high-level radioactive waste involved as expeditiously as practicable upon the request of the generator or owner of such waste or spent nuclear fuel....” 48 Fed.Reg. at 16600 (emphasis supplied). (PX 750 at SN059469; PX 751 at SN138239 and SN138176; PX 752 at SN0C01233.)

This contract applies to the delivery by Purchaser¹¹ to DOE of SNF and/or HLW of domestic origin from civilian nuclear power reactors, acceptance of title by DOE to such SNF and/or HLW, subsequent transportation, and disposal of such SNF and/or HLW and, with respect to such material, establishes the fees to be paid by the Purchaser for the services to be rendered hereunder by DOE. The SNF and/or HLW shall be specified in a delivery commitment schedule as provided in Article Y below. The services to be provided by DOE under this contract shall begin, after commencement of facility operations, not later than January 31, 1998 and shall continue until such time as all SNF and/or HLW from the civilian nuclear power reactors specified in Appendix A, annexed hereto and made a part hereof, has been disposed of.

10 C.F.R. § 961.11, Art. II. DOE’s obligation to commence performance was not conditioned on the existence of “a facility.”¹² DOE’s performance was to begin when a “facility” was operational, or January 31, 1998, whichever first occurred. Indiana Michigan Power Co. v. DOE, 88 F.3d 1272, 1276-77 (D.C.Cir.1996) (rejecting DOE’s position that performance was contingent upon the commencement of the operation of a repository, holding that payment of fees by a utility was the quid pro quo for timely commencement of performance). See also Northern States Power Co. v. DOE, 128 F.3d 754, 760 (D.C.Cir.1997) (rejecting DOE’s position that the delay was “unavoidable” under the delays clause of the contract and reaffirming that “the NWPA directs DOE to undertake the duty to begin taking the SNF by January 31, 1998, whether or not it has a repository or interim storage facility”).

GPC signed Standard Contracts for Plant Vogtle and Plant Hatch on June 10, 1983; APC signed for Plant Farley on June 13, 1983.¹³ (PX 751, 752, 750 (hereinafter “Standard Contract”).) The Standard Contract did not contain an acceptance rate, despite industry urging. Michael Lawrence, Deputy Director of the NWPA Project Office at the time the Standard Contracts were signed, testified that in 1983 it was not possible to specify an exact rate for SNF acceptance that would not begin until 1998. (Lawrence Dep. 62-63, May 20, 2002 (Pis.’ Dep. Designation (“PDD”) 18.))

While the Standard Contract did not contain a rate or schedule for the acceptance of SNF either on an industry-wide basis or by specific utility, it included a process by which a schedule and quantities would be established. Pacific Gas & Elec., 73 Fed.Cl. at 349-51, 366-70; Sacramento Mun. Util., 63 Fed.Cl. at 497, 504-05; Sacramento Mun. Util., 70 Fed.Cl. at 339; Tennessee Valley Auth. v. United States, 60 Fed.Cl. at 668 (“The Standard Contract did not establish a specific rate or schedule for the collection of SNF. Rather, it established a process by which a rate would be established for each utility.”). This process, although started, stopped and abandoned several times, is summarized for background purposes and because defendant argues the commencement of this process in 1991, defines the so-called nonbreach world and caps plaintiffs’ damages.

As an initial matter, under the Standard Contract, priority of acceptance is generally based on the age of the SNF, calculated from the date the material was discharged from the reactor core. Standard Contract, Art. VI.B.1(a); see also Art. IV.B.5(a) (“[Pjriority ranking shall be based on the age of SNF and/or HLW as calculated from the date of discharge of such material from the civilian nuclear power reactor. The oldest fuel or waste will have the highest priority for acceptance, ----”). This priority is referred to as Oldest Fuel First (“OFF”). Beginning annually starting on January 1, 1992, utilities were required to submit for DOE’s approval, a proposed Delivery Commitment Schedule (“DCS”), specifying the amount of SNF it “wishes to deliver to DOE beginning sixty-three (63) months thereafter.” Art. V.B.1. The amount of SNF in a proposed DCS was to be based on OFF allocations from two types of DOE documents—Annual Capacity Reports (“ACRs”) and Annual Priority Rankings (“APRs”). DOE would accept or reject the submitted DCSs. Any disagreement would be negotiated. To the extent a DCS was approved, the utility would then submit a Final Delivery Schedule (“FDS”) some four years later, one year prior to scheduled acceptance, describing in more detail the SNF to be relinquished. The utility could adjust the quantity of SNF by plus or minus twenty percent and the delivery date by two months. Art. V.B.

DOE’s ACRs

Mindful that DCSs were many years hence, beginning in June of 1987, DOE would issue an ACR “for planning purposes.” Standard Contract, Art. IV.B.5(b); 48 Fed. Reg. at 16,592 (stating that DOE added a contractual provision for ACRs “at the request of a substantial number of eommen-ters____”). ACRs were non-binding projections of the annual aggregate industry-wide weight of SNF DOE would be accepting for the first ten-years. (Morgan Dep. 139-41, Mar. 21, 2002 (PDD 26).) Every ACR DOE has issued stated it was for planning purposes only and not contractually binding on either the utility or DOE. (PX 4 (1987 ACR) at 2 (June 1987)); PX 8 (1991 ACR) at 1-2 (Dec.1991); PX 14 (2002 APR & ACR) at 1 (July 2004); Tr. 1990-91 (Zabransky) (“The ACR in itself is a planning document”) Nancy Slater-Thompson, the DOE official in charge of receiving and processing DCS submissions in the early 1990s, did not consider them to be binding on either the utility or DOE. (Slater-Thompson Dep. 98-99, June 13, 2002 (PDD 37).) Man Browmstein, the DOE official responsible for the division that handled DCSs in the early to mid-1990s, testified they were for planning purposes only. (Brownstein Dep. 376-78, Apr. 10, 2002 (PDD 8); Brownstein Dep. 427, June 14, 2002 (PDD 10); Tr. 1901-02 (Pollog); Lawrence Dep. 131, May 20, 2002 (PDD 18); Morgan Dep. 135, June 25, 2002 (PDD 28).)

The first ACR issued in June of 1987 listed all SNF assemblies by date of discharge from the reactor, starting with the oldest (fuel discharged in 1959), cumulating a total of over 18,000 MTU, ending the listing with fuel removed in 1989. The assemblies were grouped into annual capacity segments based on the total amount DOE then-projected accepting. In “Years 1-5,” specific allocations of 1200 MTU annually are charted. For example, Year 1 listed the location of the oldest 1200 MTU of SNF. The next four years continued with the next oldest 1200 MTU. After five years at 1200 MTU annually (for a total of 6000 MTU), the allocations for subsequent years were: Year 6—2000 MTU; Year 7—2650 MTU; Year 8—2650 MTU; Year 9—2650 MTU; Year 10—2650 MTU. The ACR also noted whether transportation would be by rail or truck. The 1987 ACR contemplated initial acceptance at a monitored retrievable storage system (“MRS”) beginning in 1998, if Congressional approved DOE’s MRS proposal. In that event, repository operations would then begin in 2003. Acceptance of a total of 6000 MTU at an MRS prior to commencement of repository operations was contemplated (1200 MTU annually for the first five years). Future acceptance rates “may differ.” (PX 4.) The 1988 ACR (along with the 1988 Draft Mission Plan) delayed receipt at either an MRS or a repository until 2003, reaching an annual combined acceptance rate, using both an MRS and a repository, of 3000 MTU within five years. (Tr. 526-29 (Hunt).)

In its draft 1989 ACR, DOE recognized that delay in the repository and conditions imposed on the siting and construction of an MRS facility by the NWPA amendments (further discussed later) made it unlikely that DOE would be able to start accepting SNF significantly before 2003. Recognizing that a delay would increase utilities’ need for additional at-reactor storage, DOE was evaluating the costs and impacts of this delay and exploring whether the NWF could be used to cover costs. (PX 6.)

DOE’s December 1990 ACR utilized two waste acceptance schedules for the first ten years of operation, upper and lower bounding rates for DOE’s Waste Management System CWMS”), including an MRS if statutory conditions were removed and an early site was found. While the 1989 ACR presumed delay in commencement until 2003, the December 1989 ACR projected acceptance starting in 1998 with a ten-year cumulative rate of 24,-100 MTU (1200, 1200, 2000, 2000, 2700, then 3000) in the upper bounding case and 7375 MTU (300, 400, 550, then 875) for the lower bounding case. The upper bounding rates assumed that the linkages in the 1987 Amendments to the NWPA would be lifted by Congress. (Tr. 1773-74 (Kouts).) Similar to the 1987 ACR, individual utilities allocations for ten years under both the upper and lower bounding rates were charted, and all SNF was listed through 1992 by date of discharge from the reactor. Under the Standard Contract, it was to be the last in the series of DOE’s ACRs. Beginning in April of 1991, DOE would publish its first APR. Under the Standard Contract, the APR would establish the acceptance queue, 10 C.F.R. § 961.11, Art. IV.B.5, a chronological ranking of SNF on an industry-wide basis by date of discharge (earliest to latest), number of assemblies, weight and name of discharging reactor, aggregating the total cumulative weight of acceptance.¹⁴ This data had been included in previous ACRs. DOE’s 1991 APR also listed the ranking, and stated that it, together with a forthcoming December 1991 ACR, would form the parameters of a utility’s future DCS submissions. (PX 9.) “The APR will be used in conjunction with waste acceptance rates to be published in the 1991[ACR] as the basis for purchasers to submit delivery commitment schedules (‘DCS’) beginning January 1992 for the department’s approval.” “The Purchasers’ allocations for each delivery year are presented in Tables A.1 through A10 in Appendix A and should be used as the basis for submitting DCSs.” (DX 97 at 2.)

Under OFF,¹⁵ a utility could derive the amount of SNF eligible for pickup by applying the annual acceptance rate from the ACRs, the projected date of commencement of performance and then determining where its SNF was on that continuum. For example, if DOE commenced performance in 1998 at 3000 MTU per year, and a particular utility had 15.7 MTU of SNF with a date of discharge chronologically behind a total of 3100 MTU from other utilities, the first utility could theoretically plan that it could submit a DCS for 15.7 MTU for pickup in 1999. While the chronological listing of discharged SNF remained constant, the acceptance rate and the commencement date, varied.

DCSs, which would identify “all SNF and/or HLW the Purchaser wished to deliver to DOE”¹⁶ had to be submitted 63 months— five years and three months—in advance of the projected delivery year. Standard Contract, Art. V.B.1. In the above example, the utility could submit a DCS for 15.7 MTU for 1999 in 1993—63 months prior to that allocation. The utility could adjust that quantity by plus or minus 20 percent, and the delivery date by two months, until the submission of the “final delivery schedule” issued one year before the delivery date. Art. V.B.2.

DOE’s December 1991 ACR contained only one acceptance rate rather than the prior upper and lower bounding rates in the previous ACR. Commencement could begin in 1998 only if the NWPA was amended. “If the current [statutory] linkages between [an] MRS facility construction and repository construction authorization are maintained, it is estimated that commencement of facility operations and initial acceptance of SNF by DOE could not start until at least 2007.” (PX.8.) The annual rates (400, 600, 900 thereafter until 2007) reflected the 10,000 MTU statutory storage capacity limit placed on an MRS, and the rates were “representative” of a WMS that included an MRS.

Plaintiffs cite DOE’s ACRs as support for their growing anxiety over DOE’s inability to commence performance by January 31, 1998. In that regard, in making its findings herein, particularly on causation, foreseeability and reasonableness, the court relies on, and compares, evidence at the time of contracting and DOE’s subsequent equivocations.

Early program goals

Shortly after the Standard Contracts were executed, at a conference of nuclear utilities and other program participants, Robert Morgan, Acting Director of the NWPA Project Office,¹⁷ stated that “beginning in 1998, utilities will not have to provide any additional storage facilities on site. During the first year of operation of the repository in 1998, we should be receiving fuel at a rate so that no utility would have to add any further storage facilities either on site or at another location.” (PX 53 at 11; Morgan Dep. 38-43, Mar. 21, 2002 (PDD 26).)

The fundamental objective of the Federal Waste Management System (“FWMS”) in OCRWM’s draft Mission Plan,¹⁸ provided to the utilities in December of 1983, was to begin accepting SNF no later than January 31, 1998, at a rate which would initially preclude additional at-reactor storage and ultimately remove all backlog of SNF more than five years old.¹⁹ (PX 35 at 1-1.) “[N]o utility will have to provide additional storage capacity after January 31, 1998. Subsequently, the acceptance rate will be equal to or greater than the actual discharge rate of spent fuel each year.” (Id. at 2-1.) At that time, approximately 2000 MTU of SNF were being produced annually on a utility-wide basis. (Tr. 1894 (Pollog).) An acceptance rate of 1800 MTU in 1998, ramping up to 3000 in 2003 would “prevent, in the aggregate, the need for utilities to provide additional on-site storage after 1998.” (PX 35 at 2-2; Tr. 470 (Hunt Test.); Morgan Dep. 149-56, Mar. 21, 2002 (PDD 26).)

In February 1984 (eight months after plaintiffs signed the Standard Contracts), OCRWM’s Acting Director Michael Lawrence (Robert Morgan’s successor) testified before the Energy Conservation and Power Subcommittee of the House Committee on Energy and Commerce, presenting the FY 1985 budget. “The $327.7 million requested will be used to fund the activities under the NWPA of which the fundamental objective is for the [DOE] to accept high-level radioactive waste for safe management, storage and permanent disposal on a firm schedule, beginning not later than January 31, 1998.” (PX 54 at PNL-173-0226.) “By achieving this fundamental objective and implementing an appropriate waste acceptance schedule, this will initially preclude the need for additional at-reactor storage by nuclear utilities after January 31, 1998, and ultimately, remove all eligible waste from at-reactor storage.” (Id. at PNL-173-0228.)

OCRWM’s April 1984 draft Mission Plan, stated that “[i]n the event of a delay in repository operation, [DOE] could take the waste materials in accordance with the Waste Acceptance Schedule and arrange for either continued storage at the utilities in Federal storage casks, or for storage elsewhere pending transfer to the repository.” (PX 37.) The Waste Acceptance Schedule in the draft Mission Plan listed aggregate annual generation of spent fuel and discharge from decommissioned reactors, comprising the cumulative SNF inventory (43,800 MTU in 1998). Two repositories²⁰ were shown, the first commencing in 1998, accepting 400 MTU for the first three years, then 900 MTU in 2001, 1800 MTU in 2002, and 3000 MTU starting in 2003 and continuing at that rate until 2024. A second repository would commence in 2005, accepting 1800 MTU annually for five years, then 3000 MTU starting in 2010 and continuing at that rate until 2028. (PX 37 at 2-2.) With these combined rates, industry backlog was reduced from 43,200 MTU in 1998 to 34,000 MTU in 2020. (Id.) Recognizing that a repository had never been built, potential back-up plans included an MRS, an option authorized under the NWPA—“long-term storage of [HLW] or [SNF] in monitored retrievable storage facilities is an option for providing safe and reliable management of such waste or spent fuel.” (PX 37 at 3-B-l (citing 42 U.S.C. § 10161(a)(1)) (requiring a study and proposal be submitted to Congress by June 1, 1985).)

While the April 1984 draft plan addressed reduction of backlog, it did not mention prevention of additional at-reactor storage. Plaintiffs expressed concern to DOE that the draft did not reflect the “clear understanding” reached with DOE in December of 1983 that “sufficient spent fuel would be shipped to federal facilities beginning in January 1998 so that no additional construction of storage capacity at utility plant sites would be required after 1998 [which] is a fair, reasonable, and proper interpretation of NWPA requirements.” (PX 267 at 2.)

Interdepartmental comments at that time were consistent with a program goal of eliminating the need for additional at-reactor storage. Michael Lawrence, who was then at DOE’s Richland Operations Office, wrote to Ben C. Rusche, Director of OCRWM on July 23, 1984, that (1) to eliminate the need for additional at-reactor storage after January 31, 1998, the initial acceptance rate would have to be at least 2800 MTU; (2) assuming DOE would be responsible for post-1997 additional storage, that cost would approximate one billion in 1983 dollars. (PX 506 at 783.) “Based upon our interpretation of the NWPA, the minimum acceptance rate should be based upon the rate at which spent fuel is generated by civilian nuclear power reactors. This would be consistent with NWPA intent that no power reactor would require additional spent fuel storage after January 31, 1998.” (Id.)

The Final Mission Plan in June of 1985, with acceptance starting in 1998, contained a 3000 MTU acceptance rate for the first repository after a ramp-up (400, 400, 400, 1800 and then 3000). The second repository would be added in 2006 starting at 900 MTU, then 1800 for 2007 through 2010, 2400 in 2011, and 3000 thereafter through 2030. (PX 38 at 26.)

Plaintiffs cite to witness testimony that DOE’s objective and planning was to avoid additional at-reactor storage; that 3000 MTU a year would achieve that goal; that DOE understood Congress did not intend for utilities to have paid billions into the NWF and have to bear the cost of additional at-reactor storage after 1998; that before a utility would run out of storage space, DOE would pickup. (Pis.’ Posh-Trial Br. 35-37.) The intent of the DOE at the time of the execution of the Standard Contracts was “to get a facility operating in '98, to take the stuff away fast enough so that utilities would not have to add additional storage. That was the intent.” (Id. at 37, citing Cole Dep. 80-81, Mar. 12, 2002 (PDD 11).) To meet that goal and to reduce the backlog of accumulated SNF, the DOE initially planned a 3000 MTU rate. (Id.) DOE’s RCFC 30(b)(6) witness testified that DOE’s goal in the mid-1980s was to “alleviate the purchasers’ need to have storage outside of their [spent fuel] pools.” As calculated by DOE, the rate that would achieve that objective was 3000 MTU annually. (Pollog Rule 30(b)(6) Dep. 96-97, Apr. 11, 2002 (PDD 26).)

DOE also used a 3000 MTU annual rate for operational and financial planning, particularly in assessing program costs and the adequacy of the 1 mil per kilowatt hour fee charged to the utilities under the Standard Contract. (Pis.’ Br., 40-45.) OCRWM’s more recent WMS requirements documents have acceptance rates of 400, 600,1200, 2000, and 3000 MTU annually with performance commencing in 2010. (PX 98 (Jan.2002); PX 170 (May 2002); PX 180 (Sept.2004).)

The 1987 Amendments to the NWPA

In March 1987, DOE sought Congressional authority to construct an MRS as an integral part of the WMS, both for storage and as a central receiving station, to prepare fuel for emplacement in the repository. (PX 59.) The proposal was that acceptance at an MRS could not occur until construction authorization for the first repository was received. The MRS could accept no more than 15,000 MTU over five years. (Tr. 1813-15 (Kouts).) Ben Rusche, Director of OCRWM, testified before the Senate Committee on Energy and Natural Resources, that the first repository would be not be ready until 2003, but with an MRS, the 1998 deadline could be met. “The MRS facility could allow DOE to begin receiving waste in 1998, and the waste acceptance rates of the waste management system could start exceeding reactor discharge rates about eight years earlier than would be the ease then if there were no MRS.” (PX 517 at 169.) As a result, an MRS was projected to eliminate additional at-reactor storage at more than 15 reactors sites during 1998 to 2003, saving rate-payers about one billion dollars. (Id. at 168.)

In its 1987 Mission Plan, DOE formally announced a five-year delay in the commencement of repository operations from 1998 to 2003, and its proposal to accept SNF during this five-year period at an MRS. (PX 39, 40.) DOE also reported thirty-five pending lawsuits, any one of which could affect the repository schedule. (PX 40 at 5.) The MRS was planned as a stand-alone facility from 1998 to 2003 when SNF would then be gradually transferred from the MRS to the repository. (PX 40 at 12, 61.) DOE’s Chief Operating Officer, Ron Milner, testified the MRS could have operated at an annual acceptance rate approaching 3000 MTU consistent with prior planning.²¹ (Milner Dep. 555-56, May 3, 2002 (PDD23).) As “a planning base that will be updated annually in response to the latest forecasts of nuclear power growth,” the “Illustrative Waste Acceptance Schedule” in the 1987 Mission Plan was:

MRS—Spent MRS—Spent Shipped from fuel fuel in MRS to Year received storage repository

1998 1200 1200

1999 1200 2400

2000 1200 3600

2001 1200 4800

2002 1200 6000

2003 2000 7600 400

2004 2650 9850 400

2005 _2650_12100_400

2006 2650 13850 900

2007 2650 14700 1800

2008 2650 14700 2650

2009 2650 14700 2650

2010 2650 14700 2650

2011 _2650_14700_2650

2012 _2650_14700_2650

(PX 40 at 61.) At these rates, with shipment from the MRS to a repository starting in 2003, the MRS inventory would not exceed its 15,000 MTU capacity under DOE’s proposal. DOE’s objective with these acceptance rates was to prevent additional at-reactor storage and reduce SNF backlog. (Pollog RCFC 30(b)(6) Dep. 202-03, Apr. 11, 2002 (PDD 29).) This is how DOE planned on “performing” before the intervention of the 1987 Amendment to the NWPA in which Congress, not the Standard Contract, constrained capacity and timing.

In December 1987 amendments to the NWPA, Congress authorized an MRS, but with more stringent conditions than DOE had proposed. While DOE had proposed no waste acceptance at an MRS until construction of a repository had been authorized, Congress precluded construction of an MRS until construction of the repository had been authorized. 42 U.S.C. § 10168(d)(1). This condition would delay commencement by five years. (DX 71.) Congress also limited acceptance at an MRS to 10,000 MTU until a repository started accepting SNF, and then the capacity was limited to 15,000 MTU. 42 U.S.C. § 10168(d)(3) and (4). And, in any event, an appropriate MRS site had to be located. No site was located. The conditions for the construction of an MRS were never met. These statutory conditions were never amended or rescinded and there is no MRS. The Standard Contract does not contain these constraints.

In June 1988, DOE issued another draft amendment to the Mission Plan. Acceptance at a repository was again predicted to start in 2003, assuming construction authorization in 1998. (PX 42 at 15; Tr. 1987 (Zabransky); Tr. 1819-23 (Kouts).) Also in June 1988, DOE published its second ACR, which, conceding a five-year delay, projected acceptance starting in 2003.

The delay in the repository schedule first noted in the OCRWM Mission Plan Amendment published in June 1987 and the conditions imposed on the siting and construction of an MRS facility by the [1987 NWPA amendments] make it unlikely that DOE will be able to start accepting SNF significantly before 2003. As recognized in the draft Mission Plan Amendment, earlier waste acceptance would require additional Congressional action or an acceleration of the system development schedule by some other means. Under current conditions, the owners and generators of SNF will continue to be responsible for storing their spent fuel until acceptance by DOE. The DOE will continue working with the Purchasers to expedite the effective use of available storage and the development of additional storage at reactor sites.

(DX 71 at 4 (footnote omitted).) Assuming repository construction would be authorized in 1998, commencement in 2003 was thought to be achievable. It was assumed the MRS and repository would commence acceptance simultaneously, accepting at total of 1200 MTU in 2003; 1200 MTU in 2004; 2000 MTU in 2005 and 2006; 2700 MTU in 2007; and 3000 MTU in 2008 through 2012, for a total of 24,100 MTU in the first ten years. (Id. at 5.) The 1988 ACR also explained that, because of limitations in the 1987 Amendments to the NWPA, should the repository be delayed, an MRS could only accept 10,000 MTU. (Id. at 7.) Accordingly, by 1988, performance at an MRS was contingent on construction authorization for a repository (which never has occurred) and successful siting of an MRS (which also never occurred). Even under the best-case scenario, performance at any rate, at anyplace, would not commence by January 31,1998.²² And, because of the delay in the repository, the capacity of the MRS was limited to 10,000 MTU.

Plaintiffs were aware of, and complained about, DOE’s then five-year delay. On September 23, 1988, Hunt wrote: “[t]he DOE’s assertions in the ACR and [Draft Mission Plan Amendment] that it will not accept any SNF until 2003 is contrary to the disposal contract and the expressed will of Congress.” (PX 64, 65.)

This departure from the [NWPA’s] requirements is completely unacceptable. [APC and GPC] do not agree with the DOE’s assertion that the owners and generators of spent nuclear fuel will continue to be responsible for the waste material after 1998. The DOE’s obligations under the disposal contract begin January 31, 1998 and the DOE is responsible for the SNF, or spent nuclear fuel, after that date. The DOE’s assertions in the ACR and the Draft Mission Plan that it will not accept any [SNF] until 2003 is contrary to the disposal contract and the expressed will of Congress.

