
    BOSTON EDISON CO., Plaintiff, v. UNITED STATES, Defendant. Entergy Nuclear Generation Co., Plaintiff, v. United States, Defendant.
    Nos. 99-447C, 03-2626C.
    United States Court of Federal Claims.
    Filed Under Seal: Feb. 15, 2008.
    Reissued: Feb. 20, 2008.
    
      Richard J. Conway, Diekstein Shapiro LLP, Washington, D.C., for plaintiff Boston Edison Co. With him at trial and on the briefs were Bradley D. Wine and Bernard F. Sheehan, Diekstein Shapiro LLP, and with him on the briefs was Nicholas W. Mattia, Jr., Diekstein Shapiro LLP, Washington, D.C. Of counsel was Neven Rabadjija, Associate General Counsel, NSTAR Electric & Gas Corp., Boston, MA.
    Alex D. Tomaszczuk, Pillsbury, Winthrop, Shaw, Pittman, LLP, McLean, VA, for plaintiff Entergy Nuclear Generation Co. With him at trial and on the briefs were Jay E. Silberg, Daniel S. Herzfeld, and Jack Y. Chu, Pillsbury, Winthrop, Shaw, Pittman, LLP, Washington, D.C., and L. Jager Smith, Jr., Wise, Carter, Child, & Caraway, PA., Jackson, MS.
    Alan J. Lo Re, Senior Trial Counsel, Commercial Litigation Branch, Civil Division, United States Department of Justice, Washington, D.C., for defendant. With him at trial and on the briefs were Joshua E. Gardner, Scott R. Damelin, Patrick B. Bryan, Sonia M. Orfield, and Stephen P. Finn, Trial Attorneys, United States Department of Justice, Washington, D.C. With him on the briefs were Peter D. Keisler, Assistant Attorney General, Jeanne E. Davidson, Director, and Harold D. Lester, Jr., Assistant Director, Commercial Litigation Branch, Civil Division, United States Department of Justice, Washington, D.C. Of counsel was Jane K. Taylor, Office of General Counsel, United States Department of Energy, Washington, D.C.
   OPINION AND ORDER

LETTOW, Judge.

INTRODUCTION

This case is one of first impression for the court. Although suits brought by utilities against the government for damages resulting from the non-performance by the Department of Energy (“DOE”) of its statutory and contractual obligations to collect spent nuclear fuel have become commonplace, this case is novel in that it involves the post-breach sale of a nuclear power plant and alleged damages measured by the diminution of the plant’s value caused by DOE’s non-performance.

Both the seller and the buyer of the Pilgrim Nuclear Power Station (“Pilgrim”) located in Plymouth, Massachusetts, have brought claims for contractual damages in this court. The seller, Boston Edison Company (“Boston Edison”) entered into a Standard Contract with DOE on June 17, 1983, calling for the disposal by DOE of spent nuclear fuel (“SNF”) and high-level radioactive waste (“HLW”) generated at Pilgrim. Stip. 111. In effect, the Standard Contract reflects and carries out certain provisions of the Nuclear Waste Policy Act of 1982 (“NWPA”), Pub.L. No. 97-425, § 302, 96 Stat. 2201, 2257-2261 (Jan. 7, 1983) (codified as amended at 42 U.S.C. § 10222). Under the NWPA and the Standard Contract, DOE was to begin collecting SNF no later than January 31, 1998. See 42 U.S.C. § 10222(a)(5)(B); see also Boston Edison Co. v. United States, 64 Fed.Cl. 167, 170 (2005) (“Boston Edison I ”). To date, DOE has not disposed of the SNF generated at Pilgrim, and DOE is not likely to have a SNF repository available to begin acceptance of SNF from Pilgrim or any other source within the foreseeable future. See System Fuels, Inc. v. United States, 79 Fed.Cl. 37, 40-41, 47 (2007).

Boston Edison filed its complaint in this court on July 12, 1999, alleging that the United States had partially breached the Standard Contract and had breached the implied covenant of good faith and fair dealing. Boston Edison I, 64 Fed.Cl. at 170. One day later, on July 13, 1999, Boston Edison sold Pilgrim to Entergy Nuclear Generation Company (“Entergy”), assigning its Standard Contract to Entergy as part of the Purchase and Sale Agreement. Stip. 115; see also Entergy Nuclear Generation Co. v. United States, 64 Fed.Cl. 336, 338 (2005). Under the assignment, Boston Edison retained claims that had accrued as of the closing date, with Entergy acquiring claims accruing thereafter. See Boston Edison I, 64 Fed.Cl. at 173. Entergy filed suit against the United States on November 5, 2003, also alleging a partial breach of the contract and breach of the implied duty of good faith and fair dealing. See Entergy Nuclear, 64 Fed.Cl. at 338.

