# Southern Nuclear Operating Co. v. United States

> United States Court of Federal Claims · July 9, 2007 · 77 Fed. Cl. 396

URL: https://www.frixlaw.com/law-library/cases/6656498

## Case

- **Full name:** SOUTHERN NUCLEAR OPERATING COMPANY, Alabama Power Company, Georgia Power Company v. United States
- **Court:** United States Court of Federal Claims
- **Decided:** July 9, 2007
- **Citations:** 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
- **Precedential status:** Published
- **Opinion:** Opinion of the court by Merow
- **Judges:** Merow
- **Cited by:** 42 later opinions in the Frix Law Library

## Citator (automated)

- **Red flag:** Vacated in part, on other grounds by Southern Nuclear Operating Co. v. United States, 637 F.3d 1297 (2011).
- Negative treatments: 1
- Distinguished by: 0
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/6656498

## How later opinions describe it (automated extraction)

- holding that “the government had partially breached the Standard Contract by failing to begin accepting [spent nuclear fuel] in January 1998,” and stating that “[t]here is no issue on appeal as to liability; liability in these [spent nuclear fuel] cases has been established”
- finding that use of internal labor was “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”
- holding that “defendant bears the burden of establishing that mitigating decisions or expenditures were unreasonable”
- declining to award PFS-related damages and holding “that on this recoi’d, foreseeability and substantial causation wei’e not established”

## Opinion text

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 *399 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 customers 4 and is their *400 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).
*401 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
*402 (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- *403 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 .
*404 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 *405 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 *406 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. *407 647, 652 (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 moti *408 vated/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 *409 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 Purchaser 11 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 *410 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 *411 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 *412 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.
*413
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 repositories 20 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, *414 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 *415 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, *416 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 *417 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 *418 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 *419 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 *420 v. United States, 308 F.3d 1233 , 1240 (Fed.Cir.2002)).
The 1992 ACRs 25 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- *421 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 *422 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 *423 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- *424 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 *425 (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 *426 ($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. *427 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 *428 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 *429 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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/6656498. Public record. Not legal advice.