(Tr. 531-32 (addressing the June 1988 ACR).) The letter also complained that the acceptance level was too low. DOE responded indicating those concerns were expressed by others. (Tr. 523.)

DOE published a “Report to Congress on Reassessment of the Civilian Radioactive Waste Management Program” in November of 1989. (PX 67.) While DOE had already announced a delay in commencement of repository operations until 2003, in the Report, DOE stated that unless the conditions or linkages in the 1987 Amendments to the NWPA were lifted, SNF acceptance at an MRS would not, and could not, commence in 1998, and the expected start of repository operations fell another seven years, from 2003 to 2010. (PX 67 at vii, 8-11.) Absent Congressional action, as a repository was delayed until 2010, the earliest an MRS could accept utility SNF would have been 2007, assuming a three-year construction time because an MRS could not accept SNF until construction authorization for the repository. (PX 59, 68.) No ACR was issued in 1989.²³ (PX 70.)

At this point, DOE conceded that commencement of performance could not start until 2010 absent Congressional action. While the 1988 ACR initiated performance in 2003 (the then predicted start-up date for the repository—a date that fell back another seven years to 2010 in DOE’s 1989 Reassessment Report to Congress), despite these pri- or admissions, DOE projected commencement of performance in the 1990 ACR in 1998 with initial acceptance at an MRS at upper and lower bounding rates.²⁴ (PX 7.)

Defendant’s response to plaintiffs’ claimed damages relies on rates DOE projected in the December 1991 ACR. (DX 97, PX 8.) These are the rates that define the non-breach world according to defendant, and damages for any higher level of performance than this—what DOE was agreeing to or projecting at that time—would either not be caused by DOE’s delay, or be a windfall. This position is discussed in further detail hereinafter. At this point, it is appropriate to note this document, in the context of DOE’s prior and subsequent statements.

DOE’s performance starting in 1998 with an MRS under the 1991 ACR, was conditioned and constrained by legislation enacted subsequent to the signing of the Standard Contracts, including a 10,000 MTU capacity and delay in construction of an MRS until repository construction was authorized. DOE’s pre-1987 amendment performance plans in the previous ACR, the March 1987 proposal to Congress, and the 1987 Mission Plan, were not conditional and had higher rates of acceptance. (PX 517, 39, 40.) For example, the 1987 ACR contemplated acceptance at an MRS starting in 1998, accepting 1200 MTU annually for the first five years when the repository would come on board, reaching an annual combined acceptance rate of 3000 MTU within five years. (PX 4; PX 40.)

The 1991 ACR, like the earlier planning documents, was estimated, but unlike earlier projections, was contingent on legislative changes.

2.0 WASTE ACCEPTANCE PROJECTIONS

The waste acceptance projections used in this ACR are representative of a FWMS configuration authorized by the NWPA, which includes a[n][MRS] facility. Article II of the Standard Contract specifies that “[t]he services to be provided by DOE under this contract shall begin, after the commencement of facility operations, not later than January 31, 1998.... ” DOE recognized that, under current conditions, waste acceptance at a DOE facility can begin in 1998 only if the Federal Government is able to consummate a timely agreement, which is enacted into Federal law, with a host State or Indian Tribe for the siting of an MRS facility. The Office of Nuclear Waste Negotiator, the head of which is a representative of the Federal Government appointed by the President, is actively seeking a State or Indian Tribe willing to host an MRS facility or a geologic repository.

The acceptance rates in Table 2.1 do not reflect the MRS facility schedule linkages with the repository development that were imposed by the NWPA, but are consistent with the 10,000 MTU storage capacity limit contained in the NWPA for an MRS facility before a repository starts operation. These acceptance rates assume commencement of facility operations in 1998. If the current linkages between MRS facility construction and repository construction authorization are maintained, it is estimated that commencement of facility operations and initial acceptance of SNF by DOE could not start until at least 2007.

(PX 8 at HQR-001-2365 (emphasis added).) Thus, absent Congressional action, given the delay in repository operations until 2010, the aggregate acceptance rate for the years 1998 through 2007 would be zero. David Zabran-sky, DOE’s contracting officer, admitted the rates in the 1991 ACR assumed there was an approved MRS and that the statutory linkages were removed, neither of which ever occurred. (Tr. 1990 (Zabransky).)

Mr. Zabransky also testified that DOE’s position was that utilities, but not DOE, would be bound by either the ACRs or the DCSs, a position with which he disagreed.

A. (quoting from the 1991 ACR) As specified in the [SJtandard [Contract, the ACR’s [sic] for planning purposes only. It is thus not contractually binding on either DOE or the purchaser.

Q. So DOE didn’t think the 1991 was— ACR was contractually binding, right?

A. Well, again, as I’ve explained, DOE didn’t think the DCSs were, they thought they were conditional commitments. The ACR in itself is a planning document. It’s when it was used by the contracting officer as the basis for the DCSs that it started the contractual process.

Q. Okay. And that was—you skipped to my next question. DOE didn’t consider the DCSs binding, is that your testimony?

A. I think DOE erroneously considered them to be deconditional [sic] commitments.

Q. Erroneously, in your judgment?

A. I always thought that was erroneous. I just work there.

(Tr. 1990-91.)

Under the Standard Contract and DCS instructions (PX 74), utilities could submit DCSs beginning January 1, 1992. A DCS had to be submitted at least 63 months (five years and three months) prior to an allocation. Putting aside the DOE’s equivocations prior to the 1991 ACR, it is not clear whether DOE’s conditional and contingent commitments in the 1991 ACR would have started the 63-month clock. In the absence of a firm commitment to take delivery within 63 months of a date certain, the DCS process is/was largely academic for plaintiffs. At the 1991 ACR rates, plaintiffs’ allocations never came within 63 months of pickup before DOE repudiated its obligation to unconditionally commence performance by January 31, 1998 and suspended the DCS process. Under the December 1991 APR, plaintiffs’ first allocation was for Hatch Unit 1—.749 MTU when cumulative total acceptance reached 2,383.22 MTU. (PX 9 at 1398; PX 13 at Table B.4 (annual allocations for ‘Year 4”—listing .8 MTU for Hatch 1).) At the 1991 ACR rates (400, 600 and then 900), cumulative total acceptance would reach 2800 MTU in 2001— the year in which Hatch Unit l’s initial allocation under defendant’s theory was slated for pickup. (PX 8 at 5.) The DCS instructions suggest a calendar year with 63 months measured from January of the pickup year. Sixty-three months prior to January, 2001 is September 30, 1995 which is when plaintiffs’ first DCS would have been due. Before that due date, DOE had already announced it would not begin SNF collection until 2010, 59 Fed.Reg. 27,007-27,008 (May 25, 1994), and stated in its 1995 Notice of Inquiry that it had no obligation to commence performance absent a repository, and had no authority to build an MRS. 60 Fed.Reg. 21,793, 21,794 (May 3, 1995) (announcing it “does not have an unconditional statutory or contractual obligation to accept [HLW and SNF] beginning January 31,1998 in the absence of a repository or interim storage facility constructed under the [NWPA]”).

Interim storage by DOE was contemplated by the Act in only two situations, neither of which currently applies. Under the Act, DOE had authority to offer a limited interim storage option. See 42 U.S.C. [§ ] 10156. However, that authority has, by its express terms, expired. Under the Act, DOE also has authority to provide for interim storage in an MRS. That authority also is inapplicable, however, because the Act ties construction of an MRS to the schedule for development of a repository. See 42 U.S.C. [§§ ] 10165,10168.

60 Fed.Reg. 21,797. The March 1995 ACR had no specific years of acceptance; rather listed “Year 1,” “Year 2,” etc. (PX 13.) Eliminating specific years effectively precluded utilities from determining the due date of DCS forms, 63 months before that unknown. Thus, it was impossible for plaintiff to hold an approved DCS. (Tr. at 1826 (Kouts).) Also, the DCS instructions refer the utility to its allocations in the 1991 ACR “or subsequent ACRs, as appropriate.” (PX 74 at 1 (emphasis added).) As allocations for the other plants came later, the same “overcome-by-events” would have applied and defendant’s reliance on the 1991 ACRs unravels.

DOE will not resume the DCS process until it has a reasonably firm date for the beginning of repository operations. At that time utilities would comply with the required 63-month lead time for DCS submittals. (Tr. 2002-04 (Zabransky); id. at 1853-54 (Kouts).) Nevertheless, on September 30, 1996, SNC submitted DCS forms for a 2001 allocation for Plant Hatch. “The attached meets the notice obligations under the spent fuel disposal services contracts, but does not indicate [SNC’s] acceptance of the removal rates contained in the current ACR. [SNC] believes the ACR rates are too low and are therefore inadequate.” (PX 82; see also PX 83 dated October 21, 1996.) In reply, DOE informed that it was “not able at this time to approve your DCS submittal. Consequently, the Department hereby waives until further notice the contract requirement that you provide a revised schedule within 30 days.” (PX 86 (received March 13, 1997).) DCSs were not approved because the DOE suspended the DCS process. (Tr. 1966-68 (Zabran-sky).) Cf. Pacific Gas & Elec., 73 Fed.Cl. 333, 364 (2006) (concluding on evidence presented, that Pacific Gas and Electric believed that DOE’s proffered performance in the 1991 ACR, even with the capacity constraints of the 1987 amendments, would have satisfied its contractual obligations.)

While the Standard Contract does not limit acceptance to a repository (so performance at an MRS would not necessarily have been foreclosed), the conditional and contingent nature of the 1991 ACR did not comport with the DOE’s unconditional statutory and contractual obligations. Defendant’s position is that plaintiffs’ acceptance rights in the 1991 ACR define the nonbreach world and any mitigation damages cannot exceed what that nonbreach world would have been. However, even if plaintiffs consented to this level (which by their objections, they did not), DOE’s inability to implement the 1991 ACR rates would nullify their use as equivalent to an “accord,” to define nonbreach world performance.

(1) An accord is a contract under which an obligee promises to accept a stated performance in satisfaction of the obligors existing duty.

(2) Until performance of the accord, the original duty is suspended unless there is such a breach of the accord by the obligor as discharges the new duty of the obligee to accept the performance in satisfaction. If there is such a breach, the obligor may enforce either the original duty or any duty under the accord.

Restatement (Second) Contracts § 281. A valid accord and satisfaction requires: (1) proper subject matter; (2) competent parties; (3) a meeting of the minds; and (4) consideration. O’Connor v. United States, 308 F.3d 1233, 1240 (Fed.Cir.2002). For a meeting of the minds, “[t]here must be accompanying expressions sufficient to make the creditor understand, or to make it unreasonable for him not to understand, that the performance is offered to him as full satisfaction of his claim and not otherwise.” Chesapeake & Potomac Tel. Co. of Va. v. United States, 228 Ct.Cl. 101, 109, 654 F.2d 711, 716 (1981). Consideration is present only when the “contract is fully performed as agreed.” 228 Ct.Cl. at 108, 654 F.2d at 716 (internal quotation and citation omitted). “A claim is discharged by accord and satisfaction when ‘some performance different from that which was claimed as due is rendered and such substituted performance is accepted by the claimant as full satisfaction of his claim.’ ” England v. Sherman R. Smoot Corp., 388 F.3d 844, 849 (Fed.Cir.2004) (citing O’Connor v. United States, 308 F.3d 1233, 1240 (Fed.Cir.2002)).

The 1992 ACRs²⁵ had the same projected acceptance rates as in the 1991 ACR, and again assumed acceptance at an MRS facility in 1998, if the statutory conditions were removed. As in the 1991 ACR, DOE admitted that “[i]f the current linkages between MRS facility construction and repository construction authorization are maintained, it is estimated that facility operations and initial acceptance of SNF by DOE could not start until at least 2007.” (PX 10 at 3; PX 11 at 3.) And, as in the others, the 1992 ACR stated that, “[a]s specified in the Standard Contract, the ACR is for planning purposes only, and, thus, is not contractually binding on DOE or the Purchasers.” (PX 10 at 1-2; PX 11 at 1-2.)

By 1994, MRS siting efforts “effectively ceased.” (Tr. 1773 (Kouts); Tr. 1978-79 (Za-bransky).) By 1998, no MRS was included in DOE’s program planning; efforts to construct an MRS terminated. (Tr. 1833-35, 1839-40 (Kouts); PX 78 at 3,13-15.) Nevertheless, the projected nominal acceptance rates in DOE’s 1994 combined ACR/APR were the same as in the 1991 and 1992 ACRs. (PX 13 at 4 (dated March 1995).) Unlike prior ACRs, however, quantities were not tied to specific calendar years. Instead, the initial projected rate of 400 MTU was for ‘Tear 1,” 600 MTU for ‘Tear 2” and so on. “In the previous ACR, the projected nominal acceptance rate was based on the assumption of SNF acceptance beginning in 1998 at a[n][MRS] facility prior to repository operations. Due to the uncertainty associated with the date of commencement of operation of the waste management system, the annual nominal waste acceptance rates are presented by year(s) of operation of the system rather than by specific calendar year(s).” (PX 13 at 3-4; Tr. 1969-70 (Zabransky) (language added because of uncertainty regarding the first year of operations).) Once again, the 1994 ACR/APR cautioned that, “[a]s specified in the Standard Contract, the ACR is for planning purposes only and, thus, is not contractually binding on either DOE or the Purchasers.” (PX 13 at 1.) However, it also provided that “[tjhese capacity allocations, as listed in the ACR, form the basis for the Purchasers’ submittal of [DCSs].” ([Id.)

DOE’s most-recent (at the time of trial) ACR/APR issued in July 2004 has an acceptance rate of 3000 MTU within five years of the predicted 2010 repository opening, starting with 400 MTU, then 600 in 2011, 1200 MTU in 2012, 2000 MTU in 2013 and then 3000 MTU annually from 2014 to 2019. (PX 14 at 2.) Again, “[a]s specified in the Standard Contract, the ACR is for planning purposes only and, thus, is not contractually binding on either DOE or the Purchasers.” {Id. at 1.) In July of 2004, DOE, predicting that the Yucca Mountain repository would begin operation in 2010, resumed the DCS process. (PX 179.) Utilities were directed to use the 2004 ACR as the basis for their DCS submittals and encouraged to submit DCSs for all allocation years “to assist us in our planning efforts.” (PX 179 at 1.) However, new DCS submissions were required, replacing any previously approved.²⁶ “DOE recognizes that many Purchasers have submitted and DOE has approved DCSs based upon the January 31, 1998 operations date included in the Standard Contract. Purchasers should submit new DCSs based upon the currently planned operation date of 2010.” {Id., General Instructions at 2.) No DCSs were subsequently approved. (Tr. 2001 (Za-bransky).) DOE has not approved any DCSs since March of 1997. (Zabransky Dep. 636-37, Apr. 19, 2002 (PDD 42); Barrett Dep. 1095-97, May 8, 2002 (PDD 4); Brownstein Dep. 375, Apr. 10, 2002 (PDD 8); Cole Dep. 204, Mar. 12, 2002 (PDD 11); Klein Rule 30(b)(6) Dep. 104-05, 109-10, April 24, 2002 (PDD 13).) Accordingly, since 1997, it has been impossible for a utility to have an approved DCS. {Id.) And, “[u]ntil there is an operational date that the department ... can stand behind, I don’t believe that we’re going to initiate the process again.” (Tr. 2002 (Za-bransky).) Zabransky wrote to plaintiffs on August 14, 2002, that DOE did not intend to issue a new ACR at that time, nor issue allocations for years 2008 and 2009. (PX 103.) Accordingly, even if plaintiffs came within 63 months of an allocation under defendant’s touted rate, and had submitted a DCS, assuming approval by the DOE, it would have been subsequently voided.

To date, the DCS process of the Standard Contract has not been completed. Maine Yankee Atomic Power Co., 225 F.3d at 1342 (“At present there are no schedules containing specific dates for disposing of the waste of particular companies. It is uncertain when they will be adopted and to what extent, if any, they will, or could effectively reflect the Department’s breach of the contract.”). “DOE effectively short-circuited this process by its failure to perform [the] Standard Contract.” Tennessee Valley Auth. v. United States, 69 Fed.Cl. 515, 521 (2006) (citing Tennessee Valley Auth. v. United States, 60 Fed.Cl. 665, 674 (2004)). See also System Fuels, Inc. v. United States, 66 Fed.Cl. 722, 731 (2005) (discussing suspension of the DCS process and voiding of those previously approved); Entergy Nuclear Indian Point v. United States, 64 Fed.Cl. 515, 519-20 n. 6 (2005) (discussing suspension of DCS process and brief reprise in 2004 requiring new DCSs to replace, not supplement, prior submissions); Consumers Energy v. United States, 65 Fed.Cl. 364, 368 (2005); Entergy Nuclear Generation Co. v. United States, 64 Fed.Cl. 336, 341 (2005).

Plaintiffs’ mitigation

Plant Hatch ISFSI

As previously noted, utilities needed empty space in their spent fuel pools to operate—to unload and load fuel, and for inspections and repair of the reactor. Up until the early 1990s, loss of room did not appear to be an issue. Company documents did, however, note when pools would lose one FCR. (DX 38, 39, 101, 104, 106, 312, 313, 324.) Loss of two FCRs was noted for Plant Hatch. (PX 789, 800; DX 208.) Plaintiffs monitored DOE’s planning and positions. Uncertainty ripened into reality. When it became apparent that DOE was not going to commence performance by January 31, 1998, plaintiffs had two options: (1) allow their spent fuel pools to completely fill which would force a shutdown and loss of the most cost-efficient and emission-free source of electricity, or (2) obtain additional storage.

There was concern in Plant Hatch’s 1994 fuel storage task force study about DOE delays and its position that it had no obligation to commence performance. A repository would not be available until 2010 and perhaps much later. Loss of two FCRs was projected for the Fall of 1998, with loss of a single FCR in 2001. Pool capacity would be exceeded in the Fall of 2003. (DX 154, 158.)

A Strategic Plan was prepared each year to advise owners of the overall status of the plants. (Tr. 152; PX 789 (Long).) Hatch’s 1997 Strategic Plan stated that because of DOE’s partial breach, additional SNF storage was needed. “The capacity of the spent fuel pools [will] be exceeded with discharges scheduled to occur in 2003. Because of [DOE’s] continuing delays or the lack of a feasible alternative offsite storage option, Hatch intends to add dry cask storage capacity by as early as 1999.” (PX 856 (Hatch Strategic Plan, May 1997) at 10.) Dry storage was classified as a “mandatory” and “major” project with capital expenditures of nearly 25 million dollars through 2002 expected. (Id.) “This mandatory project is needed to support normal operations in accordance with prudent utility prac-tice____ Future expenditure beyond 2002, could include additional dry cask storage capacity based on U.S. DOE actions.” (Id.)

[DOE] has contracted to dispose of Plant Hatch’s spent fuel in a permanent repository, which is not expected to be available before 2010. Following a lengthy period of increasing uncertainty regarding when DOE would begin spent fuel pickup, DOE formally announced in December 1996 that it would not commence spent fuel pickup in 1998, as originally committed. This announcement followed DOE’s decision not to further appeal the ruling by the U.S. Court of Appeals in July 1996 that DOE indeed had an obligation to commence spent fuel pickup in 1998. Industry efforts continue to compel DOE to commence spent fuel pickup starting as close to 1998 as feasible, including more industry dialogue and work groups, new legislation, and additional legal action. Southern Nuclear is also part of a joint utility corporation effort to develop a private spent fuel storage facility for operation as early as the year 2002.

(PX 789.)²⁷ Because of DOE’s delays, and lack of confidence in future commencement of performance at a reasonable rate, after exploring alternatives, long-term dry storage was also selected first at Plant Hatch, then at Plant Farley and Plant Vogtle. (Id, Farley Strategic Plan, May 1997 at 15; PX 800 Vogtle Strategic Plan, April, 1997 at SN 152238.)

Dry cask storage, as opposed to wet pool storage, is the containment and storage of SNF in giant casks on large concrete pads adjacent to the reactor buildings. Dry cask storage facilities, also known as independent spent fuel storage installations (“ISFSIs”), were constructed at Plants Hatch and Farley to store huge, highly-engineered storage casks containing shielded SNF. As detailed at trial, ISFSI construction is a massive project, requiring licensing and inspection by the NRC. Planning and decision-making preceded ground-breaking by years. Demonstratives, numerous photographs and witness testimony are credited in the court’s consideration of the magnitude of these endeavors and the time to plan, license, test, train and then commence and complete construction.²⁸ (Tr. 1153-54 (Bland—Plant Hatch); Tr. 1195-96 (Bland—Plant Farley); Tr. 1297-1325 (MeCallum-Plant Vogtle).) There were many unknowns in this process, particularly since this was a new, relatively untested endeavor. (Tr. 1153-54 (Bland).)

The ISFSI at Plant Hatch includes four pads, roughly adjacent to the plant site, each approximately 31 by 96 feet, made primarily of steel and specialty concrete. (Tr. 1195-96 (Bland); Tr. 2387 (Johnson).) Three ISFSI pads were built at Plant Parley; each pad can hold up to twelve casks in a two-by-six array. (Tr. 1318-19 (McCallum).) The Plant Farley ISFSI was constructed in 2004; cask loading costs began in 2005—beyond the December 31, 2004 current cost-incurred damage period. Plant Vogtle procured and installed additional racks for its wet pool from 1998 through 2000 which increased its storage capacity. (Tr. 167-68 (Long); Tr. 278-83 (Cocherell).) This additional wet storage capacity postponed the building of dry storage at this plant until 2015. (Tr. 1613-14 (Metcalfe).)

Because of long lead times, planning for Plant Hatch began in the late-1990s. (Tr. 1153-54 (Bland).) Mr. Bland, project manager for the Plant Hatch dry storage project beginning in August of 1997, testified about the decision-making process and implementation. The number of assemblies in the spent fuel pool was a given, as were additions to the pool from future core off-loads, although increased efficiencies in fuel-burnup in the reactor core extended the time between discharges. Bland also had a mandate that he “shall not allow single-core offload capability to disappear. We need that to ensure availability of these assets to make electricity.” (Tr. 1163 (Bland).) It was assumed that plant would remain operational at least until the end of its plant life—2013 when its NRC license expired. A license extension would, however, add an additional twenty years of operation and attendant production of SNF. Based on feedback from those dealing with DOE, he assumed storage needs would exist throughout that time. His analysis would have changed with confidence that DOE would appear at a fairly certain date and pick up a fairly certain amount of SNF.

Q. Would it have changed your analysis about what kind of system you needed to design or develop if you had assumed DOE would appear at a fairly certain date and pick up a fairly certain quantity of fuel?

A. Oh, sure. The realities of an engineering job are that you start with a set of input parameters and those needed outcome and you create a solution that’s cast around them. If you change the desired outcome or change the input parameters, it can change your entire solution. Let me give you a specific example of that. Say today you were asking me to build a boat that I was going to personally live on. Now, if you tell me that I’m going to need to be on this boat for the next six hours, I’m going to create probably a raft, because I don’t have a lot of time and I’m not going to be on it that long. If you tell me I’m going to live on this boat for the next six years, if I could afford it, I’m going to build a very large yacht, because I have to live on it.

(Tr. 1165 (Bland).)

Mr. Bland discounted utilizing unused areas of the spent fuel pool where operational tools were stored. At best, this small area would only be a stop-gap measure. (Tr. 1159-60 (Bland).) Also, additional reracking, handling all the assemblies and placing them in denser arrays with the acquisition of more compact racks, was rejected because of risk to the plant and the public. (Tr. 1160 (Bland).)

Dry storage, the chosen option, was reasoned and reasonable, although it was a complex, time-consuming and expensive endeavor fraught with many unknowns. Constructing and implementing a dry storage system is not unlike licensing and building a new nuclear power plant.

The container or cask system in which the SNF assemblies are placed and stored is another major component of a dry storage system. There was also unpredictability in this relatively new and evolving technology. During the planning and initial acquisition period here, there were only six cask vendors. Two were shutdown by the NRC; one recently emerged from an NRC-issued shutdown for quality issues and one was in bankruptcy. Two of the then six existing reactors with ISFSIs had been shutdown for over a year due to problems with their selected cask vendors. Some nuclear utilities had failed in them attempts to implement dry storage systems. (Tr. 956-57 (Wade); Tr. 1164-67 (Bland).) Accordingly, planning included a two-year buffer for unexpected contingencies.

A cask vendor proposal request was issued in August of 1997 for Plant Hatch; offers were received in October 1997; Holtec International was selected to provide the dry-cask storage system and a contract was signed in January of 1998.²⁹ (PX 288.)