In prior proceedings, this court denied a motion by the government to dismiss Boston Edison’s claims and also denied the parties’ cross-motions for summary judgment on liability. See Boston Edison I, 64 Fed.Cl. at 170. Thereafter, the government moved to consolidate the Boston Edison and Entergy Nuclear eases, contending that both cases arose out of the same contract and, absent consolidation, the government would be potentially exposed to overlapping awards of damages. The court consolidated the cases “for the limited purpose of addressing issues concerning (1) contract formation, (2) contract implementation through the date of sale of the Pilgrim Nuclear Power Station, and (3) Boston Edison Company’s diminution-in-value claim and the government’s attendant offset claim against Entergy.” Boston Edison Co. v. United States, 67 Fed.Cl. 63, 67 (2005) (“Boston Edison II”). As the parties were preparing for trial, the court addressed and resolved several contentious discovery disputes in what by then had become a tripartite litigation. See Boston Edison Co. v. United States, 75 Fed.Cl. 557 (2007) (“Boston Edison III”). A thirteen-day trial was held June 4-20, 2007. Following completion of post-trial briefing and a closing argument on November 8, 2007, the case is ready for final disposition.

FACTS

Pilgrim is a “boiling water” nuclear reactor that went into commercial operation in 1972, when the Nuclear Regulatory Commission (“NRC”) issued Boston Edison a forty-year operating license, valid until 2012. See Tr. 277:2-13, 412:11-13 (Test, of Edward Howard, a former Executive Vice President of Boston Edison). Under the license, Pilgrim is subject to a detailed NRC regulatory regime, which includes rules adopted in the 1960s bearing on the sale of nuclear plants. See 10 C.F.R. § 50.80 (transfer of licenses); Tr. 806:4-20 (Test, of Robert S. Wood, a former Financial Analyst for the NRC). In its operations, Pilgrim “burns” nuclear fuel assemblies in its reactor core, and when those fuel assemblies have been burned to the point where they are “spent,” they are discharged to a spent-fuel pool. See System Fuels, 79 Fed.Cl. at 48-49 (describing more completely the operational characteristics of a comparable nuclear power-generating reactor). In the pool, the spent assemblies are stored in basket-like racks under water, where the radioactive products of nuclear fission present in the assemblies can decay safely. Id. Pilgrim -will discharge more than 3,000 spent fuel assemblies by the end of its license life in 2012. BX 122 (Expert Report of William J. Manion) at 4186.

A The Statutory and Contractual Regime

On January 7, 1983, Congress enacted the NWPA to “establish the Federal responsibility, and a definite Federal policy, for the disposal” of SNF and high-level radioactive waste, 42 U.S.C. § 10131(b)(2), while ensuring “that the costs of carrying out activities relating to the disposal of such waste and spent fuel will be borne by the persons responsible for generating such waste and spent fuel.” 42 U.S.C. § 10131(b)(4). Through the NWPA as initially enacted, Congress authorized “the siting, construction, and operation of repositories” by the federal government, that would be used for “the permanent disposal of high-level radioactive waste and ... spent nuclear fuel.” Pub.L. No. 97-425, § 111, 96 Stat. 2207 (codified at 42 U.S.C. § 10131(a)(4), (b)(1)). Congress directed the Secretary of Energy to nominate repository sites, and, following Presidential and Congressional approval, to authorize construction of repositories through action of the NRC. Id., §§ 112, 115, 96 Stat. 2208, 2217 (codified at 42 U.S.C. §§ 10132, 10135); see also Yankee Atomic Elec. Co. v. United States, 73 Fed.Cl. 249, 255 (2006) (citing 42 U.S.C. §§ 10132-35).