At this time Holtec was developing two types of casks—the HI-STAR and the HI-STORM. Defendant alleges that the selection of the HI-STAR at Plant Hatch was unreasonable and the costs attendant that system and its implementation should not be included in damages. The difference in cost of the HI-STAR versus the HI-STORM is considerable. HI-STAR casks cost approximately $1.15 million each. (Tr. 2294 (Johnson).) HI-STORMs cost about $620,000. (PX 414 at SNC002615; Tr. 2329-30 (Johnson).)

Mr. Bland testified the decision to initially purchase and load three HI-STAR casks was because the HI-STAR was further along in the NRC review process, principally because Dresden, a nuclear power plant in Illinois owned by Commonwealth Edison, had selected the HI-STAR for its decommissioning.³⁰ Early in 1999, the two overpack components of the HI-STORM that differentiated it from the HI-STAR were lagging behind the HI-STAR and it was not known when the HI-STORM would be licensed. “Since the HI-STAR was being used by Commonwealth at the time, it was further through the review process. In fact, the HI-STORM was nowhere in the process [when] we made our procurement decision.” (Tr. 1178 (Bland).)

The court credits the testimony of Mr. Long and Mr. Bland concerning the selection of the HI-STAR:

To create a facility—again remember our end date, which was the summer of 2000, we needed to have loaded three systems to maintain single-core offload. To be able to achieve that requires a long line of successful activities. We’ve got to build these pieces of equipment that can take as much as a year to do. We’ve got to construct the facilities on which they’re doing it, which again can take as much as a year to do. We have to—before we can do either of those, we have to produce the designs under which we’ll do that work, which takes from six months—six to nine months to do. So in reality, for a load to occur in the summer of 2000, we’re back in mid '98, late '98, no later than early '99 making decisions about what we’re going to load or we’re not going to make it.

Q. All right, sir. And this is in early '98,

A. That’s correct.

Q. Okay. And do you recall in early '99 where HI-STAR was in that process.

A. In early '99, we had gotten the NRC to agree that it was safe. I don’t think we had yet the certificate done, not even sure we were very far through the rule-making process. It’s a little bit fuzzy, but we really got a lot of that stuff towards the end of '99, early 2000.

Q. And where was HI-STORM?

A. HI-STORM was lagging____ [W]hat the review for the HI-STORM was focusing on was the other two overpack components that are unique to the HI-STORM. But they still required review because they did provide safety functions and they still required evaluation. And even once that was complete, they had to go through this rule-making process as well because they were unique components with regard to that work too. And so to my memory, at least in the '99 time frame that—well frankly, that process is hard to predict, you know? Because as long as there’s one more question on a technical reviewer’s mind, even if there’s only one question, it could be three years before you get a final answer. So you can’t very well predict ruling making and evaluation process, you can only try your best to manage it.

(Tr. 1180-83 (Bland).)

Mr. Long also testified that the HI-STAR was selected initially because it would likely be licensed first:

Q. [A]t the time you had to make a decision about what kind of overpack you were going to use, where was the HI-STORM compared to the HI-STAR in terms of regulatory approval.

A. [The HI-STORM] was behind [the HI-STAR], Because all—the HI-STORM didn’t get licensed until like 2000, at the time we loaded our cask for the HI-STAR. So it’s licensing was behind____We would have been—well, we picked the system that was going through the licensing process first, that was due to get out first, so it could be licensed on our site where we could use it. And we were in a rush for time. So that’s why we chose to do what we did.

(Tr. 180 (Long); see also DX 217.)

That the HI-STAR was further in the NRC licensing process was a reasonable factor in the mitigating decisions for Plant Hatch. NRC licensing is time-consuming and the outcome can be uncertain. There is a technical review by NRC staff for health and safety concerns. A safety evaluation report is produced which can take three to six months. There is an opportunity for public input—a Part 72 rule-making process, after which a certificate of compliance may be issued.

An additional factor in selecting the HI-STAR was its transportability. (Tr. 185 (Long).) The HI-STAR cask is dual-purpose, licensed for both transportation and storage. A HI-STORM cask is licensed only for storage. (Tr. 173-74 (Long); Tr. 907 (Wade).) The objective was to get the SNF off-site as soon as possible. There was never an intention to have dry storage at Plant Hatch until DOE’s impending partial breach required this additional capacity be established. The court also rejects defendant’s assertion it was unreasonable to purchase the HI-STAR which can be transported off-site, because DOE subsequently stated it will not accept transportation casks. At the time the decision was made to purchase the HI-STARs, DOE had not yet announced that it would not accept transportation casks, and indeed was encouraging the use of multipurpose containers. Furthermore, as DOE has subsequently announced that it will not accept SNF in canisters (Zabransky Dep. at 55, 4/12/2005 (PDD 45)), the HI-STAR casks could be used to ship SNF off-site to be removed from the canisters in preparation for delivery of the SNF to DOE. (Tr. 173-74 (Long).)

HI-STARs each weigh about 125 tons and are about 7}£ feet in diameter. They arrive on-site by specialized railcar in a horizontal position and are “upended” to vertical. The tremendous weight and size of the casks required modifications to the plant and construction of a rail spur. Suitable cranes and other equipment, including an upender pad, were needed. This required additional design and engineering work. (Tr. 891 (Wade).) Three HI-STARs were purchased and loaded at Plant Hatch.

To load a HI-STAR, assemblies filled with SNF are taken from racks in the pool and loaded into a metal canister in the pool that is then welded shut, dried and filled with helium. A HI-STAR cask is lowered into the SNF pool for loading of the filled canisters. (Tr. 1202-03 (Wade).) The HI-STAR is transferred out of the fuel building in a horizontal position and then upended on an upender pad at the ISFSI. (Tr. 1237 (Bland).)

The HI-STORM was licensed in June 2000. (Tr. 180, 184 (Long).) HI-STORMs each weigh 175 tons and have roughly a 10-foot diameter footprint. (PX 414 at SNC002615; Tr. 2329-30 (Johnson).) Anticipating its eventual licensing, the ISFSI was designed to accommodate the heavier HI-STORM.

Prior to December 31, 2004, nineteen HI-STORMs were purchased and loaded at Plant Hatch. The first four HI-STORM casks were loaded in June 2001, prior to the September 2001 discharge from Unit 2. (Tr. 983 (Wade).) Unlike the HI-STAR, the HI-STORM is not lowered into the pool. A HI-TRAC transfer cask is lowered into the pool and the loaded canister is inserted. The HI-TRAC is removed from the pool and the canister is welded shut, dried and filled with helium. The HI-TRAC transfer cask is then placed on the top of the HI-STORM cask; the bottom of the HITRAC is opened and the canister is lowered into the cask. The HI-STORM is then transferred to and placed on the ISFSI. In connection with the loading of the HI-STORM casks, significant costs associated with equipment, plant modifications, and NRC dry runs and inspections were incurred. (Tr. 1118-19 (Wade).)

Defendant argues plaintiff should not have ordered and loaded the three HI-STARs but should have waited and used the less-expensive HI-STORMs. Based on defendant’s economist Dr. Neuberger’s simulations and conclusion that Plant Hatch could have waited longer before it selected the initial three HI-STAR casks, defendant’s accountant Mr. Johnson, calculated the costs attributable to the HI-STAR that would not have been incurred if only HI-STORM had been selected. Neither Dr. Neuberger nor Mr. Johnson have any particular nuclear experience and did not opine on the reasonableness of these expenditures. Rather, Mr. Johnson parsed costs associated with the HI-STAR that, in his opinion, would not have been incurred with the HI-STORM. HI-STAR specific costs include: (i) cask procurement costs ($3,458,904) (Tr. 2294-95 (Johnson)); (ii) Southern Company HI-STAR-specific engineering work ($50,362) (Tr. 2277-78 (Johnson)); (iii) Williams labor related to HI-STAR ($135,696) (Tr. 1010 (Bland)); (Tr. 992-93 (Wade)); (iv) construction of HI-STAR upender pad ($803,404) (Tr. 1235-36 (Bland)); (v) gantry crane rails for upender pad ($105,697) (Tr. 1094 (Wade); see also DX 308); (vi) Holtec NRC demonstration costs ($1,125,407) (Tr. 1104-06 (Wade)); (vii) NRC demonstration costs ($606,897) (id); (viii) leased railcars for HI-STAR loading ($108,-645) (Tr. 1092-93 (Wade)); (ix) 900 Gantry Crane used for loading ($80,752) (Tr. 1094 (Wade); see also DX 239); (x) HI-STAR closure materials ($161,784) (Tr. 1246-49 (Bland)); (xi) leased Manatowak crane for loading campaign ($682,887) (Tr. 1095-96 (Wade); see also DX 256); (xii) HI-STAR cask cradle cancellation charges ($168,240) (Tr. 1097-98 (Wade)); (xiii) cancellation charges due to transition in lifting equipment from HI-STAR to HI-STORM operations ($30,606) (Tr. 1099-1100 (Wade)); (xiv) HI-STAR cask cradle ($225,983) (Tr. 1097-98 (Wade)); (xv) metal plates used to test HI-STAR cask cradle ($99,732) (Tr. 1244-45 (Bland)); (xvi) Holtec engineering analyses related to the HI-STAR system ($57,583) (Tr. 2295-96 (Johnson)); (xvii) cradle drop analysis for HI-STAR ($125,000) (Tr. 1097-98 (Wade)); (xviii) leased railcar to transport HI-STAR casks to the plant site ($87,500) (Tr. 2296-97; PX 422 at SNC004649); (xix) Williams labor for maintenance of HI-STARs ($15,713) (Tr. 1246 (Bland)); (xx) Holtec delay charges related to loading campaign ($280,000) (Tr. 1103-04 (Wade)); (xxi) materials related to loading ($50,491) (Tr. 2304-05 (Johnson)); (xxii) Williams labor relating to loading ($477,172) (Tr. 2303-04 (Johnson)); (xxiii) other contract labor related to loading ($595,063) (Tr. 2304 (Johnson)), and other costs and a credits, as itemized on page 99 of plaintiffs’ Post-Trial Brief, for a total of $14,919,855 in proposed reductions to plaintiffs’ requested mitigation damages.

When initial decisions to acquire the HI-STARs were made, Plant Hatch had enough room in the pool to maintain one FCR through the next scheduled refueling outage and discharge in 2001. Engineering and licensing work for the Plant Hatch ISFSI began in 1998; construction was complete in mid-2000. (Tr. 159 (Long).) Three HI-STARs were purchased in late 1998 and loaded with 204 SNF assemblies and placed on the ISFSI through the summer of 2000. (PX 657 at KRG00697, 701.) By December 31, 2004, a total of twenty-two casks had been purchased, loaded with a total of 1496 assemblies, and installed on the ISFSI pad. (Tr. 1508-10 (Metcalfe).) Because Plant Hatch did not lose one FCR until September of 2001, and because the less expensive HI-STORMs became available in June of 2000,³¹ defendant argues that waiting would not have been unreasonable. Indeed, four HI-STORMs were loaded in September of 2001. The decision to build the ISFSI and order the three HI-STARs was made in 1998 and early 1999. (Tr. 1187-88 (Bland)) (“Q.... [A]m I correct that in early '99, you had to make your final decision between HI-STAR and HI-STORM? A. Yes. Q. Had the license work for the two bathtub racks been completed? A. No, it had not.”); id. at 1222-26 (Bland) (“Plant Hatch must have the capability to begin loading the [dry cask storage system] by June 2000 to avoid the loss of single-core offload capacity.”) Southern’s April 13, 1998 letter from Lewis Sumner, Vice President Hatch Project Support to Charles Haughney, Director, Spent Fuel Project Office, Office of Nuclear Materials Safety and Security at the NRC, stated that Plant Hatch must begin loading casks in June of 2000 to avoid loss of FCR. (DX 217.) In planning to load casks a few months before loss of FCR, allowance was made for any unexpected delays in licensing or construction of the ISFSI or licensing, acquisition and loading of casks. (Tr. 955-57 (Wade).) Although the licensing process was underway to authorize the installation of racks that would extend the time of loss of FCR for 12 to 18 months, that process had not been completed when the dry storage decisions were made, and neither the timing nor the result was certain. (Tr. 1223-26 (Bland).) Faced with these circumstances in 1998 and early 1999, Southern’s experienced nuclear engineers and plant managers made the reasonable decision to purchase three HI-STAR casks, related services and equipment.

Defendant’s hindsight does not negate plaintiffs’ reasonable mitigating decisions. After-the-fact criticism by the breaching party is irrelevant so long as the mitigating decisions were reasonable.

It is a bedrock principle of mitigation of damages, however, that even where the plaintiff bears the burden of mitigation, such Monday-morning quarterbacking is irrelevant to an award of mitigation costs. See, e.g., E. Allan Farnsworth, Contracts § 12.12 (3d ed. 1999) (“[A] party that takes steps that seemed reasonable at the time will not be judged by hindsight.”) As the Third Circuit explained in In re Kellett Aircraft Corp.:

Whether or not the buyer’s obligation to mitigate damages has been discharged depends on the reasonableness of its conduct. In this connection, reasonable conduct is to be determined from all the facts and circumstances of each case, and must be judged in the light of one viewing the situation at the time the problem was presented. Where a choice has been required between two reasonable courses, the person whose wrong forced the choice can not complain that one rather than the other was chosen.

186 F.2d 197, 198 (3d Cir.1950) (footnotes omitted).

Citizens Fed. Bank v. United States, 66 Fed.Cl. 179, 185 (2005) (alterations in original, other footnote omitted), aff'd, 474 F.3d at 1314 (Fed.Cir.2007).

Mr. Bland presented the foregoing analysis of options leading to the initial selection of the HI-STAR to the NRC. (PX 238.) That defendant does not point to any objection by NRC speaks to the reasonableness of these decisions and their implementation. Crediting the testimony of the decision-makers, the court concludes that the decisions to build dry storage, and implementation with HI-STARs and then HI-STORMs, was reasonable. While defendant asserts the three HI-STARs, or a number of the subsequently-acquired and loaded HI-STORMs, and their accompanying charges, were either not caused by DOE’s partial breach, or an award of these costs would be a windfall, defendant does not disagree that these costs were incurred.

Dry cask storage was new and complex. Long lead-times were planned to accommodate ISFSI engineering, licensing and construction as well as the design, implementation and execution of SNF-loading—a host of unknowns. Application had been made to license and install a bathtub rack which would have increased storage capacity in the wet pool by 167 spaces. However, at the time the initial decision to acquire the three HI-STARs was made, that process was not completed. NRC license approval for those additional racks was finalized in March of 2000. By adding 167 additional spaces with the approval and then installation of the bathtub rack, Plant Hatch then anticipated loss of a FCR with the next-scheduled refueling discharge in early 2001. This rerack postponed the loss of full core reserve from Fall of 2000 to the end of the Fall 2001 “an important achievement.” (PX 363.) A second bathtub rack, which was approved, was not used, in part to preserve operational flexibility. (Tr. 157 (Long).) Also, by this time, cask loading had begun. (Tr. 160 (Long); 1180 (Bland).)

The court concludes that the decision to build the ISFSI at Plant Hatch was caused in substantial part by DOE’s delay, and that but for the partial breach—in the nonbreach world, plaintiff would not have built it. In this regard, the court credits Mr. Long’s testimony that the dry storage decisions would not have been made if DOE’s commencement of performance had not been delayed. If DOE had timely commenced performance, a second bathtub rack would have been installed to accommodate discharges for the relatively short time until DOE’s accepted SNF from this plant. The cost of the second bathtub rack was deducted from damages. Rather than build expensive dry storage, any loss of FCR would have been tolerated because DOE’s continuing performance in the nonbreach world would have restored FCR in a relatively short time. The court credits Mr. Long’s testimony:

This whole business of ISFSI and having to store these casks out in rods, or out in the yard is not part of our core business. It is something we’re being made to have to do because [DOE] did not come and pick up our fuel and we would not be in that business but for that. And if there was a choice where I didn’t have to build an ISFSI and I had to put in, you know, a second set of racks for a while, in the unit 1 pool, I probably would have selected to do that rather than go out and build this thing out there.

(Tr. 160-61(Long).) Upon consideration of the testimony and evidence, the court concludes defendant did not establish the decision to acquire the three HI-STARs was unreasonable. The decisions at Plant Hatch in this regard were foreseeable, substantially caused by DOE’s partial breaches, were reasonable, and the costs were established with reasonable certainty.³²

Cask loading schedule at Plant Hatch

Once its ISFSI was constructed, Plant Hatch made an operational decision to load more than simply enough to reach one FCR—at a schedule approaching two FCR. Defendant argues this level of loading was an independent business decision, and as in Indiana Michigan, not caused by DOE’s partial breach. Defendant asserts that only nine casks were necessary or caused by the breach at the acceptance rate DOE argues it would have performed. Defendant also calls Plant Hatch’s positions inconsistent or disingenuous, by arguing loss of one FCR as the “floor” for ISFSI causation purposes, yet ordering and loading casks at a more aggressive schedule.

Witnesses testified about operational loading decisions. First, because both units at Plant Hatch have the same reactor model, an NRC directive or other requirement to inspect both reactors at the same time, would require the offloading of both reactor cores simultaneously, utilizing two FCRs. (Tr. 955 (Wade).) The economic cost of any such simultaneous shutdown would be significant. (Tr. 145-49 (Long).) At the time of trial however, Plant Hatch was operating at less than two FCR, evidence defendant uses as support for its position the loading schedule was excessive and not caused by DOE’s partial breach. Southern contends that its actual loading of twenty-two casks (holding a total of 1496 assemblies) was reasonable (and not unreasonable) in light of its long-term goal of dual-reactor off-load capability. (Tr. 309 (Cocherell), 1531, 1508-10 (Metcalf); PX 657 at KRG00697, 101.) Mr. Long testified that there is a difference between operating at one FCR reserve in the short-term, versus planning for a higher reserve in the long-run, particularly as plants age.

Q. Well, if it is so important to have dual core off-load capability, why haven’t you recovered it already [at Plant Hatch]?

A. Because it is a risk management kind of decision that you make. Not all decisions are black and white. There is a probability of having to off-load one core at a time. There is a less probability to have to off-load two simultaneously.

But as our plants grow older, get older, I think that the probability increases, and, therefore, we made a short-term judgment that we can live with something happening and us being able to kind of manage through that problem by doing this, and this, but we would really like to have dual core off-load capacity. So we’re working as a matter of policy to try and, for our system, to have the capability.

(Tr. 148^9 (Long).)

Another asserted reason for working toward a FCR per reactor is to guard against contingencies in the cask loading process that could impact operational reliability, such as late arrival or defect in casks or canisters, unavailability of internal or contract labor, malfunctioning of cranes, helium evaporators or other equipment or NRC stop-work orders. The NRC stopped cask loading for over a year at another plant. (Tr. 1163 (Bland).) Also, Southern’s managers balanced the cost of paying earlier, rather than later, for casks and loading. (Tr. 147 (Long); Tr. 956-57 (Wade).)

During each refueling outage, Plant Hatch loads approximately three and one-half casks. Therefore, if Plant Hatch maintained an operating reserve of only one FCR total for its shared pool, an unexpected delay in a single loading campaign, followed by a regular discharge of SNF, would bring the operating reserve below one FCR. In that event, a need to offload the core of either reactor would force that reactor to shut down. (Tr. 957-58 (Wade); 136-39 (Long).) If DOE had performed at the 3000 MTU rate, as of December 31, 2004, more SNF would have been removed from Hatch than Southern actually loaded. (Tr. 2117-18 (Neuberger).)

Defendant did not present any witness from the nuclear industry to testify what a reasonable cask loading schedule would be or would have been. Defendant points to a 1992 document indicating that the need for a two core reserve, one for each reactor, was not credible. Mr. Long testified that “as time goes on, the industry is finding things that are unexpected. There is a possibility that some issue might be found that a TVA Browns Ferry reactor, that Nuclear Regulatory could say, hey, look, this thing could be a generic problem facing all BWRs [boiling water reactors] of that vintage, like our Plant Hatch, you all need to go fix this thing.” (Tr. 146 (Long).)

Q. [I] f you don’t have that [two FCR] now, what would you have to do if you needed to shut down both reactors at the same time and remove the cores?

A. What I would have to do is off-load one core, fix the problem on that unit, and reload that core and then go the next unit, off-load that core and fix that unit. And then, you know, that’s just time and money, just takes additional time to do that.

(Tr. 149 (Long).)

Mr. Wade, the Southern engineer who managed the loading at Hatch, testified: [A] single core off-load would take about three years to use up during normal refueling operations. About that amount of time is what we estimate to qualify and select and test a cask from a new vendor. So the second full core off-load, not only does it give us the capability to off-load both reactors at the same time, it also gives us some margin for some contingency in case Holtee goes out of business or if they are required—or if they can’t supply casks to use any longer.

[To change cask vendors], you would have to redo the entire operational evaluation. You would have to do a licensing evaluation, go through planning. You would have to go through evaluation of the building of the structure. You would have to do [an] evaluation of the concrete pads at the ISFSI itself. Particularly [if] the ISFSI is designed for a single cask vendor’s casks. So all of those evaluations would have to be redone as a prerequisite to being able to load a cask from another vendor.

(Tr. 956-57 (Wade).) These concerns are not unreasonable. Several nuclear utilities have had to change cask vendors. (Tr. 956 (Wade); Tr. 1166-67 (Bland).)

The trial court opinion in Indiana Michigan, 60 Fed.Cl. 639 (2004), aff'd, 422 F.3d 1369 (Fed.Cir.2005), is cited by defendant in support of its argument that the court should reject plaintiffs two FCR policy, calling it a “litigation reserve.” (Def.’s Br. 175-76.) In Indiana Michigan, defendant presented expert testimony as to the size of the utility’s reserve. In contrast here, the defendant withdrew its nuclear expert and offered no expert testimony in this regard. Dr. Neuberger, defendant’s economic expert, disavowed any nuclear expertise. (Tr. 2033-34 (Neuberger).) Secondly, the loading schedule at issue in Indiana Michigan was in the future (2009-10); here the loading actually occurred and two FCRs were calculated and monitored since 1992—six years before the Complaint was filed. Because Indiana Michigan had not built an ISFSI, or purchased or loaded any casks, or spent any of the millions it claimed in future damages, and testimony as to the utility’s plans was contradictory, the court looked for written evidence that an ISFSI would be built in order to maintain the 2.9 FCR reserve advanced, and found none. 60 Fed.Cl. at 655 (concluding Indiana Michigan’s future reserve policy and need for an ISFSI was generally not credible). In contrast, an ISFSI was built at Plant Hatch, casks were purchased and loaded, internal documents tracked different reserve levels, including two FCR, and witness testimony in this regard was presented.

The court credits testimony that from a long-term operating perspective, it was not unreasonable to load more than the minimum. It may be that with equipment and personnel on-site, economies of scale and efficiency affected loading quantities. Witnesses testified operations decisions were not litigation-driven. Defendant does not point to any evidence that loading was accelerated for litigation purposes. There was no evidence that this was an unreasonable way to run a nuclear power plant and, as counsel quipped, we are not storing marbles in this pool—this is radioactive nuclear waste. Plaintiffs’ counsel used the “idiot light” analogy—one does not go to the gas station and just buy enough gas to get the light to turn off. You fill up the tank or at least get more than the minimum—particularly when you know that the next gas station is on the far horizon. That defendant did not establish that this cask-loading schedule was not commercially reasonable is another reason for including these costs in mitigation damages.

Regardless, the court concludes that with DOE’s admitted commencement of performance delayed until 2017 (and perhaps 2018), there is no question the casks that were loaded would have to be acquired and loaded in any event; accordingly, there is no windfall. Loading was caused by DOE’s delays and the costs were incurred. Indiana Michigan limits damages to costs incurred. If recovery is not obtained now, there may be statute of limitations issues if the incurred costs were claimed later. The Federal Circuit foresaw this possibility and counseled: “subsequent claims for future damages are considered to accrue for the purposes of the statute of limitations at the time such damages are incurred. Accordingly, Indiana Michigan must bring any future actions for damages related to DOE’s breach of the Standard Contract within six years of incurring such damages.” 422 F.3d at 1378.

Even at the 900 MTU annual rate defendant advocates, the amount of SNF at issue would have been loaded to the ISFSI at some time prior to commencement of DOE’s now-projected performance in 2017-2018. Plant Hatch loaded 22 casks containing 1496 assemblies. (Tr. 309 (Cocherell); Tr. 2122, 2152 (Neuberger).) Plant Hatch’s allocations reach 1496 with the 181 assemblies allocated to Hatch when DOE’s cumulative total acceptance reaches 12,050.50 MTU. (PX 9 at 1412.) Assuming for ease in calculation, a steady 900 MTU rate, it would (or will) be approximately 13.4 years after commencement of performance before that total tonnage is accumulated. DOE’s projected start date of 2017 is a 19-year delay; 2018 is a 20-year delay. There is no possible windfall. This is more evident when it is recognized that the 1991 ACR rate was impossible to implement and cannot be used to define DOE’s performance had there been no partial breach.

Plant Farley ISFSI

Like the Strategic Plan for Plant Hatch, the May 1997 Strategic Plan for Plant Farley reported:

Based on projected Plant Farley spent fuel discharges to current onsite storage, the last cycle at which full-core offload capability is maintained begins in 2004 for Unit 1 and 2008 for Unit 2. The capacity of the spent fuel pools would be exceeded with discharges scheduled to occur in 2010 for Unit 1 and 2013 for Unit 2. If necessary, because of the [DOE’s] continuing delays or the lack of a feasible alternative offsite storage option, additional onsite storage could be obtained, most likely using transportable dry cask storage technology. Planning for additional onsite spent fuel storage capacity at Plant Farley is expected to begin as early as 1997, with the intent to place additional spent fuel storage capacity in operation by as early as 2004.

The DOE has contracted to dispose of Plant Farley’s spent fuel in a permanent repository, which is not expected to be available before 2010. Following a lengthy period of increasing uncertainty as to when the DOE would begin spent fuel pickup, the DOE formally announced in December 1996 that it would not commence spent fuel pickup in 1998, as originally committed. This announcement followed the DOE’s decision not to further appeal the ruling by the U.S. Court of Appeals in July 1996 that DOE indeed had an obligation to commence spent fuel pickup in 1998. Industry efforts continue to compel the DOE to commence spent fuel pickup starting as close to 1998 as feasible, including more industry dialogue and work groups, new legislation, and additional legal action. SNC is also part of a joint utility corporation effort to develop a private spent fuel storage facility for operation as early as the year 2002.

(PX 865 at 15.) Substantially the same statements are” in a draft dated April 23, 1997, reflecting edits made on March 27, 1997. (PX 795.)

Tom MeCallum, Project Manager, was assigned to the Farley dry storage project in the summer of 2001. (Tr. 1269 (MeCallum).) At that point, the decision had been made to construct dry storage and bids had been received from three cask vendors. In January of 2002, Farley selected Holtec’s HI-STORM. (Tr. 1270-71 (MeCallum).)

Plant Farley has two reactors, each with a separate dedicated pool. (Tr. 134 (Long).) Unit 1 pool holds 1358 assemblies; Unit 2 holds 1386 assemblies. (PX 594 (Neuberger expert report, Ex. 3-Model Assumptions-Ae-tual Scenario).) Each reactor core holds 157 assemblies. (Id.) Unlike at Plant Hatch where only the fuel to be replaced is removed, at each refueling, the entire Plant Farley reactor core is removed and placed in the pool. (Tr. 1365-71 (MeCallum)³³.) Accordingly, each of the two Farley pools must maintain sufficient space for the 157 assemblies from the reactor core plus the new fuel to be inserted into the core—approximately 65 assemblies. (Id.) Management set a minimum reserve for each of the two Farley pools of FCR plus two reloads (157 + 130 = 287 assemblies). (Id. at 1364-77.) Defendant offered no witnesses with nuclear plant operating or management experience regarding the reasonableness of this reserve. To avoid dry storage in the nonbreach world, DOE needed to remove only one reload prior to the Fall of 2005. (Tr. 166 (Long).) Plaintiffs assert that under any acceptance rate, no dry storage would have been added at Plant Farley. (Tr. 315 (Cocherell) (DOE performance at the 1990 ACR upper bounding rate or the 2004 ACR rate beginning in 1998).)

Tom MeCallum testified that Farley’s ISFSI was completed in 2004 and the first cask was loaded in 2005. The only costs claimed at this time are the costs of ISFSI construction and of the three casks purchased as of December 31, 2004. (Tr. 165 (Long).) The same type of engineering design, licensing, procurement, fabrication, construction, testing and implementation activities were undertaken at Plant Farley as at Plant Hatch. (Tr. 1195-96 (Bland); Tr. 1297-1325 (MeCallum).) The three ISFSI pads are constructed out of highly-engineered steel and concrete, are approximately two feet thick and can hold up to twelve casks each. (Tr. 1312-19 (MeCallum).)

Damages sought for Plant Farley total $21,355,367. At or prior to trial, plaintiffs removed-several claimed costs. Mr. Johnson, defendant’s economic, expert asserted further adjustments/deductions of $7,723,886 including $4,045,589 in what defendant claims is “prejudgment interest” (referred to by plaintiffs as cost of capital); $2,822,224 for investment in Private Fuel Storage and $821,103 • for internal labor, all discussed hereinafter.³⁴ (Def.’s Br. 86 (citing Tr. 2311-16 (Johnson)).) Defendant does not contest the reasonableness of the costs incurred in building the ISFSIs and in purchasing and loading the HI-STORMs.

Plant Vogtle reracking

Plant Vogtle, the newest plant, has the least amount of SNF. Its spent fuel pool capacity was increased with the installation of an additional rack purchased and installed for several million dollars.

Vogtle’s Strategic Plan Update dated April 23, 1997, reported DOE’s announcement not to commence SNF pickup in January of 1998 as committed; the delay in the repository until 2010; continuing industry efforts to compel DOE performance as soon after 1998 as feasible; joinder with others in the industry to develop private spent fuel storage; and the acquisition of racks from Maine Yankee. (PX 800.) Vogtle would maintain FCR into 2007, but would completely fill the pool with discharges scheduled for 2008. The 1998 reracking would increase storage by some 1100 assemblies, extending storage capacity for at least ten years. “If necessary, because of DOE’s continuing delays or the lack of a feasible alternative off-site option, additional on-site storage could be obtained, most likely using transportable dry cask storage technology.” (PX 800.)

Plaintiffs’ storage mitigation decisions and expenditures were reasonable

The court concludes plaintiffs’ reracking and ISFSI decisions were reasonable mitigation given the utilities’ rational belief that DOE was not going to commence performance in January of 1998, or at any reasonably foreseeable time thereafter. Indeed, the Federal Circuit in Indiana Michigan held that at least by 1995, nuclear utility/contraet holders had an obligation to mitigate. 422 F.3d at 1375. As initiation of performance appeared more remote, exigencies reinforced the reasonableness of plaintiffs’ decisions in this regard. Sacramento Mun. Util. v. United States, 70 Fed.Cl. 332 (2006) (awarding mitigation costs without finding an acceptance rate); Tennessee Valley Auth. v. United States, 69 Fed.Cl. 515 (2006) (same); Yankee Atomic v. United States, 73 Fed.Cl. 249 (2006) (same). Nuclear power plant managers made long-range planning decisions and capital expenditures in the “real” “breach” world, not with a crystal ball prediction of exactly when or how DOE was going to perform. These mitigation decisions were substantially caused by DOE’s admitted failure to commence performance and admission that commencement of performance at whatever rate would be years hence.

In addition to proving that their mitigation decisions were foreseeable and caused by DOE’s partial breach and establishing their costs with reasonable certainty, defendant also asserts plaintiffs have a concomitant burden to prove that those costs would not have been incurred if DOE had performed—that the expenditures would not have been made in the nonbreach world. Absent such proof, plaintiffs would enjoy a windfall, defendant posits. Defendant acknowledges delays resulted in at least some mitigating efforts, but only to the extent of storage needed for the quantity of SNF that would have been picked-up under the 1991 ACR. Defendant asserts causation is limited by the level of performance DOE was espousing in the 1991 ACR-400, 600, 900 MTU. “Plaintiffs’ Burden Includes Their Obligation To Establish A Reasonable ‘But For’ World Against Which To Measure Whether DOE’s Delay ‘Caused’ Them to Incur Incremental Costs.” (Def.’s Br. 95.) Defendant reasons that because of the limitations on the total amount of SNF that could be accepted at an MRS prior to the commencement of repository operations, DOE planned to accept SNF at the rates set forth in the 1991 ACR. Accordingly, only appropriate expenses to load the amount of SNF DOE would have picked-up under the 1991 ACR were caused by the breach. (Def.’s Br. 41, 154-57.)

In many respects, the parties here quarrel over hypotheticals—about what would have happened if there had been no breach. Although “effort is made to put the injured party in as good a position as that in which he would have been put by full performance of the contract,” that effort must be “at the least cost to the defendant and without charging him with harms that he had no sufficient reason to foresee when he made the contract.” Northern Helex Co. v. United States, 207 Ct.Cl. 862, 875, 524 F.2d 707, 713 (1975) (quoting Restatement of Contracts § 329 cmt. a). Difficulties in determining what DOE would have done had the DOE commenced performance as required under the Standard Contract does not shield defendant from liability. “[W]hen damages are hard to estimate, the burden of imprecision does not fall on the innocent party.” LaSalle Talman Bank v. United States, 317 F.3d 1363, 1374 (Fed.Cir.2003). “The defendant who has wrongfully broken a contract should not be permitted to reap advantage from his own wrong by insisting on proof which by reason of his breach is unobtainable.” Locke v. United States, 151 Ct.Cl. 262, 267, 283 F.2d 521, 524 (1960).

The parties present alternative views on whether this nonbreach or “but-for” world is an appropriate inquiry and even if it is, they differ on what that world would have looked like, and how, or if, it applies in this case. Much effort is expended in urging the court to adopt a rate at which DOE would have performed starting in 1998. Defendant insists the conditional 1991 ACR is the yardstick that limits mitigation, and because plaintiffs have removed more SNF from their wet pools than DOE would have at that rate, awarding mitigation costs at the higher level would place plaintiffs in a better position than if there had been no partial breach. However, even at those rates, defendant’s economic expert admitted that over sixteen million dollars of plaintiffs’ dry storage costs would have been incurred. (Tr. 2348 (Johnson); Def.’s Br. 6 (at the 1991 rate, plaintiffs’ damages are no more than $16,707,845).) Plaintiffs insist that in the nonbreach world, DOE would have been performing at a 3000 MTU annual rate after a short rampup, and at that rate, would have removed more SNF from their pools than plaintiffs have; accordingly, plaintiffs are not in a better position than if DOE had commenced performance and there is no windfall.

Defendant conflates mitigation and causation, a position the Federal Circuit rejected in similar circumstances in First Heights Bank v. United States, 422 F.3d 1311, 1317 (Fed.Cir.2005). In First Heights Bank, the government breached its contract with the thrift by passage of the so-called Guarini Amendment which abrogated promised tax treatments. As damages, the thrift sought consequent increased taxes. The government argued tax liability could have been reduced by accelerating certain charge-offs— a failure to mitigate; accordingly, the cause of the increased tax liability was not the breach but the failure to accelerate those charge-offs. The Federal Circuit rejected the government’s causation analysis, casting the appropriate inquiry as one of mitigation:

The clear import of the government characterizing its argument as one of causation is to avoid the reasonability element of the mitigation doctrine. We disagree, however, with the causation label that the government assigns to its argument. The sole allegation underlying the government’s argument is that plaintiffs failed to take actions that would have eliminated some of the damages from the breach. Such an allegation is covered by the mitigation doctrine and its reasonability element. We thus conclude that the government’s so-called causation argument is identical to the government’s mitigation argument and reject it.

422 F.3d at 1317. The same reasoning applies here.

To reiterate, generally, the remedy for breach of contract is “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, 422 F.3d at 1373 (citing San Carlos Irrigation & Drainage Dist. v. United States, 111 F.3d 1557, 1562 (Fed.Cir.1997)). However, “ ‘the non-breaching party should not be placed in a better position through the award of damages than if there had been no breach.’ ” Old Stone Corp., 450 F.3d at 1378 (citing Bluebonnet, 339 F.3d at 1345). “[T]he non-breaching party is [generally] not entitled, through the award of damages, to achieve a position superior to the one it would reasonably have occupied had the breach not occurred.”. Id. (alteration in original) (citing LaSalle, 317 F.3d at 1371). See also White v. Delta Constr. Int’l, Inc., 285 F.3d 1040, 1043 (Fed.Cir.2002) (“the non-breaching party ‘should on no account get more than would have accrued if the contract had been performed.' ”) (quoting DPJ Co. v. FDIC, 30 F.3d 247, 250 (1st Cir.1994)). In other words, plaintiff should not get a windfall. Lary v. United States Postal Serv., 472 F.3d 1363, 1370 (Fed.Cir.2006), clarified on denial of reh’g, 493 F.3d 1355, 2007 WL 1892311 (July 3, 2007).

Once plaintiff has established, to a reasonable certainty, its expenditures were the foreseeable result of, and caused by, DOE’s partial breach, the burden shifts to defendant to prove that such damages “could have [been] avoided by reasonable efforts.” Pa-tific Gas & Elec., 73 Fed.Cl. at 406 (alteration in original) (citing Indiana Michigan, 422 F.3d at 1375) (quoting Robinson v. United States, 305 F.3d 1330, 1333 (Fed.Cir.2002) (quoting Restatement (Second) of Contracts § 350 cmt. b)). See also Yankee Atomic, 73 Fed.Cl. at 264 (“Defendant has the burden of showing that plaintiffs’ mitigation efforts were unreasonable.”); Sacramento Mun. Util., 70 Fed.Cl. at 367; Tennessee Valley Auth., 69 Fed.Cl. at 528.

In asserting plaintiffs’ burdens include establishing a “but-for world,” defendant cites Winstar cases concerning expectancy damages. (Def.’s Br. 97.) Seeking expeetancy/lost profits, the nonbreaching party attempts to prove what would have happened—how many widgets would have been sold, etc. and what profits would have been made. Glendale Fed. Bank v. United States, 239 F.3d 1374, 1380 (Fed.Cir.2001) (lost profits); Coast Fed. Bank v. United States, 48 Fed.Cl. 402, 430 n. 25 (2000) (same), rev’d on other grounds, 309 F.3d at 1353 (Fed.Cir.2002), vacated and reh’g en banc granted, 320 F.3d at 1338 (Fed.Cir.), aff'd, 323 F.3d 1035 (Fed.Cir.2003). In Bluebonnet Sav. Bank v. United States, 339 F.3d 1341, 1345 (Fed.Cir.2003), increased financing costs were sought as damages consequent from the government’s breach. The Federal Circuit remanded for further refining of damages, including offsets, to determine the net financial effect of the breach. In the complex financial transaction, increased financing costs may have been attributable, at least in part, to the conveyance of substantial equity in the thrift to the lender. See also Bluebonnet Sav. Bank v. United States, 466 F.3d 1349 (Fed.Cir.2006) (affirming subsequent jury verdict approach to determine the net effect of the breach). In those cases, expenses or benefits must be established to determine net loss. Plaintiffs’ damages are, in such instances, unliquidated. In contrast, mitigation expenses are liquidated after passing the reasonably foreseeable, substantial causal factor and reasonably certain hurdles. Consequently, offsets and deductions must be proven by defendant, the breaching party-

Analogously, in awarding foreseeable costs incurred in reliance on a contract, the breaching party has the burden of establishing any loss that would have been incurred in the nonbreach or “but-for” world—if the contract had been performed. Damages for the nonbreaching party’s reliance on a contract are recoverable less “ ‘any loss that the party in breach can prove with reasonable certainty the injured party would have suffered had the contract been performed.’ ” American Capital Corp. v. Fed. Deposit Ins. Corp., 472 F.3d 859, 867 (Fed.Cir.2006) (citing Restatement (Second) of Contracts § 349). “[I]t is the breaching party’s burden to prove that the actions taken in mitigation were not reasonable.” Spodek v. United States, 73 Fed. Cl. 1, 19 (2006) (citing T.C. Contr. Co. v. United States, 162 Ct.Cl. 145, 188, 319 F.2d 135, 160 (1963)). See also American Fed. Bank v. United States, 72 Fed.Cl. 586, 600 (2006); Old Stone Corp. v. United States, 63 Fed.Cl. 65, 96 (2004) (“The breaching party has the burden of proving windfall.”), aff'd in part, rev’d in part, 450 F.3d at 1360 (Fed.Cir. 2006), cert. denied, — U.S.-, 127 S.Ct. 1831, 167 L.Ed.2d 319 (2007).

In American Capital Corp., the Federal Circuit explained the shifting burden of proof, upholding an award equal to the cash infusion made in reliance on the government’s promises. Not unlike here, the government argued that TransCapital Financial Corporation (“TFC”) the nonbreaching party, had the burden of proving what its expenditures would have been had the government not breached. The Federal Circuit rejected that approach. If the nonbreaching party established foreseeable loss (and in American Capital, the government had reason to know the loss would occur and it did), the burden shifts to the breaching party to establish with reasonable certainty any costs would have been incurred in the absence of the breach.

Essentially, the injured party may not be able to prove with reasonable certainty what it would have made if the contract was performed; however, it may be able to prove what expenditures it made in relying on the contract. Here TFC demonstrated that its $42.2 million loss in reliance on the contract was foreseeable. At that point, we shift the burden to the breaching party and allow it to prove what expenditures would have been lost despite the breach. If the government can show with reasonable certainty that TFC would have lost the $42.2 million regardless of its breach, then TFC could not recover.

472 F.3d at 869 (citing Westfed, 407 F.3d at 1369-70); Caroline Hunt Trust Estate v. United States, 470 F.3d 1044, 1052 (Fed.Cir. 2006) (“This court has previously held that ‘it [is] the government’s burden to prove with reasonable certainty the quantum of benefit retained by the [aggrieved party] despite the government’s breach.’ ”) (citing Westfed Holdings, Inc. v. United States, 407 F.3d 1352, 1370 (Fed.Cir.2005)). See also Old Stone Corp. v. United States, 450 F.3d 1360, 1370 (Fed.Cir.2006) (“The government has not shown that it was unreasonable for [the non-breaching party] to replace the entire amount of regulatory capital that was eliminated by [the breach].”); Lisbon Contractors, Inc. v. United States, 828 F.2d 759, 769 (Fed.Cir.1987) (“The burden was on the government to prove the [the claimed offset].”); Caroline Hunt Trust Estate v. United States, 65 Fed.Cl. 271, 317 (2005), aff'd in part, rev’d in part on other grounds and remanded, 470 F.3d 1044 (Fed.Cir.2006), reh’g en banc denied, (Mar. 19, 2007) (“While plaintiff has the burden of proving its damages, the government has the burden of proving any offsets____”). See also First Heights Bank v. United States, 422 F.3d 1311, 1316-17 (Fed.Cir.2005); Tennessee Valley Auth., 69 Fed.Cl. at 543 (denying as speculative, the “benefits” defendant sought to offset from established mitigation expenses).

These Winstar cases for the most part involve reliance damages. Granted, reliance and mitigation differ. Reliance damages are actual expenditures made in preparation or in performance; here mitigation damages are actual expenditures addressed to an admitted future partial breach. In both instances, however, the costs must be proven by the nonbreaching party. What would have happened had the breach not occurred, is in both instances based at least in part on conjecture and the burden in both should be born by the breaching party. In contrast, in seeking consequential damages for breach—such as lost profits—assuming the contract had been performed, the burden is on the nonbreaching party to establish its cost of performance in the nonbreach world, in order to determine net profits. Defendant’s position that the nonbreaching party has the burden of establishing what DOE would have done and would have performed in a process in which DOE, for the most part, controls that process, is further reason not to place the burden of establishing any offset for this world on the plaintiffs. The very breach for which plaintiffs seek recompense would deny plaintiffs the ability to meet the burden defendant advocates. To the extent that this inquiry is appropriate, DOE’s failures to establish a firm comparison doom its burden in this regard. “The government contends that TVA’s damages should be constrained to the difference between the costs of building the dry storage facilities in the present (breach) world versus the costs of building the facilities later in the but-for, non-breach world. Because the government seeks to limit the non-breaching party’s recovery for mitigation, the government bears the burden of proof.” Tennessee Valley Auth., 69 Fed.Cl. at 530 (record citations omitted). “The amount of loss that [the non-breaching party] could reasonably have avoided by ... making substitute arrangements or otherwise is simply subtracted from the amount that would otherwise have been recoverable as damages.” Restatement (Second) of Contracts § 350 cmt. b. The court concludes that defendant did not meet its burden in this regard.

The court also rejects defendant’s assertion that the Standard Contract is too indefinite to be enforced if the court does not accept the DCS process with the 1991 ACR. (Def.’s Br. 153,160.) Embedded in the Standard Contract is a process for honing the rate as the system was to be (and is) developing. The Contract is not too indefinite to be enforced. The mechanism is there. It is DOE’s delays and partial breaches that have thwarted or stunted the process. Even if the mechanism under the Standard Contract was left to future defining, an obligation to proceed in good faith is imposed. In North Star Steel Co. v. United States, 477 F.3d 1324, 1332 (2007), the Federal Circuit explained:

This court has recognized that a provision which calls upon the parties to a contract to agree in the future on a specified point or contract term, often referred to as an ‘agreement to agree,’ imposes an obligation on the parties to negotiate in good faith. See Aviation Contractor Employees, Inc. v. United States, 945 F.2d 1568, 1572 (Fed. Cir.1991); see also Gardiner, Kamya & Assocs. v. United States[Jackson], 369 F.3d 1318, 1322 (Fed.Cir.2004); City of Tacoma v. United States, 31 F.3d 1130, 1132 (Fed.Cir.1994).

See also Chapman Law Firm Co. v. United States, 490 F.3d 934, 939-40, 2007 WL 1662323, at *4 (Fed.Cir. June 11, 2007); Am. Sav. Bank v. United States, 74 Fed.Cl. 756, 761 (2006) (“[A] breaching party may not take advantage of uncertainties that its own breach created.”).

The contingent and conditional 1991 ACR was discussed previously and the court declines to find that DOE would have performed at that level. Indeed DOE could not have performed at that level without Congressional action. The court does not accept either defendant’s proffered 1991 ACR rate or the 3000 MTU rate advocated by plaintiffs. Prior SNF cases have found specific rates, others have not. Indiana Michigan Power Co. v. United States, 57 Fed.Cl. 88, 99-100 (2003) concluded: “The [DOE] would have begun performance by collecting 400 metric tons of nuclear waste in 1998, and ramped up to 3,000 metric tons by the end of 2002. Defendant would have continued performance pursuant to the Standard Contract at a minimum rate of 3,000 tons thereafter.” When Indiana Michigan appealed the trial court decision that pre-breach damages were not recoverable and alternatively that causation had not been met, defendant attempted to cross-appeal. The Federal Circuit dismissed the cross-appeal, because “the trial court’s rate calculation determination was not necessary to the judgment.” 112 Fed.Appx. at 38 (Fed.Cir.2004). The Federal Circuit proceeded to the merits of the appeal without addressing an acceptance rate. Subsequent eases in this court have made final mitigation determinations without finding an acceptance rate. Sacramento Mun. Util., 70 Fed.Cl. at 375 n. 40 (2006) (“The court finds that the evidence presented on the acceptance rate under the terms of the Standard Contract to be highly speculative, therefore, the court declines to make any determination of the acceptance rate based on this record.”) In Tennessee Valley Authority, the court accepted the parties’ litigation stipulation to the 1991 ACR rates for the first ten years. In computing damages commencing after 2001, periods beyond the stipulation of the parties, the court concluded that it was reasonable to assume DOE would have performed at an annual rate of 3000 MTU by 2008. 69 Fed.Cl. at 531. In Pacific Gas and Electric, evidence was cited that the parties supported DOE’s use of an MRS to meet its obligations under the Standard Contract. 73 Fed.Cl. at 394-95. “[N]o evidence presented at trial indicates that DOE, EEI or PG & E believed during this period that if DOE operated under an acceptance schedule—beginning on January 31, 1998—that complied with the 10,000 MTU limit on the MRS set by Congress in the 1987 Amendments Act, DOE would breach its statutory or contractual obligations under the NWPA or the Standard Contract.” 73 Fed.Cl. at 366. Here, on a different record, the court makes no such finding.