The NWPA also establishes the regime by which nuclear power generators have contracted with DOE for the acceptance, transport, and disposal of SNF. System Fuels, 79 Fed.Cl. at 41 (citing 42 U.S.C. § 10222(a)(1)). The NWPA provides that contracts were to be entered requiring the contracting utilities to pay a one-time fee for the electricity generated and sold prior to April 7, 1983, and a continuing fee based on the amount of electricity generated after that date. Id. (citing 42 U.S.C. § 10222(a)(2)-(3)). In return, the contracts were to oblige the government to begin to collect and dispose of SNF and HLW no later than January 31, 1998. Id. (citing 42 U.S.C. § 10222(a)(5)(B)). Operators of nuclear power facilities had to enter into these contracts to avoid losing their nuclear facility licenses. Id. at 42 (citing 42 U.S.C. § 10222(b)(1)(A)); see also Indiana Michigan Power Co. v. United States, 422 F.3d 1369, 1372 (Fed.Cir.2005) (citing 42 U.S.C. § 10222); Northern States Power Co. v. United States, 224 F.3d 1361, 1364 (Fed.Cir.2000). To implement the NWPA, the government promulgated a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, codified at 10 C.F.R. § 961.11. See 48 Fed.Reg. 5,458 (Feb. 4,1983).

Both the NWPA and the Standard Contract anticipated and provided for the transfer of nuclear facilities. The statute provides that “[t]he rights and duties of a party to a contract entered into under this section may be assignable with transfer of title to the spent nuclear fuel or high-level radioactive waste involved.” 42 U.S.C. § 10222(b)(3). The Standard Contract has a provision to the same effect with an added proviso, stating that “rights and duties of the Purchaser may be assignable with transfer of title to the SNF and/or HLW involved; provided, however, that notice of any such transfer shall be made to DOE within ninety (90) days of transfer.” BX 5 (Contract # DE-CR01-83NE44368 for the Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (“Boston Edison’s Standard Contract”)), art. XIV; see also Rochester Gas & Elec. Corp. v. United States, 65 Fed.Cl. 431 (2005) (holding that the express authorization in 42 U.S.C. § 10222(b)(3) for assignments of Standard Contracts supersedes the Assignment of Contracts Act, 41 U.S.C. § 15, and the Assignment of Claims Act, 31 U.S.C. § 3727).

B. Experience Under the Contract

As the parties have stipulated, Boston Edison met its obligations under the Standard Contract. Stip. 116. Boston Edison paid the one-time fee in the amount of $40,582,782 on June 27, 1985, and paid all one-mill-per-kilowatt-hour continuing fees required under the Standard Contract, in an amount in excess of $48,500,000. Stip. 117. On September 21, 1993, September 20, 1994, September 26, 1995, and September 29,1998, Boston Edison submitted Delivery Commitment Schedules to the Department of Energy, as part of the process established in the Standard Contract by which DOE would identify and then collect SNF and HLW from nuclear utilities. Id. at H 2; see also Tennessee Valley Auth. v. United States, 60 Fed.Cl. 665, 668-69 (2004) (outlining the process established in the Standard Contract for identification and collection of SNF). DOE, on the other hand, has not disposed of any SNF at Pilgrim, and DOE is not likely to have a SNF repository available to begin acceptance of SNF from Pilgrim or any other source for at least another ten years. See System Fuels, 79 Fed. Cl. at 44-48 (chronicling DOE’s steps toward implementing the Standard Contract and its ultimate non-performance).

C. Deregulation and Boston Edison’s Generation-Divestment Program

During the late 1990s, governmental actions were taken at the state and federal levels to deregulate the electric utility industry. Tr. 530:18-531:4 (Test, of Geoffrey O. Lubbock, Vice President-Financial Strategic Planning and Policy, NSTAR Electric and Gas Corporation, and former Director of Generation Divestiture for Boston Edison); BX 155 (Amended Expert Report of John J. Reed on behalf of Boston Edison (“Reed Report”)) at 3986. At the federal level, the Federal Energy Regulatory Commission (“FERC”) sought to encourage market competition through the issuance of FERC Order 888. See FERC, Promoting Wholesale Competition Through Open Access Nonr-Dis-criminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats, and Regs. K 31,-036, 61 Fed.Reg. 21,540 (May 10, 1996); see also Tr. 532:21 to 533:1 (Lubbock). FERC Order 888 “required the functional unbun-dling of utilities and an open access requirement for transmission in the transmission markets ... [and strongly] encouraged utilities to divest their generation and separate generation from the transmission and distribution businesses.” Tr. 530:23 to 531:4 (Lubbock).