Perhaps any “would have been world” is more appropriately determined, not seven years before the time for performance was to begin, but at subsequently acknowledged levels, or as envisioned as of the date of the damages cut-off, or as of the date of judgment(s). The fundamental purpose of limiting mitigation damages is to prevent a windfall— that is, to not award costs that would have been incurred anyway. While the Standard Contract has not changed, conditions and the level of DOE’s performance have. If plaintiffs’ foreseeable mitigation measures and expenses were substantially caused by DOE’s admitted delays in commencing performance, which is and was a partial breach in and of itself, and those expenses would not have been incurred if DOE had commenced performance at the level it recently has proposed as its performance obligation (which is also the level contemplated at the time of the enactment of the NWPA and the contract formation), or at any reasonable level, there is no windfall. Defendant’s advocated non-breach world could not have transpired absent resolution of a whole host of contingencies which did not and has not occurred. Neither windfall nor a nonbreach world is measured by contingent, litigation-driven and subsequently-abandoned rates.

La Salle Talman v. United States, 462 F.3d 1331, 1336 (Fed.Cir.2006) held the trial court did not err in rejecting as deductions from damages the cost-avoidances proffered by the government if there had been no breach, because they were “not an accurate indicator” of how the nonbreaching party would have behaved had there been no breach. In this regard, assuming inquiry into the nonbreach world is appropriate on this record, inquiry is not minimum contract performance, but what DOE would have done. The court finds on this record that the contingent rates of acceptance in the 1991 ACR did not fulfill DOE’s contractual duties to commence performance, were not an accurate indicator of how DOE would have performed, and that defendant did not meet its burden in this regard.

Adopting in part the reasoning of Commonwealth Edison Co. v. United States, 56 Fed.Cl. 652, 665-66 (2003), in denying summary judgment, the undersigned earlier declined to credit the 1991 ACR as defining plaintiffs’ mitigation damages. (Order, Apr. 7, 2004, Dkt. 234, 6.) See also Yankee Atomic Elec. Co. v. United States, 2004 WL 1535686, at * 1 (Fed.Cl.2004); System Fuels, Inc. v. United States, 66 Fed.Cl. 722, 730-32 (2005); Entergy Nuclear Generation Co. v. United States, 64 Fed.Cl. 336, 343 n. 8 (2005); Sacramento Mun. Util. Disk v. United States, 63 Fed.Cl. 495, 503-05 (2005).

Both parties presented expert testimony which, in great detail, calculated reactor core discharges, spent fuel pool inventory and one or two full core reserves under various hypothetical, as support for their respective non-breach worlds. Plaintiffs’ expert Eileen Supko,³⁵ calculated the effect of alternative acceptance rates on what she concluded were program goals of (1) minimizing the need for additional SNF storage either at the reactor site or elsewhere; and (2) reducing the backlog of inventory of SNF that had accumulated at reactor sites to allow timely decommissioning. As SNF inventory and dates of discharge from reactors were givens (and projected for future), Ms. Supko measured the result of the application of four different rates on costs to the nuclear power industry (substantially passed on to ratepayers) for additional storage during operation of the plant and following the permanent shutdown of the plant and delay in decommissioning— both tremendous costs to utilities. The efficiency of DOE’s waste management system was also considered. If an acceptance rate is too high, the repository or other disposal system would have unused capacity after a relatively short period of time, and the system, which was designed for acceptance over a forty-year period, would not be operated efficiently. (Tr. 617-72; 678-79 (Supko).)

Four ramp-up and acceptance rates scenarios were used: Scenario 1 reached 3000 MTU by 2002 and remained at that rate; Scenario 2 (based on the 1991 ACR) reached 900 MTU by 2000 and remained at that rate; Scenario 3 (based on the 1992 ACR) reached 900 MTU by 2000 and increased to 3000 MTU by 2015; Scenario 4 reached 6000 MTU by 2001. (PX624.)

Using strictly OFF (Oldest Fuel First) and applying these four scenarios, Ms. Supko charted the following:

Comparison of Factors Important to Spent Fuel Acceptance

[[Image here]]

(Id. at 14.) Of these four rates, only Scenario 1, 3000 MTU, met the goals of generally preventing additional at-reactor storage after 1998 and reducing backlogs of SNF inventory to allow timely decommissioning. Additional dry storage of 1030 MTU (less than the cumulative amount of industry-wide SNF discharge in one year) was projected. On the other hand, under Scenarios 2 and 3, additional dry storage of 13,130 and 6200 MTU, respectively, was projected. Also, Scenario 1 would result in a relatively short average time for post-shutdown fuel storage—nine years vice sixty-four years under Scenario 2 and 16.5 under Scenario 3. Also, under Scenario 1, DOE’s waste management system would operate at maximum capacity for twenty-eight years (after a five-year start-up), which was fairly consistent with the planned forty-year period of acceptance operation. In contrast, under Scenario 2, the program would operate for over 100 years. In concluding Scenario 1 was the most efficient and best met her identified goals, based on the greater volume of SNF that would have to be stored on-site under Scenario 3, Ms. Supko rejected Scenario 3 rates even though there were fewer years of both post-shutdown storage and system operation. Ms. Supko’s sensitivity analysis, assuming intra-company swaps of acceptance allocations between plaintiffs’ plants, also concluded that Scenario 1, the 3000 MTU rate, minimized the need for additional on-site storage and reduced industry backlog to allow timely decommissioning.

Accordingly, as discussed previously, the trial court in Indiana Michigan concluded DOE would have performed at the 3000 MTU rate. 57 Fed.Cl. at 99-100. In the instant case, trial testimony was that DOE adopted a steady-state 3000 MTU as the operating-rate. Christopher Kouts and David Zabransky testified that a 3000 rate is a reasonable acceptance rate. (Tr. 1844, 1856; (Kouts)); (Tr. 1987-88 (Zabransky).) For a long time, the optimum design rate for the SNF program has been 3000 MTU. (Tr. 1845-48 (Kouts).) Lake Barrett, the acting and then Deputy Director of OCRWM from 1993 until February 2002, testified that Congress did not intend that after 1998, utilities would have to pay for additional SNF storage in addition to the billions in fees paid under the Standard Contract. (Barrett Dep. 1064-65 (May 8, 2002) (PDD 4).) Mr. Barrett also testified that if DOE had begun pickups as required by the NWPA and the Standard Contract, it would have been at a 3000 MTU steady-state rate after a ramp-up. (Barrett Dep. 120-21 (May 14, 2002) (PDD 6).) DOE’s plans for removing SNF from reactor sites from the mid-1980s through the mid-1990s supported the 3000 MTU rate. (Barrett Dep. 189, 197-98 (April 22, 2002) (PDD 1).) A 3000 MTU rate was chosen “as a proper balance for total life-cycle costs as well as near-term cash flow requirements and performance. If you make the number too high, then you have—you would quickly work off the backlog, and then you would have a lot of idle capacity. If it was too low, you would have reactors needing to put in dry storage, and 3000, based on an early 1980s [sic], seemed like a reasonable number to use.” (Barrett Dep. 1332-33 (May 10, 2002) (PDD 5).)

From her spent fuel management expertise, Ms. Supko also described alternatives utilities had for dealing with small quantities of SNF to avoid building expensive dry storage facilities for a small quantity of SNF, if DOE had performed and there was industry confidence in continued performance. “[T]here are a wide range of things that could have been done, had they believed performance was going to occur.” (Tr. 689 (Supko).) Nuclear waste management options included “increas[ing] fuel burnups” or possibly lengthening fuel discharge cycles. (Tr. 684 (Supko).) Additional or temporary racks or part of the FCR discharge capability could be utilized. (Tr. 689 (Supko).) Use of the twenty-percent increase option available under the Standard Contract would increase pickup allocations, another way to avoid constructing dry storage. (PX 624 at 17; Tr. 665, 812-13.) She presumed only those utilities that needed to increase their allocations by twenty percent to avoid building dry storage, would do so.³⁶ (Tr. 856 (Supko).) Inter-company exchanges of allocations under the Standard Contract with DOE’s consent, could be used to avoid dry storage.³⁷ (PX 624 at 17.)

Having heard the testimony concerning time, effort and expense involved in building and maintaining dry storage, without contemplating the decommissioning efforts that will be required for the eventual shutdown, dismantling and decontamination of these football field-sized mega-pads filled with 100-plus-ton concrete containers of radioactive waste, the court concurs with the logic expressed in Tennessee Valley Authority v. United States, that “[g]iven the proportionately large cost of building and operating dry storage facilities, TVA would have had several options available in the but-for scenario to deal with its spent fuel while still avoiding dry storage.” 69 Fed.Cl. at 532.

Regardless of whether the burden is on the plaintiffs to establish lack of windfall, or on the defendant to prove windfall, the court credits witness testimony that the reracking at Plant Vogtle and the dry storage at Plants Hatch and Farley would not have occurred if DOE had been performing at any reasonable rate.³⁸ Even at the rates under the December 1991 ACR, absent DOE’s announced failure to commence performance during the time frame relevant here, storage shortages would likely have been accommodated. The court credits testimony and evidence that these plants would not have built dry storage, but plaintiff would have installed a second bathtub rack (at Plant Hatch) and/or would have lived with, or tolerated, less than FCR for a time pending pickups from DOE. Decisions to build dry storage were made after monitoring DOE’s preparation for performance; planning and financing, then equivocation; denial of contractual responsibility absent a repository; and announced delays in commencement of performance. Furthermore, there is no chance for a windfall in that defendant did not establish that DOE will perform such that the storage costs awarded here would have been incurred under any scenario that would not be unreasonable.

In the main, analysis comes full circle. The court’s conclusion that there will not be a windfall is further support for the court’s findings on causation. At DOE’s projected commencement dates and levels of performance, at the time the mitigating decisions were made, at the time DOE was required to commence performance, at the time the expenses were incurred, and at the time of trial (as well as the date of this opinion), plaintiffs will not be better off by an award of mitigating expenses, than if DOE performed at any of these levels. “[Pjlaintiffs claim to have been forced to absorb unnecessary interim storage costs. If the government reimburses such costs, it hardly puts plaintiffs in a better position.” Dominion Resources, Inc. v. United States, 77 Fed.Cl. 151, 156 (2007) (rejecting the government’s claim that the utility would be better off.)

Internal labor costs

Plaintiffs’ claimed mitigation costs include employee and management time spent on these endeavors. This includes the dry cask storage and related projects at Plants Hatch and Farley, and the rerack at Plant Vogtle— efforts consequential from DOE’s partial breach. These internal labor costs total $6,466,016, and are supported by books and records. (Def.’s Br. 82 n. 4; Pis.’ Br. 117.) Any time spent on a mitigation-related project was so “booked” on plaintiffs’ records. These time-allocations were consistent with generally accepted accounting principles required by the Alabama and Georgia Public Service Commissions. (Tr. 1565-69 (Met-calfe).) Internal labor was used where feasible because these employees were more reliable, better trained and less expensive than outside contractors. (Tr. 168-72 (Long); Tr. 1125-28 (Wade) (describing use of internal labor at half the cost of outside contractors).) For the operations portion of the projects, plaintiffs used unionized, hourly-rate employees. (Tr. 169 (Long); Tr. 1020-21 (Wade).) Management personnel, generally salaried, also booked specific time to mitigating projects.

Construction of the dry cask storage facilities and the loading, welding, transportation and placement of the casks on the pad are extremely dangerous activities, planned months in advance. Use of internal employees simplified planning. Also, but for these projects, the employees would have been doing other work which is what they were hired and paid to do. “[I]f the people are off working on dry cask storage, they are not working on the backlog of maintenance activities that we—that they are normally charged to do” and “they would be working on maintenance backlogs that we have.” (Tr. 170 (Long).) Mr. Wade, agreed that there was “other plant maintenance work that could have been done” by these employees. (Tr. 1128 (Wade).) Mr. McCallum testified that the use of internal employees on SNF storage projects meant that “there’s work that gets deferred—gets sent outside of the company, or the backlog____” (Tr. 1287 (McCallum).) “The maintenance departments have backlogs of activities that they are working on to try and work down to get fixed so that the plant runs as it is supposed to.” (Tr. 170 (Long).) However, Mr. Wade did not identify any operational maintenance activity delayed because of effort diverted to dry storage. (Tr. 1138-39 (Wade).) Identified deferred projects included the design and construction of tornado barriers and security enhancements that were outsourced because in-house personnel were tasked to mitigating work. (Tr. 1389-91 (McCallum).)

Labor-intensive cask loading was scheduled around planned outages when labor needs for plant activities were reduced. About 150 employees at Plant Hatch were trained to assist in loading activities. More than half of those employees booked less than $5,000 annually to mitigation efforts.³⁹ (Tr. 1018-19 (Wade); Tr. 2260 (Johnson).)

Plaintiffs’ economic expert opined these internal labor charges were appropriate components of the actual costs of mitigating DOE’s partial breach. (Tr. 1565-69 (Met-calfe).) As a regulated, investor-owned public utility, there is a high level of cost consciousness. While safety is paramount, idle employee time is minimal. These projects were massive and labor intensive and the use of these employees was a true cost because they were not doing the work they were hired to do.

That these people are working on these, again, major projects, complex, and the fact that you use an internal person as opposed to a third party contractor doesn’t mean that the internal person is not incremental to the utility. They need those people to work on their normal projects and to dedicate them to the size and complexity of the projects that we’re talking about here, and it makes sense that those people are incremental and should be reimbursed.

(Tr. 1553 (Metcalfe).) “[J]ust because a person is being used as internal labor doesn’t mean that their costs are not reflected or their replacement costs are not reflected somewhere in the company.” (Tr. 1554 (Metcalfe).) “[T]he utility is using that individual in a way that they were not intending to use that person____And, a fair and reasonable method of compensating for that is to use the person’s salary.” (Tr. 1554-55 (Metcalfe).) In regulated industries, “internal labor has to be recovered or the utility would never be made whole in the rate process ...,” and while the costs of the employee would already be included in the rate base, “they are not doing the work that the ratepayer expected them to do. Instead they are doing the work that the government has necessitated to be done.”⁴⁰ (Tr. 1555, 1560-61 (Metcalfe).) Engineering supervision, overhead and payroll costs, like labor costs, were “booked” to storage projects, which Mr. Metcalfe testified should be recoverable, basically for the same reasons. (Tr. 1565 (Metcalfe).)

Defendant’s position is not that internal labor costs can never be recovered; rather, that the evidence here did not show any deferred work or incremental costs, and “a contractor is not entitled to recover ‘expenses which would properly have been incurred regardless of the [breach].’ ” (Def.’s Br. 162, citing Boyajian v. United States, 191 Ct.Cl. 233, 423 F.2d 1231, 1236 (1970)) (quoting Saddler v. United States, 152 Ct.Cl. 557, 287 F.2d 411, 415 (1961).) Only if an employee is paid more than he or she would have received is that cost truly incremental, defendant argues, citing Wilner v. United States, 23 Cl.Ct. 241, 258, 262-63 (1991) (allowing recovery for costs for hours that would not have been worked but for the delay.) If the nonbreaching party incurs cost for salary, overhead or other charges that would not have been spent absent the breach, recovery may be appropriate. (Def.’s Br. 163 (citing Wilson v. Marquette Elecs., Inc., 630 F.2d 575, 586 (8th Cir.1980)) (rejecting claim that $40,000 in “lost time” for employee labor was recoverable absent evidence that company lost any money because of time the employee was required to spend on a breach-related project), AES Tech. Sys., Inc. v. Coherent Radiation, 583 F.2d 933, 942 (7th Cir.1978).) Secondly, recovery is appropriate when effort required because of the breach detracts or prevents other work—where “salary and other overhead items allocated as a bookkeeping matter to a broken contract would in fact have been recovered in a substitute contract.” (Id., citing Autotrol Corp. v. Cont’l Water Sys. Corp., 918 F.2d 689 (7th Cir.1990).)

Our position is not that, as a matter of law, these costs are not recoverable. Rather, had the plaintiffs established that employees were retained based upon work being performed upon incremental projects, that overtime was paid in connection with those projects, such costs likely would be recoverable. However, instead of establishing that specific employees were incremental, the plaintiffs relied upon eonclusory and unsupported statements concerning the asserted incremental nature of their internal labor as a whole. Plaintiffs’ litigation strategy, however, failed to meet their burden of proof.

(Defi’s Br. 166.)

As mitigation efforts must be reasonable, the lesser cost of using internal labor (highly trained, trusted and available), vice more expensive contract labor, is compelling. “If ... [utilities are told] we are not going to reimburse you for the efficiency factor of using your internal labor, the message ... is utilities for the next cases are going to say ... I want to recover this money, I’m going to go out and get third-party contractors and the third-party contractors, again, are by default a more expensive resource.” (Tr. 1557 (Metcalfe).) Internal labor charges sought here were subject to rigorous proof. Under pretrial procedure and from plaintiffs’ books and records provided to defendant, Larry Johnson,⁴¹ one of defendant’s experts, analyzed plaintiffs’ damage claims, determining first, if the costs were incurred; secondly, were the costs related to the storage of SNF; and thirdly, would the costs have been incurred but for the assertion of the partial breach. (Tr. 2197 (Johnson).) His study included review of invoices and contracts. He requested and received additional information and corresponded with plaintiffs’ representatives. Johnson segregated internal labor, supervision and overhead costs totaling $6,466,016.

The court finds that plaintiffs’ accounting for and booking costs in this regard was reliable and accurate. Defendant agreed that plaintiffs’ claims (as adjusted) were adequately supported from a books and records perspective.⁴² Accordingly, plaintiffs made an appropriate showing of the amount of time spent by internal personnel on breach-related projects—efforts for which those employees were not hired. Tennessee Valley Authority, 69 Fed.Cl. at 540. Having heard testimony of the efforts required to mitigate, reimbursement for these costs, caused by DOE’s partial breach, reasonably foreseeable and established with reasonable certainty, are included in mitigation costs awarded herein.

[T]he fact that TVA used its own internal resources to support its mitigation is not fatal to its claim for damages in mitigating a breach of contract. Rather, the test for recovery is a targeted one: whether use of the internal resources by TVA deprived it of the ability to employ those resources on other projects. That TVA would have paid its employees in all events is not material to this inquiry.

Tennessee Valley Auth., 69 Fed.Cl. at 539 (emphasis added). See also Pacific Gas & Elec., 73 Fed.Cl. at 408 (“To the extent that the costs of [the utility’s] internal labor were in fact performed on a ‘breach-related project,’ ... the court finds that such labor costs should properly be awarded to plaintiff.”); Sacramento Mun. Util., 70 Fed.Cl. at 376 (“The fact that an injured party has used internal resources to mitigate a breach does not foreclose the injured party from recovering such costs.”); Yankee Atomic, 73 Fed.Cl. at 322 (“It is concluded that defendant did not establish that the labor cost cited was not incurred.”). Cf. American Federal Bank v. United States, 72 Fed.Cl. 586, 624 (2006) (burden not met).

Use of internal labor is less expensive than hiring contractors which reduces costs to ratepayers and ultimately to the federal taxpayers who bear the burden of judgments entered by this court. As damages continue, not only in this case, but also in the some fifty cases pending in this court, to not allow recovery of appropriately established costs of internal labor (assuming causation and foreseeability is established) may lead to the use of contractors to perform future mitigation efforts at a higher cost, a result that is neither reasonable nor prudent. Under the Standard Contract, the fee paid by the utilities is intended to cover all DOE’s costs including DOE’s internal labor. (Tr. 1556-57 (Metcalfe).) Therefore, reciprocity in this regard is neither unreasonable nor unforeseen.

Private Fuel Storage

Since 1993-94, plaintiffs’ parent corporation, Southern Nuclear, has contributed over $8 million to Private Fuel Storage, LLC (“PFS”), a consortium of private entities, to finance the development of an off-site SNF storage site proposed on the Goshute Indian Reservation in Utah. Tr. 186-87, 205-06 (Long); (Tr. 385 (Cocherell); PX 715 at J-178). The PFS project would be a private ISFSI. (Tr. 186 (Long).) SNF would be shipped from reactor sites to the PFS facility. (Id.) Similar to DOE’s ill-fated proposed MRS, the PFS facility would store SNF until a repository became operational. (Id. at 186-87.) Southern Nuclear is an equity member of PFS. (Tr. 384 (Cocherell).) Approximately $4.4 million was contributed after ISFSI loading at Plant Hatch began. (Tr. 385-86 (Cocherell); PX 715 at J-178). Southern Nuclear made a total of $8,466,674 in payments to PFS between 1995 and 2004, and seeks to include those amounts in mitigation damages. (PX 715 at KRG00230.)

Mr. Long testified that Southern Nuclear’s managers decided that a private, off-site ISFSI was reasonable given the uncertainties of whether storage restrictions or expensive taxes or other uncertainties would prohibit, restrict or delay on-site storage options at plaintiffs’ sites. (Tr. 205 (Long).) Private storage was an insurance policy in case any of a host of possible obstacles to dry storage rendered that option unusable. For example, during the mid-90s, the State of Minnesota limited the amount of SNF that a nuclear power plant could store on-site. There was concern that similar local political opposition to on-site storage could occur. Possible increased taxation, uncertainties over untested NRC licensing of dry storage and the acquisition of a host of new technologies needed to build and load an ISFSI, made contingency planning necessary. Plaintiffs assert these contributions were reasonable decisions, made prior to the completion of the ISFSIs at Plants Hatch and Farley, accomplishments that were not foregone conclusions. The decision to stop contributions came only after the completion and successful operation of those ISFSIs. After five years of operating its Hatch ISFSI and one year of operating its Farley ISFSI without any tax increases or restrictions by the Georgia or Alabama Public Service Commissions, no further contributions to PFS were made. (Tr. 205 (Long); DX 338.)

Defendant argues that PFS was not reasonable mitigation because (1) it would be more expensive than dry storage; (2) it faced many licensing and financing hurdles; (3) even if it were ever built, it would not solve plaintiffs’ storage dilemmas. Mr. Cocherell, who was Southern Nuclear’s representative on the PFS Board of Managers and was against participation in the venture, felt the project was speculative and had no real chance of solving plaintiffs’ storage needs, and may never be licensed. (Tr. 339, 388-98 (Cocherell).) He also testified to substantial hurdles to the project including potential opposition from the State of Utah and problems with financing the estimated $100 million in construction costs. (Tr. 393; DX 161 at SN014291, DX 162 at SN014248.)

That there were (and are) questions whether the PFS would ultimately be built does not make it unreasonable and outside the realm of possible mitigation. Guaranteed success is not a prerequisite to recovery of mitigation expenses. Plaintiffs are “ ‘not precluded from recovery ... to the extent that [it] has made reasonable but unsuccessful efforts to avoid loss.’ ” Indiana Michigan, 422 F.3d at 1375 (quoting Restatement (Second) of Contracts § 350(2)).

One of the purposes of the NWPA and the FWMS was to address dwindling on-site storage. That off-site private storage might be needed absent a federal solution was likely contemplated. Robert Morgan, DOE’s director of SNF storage, stated in the 1983 that “[d]uring the first year of operation of the repository in 1998, we should be receiving fuel at a rate so that no utility would have to add any further storage facilities either on site or at another location.” (PX 53 at 11 (emphasis added).) The NWPA references off-site storage. 42 U.S.C. § 10155(h) (“Nothing in this Act shall be construed to encourage, authorize, or required the private or Federal use, purchase, lease, or other acquisition of any storage facility located away from the site of any civilian nuclear power reactor and not owned by the Federal Government [on the date of the enactment of the NWPA].”).

A possible PFS was contemplated and included in DOE’s contingency plans in its February 2002, draft Environmental Impact Statement (“EIS”) for Yucca Mountain:

• There are a number of possibilities that DOE could pursue____ One such centralized storage possibility, the proposed [PFS] Facility for commercial spent nuclear fuel in Utah, is currently in the Nuclear Regulatory Commission licensing process.

• There are a number of possibilities that the Nation could pursue____One such centralized storage possibility, the proposed [PFS] Facility....

• DOE recognizes interim storage at the [PFS] facility in Utah to be a reasonably foreseeable future action and has included this proposed action____

(Pls.’ Br. 102.) Southern Nuclear made payments to the PFS in 2002, 2003 and 2004 totaling $1,152,600 after DOE made these public statements. (PX 428 at SNOC007755, 7758, 7761, 7764; PX 715 at 3178.) The NRC approved a license for the PFS facility on September 9, 2005. (Tr. 339-40 (Cocherell).) Ironically, the PFS is further along in the approval process than the Yucca repository or the ill-fated MRS ever was.

In 1994, before Southern Nuclear made any contributions to the PFS, the Hatch Spent Fuel Task Force reported that “[a] private MRS could be implemented, but the date for commercial operation and pick-up is not certain.” (DX 158 at 19.) Included in that report was a legal opinion that there was no legal impediment to on-site storage. That report also noted that while there may have then been no legal impediment at that time, the State of Georgia had a moratorium on the disposal of radioactive waste, the Georgia Department of Natural Resources had previously questioned the adequacy of interim storage of radioactive waste and the Georgia Public Service Commission could question chosen technology if the issue became political. While more costly, a private MRS was noted as a back-up option. (DX 158.)

Private off-site storage would likely be more expensive than on-site. Financial analysis done by the Mescalero Apache Tribe and Northern States Power in March of 1994, estimated costs of private SNF storage at $96 per kilogram and ISFSI cost of between $62 and $83 per kilogram. (DX 143.)

Thereafter, in March 1996, after contributions began, Plant Hatch was predicted to lose FCR by 2000. At that time, the projected start-up date for PFS was 2002—two years too late for Plant Hatch. (DX 180; DX 182; Tr. 212-13 (Long).) Accordingly, additional on-site storage was the “only solution to Hatch’s storage problem.”

Plaintiffs respond that the State of Georgia could have prohibited on-site SNF storage or taxed it prohibitively. In either of those events, PFS would have been utilized. Also, use of PFS by 2002 could have avoided the dry storage expenditures at Plant Farley and Plant Vogtle, and a shutdown of any of those plants may have required the backup storage PFS could provide. In March of 1996, use of private fuel storage was not assumed, at least for decommissioning purposes, although impact of possible PFS on a permanent shutdown some decades hence would have been speculative. (Tr. 396-97 (Cocherell); DX 178.)

While plaintiffs knew as early as 1995 that PFS would probably not be licensed and constructed in time to alleviate Plant Hatch’s storage needs, there was uncertainty in all of the limited storage options plaintiffs had. However, contributions to PFS continued after ISFSI loading at Plant Hatch began, with a final $1.5 million contribution in 2004 after loading 22 casks to the ISFSI at Plant Hatch, after ISFSI construction at Plant Farley and the rack addition at Plant Vogtle. (Tr. 385-86 (Cocherell); PX 715 at J-178; DX 338.) Defendant also argues that, of the approximately $8.5 million contributed, about $4.4 million was after ISFSI loading at Plant Hatch began, as evidence that DOE’s breach was not the reason for the investment. (Tr. 385-86; PX 715 at KRG00230.)

Plaintiffs argue that their nuclear plant management made reasonable decisions to contribute to PFS prior to the completion of ISFSIs and made the reasonable decision to stop contributing after the completion and successful operation of those ISFSIs. Accordingly, plaintiffs urge those contributions be included in recoverable mitigation expenses.

Defendant asserts recovery is foreclosed by Indiana Michigan’s conclusion that the investment in PFS was “too speculative” and not foreseeable. 60 Fed.Cl. at 658-59. On appeal, the Federal Circuit affirmed. Indiana Michigan, 422 F.3d at 1376. The investment in PFS that the Federal Circuit deemed unforeseeable and speculative in Indiana Michigan, is equivalent to the investment for which plaintiffs seek recovery of their contractual responsibility to their corporate parent. Aside from the fairly recent licensing of PFS, concerns of speeulativeness and foreseeability are no less present in this case than they were in Indiana Michigan.

The Federal Circuit limited its findings in Indiana Michigan to that factual record. 422 F.3d at 1375, 1376 (noting that based “on these facts” and the “credited evidence” of utility witnesses that the PFS was “too speculative,” neither causation nor foreseeability were established). Generally “[f]oreseeability is a question of fact reviewed for clear error.” Citizens Fed. Bank v. United States, 474 F.3d 1314, 1321 (Fed.Cir.2007) (citing Bluebonnet Sav. Bank v. United States, 266 F.3d 1348, 1355 (Fed.Cir.2001)); Landmark Land Co. v. FDIC, 256 F.3d 1365, 1379 (Fed.Cir.2001) (“Foreseeability is a question of fact.”). Likewise, causation is a factual inquiry. Bluebonnet, 266 F.3d at 1356 (“Causation is also a question of fact reviewed under the clear error standard.”); Hendler v. United States, 175 F.3d 1374, 1384 (Fed.Cir.1999) (noting the trial court considered “causation, a question of fact”).

While upholding the trial court’s findings based on credited evidence that Indiana Michigan’s investment in PFS was speculative and its high cost unforeseeable, the Federal Circuit also addressed PFS from DOE’s perspective. “While DOE should have foreseen that its breach would force Indiana Michigan to find alternative storage for its SNF, it is not liable for such a speculative venture and unforeseeable costs.” The venture and costs are the same in this ease. The court in Pacific Gas and Electric, faced with this same issue, concluded that “[t]he preponderance of the credible evidence adduced at trial does not persuade the court to rule differently than the Federal Circuit under substantially similar circumstances.” 73 Fed.Cl. at 429-30. The same is true here. The court concludes that on this record, foreseeability and substantial causation were not established.

In addition, it is noted that payments and capital contributions were made by Southern Nuclear with costs allocated to APC and GPC. (PX 715 at SNOC01839-42.) An equity interest in PFS is apparently retained along with any subsequent profits or losses.⁴³ Plaintiffs’ expert divided Southern Nuclear’s total contribution to PFS in thirds, allocating it equally between the three plants. (Tr. 385 (Cocherell)); (Tr. 1531-32 (Metcalfe).) Plaintiffs rely on this allocation of the $8.5 million investment in PFS, and contend these costs were incurred in mitigation. (Pis.’ Reply Br. 53 n. 28.) Specifically, plaintiffs contend that counsel for defendant agreed at trial that, with certain exceptions, the claims in the plaintiffs’ expert damage witness report (The Kenrich Group, LLC) were supported from a books and records perspective.⁴⁴ As evidence these derivative costs were allocated between the two plaintiffs/three plants, plaintiffs cite to a footnote in Mr. Metcalfe’s workpapers that “ ‘[p]er DeWade Pittman (Southern Nuclear Operating Company Business Planning Manager), costs associated with private fuel storage are to be allocated evenly among its three plants.’” These reimbursed costs were recorded to “Location 00950.” (Pis.’ Reply Br. 53 n. 28.) Reimbursement is based on Operating Agreements with Southern Nuclear. (Id.) Even if foreseeability were not foreclosed by the Federal Circuit decision in Indiana Michigan, mitigation does not extend to contractual proportional reimbursement of investments of a third party. Furthermore, any recovery would require a finding that the retained equity interest, represented by the PFS investment, is of no value, a finding the court declines to make on this record.

Accordingly, for the reasons stated, the investments in PFS are not included in mitigation damages awarded herein.

Cost of capital

The cost of capital claimed was presented by plaintiffs’ economic expert Kenneth Met-calfe.⁴⁵ He aggregated plaintiffs’ claimed costs, including the cost of capital for the millions plaintiffs spent in mitigating DOE’s partial breach. His calculations were based on plaintiffs’ accounting records and discussions with management and employees. (Tr. 1456-61,1527 (Metcalfe).) Total mitigation costs sought are: (1) $75,758,000 for Plant Hatch; (2) $21,317,000 for Plant Farley; and (3) $8,553,000 for Plant Vogtle. (Tr. 1572; Metcalfe demonstratives 61-63; 73.) Almost forty percent, more than $28 million, is cost of capital—$21,633,033 for Plant Hatch; $4,045,589 for Plant Farley; and $3,210,275 for Plant Vogtle. (Def.’s Br. 79.)

Based on discussions with finance and rate-making departments at public utilities, Mr. Metcalfe used blended rates of debt, common and preferred equity which varied from year to year, and deducted expenses to determine after-tax weighted average costs of capital. (Tr. 1545^7.) He explained that the Federal Energy Regulatory Commission (“FERC”) recognizes equity and debt costs:

FERC rules allow public utilities to essentially book what’s called allowance for funds used during construction, and an allowance for funds used during construction is a weighted average cost of capital. It looks at their short-term debt, long-term-debt, preferred stock equity and it allows those to be recorded to the asset that’s being constructed to be recovered ultimately from the ratepayers.

(Tr. 1550.) Mr. Metcalfe testified as to his understanding of the difference between prejudgment interest and, what he opined was a separate, distinguishable component of damages in this case. “[Pjrejudgment interest ... is a simple application of interest to whatever costs are being incurred ... from the time of the claim until the time of the award____[Tjhe cost of capital is a separate component of Southern’s damages that I am putting forth in their claim.” (Tr. 1549 (Met-calfe).) His expert report, PX 651, p. 20, opines:

An additional element of past damages is the increased financing costs associated with the money spent by Southern to address the impacts of DOE’s failure to begin picking up spent fuel from the nuclear industry in 1998. Southern has had to finance the costs it has incurred related to DOE’s failure to perform in accordance with its contractual obligations from the time those costs were incurred (as have the co-owners of Hatch and Vogtle). Appropriate after-tax weighted average cost of capital rates were used to calculate these increased financing costs. The applicable annual rates were applied to the total nominal damages incurred each year from the middle of that year through August 31, 2005.

Disagreeing, defendant’s expert, Dr. Neu-berger testified that plaintiffs’ cost of capital was disguised interest.

Q. Now, if Plaintiff had actually incurred financing costs, would you—what would your opinion be concerning whether those financing costs could be claimed in damages?

A. I might have a slightly different opinion. And I guess to make that distinction, I would distinguish between interest on damages and interest as damages.

If Plaintiffs could show, for example, that it actually did pay interest to fund an ISFSI, for example, or if there was—if Plaintiff could show, for example, that it had to issue a new bond or take out a bank loan and could document that it actually incurred higher interest costs, then what I would expect to see on this chart would be another line, so we have on-site storage, we have alternative storage facilities and we have financing costs and presumably some documentary support for the actual costs incurred.

In the absence of such evidence, however, computing the present value of damages is interest on damages, and in all material respects, that’s prejudgment interest.

(Tr. 2087-88 (Neuberger).)

Plaintiffs do not point to any actual costs they incurred; rather they assert that “Southern’s claim for the cost of capital incurred represents an actual expense incurred during the construction and operation of additional storage facilities as a result of the Government’s partial breach.” (Pis.’ Br. 164 (emphasis supplied).) Plaintiffs argue that compensation is appropriate because these large amounts of capital were not available for other purposes. “While Southern did not borrow money specifically to finance the dry storage projects, Mr. Metcalfe testified that the cost of funds committed to the SNF storage expenses is a real economic cost to Southern ... [and] accounts for the impact of inflation on dollars and the cost of money in the credit and equity markets.” (Pis.’ Br. 104-05 (citing Tr. 1542-51 (Met-calfe)).)

Prejudgment interest on contract claims against the United States is precluded by 28 U.S.C. § 2516(a).⁴⁶ In England, v. Contel Advanced Systems, Inc., the Federal Circuit construed the “no-interest rule” broadly:

[T]he force of the no-interest rule cannot be avoided simply by devising a new name for an old institution: “[T]he character or nature of ‘interest’ cannot be changed by calling it ‘damages,’ doss,’ ‘earned increment,’ ‘just compensation,’ ‘discount,’ ‘offset,’ or ‘penalty,’ or any other term, because it is still interest and the no-interest rule applies to it.” United States Court of Federal Claims only under a contract or Act of Congress expressly providing for payment thereof.

384 F.3d 1372, 1379 (Fed.Cir.2004) (citing Library of Congress v. Shaw, 478 U.S. 310, 321, 106 S.Ct. 2957, 92 L.Ed.2d 250 (1986)) (alterations in original) (quoting United States v. Mescalero Apache Tribe, 207 Ct.Cl. 369, 518 F.2d 1309, 1322 (1975)). See also J.D. Hedin Constr. Co. v. United States, 197 Ct.Cl. 782, 456 F.2d 1315, 1330 (1972) (“Interest paid on bank loans made because of financial stringency resulting from a breach by the [g]overnment of a contract between it and the borrower is not recoverable as an item of damage.”) (cited with approval in England, 384 F.3d at 1379). Indeed, further quoting from J.D. Hedin, the Federal Circuit noted in England that “had the ‘plaintiff used his own money and so lost the interest which it might have earned for him, the claim ... would not have differed in principle [from plaintiffs claim for interest on borrowed money].’ ” England, 384 F.3d at 1379 (omission in original) (citing J.D. Hedin, 197 Ct.Cl. 782, 456 F.2d 1315, 1330) (quoting Myerle v. U.S., 33 Ct.Cl. 1, 25, 1800 WL 2024 (1897).). See also Columbia First Bank v. United States, 54 Fed.Cl. 693, 699 (2002) (rejecting plaintiffs’ claim for $4.4 million to “ ‘compensate] the plaintiff for the lost use of the money for the intervening period’ ” because of ban on prejudgment interest) (alteration in original) (record citations omitted).

(a) interest on a claim against the United States shall be allowed in a judgment of the

There is a difference between interest on a claim (i.e., prejudgment interest which begins accruing when a claim arises and continues through the pendency of the action) vice interest as a claim—such as interest actually paid to obtain capital to mitigate a breach or as a consequence of a breach. Illustratively, in a Winstar case, Federal Circuit upheld breach damages including higher financing costs paid by the nonbreaching party to obtain funds to replace the capital cushion eliminated by the government’s breach. See Bluebonnet Sav. Bank v. United States, 266 F.3d 1348, 1354-58 (Fed.Cir.2001). “[The] distinction ‘between interest as an element of damages and “interest on a claim” is well-recognized.’” Westfed Holdings, Inc. v. United States, 52 Fed.Cl. 135, 163 (2002), aff'd in relevant part, 407 F.3d 1352 (Fed.Cir.2005); Wickham Contracting Co. v. Fischer, 12 F.3d 1574, 1582 (Fed.Cir.1994) (“Although interest on equity capital is not recoverable, a contractor may recover interest actually paid on funds borrowed because of the government’s delay in payments and used on the delayed contract.”); LaSalle Talman Bank v. United States, 317 F.3d 1363, 1374 (Fed.Cir.2003) (noting that “capital is not ‘costless’” and concluding the trial court erred in not allowing recovery of costs derived from equity, because “the cost of capital does not depend on whether payment is made as debt, or out of anticipated future earnings”).

To recover debt costs such as interest, “changed work either must be directly traced to a specific loan or a necessity for increased borrowing must be shown to have been required by extra work or delay caused by the government.” Gevyn Constr. Corp. v. United States, 827 F.2d 752, 754 (Fed.Cir.1987) (emphasis added). “In the latter situation, the allowance of interest dependfs] upon a specific showing that the course of borrowing was affected by the change in question, i.e., that apart from the normal borrowing pattern, there was a necessity to borrow specifically due to the change in question.” Singer Co. Librascope Div. v. United States, 215 Ct.Cl. 281, 322, 568 F.2d 695, 718 (1977); Framlau Corp. v. United States, 215 Ct.Cl. 185, 198, 568 F.2d 687, 694 (1977) (to recover interest, plaintiff must “prove what part, if any, of its large borrowings were attributable to compensable changes” and that it was “forced to borrow to perform the changed work”) (footnote omitted). See also Bell v. United States, 186 Ct.Cl. 189, 404 F.2d 975, 984 (1968) (allowing a contractor to recover interest on borrowing caused by government changes to contract); Dravo Corp. v. United States, 219 Ct.Cl. 416, 427, 594 F.2d 842, 847 (1979) (“[I]t is clear that this court still holds to the view that direct tracing to a specific loan or necessity for increased borrowing is still required to be proven in order for a contractor to recover for interest costs under an equitable adjustment theory.”). See generally Centex Corp. v. United States, 55 Fed.Cl. 381, 390 (2003), aff'd, 395 F.3d 1283 (Fed.Cir.2005) (“[Foreseeable financing costs can be an element of expectancy damages.”) (citing Bluebonnet Sav. Bank v. United States, 266 F.3d 1348, 1354-58 (Fed.Cir.2001)).

Plaintiffs’ expert Mr. Metcalfe testified generally about capital having a theoretical cost, an assertion not in serious dispute. He acknowledged that his calculations of “cost of capital” was the time value of money to attempt to make plaintiffs whole, in order to account for inflation and the time value of money. (Tr. 1542-43.) He also noted that cost of capital is a factor in rate-making; utilities have to pay interest on unpaid amounts under the Standard Contract; so reciprocity is not unfair; and without some consideration of the time value of money, the utilities would not be made whole. (Id.) Plaintiffs make conclusory statements that capital was used and capital is not costless, but must be adjusted by inflation, etc. to account for the time value of money—a million dollars spent in 2001 is not the same as a million dollars awarded in a judgment in 2007, which will not be paid until it is final. However, plaintiffs do not point to any consideration by Mr. Metcalfe of either a specific or general debt from which any allocation to plaintiffs was made. It is not clear that any money was borrowed. Similarly, while cost of funds may be de rigueur in regulatory or other proceedings, something more is required to present interest as a claim versus interest on a claim.

In Tennessee Valley Authority there was discussion concerning the utility practice for rate-making purposes of adding to the amount of capital used on construction projects, a cost of and for those funds—-Allowance for Funds Used During Construction (“AFUDC”). 69 Fed.Cl. at 541. As noted, this industry-wide practice is consistent with FERC regulations. 18 C.F.R. pt. 101 Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act, Electric Plant Instructions, H3.A(17) (AFUDC “includes the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.”). “TVA’s cost of capital is equal to the interest rate that it pays on debt; as an entity of the federal government, TVA finances capital projects either through operating cash flows or through debt, and has no equity.” 69 Fed.Cl. at 541. TVA’s AFUDC was the average monthly interest charge on its short-term and long-term debts allocated to different projects based on the percentage of that project’s capital cost to the total capital projects of the plant. Id. Accordingly, a percentage of the total AFUDC was added to TVA’s mitigating efforts. Tennessee Valley Authority rejected the government’s argument that a match between capital expenditures and a specific debt instrument—was necessary for any recovery, holding that TVA’s general debt costs, allocated by size of the mitigation projects was sufficient for recovery. Id. at 541-42. Although Metcalfe subtracted any AFUDC before applying the weighted cost of capital to prevent any possible double counting (Tr. 1551), here, neither plaintiffs nor the parent corporations are financed as federal entities, so that ruling in Tennessee Valley Authority is distinguishable.

The parent company, Southern Company, provides capital to plaintiffs and it is the rates applicable to Southern Company that were calculated. (Tr. 1685-86 (Metcalfe); Def.’s Br. 92.) As evidence that Southern Company “incurred” costs of capital, then passed cost through to APC and GPC under Operating Agreements, plaintiffs rely on Metcalfe’s testimony and his underlying workpapers. (Pis.’ Reply Br. 60.) In their Reply Brief, plaintiffs cite to Mr. Metcalfe’s testimony and demonstratives. (Tr. 1547-48, 1584-86; PX 668 SNOC01645-46.⁴⁷) The documents upon which Metcalfe derived his cost of capital for each of the three plants are on letterhead of Southern Company. (PX 668; Tr. 1678-79; see also Metcalfe demonstrative 68 and 69 (indicating interest rates for debt, common equity and preferred equity came from Southern Company).) Southern Company is neither a party to the Standard Contract, nor a plaintiff. Furthermore, “Core Business Hurdle Rate for New Investment Projects,”... “recommended for ... all new traditional regulated capital projects,” given are based on economic forecasts. (PX 668, SNOC01633, second emphasis in original.) Rate derivations include the apparent debt cost of Southern Company; neither plaintiff nor plant-specific debt cost, is given. “Revenue requirement rate, the after-tax hurdle rate, is plant-specific, varying because of different state tax rates.” (Id. at SNOC1634,1637,1640.)

Hurdle rates are the minimum return on investment needed to attract capital investment. How these hurdle rates translate into actual debt cost attributable to capital used for these projects was not sufficiently established for the court to make a determination that a concrete, identifiable cost, as opposed to a time-value, inflation-related adjustment, was incurred.

A hurdle rate is typically a rate used for— an interest rate used for internal computations to determine if an investment project is potentially profitable____ You have a certain amount of outlays, cash outlays today, and you’re going to get a stream of revenue sometime in the future. Companies often want to determine whether that’s a—that stream of revenues is going to be a profitable enterprise is that the present value of that stream of future revenues, greater than today’s cost, and the interest rate that they often use to do that analysis is what’s called a hurdle rate. So when you compute present value or, more specifically, net present value, what you do is you take the present value of all of those future streams of income and you subtract from that the cost of the project and that gets you a net number. If that number is zero or greater at the hurdle rate, then the company will approve the project. If you can’t achieve that rate of return on the project, then oftentimes, it’s not funded. So that’s my understanding of a hurdle rate.

(Tr. 2082-83 (Neuberger).) See also Dock-ery v. C.I.R., 1998 WL 120369, *9 n. 9 (U.S.Tax Ct.1998) (“A hurdle rate is the minimum rate of return required by an investor for a proposed investment”) (citing Rosenberg, Dictionary of Banking and Financial Services 344 (2nd ed.1985).) Accordingly, rates on which “cost” of capital was based were minimum projected returns on investment for proposed new capital projects.

Apparently, projected profit level required to attract investment income was calculated before a capital investment project was approved. A new power plant or other capital expenditure would have to have a projected income flow sufficient to generate return of investment at the hurdle rate. It does not appear that dry-storage is such a revenue producer. Plaintiffs’ reliance on hurdle rates is another reason to deny recovery.⁴⁸

Deductions for costs to load to DOE casks and for second bathtub rack

Defendant asserts an offset of the cost that would have been spent at Plant Hatch and Plant Farley to load SNF to DOE’s casks if DOE had performed. Defendant also seeks an offset of the cost of installing a second bathtub rack at Plant Hatch— which would have been done even if DOE had commenced performance at any level in order to preserve a minimum of one FOR. The court agrees with plaintiffs that when DOE does perform, cask loading costs will be incurred then. If deducted now, and incurred later, plaintiff would bear the cost twice. Moreover, what those discrete loading costs might have been in a hypothetical, nonbreach world is speculative. The court adopts the reasoning and conclusion on this issue in Tennessee Valley Authority.

[T]he government claims that in the non-breach, but-for world, TVA would have had to incur costs in loading casks with SNF for delivery to DOE. As a result of DOE’s breach, the government claims that TVA has temporarily avoided these costs, that TVA has received a benefit as a result, and that the government should be credited with an offset to TVA’s damages to reflect this benefit.

The alleged benefit stems purely from timing; both DOE and TVA contemplate that DOE will still perform under the contract at some future date. As matters now stand, any benefit inhering in TVA because of delayed loading costs would be entirely speculative. It is not possible to ascertain the method DOE will ultimately use for SNF acceptance. The size and type of casks to be used to transport the SNF are not known; no casks have been approved for the purpose. The mode of transport has not been determined. Additionally, the date at which DOE will begin to perform in the future cannot even be estimated, let alone determined with reasonable certainty.

Tennessee Valley Auth., 69 Fed.Cl. at 542-43 (record citations omitted); Yankee Atomic, 73 Fed.Cl. at 286 (concluding future potential offsets speculative, citing Tennessee Valley Authority); Pacific Gas & Elec., 73 Fed.Cl. at 416 (“[I]t would be entirely speculative to offset plaintiff’s damages because of a purported benefit it will receive from loading large rail casks in the future rather than 25-ton truck casks in the non-breach world. Plaintiffs loading costs have been deferred rather than avoided, and the court declines to engage in a guessing game as to whether such deferred costs will have increased or decreased by the time (if ever) defendant performs the parties’ Standard Contract.”); Sacramento Mun. Util., 70 Fed.Cl. at 372. (“Since DOE and SMUD both contemplate that DOE will still perform under the Standard Contract at some future date, any benefit to SMUD, because of delayed loading costs, would be entirely speculative.”). Therefore, at this time, deduction from mitigation damages for hypothetical expenses that would (or might) have occurred is not appropriate.

The court concludes that the costs of installing the second bathtub rack at Plant Hatch that would have been incurred if DOE had performed should be offset from mitigation damages. The claimed offset for DOE cask loading is rejected and mitigation damages are awarded accordingly.

Other offsets to damages

Defendant’s expert, Mr. Johnson, proposed numerous adjustments, parsed primarily into categories of costs incurred but attributable to the HI-STARs and associated expenses, loading beyond one FOR at Plant Hatch, cost of capital, internal labor and PFS. (Tr. 2212 (Johnson).) In rejecting costs incurred that were deemed not reasonable, Mr. Johnson did so not based on any technical knowledge of the operation of a nuclear power plant, but relied upon testimony of others. He monetized and categorized evidence and testimony of others. (Tr. 2214 (Johnson).) Due to continuing cooperation of counsel in providing evidentiary support for the voluminous invoices and other documents listing the costs incurred, the amount of costs Mr. Johnson originally considered not adequately supported was reduced considerably. Also, plaintiffs unilaterally removed certain other costs from those claimed. Adjustments continued during trial proceedings. Except for the two following items, remaining proposed monetized adjustments were resolved.