Correlatively, in November 1997, Massachusetts enacted legislation to restructure its electric utility industry, “moving the state from a traditional vertically-integrated monopoly structure to a competitive generation market structure,” in particular by requiring “regulated utilities, including [Boston Edison] to either divest or functionally separate their electricity generation assets and operations from their transmission and distribution operations.” BX 155 (Reed Report) at 3986; Tr. 724:1-19 (Test, of Timothy New-hard, Financial Analyst, Utilities Division, Office of the Attorney General, Commonwealth of Massachusetts); Mass. Gen. Laws ch. 164 (1997) (“An Act Relative to Restructuring the Electric Utility Industry in the Commonwealth, Regulating the Provision of Electricity and Other Services, and Promoting Enhanced Consumer Protection”) (capitals removed).

In response to the Massachusetts restructuring legislation, Boston Edison entered into a Settlement Agreement with the Office of the Massachusetts Attorney General laying out Boston Edison’s generation-divestment program. BX 288 (Settlement Agreement); Tr. 724:25 to 725:20 (Newhard); Tr. 528:24 to 529:12 (Lubbock). The Settlement Agreement established a procedure to sell or divest the company’s power-generating assets, which included the Pilgrim nuclear plant and its contracts for purchasing power. BX 288 (Settlement Agreement, Letter from Douglas S. Horan, Senior Vice President and General Counsel, Boston Edison, to Secretary Mary L. Cottrell, Department of Public Utilities, outlining the Settlement Agreement) at 2, BEC-0002126; Tr. 725: 9-12, 725:25 to 726:3 (Newhard). The Agree-merit’s purpose was “to open up the electric market in Massachusetts” so that consumers could “buy power from the competitive market. It required the company to divest its generation and power purchase contracts and in doing so required it to either sell the nuclear power plant or to value it and move it into a nonregulated subsidiary.” Tr. 529:3-12 (Lubbock). However, the Agreement did not require, but only encouraged, the sale of Pilgrim because of uncertainty as to whether there would be a market for nuclear power plants. Tr. 726:4-18 (New-hard). Pilgrim was to be valued for the purpose of calculating stranded costs either through a competitive sale or through an administrative valuation process. Tr. 726:11-18 (Newhard); see also Tr. 528:24 to 529:12, 579:23 to 580:2, 582:8-19 (Lubbock). The Settlement Agreement was approved by the Massachusetts Department of Telecommunications and Energy (“DTE”), the state agency responsible for regulating Massachusetts utilities. Tr. 527:17-19 (Lubbock); BX 288 (Settlement Agreement, Petition of Boston Edison Co., D.P.U./D.T.E. 96-23 (D.T.E. Jan. 28,1998)) at 2456-2547; BX 289 (Notice of Corrected Pages to DTE’s order (Feb. 2, 1998)).

Boston Edison elected to value Pilgrim through the use of a competitive auction, which it determined would result in the most accurate market valuation of the plant. Tr. 580:20-23 (Lubbock).

D. Competitive Sale Process

To manage a competitive auction for Pilgrim, Boston Edison employed the services of Reed Consulting Group (“Reed” or “Reed Consulting”). Reed drafted a confidential offering memorandum (“Offering Memorandum”), solicited bids, oversaw due diligence, managed the bidding process, and negotiated the details of the purchase and sale agreement. Tr. 13:2-5, 26:14-28:3, 85:19 to 86:2, 154:15-20 (Test, of John J. Reed, principal of Reed Consulting). Reed Consulting initially sent an early-interest letter as well as other marketing materials to 175 potential bidders, who represented a wide range of persons and entities interested in energy assets. BX 155 (Reed Report) at 3987. Nine parties who met the financial and operating qualifications necessary for purchasing Pilgrim signed a Confidentiality Agreement. Id. Reed Consulting issued the Offering Memorandum to the qualified parties in June 1998, Tr. 154:15-20, 156:1 to 157:25 (Reed); BX 93 (Offering Memorandum), among other things advising them that Boston Edison intended to transfer to the successful bidder all decommissioning responsibilities, including those associated with spent fuel. BX 93 (Offering Memorandum).