Stand-by welding time

Defendant proposes deduction of costs paid by plaintiffs to welders who were on stand-by on-site. Briefly, to weld the casks shut, contract welders were used for the first loading campaigns at Plant Hatch. Charges were incurred for “standby time,” while they waited to weld the next cask, a standard industry practice. Mr. Wade testified:

Q. I want to ask you a question or two about welding. I believe Mr. Ekman had asked you a few questions about downtime for welders. Do you know if that’s industry practice for companies to pay downtime for welding?

A. That is my normal understanding. I mean, you know, we went to Welding Services to hire welders that were prequali-fied, precertified to make these welds. And my understanding is that they get normally a 40-hour week and we reserve those welders for that. Best of my understanding is it is not an uncommon practice to do that throughout the industry.

(Tr. 1129-30 (Wade).) Welders were specially trained to weld dry storage casks and worked on a plant site miles from other possible job sites. It was reasonable to pay for their on-site down time and defendant did not establish these charges were unreasonable.

Work platform for cask loading

Mr. Johnson also questioned the $48,284 cost of a 228-foot platform used at Plant Hatch to support workers while they welded or bolted the top of the HI-STORM cask before transport to the ISFSI pad, asserting that amount should not be included in damages. (Tr. 2363-64 (Johnson).) Mr. Wade testified that DOE would have supplied this equipment under the contract and the cost was appropriate cover or mitigation:

Q. But you would agree Southern Nuclear would need the 228 foot platform to load to a DOE cask, is that right?

A. I don’t—well, we would have assumed that the DOE would have provided access to the top of their casks, but since we have it, you [DOE] can use it.

(Tr. 1063-64 (Wade Test).) Mr. Wade’s assumption is supported by the language in the Standard Contract that DOE will supply equipment necessary to load the cask:

DOE shall arrange for, and provide, a cask(s) and all necessary transportation of the SNF and/or HLW 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 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 casks(s); and

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

Standard Contract, Art. IV.B.2.

There is no dispute that the platform was required to load—incident to mitigation otherwise recoverable under the court’s findings herein. This cost was incurred. To the extent at the time DOE does perform, if this platform is not needed or not used, any appropriate adjustments can be made at that time.

Is Southern Nuclear a proper party?

Defendant renews its request that SNC should be dismissed for lack of contractual privity because it is not a party to the Standard Contracts. (Def.’s Br. 92-93.) SNC was incorporated on December 17, 1990 for the express purpose of acting as operating agent and licensee of APC and GPC. (Pis.’ Resp. to Def.’s Motion to Dismiss, filed January 24, 2002, at 3.) “Because APC and GPC bear the costs claimed as damages in this action, damages should be awarded to APC and GPC only.” (Pis.’ Reply Br. 1 n. 1.) “[SNC] has not asserted any right to recovery in its own right; rather, [SNC’s] claims are asserted solely in its role as operating agent and attorney-in-fact for APC and GPC.” (Pis.’ Resp. to Def.’s Motion to Dismiss, Jan. 24, 2002 at 2.) And, “[SNC’s] elimination as a plaintiff would neither divest this [c]ourt of jurisdiction over APC and GPC’s claims nor affect the merits of the plaintiffs’ Complaint or the quantum of damages recoverable by APC and GPC in any way.” (Id. at 4 n. 3.) Plaintiffs assert SNC is a proper party because Operating Agreements with APC and GPC designate SNC as their “attorney-in-fact and agent” and SNC has administered the contracts with DOE. (PX 806, 807.). Plaintiffs contend that Southern Nuclear should remain in the litigation as attorney-in-fact and agent for APC and GPC, and indeed, trial evidence included documents authored by Southern and testimony included reference to Southern, as the managing company. In the end, however, APC and GPC, both in contractual privity, incurred most of the costs sought herein and defendant does not assert to the contrary.

This court previously ruled that it “lacks jurisdiction to consider or resolve any issues between APC, GPC, and SNC concerning their operating agreements ...” and no such issues were presented. “Absent contractual privity between SNC and the United States, no judgment can be rendered in favor of SNC.” (Order, Apr. 7, 2004, Dkt. 234, 4.) Nevertheless, the court allowed SNC to continue to participate as a plaintiff in this case because its “voluntary participation in this litigation could facilitate discovery and trial proceedings.” (Id.) No purpose is seen in dismissing SNC at this stage of the proceedings.

Waiver

The D.C. Circuit Court of Appeals issued a writ of mandamus prohibiting DOE from asserting its delay in commencing performance of the Standard Contract was unavoidable. Northern States Power Co. v. DOE, 128 F.3d 754 (D.C.Cir.1997) The government is “preclude[d] ... from concluding that its delay is unavoidable on the ground that it has not yet prepared a permanent repository or that it has no authority to provide storage in the interim” or from “implementing] any interpretation of the Standard Contract that excuses its failure to perform on the grounds of ‘acts of Government in either its sovereign or contractual capacity.’” Id. at 760 (citing 10 C.F.R. § 961.11, Art. IX.A.) In a footnote in its Post-Trial Brief in the present case, defendant stated that “[t]o the extent that the writ of mandamus [of Northern States Power ] were lifted or found ineffective, we would be able to assert [that the delay in commencement of performance was unavoidable under the terms of the Standard Contract].” (Def.’s Br. 2 n. 1.)

The so-called unavoidable delays clause, as well as the avoidable delays clause, are contained in Article IX of the Standard Contract entitled “Delays”:

A. Unavoidable Delays by Purchaser or DOE

Neither the Government nor the Purchaser shall be liable under this contract for damages caused by failure to perform its obligations hereunder, if such failure arises out of causes beyond the control and without the fault or negligence of the party fading to perform. In the event circumstances beyond the reasonable control of the Purchaser or DOE—such as acts of God, or of the public enemy, acts of Government in either its sovereign or contractual capacity, fires, floods, epidemics, quarantine restrictions, strikes, freight embargoes and unusually severe weather—cause delay in the scheduled delivery, acceptance or transport of SNF and/or HLW, the party experiencing the delay will notify the other party as soon as possible after such delay is ascertained and the parties will readjust their schedules, as appropriate, to accommodate such delay.

B. Avoidable Delays by Purchaser or DOE

In the event of any delay in the delivery, acceptance or transport of SNF and/or HLW to or by DOE caused by circumstances within the reasonable control of either the Purchaser or DOE or them respective contractors or suppliers, the charges and schedules specified by this contract will be equitably adjusted to re-fleet any estimated additional costs incurred by the party not responsible for or contributing to the delay.

Standard Contract, Art. IX.A.

After the trial in this matter, Nebraska Public Power District v. United States, 74 Fed.Cl. 762 (2006) held that the D.C. Circuit did not have jurisdiction over disputes under the Standard Contract. Accordingly, the mandamus order in Northern States “is void and does not preclude defendant from arguing [in Nebraska Public Power District ], inter alia, that it did not breach the Standard Contract based upon the unavoidable delays clause therein.” 73 Fed.Cl. at 674, appeal granted, 219 Fed.Appx. 980 (Fed.Cir.2007).

In view of defendant’s post-trial brief reference to its intention to assert an unavoidable delays defense, if not restricted by the D.C. Circuit’s mandamus, the undersigned, sua sponte ordered the parties, after the Nebraska decision, to address whether the validity of the D.C. Circuit’s writ of mandamus could be raised for consideration at this time in this case, or whether the issue has been waived. These matters were not previously addressed in the briefs.

Defendant’s position is that it did not, and could not have waived that defense. Plaintiffs counter that defendant could have asserted the D.C. Circuit lacked jurisdiction and/or could have preserved this possible defense with a statement similar to that made in other SNF cases pending in this court that but/for the writ of mandamus, the defense would be raised.

Litigation leading up to the D.C. Circuit’s prohibitory writ commenced in 1995. DOE formally announced, pursuant to Article IX of the Standard Contract (the Delays clause), it was “not obligated to provide a financial remedy for the delay [in commencement of performance] because the delay was ‘unavoidable.’ ” ⁴⁹ Northern States Power Co. v. DOE, 128 F.3d 754, 758 (D.C.Cir.1997). Pursuant to the judicial review provisions of the NWPA, a group of nuclear utilities challenged DOE’s position that its delay was unavoidable. Indiana Michigan Power v. DOE, 88 F.3d at 1272 (D.C.Cir.1996). In response to DOE’s position that the unavoidable delays clause together with the dispute clause of the Standard Contract, modified the deadline, the D.C. Circuit held that DOE’s obligation under the NWPA to commence performance on or before January 31, 1998 was unconditional, not dependent on the existence of a repository.

DOE’s duty under [under the NWPA] to dispose of the SNF is conditioned on the payment of fees by the owner and is triggered, at the latest, by the arrival of January 31, 1998. Nowhere, however, does the statute indicate that the obligation established in subsection (B) is somehow tied to the commencement of repository operations referred to in subsection (A).

In conclusion, ... we hold that section 302(a)(5)(B) creates an obligation in DOE, reciprocal to the utilities’ obligation to pay, to start disposing of the SNF no later than January 31,1998.

88 F.3d at 1276-77.

Thereafter, several utilities and others filed petitions for a writ of mandamus in the D.C. Circuit to compel DOE to commence performance by January 31, 1998. While those petitions were pending, and according to defendant, in response to comments received from utilities regarding the delay, DOE announced that, pursuant to Article IX of the Standard Contract, DOE was “not obligated to provide a financial remedy for the delay,” because the delay was “unavoidable.” DOE’s contracting officer wrote that “regulatory delays; roadblocks to implementation of interim or monitored retrievable storage; funding restrictions, litigation delays” were “unavoidable delays” that would exempt DOE from liability for damages for failure to commence performance by January 31, 1998.⁵⁰ Northern States Power Co. v. DOE, 128 F.3d 754, 760 (D.C.Cir.1997). Utilities sought a mandamus to compel DOE to commence performance. The D.C. Circuit granted mandamus in part, holding there was a potentially adequate remedy under the Standard Contract should DOE not commence performance in time, therefore a mandatory performance writ would not be appropriate, The Circuit also prohibited DOE from asserting its unconditional obligation to commence performance was or would be excused because of either the lack of an operational repository by January 31,1998, or because of acts of the government in its sovereign or contractual capacity.

We hold that the Standard Contract between DOE and the utilities provides a potentially adequate remedy if DOE fails to fulfill its obligations by the deadline, and thus do not grant in full the writ requested by petitioners. We do agree, however, that DOE’s current approach toward contractual remedies is inconsistent with the NWPA and with our prior decision in Indiana Michigan. We thus grant the petition in part, and issue a 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.

This necessarily means, of course, that DOE not implement any interpretation of the Standard Contract that excuses its failure to perform on the grounds of “acts of Government in either its sovereign or contractual capacity.”

128 F.3d at 756, 760 (citing 10 C.F.R. § 961.11, Art. IX.A).

The D.C. Circuit reiterated its holding in Indiana Michigan that DOE’s obligation under the NWPA to commence performance by January 31, 1998 was conditioned only on payment of fees by the utilities. That conclusion did not change under the Standard Contract.

Accordingly, we order DOE to proceed with contractual remedies in a manner consistent with NWPA’s command that it undertake an unconditional obligation to begin disposal of the SNF by January 31, 1998. More specifically, we preclude DOE from concluding that its delay is unavoidable on the ground that it has not yet prepared a permanent repository or that it has no authority to provide storage in the interim____We therefore issue a writ of mandamus precluding DOE from excusing its own delay on the grounds that it has not yet prepared a permanent repository or interim storage facility.

Northern States, 128 F.3d at 760-61. The D.C. Circuit “retained] jurisdiction over this case pending compliance with the mandate issued herewith.” 128 F.3d at 761.

DOE filed a petition for rehearing, contending the D.C. Circuit lacked jurisdiction to construe the unavoidable delays clause of the Standard Contract which, DOE contended, was a matter for the Court of Federal Claims. The D.C. Circuit denied DOE’s motion for rehearing, stating it was not adjudicating a contract dispute, rather, it was enforcing a statutory duty—a function clearly within its jurisdiction.

[t]he DOE ... suggests] that this Court has erroneously designated itself as the proper forum for adjudication of disputes arising under the Standard Contract. As the above should make clear, we did not; we merely prohibited the DOE from implementing an interpretation that would place it in violation of its duty under the NWPA to assume an unconditional obligation to begin disposal by January 31, 1998. The statutory duty to include an unconditional obligation in the contract is independent of any rights under the contract. The Tucker Act does not prevent us from exercising jurisdiction over an action to enforce compliance with the NWPA.

Northern States Power Co. v. United States, 1998 WL 276581 (D.C.Cir. May 5,1998).

Defendant, in its December 6, 2006 post-trial supplemental briefing cites one trial exhibit, a June 3, 1997 letter from Beth Toma-soni, former DOE contracting officer for the Standard Contract, to utilities, informing of her preliminary determination that DOE s delay in commencing performance was excusable under the unavoidable delays clause because of technical and regulatory issues, roadblocks to implementation of an MRS, funding short-falls and litigation delays. (PX 88.) This exhibit, while setting forth her preliminary determination, recognized utilities disagreed and alleged any delay was avoidable. Recognizing delay would result in increased on-site storage costs, Ms. Tomaso-ni’s letter invited suggested amendments to the contract under Article XV, including compensation for storage costs. (PX 88 at 2.) This post-trial mention in an exhibit is not sufficient to preserve this possible defense— and if defendant wishes to rely on one part of that letter as binding, then the other part of the letter suggesting possible amendments could include compensation for on-site storage—the goal of plaintiffs’ complaint—is part of the package.

Defendant also cites testimony of Christopher Kouts, a senior official at OCRWM. While defendant does not specify the portion of Mr. Kouts testimony which assertedly raised and preserved these issues, presumably the reference is to the following colloquy concerning funding issues and staff reduction.

A. [Kouts] [W]e did not always receive what we had requested of Congress, and there were certain years that had substantial impact on the program---- [E]very year ... we get less than we typically ask for____[W]hat that caused to the program at that time was a substantial reduction in our contractor structure, and subsequently, we actually underwent, about a year or two after that, a reduction in federal staff.

Q. And have these funding shortfalls affected DOE’s ability to perform the standard contract is a timely manner?

Mr. Blanton: I’m sorry to interrupt. But we object. Liability has been found in this case. The Court’s [sic] issued an order. The DC Circuit has ordered the Justice Department not to raise excusable delay as a defense. I can’t think of any other reason this testimony would be relevant other than that, and we object to it.

Ms. Sullivan: As we noted in our pretrial brief, Your Honor, we are seeking to preserve the record by having Mr. Kouts present this evidence.⁵¹ What arguments we may make in the future is still a matter to be decided, but while Mr. Kouts is here, we would ask he be allowed to testify about this so that the information is in the record.

Judge Merow: Well, I can see some possible relevance, not necessarily on the liability aspect of this, but just to complete the historical part of the matter, may not be directly related to the Southern case, but I think it gives a full picture of the program involved. And to that extent, I’ll overrule the objection. You can present the evidence, but of course, you can object to any findings—

Mr. Blanton: Thank you, sir.

Judge Merow:—that are proposed based on it in the nature of any limitation of liability or something like that that is attempted.

(Tr. 1794-96.)

Defendant did not raise the unavoidable delays clause of the Standard Contract and did not raise the question whether the D.C. Circuit had jurisdiction to issue the writ of mandamus prohibiting the government from asserting this provision in defense of its failure to meet the statutory and contractual obligation to commence performance by January 31, 1998. Questions of the validity or applicability of the D.C. Circuit’s mandamus in this court in this breach of contract suit could have been raised but were not. Defendant raised the absence of a repository as a defense in other SNF cases. Boston Edison Co. v. United States, 64 Fed.Cl. 167, 186-87 n. 21 (2005) (citing Northern States I, 128 F.3d at 761).⁵² On March 14, 2005, defendant argued that the D.C. Circuit lacked jurisdiction to issue a mandamus that limited its contractual defenses in Nebraska Public Power District v. United States, No. 01-116. Def.’s Response to Pl.’s Mot. for Recons., Dkt. 168.⁵³ Defendant’s challenge to the D.C. Circuit’s jurisdiction was more than seven months before the trial in this case began on October 17, 2005, and these were all prior to the October 31, 2006 certified order in Nebraska, holding the D.C. Circuit lacked jurisdiction to issue that mandate, at least as applied to contract actions in this court.

Recently, defendant asserted unavoidable delays as an affirmative defense:

To the extent that the defense is not barred by the United States Court of Appeals for the District of Columbia Circuit’s writ of mandamus in Northern States Power Co. v. United States Department of Energy, 128 F.3d 754 (D.C.Cir.1997), plaintiffs’ damages would be affected by the “unavoidable delays” clause of the standard contract.

Def.’s Answer to Second Am. Compl. and Supplemental Compl., in System Fuels, Inc. v. United States, No. 03-2624 (Fed.Cl.), Dkt. 125, filed Jan. 30, 2007, p. 7, H 37.⁵⁴

The initial Complaint in the instant action was filed on July 29,1998; the First Amended Complaint was filed on October 8, 2002; the Amended and Supplemental Complaint was deemed filed on October 11, 2005. (Dkts. 1, 175, 308.) Defendant’s responses did not raise the unavoidable delays clause as an affirmative defense, nor contend that but for the mandamus order, the unavoidable delays clause would be raised. (Dkt. 239 (Answer to Am. Compl.), Dkt. 318 (Answer to Am. and Supplemental Compl.).) Defendant’s motion for partial summary judgment filed on November 28, 2001, Dkt. 100, did not raise this issue either, nor was it raised in a pretrial hearing on September 15, 2005. During trial in October 2005 and January 2006, there was brief reference to the writ of mandamus, but defendant did not reserve any right to assert that if the writ were lifted or found to be invalid, the unavoidable delays clause defense would have been presented. With the exception of certain deposition designations, evidence was closed on January 31, 2006. (Tr. 2416-18.) While defendant’s post-trial footnote states that if the writ were lifted or found to be ineffective, unavoidable delays arguments would be made in this case, defendant does not point to any part of the record in this case wherein it asserted that the D.C. Circuit’s writ was invalid. There was no request to hold the record open.

Defendant argues it did not, and could not, waive these matters and that the cases cited in this court’s request for supplemental briefing on the issue of waiver, B-E-C-K Constructors v. United States, 215 Ct.Cl. 793, 571 F.2d 25 (1978) and Bennett Constr. Co. v. United States, 178 Ct.Cl. 61, 371 F.2d 859 (1967), are distinguishable.

While challenges to this court’s subject matter jurisdiction may be raised at any time, even sua sponte by the court or initially on appeal, see Rutledge v. United States, 72 Fed.Cl. 396, 399 (2006) (“subject matter jurisdiction may be challenged at any time by the parties”), the validity of the mandamus order from the D.C. Circuit questions the jurisdiction of that, not this, court. The issue is not one of subject matter jurisdiction, rather an affirmative defense, as defendant recently raised in System Fuels, supra. RCFC 8(c) requires that a party “set forth affirmatively” defenses such as “laches, license, payment, release, res judicata ... and any other matter constituting an avoidance or affirmative defense.” The contractual “out” that defendant would suggest is an avoidance—refuge under a clause that in certain circumstances absolves liability for breach. See 5 Charles Alan Wright & Arthur R. Miller, Federal Practice & Procedure § 1271 (2004); Stockton East Water Dist. v. United States, 76 Fed.Cl. 497, 508-512 (2007) (discussing government’s assertion that the sovereign acts doctrine shielded it from liability). As such, that potential defense was waived. Diversey Lever, Inc. v. Ecolab, Inc., 191 F.3d 1350, 1353 (Fed.Cir.1999) (“an affirmative defense must be raised in response to a summary judgment motion, or it is waived.”); Ultra-Precision Mfg. v. Ford Motor Co., 411 F.3d 1369, 1376-77 (Fed.Cir.2005) (“[A] preemption defense was not waived if raised anytime before the pretrial order, even if not pled as an affirmative defense____”); Cinergy Corp. v. United States, 55 Fed.Cl. 489, 499 n. 12 (2003) (“[B]y failing to raise this issue earlier so as to allow for its proper development at trial, plaintiff has waived any entitlement to deduct this amount.”).

Plaintiffs would be seriously prejudiced if the record were reopened to litigate what is or was unavoidable or beyond the control and without the fault or negligence of the government. “It is always possible to imagine more evidence which could- have been offered, but at some point litigation must come to an end.” Hazelwood School Dist. v. United States, 433 U.S. 299, 319, 97 S.Ct. 2736, 53 L.Ed.2d 768 (1977) (Brennan, J., concurring). The court is also mindful that delay prejudices plaintiffs because of the unavailability of interest. Accordingly, for the foregoing reasons, the court concludes that in this case defendant has waived any defense of the unavoidable delays clause as well as the validity the writ of mandamus in Northern States Power Co. v. DOE, 128 F.3d 754 (D.C.Cir.1997). B-E-C-K Constructors v. United States, 215 Ct.Cl. 793 n. 3, 571 F.2d 25, 28 n. 3 (1978); Bennett Constr. Co. v. United States, 178 Ct.Cl. 61, 70-71, 371 F.2d 859, 864 (1967).

In Maine Yankee Atomic Power Co. v. United States, 225 F.3d 1336, 1341 (Fed.Cir.2000), the Federal Circuit examined whether the government could rely upon Article IX.B of the Standard Contract, the avoidable delays clause, for absolution of any liability for failure to commence performance by January 31, 1998. The Federal Circuit held that clause applied only to delays once performance had commenced, and thus did not absolve DOE from liability for failure to commence performance by January 31, 1998—an unconditional requirement of the contract. The same day, in a different case, in which defendant had advanced the same arguments addressed to the avoidable delays clause, the Federal Circuit in Northern States Power Co. v. United States, 224 F.3d 1361, 1367 (Fed.Cir.2000), according to defendant, “inadvertently” penned the “unavoidable delays clause” rather than the “avoidable delay clause” in referring to the issue Maine Yankee had decided.

Both Maine Yankee and Northern States were decided on the same day, by the same panel. Both opinions were authored by Senior Circuit Judge Friedman. Maine Yankee affirmed the undersigned’s: (1) denial of the government’s motion to dismiss for failure to exhaust remedies under the contract’s disputes provision;⁵⁵ and (2) ruling that defendant had partially breached the Standard Contract. The Federal Circuit rejected the government’s assertion the avoidable delays clause applies to “any” delay, holding the provision was:

a more limited one dealing with specified kinds of delays, namely, those “in the delivery, acceptance or transport” of nuclear waste [such as] delays that routinely may arise during the performance of the contract. For them to arise, however, the parties must have begun performance of their obligations relating to disposal of the nuclear waste.

225 F.3d at 1341.

Yankee’s claim against the government is far broader than one for improper delays by the [DOE] in performing its contractual obligations. Yankee contends that the government breached a critical and central obligation of the contract—that it begin disposal of nuclear waste by January 1, 1998. Congress found this objective so important when it promulgated the Act that it took the unusual action of specifying that all the contracts must contain this explicit requirement. The breach involved all the utilities that had signed the contract—the entire nuclear electric industry. The language of the avoidable delays provision of the contract cannot properly be read to cover Yankee’s claim.

225 F.3d at 1341^12. That complete relief would not be available under the avoidable delays clause was cited as a reason for rejecting the government’s position that the matter must be addressed under the contractual disputes procedure.

Northern States “presented] the same basic issue as Maine Yankee.” Northern States Power Co. v. United States, 224 F.3d at 1363 (Fed.Cir.2000). The factual discussion in Northern States included the D.C. Circuit’s Indiana Michigan decision that the January 31, 1998 commencement of performance deadline was unconditional, not dependent on a repository. 224 F.3d at 1364 (citing Indiana Michigan, 88 F.3d at 1272 (D.C.Cir.1996)). DOE’s characterization of the lack of either permanent or temporary storage as an unavoidable delay is cited along with the resulting D.C. Circuit’s writ of mandamus. 224 F.3d at 1365. Referencing its simultaneous opinion in Maine Yankee, the Federal Circuit held:

that the unavoidable delays provision deals with delays arising after performance of the contract has begun, and does not bar a suit seeking damages for the government’s failure to begin performance at all by the statutory and contractual deadline of January 31,1998.