The Offering Memorandum specifically advised that Boston Edison would provide a fully-funded decommissioning fund in an amount deemed sufficient by the buyer to cover the costs of decommissioning Pilgrim plus “interim fuel storage until such a time as the [DOE] takes title to the fuel.” BX 93 (Offering Memorandum) at 0009; Tr. 156:9-24 (Reed). Under this proposed approach, the decommissioning fund would reach beyond NRC’s requirements, which provided that a decommissioning fund had to cover the costs of decommissioning the radioactive portions of a nuclear power plant but not also on-site storage costs for SNF. See 10 C.F.R. § 50.75(c) footnote 1 (“Amounts [required for the fund] are based on activities related to the definition of ‘Decommission’ in § 50.2 of this part and do not include the cost of removal and disposal of spent fuel or of nonradioaetive structures and materials beyond that necessary to terminate the license.”). By June 1998, DOE was already months late in commencing spent fuel collection under the Standard Contract. Boston Edison, relying on the government’s then-expressed position that performance would begin “no longer [in the future] than 2010,” Tr. 157:6-7 (Reed), held the “expectation that it [i.e., DOE’s collection] wasn’t going to happen anytime soon.” Tr. 158:3-4 (Reed). The fund therefore was intended to cover the cost of what Boston Edison characterized as “long-term” on-site storage. Boston Edison’s Posh-Trial Br. at 19. In addition to the Offering Memorandum, Boston Edison also supplied bidders with a draft dated April 1998 of a site-specific decommissioning study by Nuclear Energy Services, Inc. (“NES”), a decommissioning cost estimating firm, which provided detailed information about a number of decommissioning scenarios for Pilgrim. Tr. 159:18 to 161:22, 177:2-8 (Reed), 612:15 to 613:7 (Lubbock), 2282:20 to 2283:8, 2380:2-14 (Test, of William J. Manion, WJM Consulting Services LLC); BX 305 (NES Study). NES’s site-specific decommissioning study included SNF storage costs, and the scenarios that were addressed in the study varied in their assumptions about future SNF storage. See BX 305 (NES Study) at RFP-21-14065-66.

1. Bidders’ due diligence.

Two principal bidders, Entergy and Amer-Gen Energy Co. (“AmerGen”), conducted a due-diligence examination of Pilgrim. En-tergy commenced the due-diligenee process with a detailed examination of Pilgrim and its operations that included a week-long visit by a team of over forty Entergy employees, a review of the plant and facility, and staff interviews. Tr. 1006:5 to 1007:25 (Test, of Jack Harrington, a former vice president of business systems and information for Enter-gy, retained as a consultant by Entergy for assistance with due diligence and who was called by Boston Edison to testify at trial). The Entergy team identified a need for installation of additional racks in Pilgrim’s spent fuel pool to provide interim storage of SNF. Tr. 1027:22 to 1028:18,1036:2-19 (Harrington); BX 47 (Entergy’s due-diligence field notes) at RFP-21-787; cf. Tr. 446:19 to 448:6 (Test, of Henry V. Oheim, NSTAR Project Manager and former Pilgrim senior manager). It concluded that Pilgrim was then in good operating condition. BX 156 (Expert Rebuttal Report of John J. Reed) (“Reed Rebuttal Report”) at 4055-56.

Entergy also conducted detailed due diligence regarding decommissioning expenses. It expressly noted that decommissioning expenses (including those associated with SNF storage) were “the largest factor” in developing the Pilgrim bid. Tr. 2042:13 to 2043:6 (Test, of Dan Keuter, Vice President for Business Development for Entergy); BX 67 (Letter from Keuter to Michael Meisner, President, Maine Yankee Atomic Power Co. (Aug. 24, 1998)). Entergy retained a decommissioning cost-evaluation firm, TLG Services Inc. (“TLG”), to independently analyze the NES study, and Entergy also requested a separate analysis from Entergy’s decommissioning team that was managing the Maine Yankee nuclear plant decommissioning process. Tr. 1947:11 to 1950:4 (Keuter); BX 29 (Entergy’s Pilgrim Acquisition Analysis (Sept. 1998)) at 13052, 13165-253; BX 67 (Letter from Keuter to Meisner). In comparing the decommissioning scenario of the NES study of Pilgrim that was deemed more likely to occur to TLG’s estimates for decommissioning other similarly-sized plants, TLG determined that dry storage would be needed at Pilgrim. Interim storage of SNF in added racks at the pool would become insufficient as the plant continued in operation. Tr. 1179:1 to 1180:23 (Test, of Thomas La-Guardia, former President, TLG). When required, dry storage at Pilgrim would entail significant risks and costs. BX 72 (TLG Study) at SUPPL-21; BX 69 (Mem. from LaGuardia to Steve Downes, Entergy Nuclear, Inc. (Sept. 23,1998)) at SUPPL-29. Specifically, TLG’s study estimated approximately $80 to $85 million for SNF storage costs. Tr. 1161:12 to 1162:4 (LaGuardia). Correla-tively, Entergy’s Maine Yankee team confirmed that significant costs would be imposed for dry storage at Pilgrim, BX 29 (Entergy’s Pilgrim Acquisition Analysis) at 13238, and both TLG and Entergy estimated that the annual operation and maintenance costs for a dry storage facility at Pilgrim would be more than $2 million. Tr. 1967:20 to 1969:3, 2110:5 to 2115:2 (Keuter); BX 72 (TLG Study) at Supp. 21; BX 29 (Entergy’s Pilgrim Acquisition Analysis) at 13030.

Entergy’s due-diligence efforts were matched by those of AmerGen, the other principal bidder. AmerGen assessed a decommissioning strategy for Pilgrim and hired BNFL Inc. to provide a cost estimate and review the NES study. Tr. 1764:17 to 1770:8 (Test, of Drew Fetters, former Vice President, Nuclear Acquisitions, AmerGen). Am-erGen also determined that Pilgrim would need additional storage racks for its spent fuel pool to provide interim storage of SNF, and that on-site, dry storage would be necessary for longer-term storage of SNF. Tr. 1752:3 to 1755:9, 1809:23 to 1810:8 (Fetters); BX 76 (AmerGen Due-Diligence Report) at 818; BX 78 (BNFL Study) at 1264.

2. Indicative and subsequent bids.

Four parties submitted indicative bids, En-tergy, AmerGen, and two parties code-named “Cranberry” and “Purple.” Tr. 31:8 to 32:8 (Reed). Both Entergy and AmerGen’s lead venture partner, PECO Energy, submitted bids that included separate amounts for the purchase of the plant and for the transfer of the decommissioning trust fund. DX 202 (Entergy’s Indicative Bid (July 30, 1998); Tr. 1764:17 to 1770:8, 1808:2 to 1811:13 (Fetters). Qualifying bidders then submitted so-called “Final Bids.” Tr. 32:13-23 (Reed); see DX 241 (Entergy’s Final Bid (Oct. 15, 1998)); BX 384 (PECO’s Bid (Oct. 16, 1998)). Entergy and PECO submitted competitive bids at that stage, Tr. 32:13-23 (Reed), and those two bidders were asked to supplement and clarify their bids. See, e.g., DX 244 (PECO’s Supplemental Bid (Oct. 26, 1998)), responding to Reed’s request). The two bidders were asked to address decommissioning costs in particular because Boston Edison was concerned that the amount the bidders wanted for the decommissioning fund was too high. See Tr. 1999:15-18 (Keuter) (“[Mr. Reed] basically gave us categories of where we could improve our bid and what approximately ... we needed to be competitive.”); DX 244 (PECO’s Supplemental Bid); BX 91 (Letter from Reed to Keuter (Oct. 29,1998)); DX 247 (Entergy’s Second Supplemental Bid (Oct. 29,1998)). Entergy ultimately adjusted both the purchase-price and decommissioning-fund elements of its bid to Boston Edison’s satisfaction. As Mr. Keuter testified:

Q. This letter, DX-247, is in response to Mr. Reed’s BX-91 letter, correct?
A. Correct.
Q. Now this figure of 466 [for the decommissioning trust fund], did Mr. Reed suggest to you that that’s the number you have got to come up with?
A. He indicated that the 535 was significantly high and that we would have to reduce our bid to be competitive, but he did not quote a number, no.
Q. He didn’t tell you 466 or any particular number, did he?
A. No.
Q. This is a number that Entergy came up with, right?
A. Yes.

Tr. 1978:14 to 1979:4 (Keuter). Entergy’s successful bid reflected a purchase price of $80 million for the plant, inventory, fuel, and land, and called for a decommissioning trust fund of $466 million to be transferred by Boston Edison to Entergy. DX 256 (Enter-gy Improved Supplemental Bid (Oct. 30, 1998)); BDX 1 (Pilgrim Sale Price); Tr. 64:19-24, 82:17-21 (Reed), 1920:5-21 (Keu-ter).