224 F.3d at 1367 (emphasis supplied).

Both the avoidable and unavoidable delays clauses mention adjustment of schedules. The unavoidable delays clause provision provides that “the parties will readjust their schedules, as appropriate, to accommodate such delay.” Standard Contract, Art. IX.A. The avoidable delays clause also provides for adjustment of schedules as well as adjustment of charges. “[T]he charges and schedules specified by this contract will be equitably adjusted to reflect any estimated additional costs incurred by the party not responsible for or contributing to the delay.” Standard Contract, Art. IX.B.

In our Maine Yankee opinion we pointed out that it was unclear whether the amount the company had paid for electricity generated before April 17, 1983 could be equitably adjusted at all under the unavoidable delays clause. The same problem does not arise with respect to the charges Northern States paid after that date, which presumably are subject to equitable adjustment. For the reasons set forth in our Maine Yankee opinion, however, that factual difference between the two cases does not warrant a different outcome in them.

224 F.3d at 1361. Defendant in the instant case stated the Federal Circuit’s use of the word “unavoidable” was inadvertent.⁵⁶ (Dkt. 353, 6 n. 1, Dee. 5, 2006.) However, pending any precedential ruling to the contrary, the court is bound by the Federal Circuit’s language. Accordingly, it is concluded that defendant waived assertion of any unavoidable delays defense in this litigation, but in any event the defense is not viable in view of the Federal Circuit’s ruling in Northern States.

CONCLUSION

Historically, for reasons of public health and safety, the federal government has long assumed responsibility for disposal of highly radioactive waste such as that involved in this litigation. As provided by the NWPA in 1983, the United States, represented by DOE, entered into contracts with plaintiffs under which DOE, in return for plaintiffs’ payment of fees calculated to cover DOE’s costs of developing and implementing the waste disposal system required by that contract, was to start accepting and removing plaintiffs’ SNF no later than January 31, 1998. The contracts have been breached by a series of delays that now continue into 2017 and perhaps 2018. As a result, plaintiffs have built dry storage and reracked, as detailed herein, mitigating efforts that would not have been necessary if DOE had commenced performance at any reasonable pickup rate. In these circumstances, it is concluded that plaintiffs are entitled to recover the following expenses incurred through December 31, 2004, in reasonably mitigating DOE’s acknowledged delays in initiating performance of the Standard Contract.

As the court in Pacific Gas and Electric observed:

The sole reason plaintiff is being awarded damages in this case is the government’s delay in providing storage facilities for spent fuel after having contracted to do so. The United States, with the vast resources of the most powerful nation on Earth, has failed, after nearly a quarter century, to accomplish a task that plaintiff, with limited resources, has accomplished in less than a decade.

73 Fed.Cl. at 432 n. 81 (emphasis in original).

Accordingly, upon consideration of the evidence, testimony and argument in this regard, damages are awarded as follows:

(1) Final judgment shall be issued in favor of plaintiffs for the following total sums:

ALABAMA POWER COMPANY

Plant Farley

$14,821,000.00 ISFSI

Dry Casks 2,191,000.00

Loading to ISFSI 266,000.00

APC TOTAL $17,278,000.00

GEORGIA POWER COMPANY

Plant Hatch

ISFSI $25,871,000.00

Dry Casks $18,978,000.00

Loading to ISFSI $10,570,000.00

Bathtub Racks $ 3,186,000.00

Less cost to install ($ 419,800.00)

bathtub rack (offset for

nonbreach world)

Adjustments⁵⁷ ($ 982,120.00)

Hatch Subtotal $57,203,080.00

Plant Vogtle

SpentFuel Rerack $ 2,716,000.00

Vogtle Subtotal $ 2,716,000.00

Hatch Subtotal $57,203,080.00

Vogtle Subtotal $ 2,716,000.00

GPC TOTAL $59,919,080.00

(2) In accord with Restatement (Second) of Judgments § 26(b)(1) and (e), plaintiffs may bring a subsequent action(s) for damages incurred after December 31, 2004. Indiana Michigan, 422 F.3d at 1377-78.

1 . Spent nuclear fuel “has been withdrawn from a nuclear reactor following irradiation, the constituent elements of which have not been separated by reprocessing.” 42 U.S.C. § 10101(23) (2005).

2 . Briefing was extensive. Plaintiffs’ Post-Trial Brief was 167 pages; defendant's was 186; plaintiffs’ Reply was 63 pages.

3 . GPC owns 50.1% of Plant Hatch and 45.7% of Plant Vogtle. Other owners of Plant Hatch are Oglethorpe Power Company (30%), Municipal Electric Authority of Georgia (17.7%) and the City of Dalton (2.2%). Plant Vogtle is also owned by Oglethorpe Power Corporation (30%), Municipal Electric Authority of Georgia (22.7%) and the City of Dalton (1.6%). (PX 6 (Kenrich Report) at 1.)

4 . APC has about 1.3 million customers consisting of businesses, families and government agencies; GPC serves around 2 million. (Tr. 26-27.)

5 . Mr. Long received a bachelor’s degree in physics from the Georgia Institute of Technology in 1966, a master’s degree in nuclear engineering from that institution in 1969 and an MBA from the University of Alabama in Birmingham in 1979. He attended Harvard Advanced Business Management School in 1995. During his senior year and into his first year of graduate school, he calculated fuel burn-up rates at the Savannah River Plant which produced plutonium for weapons. He was in the Army as a weapons analyst, assessing foreign tactical nuclear weapons, for a year and a half before serving in Vietnam. (Tr. 115-16.) After analyzing Soviet and Chinese nuclear weapons for the United States Army in the 1960s, in 1970, he started as a licensing engineer at Plant Hatch, Unit 2, responsible for obtaining the construction permit from the Nuclear Regulatory Commission (“NRC”). Since then, he has managed hundreds of engineers responsible for the operation and modification of Southern Company's three nuclear plants. In 1979, he became manager of procurement for both nuclear and fossil fuel plants for Southern Company Services, a corporate subsidiary. In 1981, he headed the Nuclear Safety and Licensing Group at Southern Company Services which had licensing and support responsibilities. Responsibility for nuclear fuel was added in 1985. In 1987, he was a member of a task force to consolidate operations at all three nuclear plants. In 1988, he was appointed Vice President of Technical Support of Southern Company Services, where he was responsible for in-service inspections, quality assurance, nuclear fuel and regulatory environmental services. In 1990, SNC was formed and he was appointed Vice President of Technical Support. In the conclusions reached herein, the court credits Mr. Long’s extensive experience in the nuclear industry.

6 . The NWF was established to cover DOE’s costs. The Fund is "composed of payments made by the generators and owners of such waste and spent fuel, that will ensure that the costs of carrying out activities relating to the disposal of such waste and spent fuel will be borne by the persons responsible for generating such waste and spent fuel.” 42 U.S.C. § 10131(b)(4). Utility breach of contract claims cannot be settled by offsets to future payment obligations. Alabama Power Co. v. DOE, 307 F.3d 1300, 1313-14 (11th Cir.2002). The NWF cannot be used to finance the State of Nevada’s participation in NRC licensing hearings. Nevada v. DOE, 400 F.3d 9 (D.C.Cir.2005). See Northern States Power Co. v. DOE, No. 97-1064, 1998 WL 276581 (D.C.Cir. May 5, 1998) (declining to opine on use of the Fund to pay breach damages).

7 . Hughes launched the five satellites in question, from 1985 to 1994, thus “covering” NASA’s pre-deadline announcement. Hughes Commons Galaxy, Inc. v. United States, 47 Fed.Cl. 236, 240 (2000).

8 . San Carlos Irrigation & Drainage was cited by the Federal Circuit in Indiana Michigan, 422 F.3d at 1373.

9 . Congress intended that under the contract, beginning no later than January of 1998, DOE would accept, transport and dispose of SNF and the utilities would pay for these services. H.R.Rep. No. 97-491, Pt. 1, at 59 (1982), U.S.Code Cong. & Admin.News 1982, pp. 3792, 3825 (DOE "is responsible for disposing of [HLW or SNF] ... in permanent disposal facilities, beginning not later than January 1998, in return for the payment of fees established by this section.”); Standard Contract, 10 C.F.R. pt. 961, pmbl. & Art. VII; Indiana Michigan Power Co. v. DOE, 88 F.3d 1272, 1276 (D.C.Cir.1996).

10 . Bruce Hunt is the nuclear fuel manager for Southern Company, a position he has held since 1989. He has a bachelor’s of science degree in engineering physics from Cornell University and a master of science degree in nuclear engineering from the Georgia Institute of Technology. (Tr. 439-40.) He joined Southern Company Services (which later became Southern Company) in 1972. One of his responsibilities starting in 1979 was the development of the contract with DOE. He was aware of pre-contracting activities and, on behalf of GPC and APC, participated in early meetings with DOE. (Tr. 446.)

11 . The Standard Contract defines the signing utility as the “Purchaser.” 10 C.F.R. § 961.11 (Preamble).

12 . The final Standard Contract defined “DOE facility” as "a facility operated by or on behalf of DOE for the purpose of disposing of spent nuclear fuel and/or high-level radioactive waste, or such other facility(ies) to which spent nuclear fuel and/or high-level radioactive waste may be shipped by DOE prior to its transportation to a disposal facility.” 10 C.F.R. § 961.11, Art. 1.10.

13 . If there was any doubt that the contract was with the United States, explanatory comments prefatory to the published final contract reported that twelve commentors requested the definition of DOE include successor agencies. That suggestion was declined in part because “the Purchaser is not contracting, as such, with DOE, but rather with 'the United States of America ... represented by the U.S. Department of Energy.' " 48 Fed.Reg. at 16,591, Supplementary Information, Art. I (alteration in original).

14 . Discharge date came from RW-859 data forms submitted to DOE periodically by the utilities. The longer SNF has been out of the reactor the cooler it is.

15 . If the aggregate requests for acceptance exceeded the annual capacity of the disposal facility, acceptance would generally be based on OFF. 1. Acceptance Priority Ranking.

Delivery commitment schedules for SNF and/or HLW may require the disposal or [sic] more material than the annual capacity of the DOE disposal facility (or facilities) can accommodate. The following acceptance priority ranking will be utilized:

(a) Except as may be provided for in paragraph (b) below and Article V.D. of this contract, acceptance priority shall be based upon the age of the SNF and/or HLW as calculated from the date of discharge of such material from the civilian nuclear power reactor. DOE will first accept from Purchaser the oldest SNF and/or HLW for disposal in the DOE facility, except as otherwise provided for in paragraphs B and D of Article V.

10 C.F.R. § 961.11, Art. VI.B.1(a).

16 . The “commitment” was that of the utilities, not DOE. From the history, the reason could relate to the potential value of recoverables in the waste. SNF is not truly “spent,” but can, through processes beyond the pale of this Opinion, be reprocessed. With transfer of title, DOE will be entitled to any proceeds of reprocessing.

17 . DOE established the Nuclear Waste Policy Act Project Office to begin implementation of its responsibilities under the NWPA and later formed "OCRWM.” 42 U.S.C. § 10224. (Lawrence Dep. 24-25, May 20, 2002 (PDD 18); PX 45.)

18 . Despite its "draft” moniker, the NWPA required "a draft mission plan” to be published in the Federal Register. See 42 U.S.C. § 10221(b).

19 . The Standard Contract requires the SNF to be cooled for five years before acceptance disposal by DOE. 10 C.F.R. § 961.11, App. E.B.3.

20 . The NWPA authorized the DOE to conduct siting activities for a second repository. Until a second repository was in operation, the first repository could accept only 70,000 MTU. Projections at that time were for a total of 130,000 MTU industry-wide. Accordingly, a second repository was contemplated. (PX 38 at 22.) On May 28, 1986, the Secretary of Energy postponed site-specific activities for a second repository. (PX 40 at 13.)

21 . Five years of operation divided by a 15,000 MTU capacity is 3000 MTU annually.

22 . When DOE issued the Standard Contract as a final rule, 48 Fed.Reg. 16590 (April 18, 1983), several modifications were made from the proposed rule, following industry input. The final Standard Contract eliminated any requirement for DOE to begin SNF “disposal” in a permanent repository by January 31, 1998. The final rule required DOE to begin SNF acceptance after "the commencement of facility operations, not later than January 31, 1998.” "Facility" was defined as either a permanent repository to be constructed pursuant to the NWPA or such other facility to which SNF might be shipped by DOE prior to shipment to a permanent repository. 10 C.F.R. § 961.11, Art. 1.10, Art. II; 48 Fed.Reg. 16590, 16591 (April 18, 1983). Defendant does not point to any provision of the NWPA or the Standard Contract that permits contingent performance.

23 . No 1989 ACR was issued because, at the request of the Secretary of Energy, an assessment of the program schedule to Congress concluded there was a "significant slip for the expected start of repository operations—from the year 2003 to approximately 2010.” (PX 70.) Until a revised schedule was developed, an ACR would not be useful for planning. (Id.)

24 . “Upper bounding” and "lower bounding” denoted generally maximum and minimum. (Tr. 1174 (Bland).)

25 . The 1992 ACR, Revision 1, dated May 1993 (PX 11 at 4), differs from the 1992 ACR dated March 1993 (PX 10 at 4), in that the former adds the word "nominal" to the description of the projected annual rates.

26 . That all DCSs solicited under the 1991 ACR were disregarded by DOE is another reason for rejecting defendant’s reliance thereon.

27 . This statement was also in the 1997 Strategic Plans of Plant Hatch and Plant Vogtle.

28 . Building an ISFSI required specialized soils engineering including earthquake-protected concrete pad design. Engineering work was handled primarily by Southern Company. The concrete was designed to assume a 175-ton loaded cask would fall; accordingly, the concrete had to be relatively "soft” to absorb such a load—a very difficult engineering task. Analysis of the reactor plant also included floor loading capacity to handle the tremendous weights involved, as well as the dangers associated with moving nuclear material. About 100 pieces of equipment were required, including vacuum pumps, gantry cranes, railcar pushers and lifting slings. The fabrication of many of these items was inspected by the NRC. Dry-run testing was done internally and then for the NRC, including demonstrations of loading, lifting and moving these 175-ton containers. Demonstrations of loading and moving required specialized weights to replicate the cask systems.

29 . A Holtec dry storage system was used by other nuclear utilities during this time. Pacific Gas & Elec., 73 Fed.Cl. at 411; Tennessee Valley Auth., 69 Fed.Cl. at 524-25; System Fuels, Inc. v. U.S., 65 Fed.Cl. 163, 168 (2005); Entergy Nuclear Indian Point, 64 Fed.Cl. at 522; Indiana Michigan, 60 Fed.Cl. at 657.

30 . Decommissioning is the process of permanently shutting-down a nuclear power plant.

31 . Southern's licensing efforts on the HI-STAR benefltted the HI-STORM, leading to its licensing in 2000. (Tr. 1178-80 (Bland).)

32 . To the extent that the HI-STARs may have a residual value, and/or whether further costs or offsets may be significant in this regard, await future events when such matters may become relevant.

33 . Thomas MeCallum is a Project Manager for Southern Nuclear and managed the construction of Plant Farley’s ISFSI. He has over 20 years of nuclear-related engineering and management experience and received his bachelor’s and master’s degrees in mechanical engineering from Mississippi State University. (Tr. 1258-71(McCallum).)

34 . Other relatively minor adjustments as detailed in defendant’s Brief were also made. (Def.’s Br. 86.)

35 . Eileen Supko is a Senior Consultant with Energy Resources International, Inc., consultants on nuclear fuel cycle matters, including spent fuel management. The court accepted Ms. Sup-ko as an expert in nuclear engineering, DOE’s waste management program, storage and disposal of SNF and modeling of SNF acceptance and allocation rates. (Tr. 878-81.)

36 . The court in Tennessee Valley Authority rejected the government’s challenge to the "viability of the 'plus or minus 20%’ provision” of the Standard Contract, citing testimony of David Zabran-sky, DOE’s contracting officer, that "expressed an understanding that the Standard Contract would require DOE to accommodate a request by a utility” under this provision. 69 Fed.Cl. at 533.

37 . Tennessee Valley Authority also rejected as “unavailing” the government’s argument that an inter-utility exchange "market" was speculative. 69 Fed.Cl. at 533. See also Yankee Atomic, 73 Fed.Cl. at 299-306 (discussing as “compelling,” expert witness testimony as to the economics of inter-company exchanges under the Standard Contract).

38 . The record evidence demonstrates that a reasonable annual removal rate in most circumstances would fall between the 2000 MTU annual industry SNF discharge as the floor and the annual 3000 MTU design capacity of the planned repository as the ceiling.

39 . Tennessee Valley Authority rejected the government’s suggestion that an employee’s time be included in mitigation only if that employee spent more than fifty percent of his or her time on mitigating efforts. 69 Fed.Cl. at 540 (”[U]se of a '50%' criterion as a surrogate [for whether an employee was precluded from other work and/or whether that employee’s cost should be included in mitigation damages] is not supportable.’’). Applying that same reasoning here, defendant’s suggested $5,000 a year per employee threshold is, likewise, rejected.

40 . The court inquired as to whether recovery in this litigation would result in a rebate to ratepayers. In response, Mr. Metcalfe testified that in his experience, "the [state regulatory] commission works with the utilities to decide how that money will be distributed. Generally, the proposition is that a substantial if not ... total amount of the moneys will go back to the ratepayers in some fashion with adjusted rates going forward.” (Tr. 1563-64 (Metcalfe).)

41 . Larry Johnson, President and CEO of Veris Consulting in Reston, Virginia, graduated from the University of Maryland with a degree in accounting. He attended graduate school at George Washington University where he completed all the course work for a master’s in finance, but did not write a thesis, so does not have the designation. He is a certified public accountant. He spent 18 years as an accountant at Ernst and Ernst, one of the big eight accounting firms. He left that firm in 1986 to open up his own firm with another individual, that grew from those two founders to over 100 professionals. The firm focused primarily in accounting and auditing. In 2000, he formed Veris Consulting which concentrates on forensic-litigation matters in addition to providing outsourcing of audit and accounting and surveying services. Veris Consulting has approximately 100 professionals with offices in Virginia, New Jersey and Ohio. (Tr. 2178-84 (Johnson).) His experience includes damage analysis involving "but-for worlds” and analysis of damage models. He has been qualified as a expert witness in several courts, including this court in Winstar-related cases and other SNF cases. (Tr. 2184—88 (Johnson).) The court qualified Mr. Johnson as an expert witness in the areas of financial analysis, cost accounting, auditing and analysis of economic damages. (Tr. 2190, 2196.) Mr. Johnson admitted he had no experience in the operation of nuclear power plants. {Id.) He applied data from plaintiffs' claim. In reaching his expert opinions, he relied on conclusions of Dr. Neuber-ger as to the number of casks loaded and room in the spent fuel pool, although Dr. Neuberger also did not claim any nuclear operational experience. (Tr. 2193-95.)

42 . For internal, regulatory and other purposes, employees would record their time to certain projects or tasks.

43 . Q. Southern Nuclear is an investor in PFS right?

A. That’s correct.

Q. So if PFS were to earn a profit, Southern Nuclear would be entitled to a share of that?

A. I believe that’s correct.

(Tr. 211 (Long).)

44 . Mr. Blanton (plaintiffs’ counsel): But other than that [certain maintenance work orders for Plants Hatch and Farley], I think everything else in this—in the claim as expressed by the Ken-ric[h] group, the government has agreed is supported from a books and records standpoint. Is that right?

Mr. Ekman (defendant’s counsel): That's correct.

(Tr. 6.)

45 . Kenneth Metcalfe is the President of The Ken-rich Group LLC, a business and litigation consulting firm. He is a Certified Public Accountant and a Certified Valuation Analyst and has computed accounting, financial, and economic damages in matters involving the construction and operation of over forty nuclear plants during the past twenty years. (Tr. 1406 (Metcalfe).) The court accepted Mr. Metcalfe as an expert in accounting, finance and economics related to damages and other related issues with respect to regulated utilities, nuclear power plants and government contracts. (Id. at 1446, 1449.)

46 . 28 U.S.C. § 2516(a) provides:

47 . Metcalfe’s demonstrative slide 69 referenced in his testimony is from these two pages of PX 668.

48 . Also, a cost of capital accelerator was added by plaintiffs' expert to all damages components, not just capital expenditures. While the cost of internal labor has been allowed as a reasonable mitigation expense, since no additional capital expense is involved in this cost, the addition of a capital accelerator to internal labor is not supportable in any event. If cost of capital were to be awarded, the amount associated with any claim item rejected, such as the investment in PFS, must also be deducted.

49 . DOE's Final Interpretation of Nuclear Waste Acceptance Issues, 60 Fed.Reg. 21,793, 21,797 stated that the lack of a operational repository on January 31, 1998 would exempt it from liability for breach of contract under the delays clauses.

50 . The unavoidable delays clause addresses liability for damages if the delay "arises out of causes beyond the control and without the fault or negligence of the party failing to perform.” The contracting party with the utilities is the government. See Yankee Atomic Co. v. United States, 73 Fed.Cl. at 258 n. 14. Regulatory delays and funding restrictions would not be actions beyond the control of the government. They are actions of the government.

51 . A footnote in the defendant’s Memorandum of Contentions of Fact and Law, states "as part of the Government's evidence at trial, we anticipate that Mr. Kouts and perhaps other witnesses will testify regarding the reasons for DOE's delay in beginning SNF acceptance and its excusabilily. The [c]ourt may find it necessary to resolve these issues at trial.” (Dkt. 309-2, 34 n. 7, filed Sept. 28, 2005.)

52 . “[T]he government has persisted in urging in this court that it has an obligation to accept and dispose of SNF and HLW only if an appropriate repository is available, notwithstanding the D.C. Circuit’s grant of a writ of mandamus in November 1997 precluding DOE from excusing its own delay on the grounds that it has not prepared a permanent repository or interim storage facility-”'

53 . That Response (signed by government trial counsel who was also trial counsel in the instant action) included a section, titled in part:

WE BELIEVE THAT THE D.C. CIRCUIT OVERSTEPPED ITS JURISDICTION IN RULING UPON THE SCOPE OF THE 'UNAVOIDABLE DELAYS' CLAUSE IN THE STANDARD CONTRACT

[T]he Government consistently has taken the position that the Court of Federal Claims has the exclusive jurisdiction to resolve issues concerning the construction and administration of the Standard Contract.... [T]he United States courts of appeals do not possess jurisdiction under section 119 of the NWPA to review performance-related matters arising under the Standard Contract. Yet, in Northern States, the United States Court of Appeals for the District of Columbia Circuit expressly asserted jurisdiction to interpret and rule upon the "unavoidable delays” clause contained in the Standard Contract and to determine whether the delay at issue in these cases is encompassed within that contract provision. The D.C. Circuit then purported to bar the [DOE] from asserting any interpretation of the "unavoidable delays” clause that would excuse its delay based upon that contract clause. Because the D.C. Circuit lacked jurisdiction to resolve that issue, the Government should not be barred from revisiting that issue in this Court. See Christopher Village, L.P. v. United States, 360 F.3d 1319, 1329-30 (Fed.Cir.2004), cert. denied, 543 U.S. 1146, 125 S.Ct. 1296, 161 L.Ed.2d 106 (2005). It is for this very reason that this [c]ourt can, and should, notwithstanding the United States Court of Appeals for the District of Columbia Circuit's decision in Northern States Power, resolve the issue of whether DOE may properly invoke the "unavoidable delay” provision of the Standard Contract.

Nebraska Public Power Dist., Dkt. 168, 5-6.

54 . Defendant did not raise this defense in its recent Amended Answer in Wisconsin Electric Power Co. v. United. States, another pending SNF case. Def.'s Answer to Second Am. Compl. and Supplemental Compl., No. 00-697 (Fed.Cl.), Dkt. 248, June 25, 2007.

55 . Under the disputes provision of the Standard Contract: "any dispute concerning a question of fact arising under this contract which is not disposed of by agreement shall be decided by the Contracting Officer....” Standard Contract, Art. XVI. Appeals are to the DOE Board of Contract Appeals. Id.

56 . The unavoidable delays clause was addressed in briefing in Northern States. Br. for Def.Appel-lee, Northern States Power v. United States, No. 99-5096, 1999 WL 33607498, at *6, 9, 10 (Fed.Cir. Oct.29, 1999); No. 99-5096, 2000 WL 34467127, at *3, 6 (Fed.Cir. Nov. 15, 2000).

57 . Defendant proposed "Other Adjustments” of $1,080,404, to which plaintiffs responded in part. (Pis.' Br. 117.) With the exception of stand-by welding labor costs ($50,000) and the expenses of the work-platform for loading Hi-STORMs ($48,284), this adjustment is accepted.