To arrive at the $80 million purchase price, Entergy retained its former vice president, Mr. Harrington, as a consultant to develop a discounted-cash-flow (“DCF”) model to value Pilgrim. Tr. 1286:10 to 1287:12 (Test, of Carolyn Shanks, then manager of financial control for Entergy Operations, Inc.); see also Tr. 1003:2 to 1004:2, 1039:24 to 1040:4, 1080:8-25 (Harrington). Mr. Harrington’s model incorporated revenue and expense drivers to estimate Pilgrim’s cash flows through 2012, when its license from the NRC was due to expire and it was expected that commercial operation of the plant would cease. Tr. 1018:1-14, 1023:7-21 (Harrington). The cash flows were discounted at a rate which equated to Entergy’s “cost of capital” (based on a capital structure of 100% equity), to produce a net present value (“NPV”) and internal rate of return (“IRR”) for Pilgrim. Tr. 1024:10-18, 1053:2-9 (Harrington), 3014:20 to 3015:13 (Reed). While Entergy’s model did not assume an extension of the plant’s operating license past 2012, it did contemplate that SNF would have to be stored after plant closure, and, indeed, it assumed that the last pick up of SNF from Pilgrim by DOE would not occur until 2043. Tr. 1929:14-18 (Keuter). Entergy anticipated that there would be capital expenditures for cask purchases, construction of an independent on-site spent fuel storage facility, and handling equipment, as well as annual operating and maintenance costs for storing the SNF until that time. BX 72 (TLG Study) at SUPPL-21; BX 29 (Entergy’s Pilgrim Acquisition Analysis) at 13030. Uncertainty associated with accurately estimating the actual costs and timing of storing and disposing SNF, however, dictated that En-tergy could not guarantee that the decommissioning transfer amount it sought would be sufficient to cover these costs. BX 156 (Reed Rebuttal Report) at 4052-53. This residual risk and others associated with ownership and operation of a nuclear power plant were taken into account by Entergy’s board in requiring that the purchase be made only with a projected NPV that was tens of millions of dollars above the acquisition cost, resulting in an estimated IRR well above Entergy’s cost of capital. Tr. 1250:11-17 (Shanks) (“[W]e took a very conservative view because, again, it was a new business venture we were going into that did have risks that did not have ratepayer revenues to support it ... if it were shut down, and we had no other power source to back that facility up, should it shut down.”); see also BX 62 (Entergy board resolution approving purchase of Pilgrim (Oct. 30, 1998), with appended revised terms of purchase showing NPV analysis). Entergy’s valuation thus accounted for all of the risks associated with the purchase that it could identify.

Specifically with respect to the decommissioning trust fund, to reach the $466 million figure, Entergy (1) began with the TLG cost estimate of $578.1 million, (2) removed $6.1 million for pre-planning decommissioning costs identified in TLG’s analysis, (3) anticipated an April 1, 1999 closing date, and, (4) applied a particular discount rate. Tr. 2986:1 to 2987:11 (Reed). Entergy determined that it would require $782 million to decommission Pilgrim in 2012, BX 88 (Closing Binders) at 3265-67, with $466 million representing the funding necessary as of April 1, 1999 to yield $782 million by 2012. Tr. 2222:21-25, 2230:25 to 2233:15 (Keuter), 2985:9 to 2989:15 (Reed); see also BX 57 (charts and graphs prepared by TLG for Entergy showing site-specific funding requirements as of particular dates) at SUPPL-1 to -5.

3. The focus of the final negotiations.

Two key elements in the final negotiations over the Purchase and Sale Agreement were a contractual provision regarding Boston Edison’s retention of certain claims and the amount of the decommissioning fund.

In preparation for the final negotiations, Geoffrey Lubbock and others from Boston Edison met with representatives of the Office of the Massachusetts Attorney General. The Massachusetts Attorney General’s representatives advanced two requirements for the Pilgrim sale: (1) that Boston Edison ensure that it retained all of its claims against the United States arising out of DOE’s breach of the Standard Contract, and (2) that Boston Edison agree that any damages awarded be returned to Boston Edison’s ratepayers. Tr. 734:2 to 735:8 (Newhard); see also Tr. 539:22 to 540:11 (Lubbock). The latter requirement was intended to compensate Massachusetts ratepayers for having shouldered the burden of SNF-related costs, if Boston Edison recovered damages from and against the government for breach of Pilgrim’s Standard Contract. Tr. 255:16 to 256:3 (Reed).

After Boston Edison’s meeting with representatives of the Office of the Massachusetts Attorney General, one of Boston Edison’s outside counsel drafted, and Reed Consulting negotiated with Entergy, a provision retaining Boston Edison’s rights with respect to DOE’s breach. Tr. 223:22 to 224:9 (Reed), 540:12-24 (Lubbock); BX 79 (E-mail from Jay Silberg to Keuter (Nov. 13,1998), setting out draft language (“Silberg e-mail”)). The language adopted in the Purchase and Sale Agreement stated that Boston Edison would retain “any claims of Seller related or pertaining to the [DOE’s] defaults under the DOE Standard Contract accrued as of the Closing Date, whether relating to periods prior to or following the closing date.” DX 265 (Purchase and Sale Agreement, § 2.2(g)) at 0176-77; Tr. 541:18 to 542:2 (Lubbock); BX 79 (Silberg e-mail).

The negotiations between Boston Edison and Entergy also focused on the amount of money to be transferred to Entergy in the decommissioning fund. The Agreement established the rights and duties of Boston Edison and Entergy with respect to the fund. Tr. 192:24 to 193:17 (Reed), 706:7 to 708:14 (Lubbock); DX 265 (Purchase and Sale Agreement, § 5.21) at 0208-10. Specifically, Section 5.21 of the Agreement was developed to provide that Boston Edison would transfer a decommissioning trust amount totaling $466 million to Entergy, $70 million of which was to be deposited in a provisional trust pending the outcome of a request for a private letter ruling from the Internal Revenue Service (“IRS”) relating to the taxability of income from amounts included in the fund. DX 265 (Purchase and Sale Agreement, § 5.21) at 0208-10; Tr. 190:2 to 191:23 (Reed), 706:22 to 707:16 (Lubbock). The $466 million figure was based on Entergy’s calculation of the funding necessary to be transferred at the time of closing to provide for decommissioning commencing in 2012 and on-site SNF storage through 2043, as discussed above. Under the NRC’s regulations, the amount of a decommissioning fund set up for a plant could be derived either from a plant-specific study or from a calculation that used a generic formula specified by the NRC. See 10 C.F.R. § 50.75(b)(4) (site-specific cost estimate for decommissioning a facility), (c) (formula for calculating “minimum amounts”); see also 10 C.F.R. § 50.75(e)(l)(i) (differing provisions for credit for projected earnings of the fund, depending upon whether a site-specific estimate or a formula-based computation was used to determine the amount of the fund). Relying on testimony of Ms. Shanks and Mr. Keuter, both the government and Entergy contend that the amount that Entergy finally agreed to accept for the decommissioning amount was derived from the NRC’s minimum-amount formula expressed in 10 C.F.R. § 50.75(c). See Def.’s Post-Trial Br. at 20-21; Entergy’s Post-Trial Br. at' 14-15. Because that amount excludes SNF-storage costs, see 10 C.F.R. § 50.75(c) footnote 1, quoted swpra, at 473, the government and Entergy assert that Boston Edison paid Entergy nothing for SNF-storage costs when it transferred a decommissioning fund amounting to $466 million to Entergy. Id. Both the government and Entergy use $396 million as the calculated minimum amount. See Def.’s Post-Trial Br. at 20-21; Entergy’s Post-Trial Br. at 14-15. All parties including Boston Edison agree that $396 million was the minimum amount calculated under the NRC’s formula, as the formula existed at the time the Purchase and Sale Agreement was entered, which was before a regulatory change, Revision 8 of NUREG 1307, reduced the minimum decommissioning-cost formula.

The evidence supporting the government’s and Entergy’s contentions in this regard is very weak, to the point that it is barely colorable. The record shows that Entergy wanted $466 million for the decommissioning fund, not $396 million, and that the formula-based calculation that produced $396 million was a cross-check prepared to insure that no difficulties would occur in obtaining the NRC’s approval of the sale and transfer of the operating license. See BX 57 (charts and graphs prepared by TLG for Entergy showing site-specific funding requirements, as of particular dates, reflecting cost-escalation and fund-growth rates and the effect of tax-benefit assumptions, plus “NRC” minimum-formula amounts) at SUPPL-1 to -5; BX 62 (Entergy board resolution approving purchase of Pilgrim (Oct. 30,1998), with appended revised terms of purchase showing NPV analysis) (“Transfer from seller of a fully-funded decommissioning trust of $466M (1999$).”).

The testimony of Ms. Shanks and Mr. Keu-ter sidesteps the fact that $466 million was actually provided by Boston Edison for the decommissioning fund. Ms. Shanks testified that Entergy’s board of directors authorized a minimum decommissioning “bid” of $396 million. See Tr. 1267:8-12 (Shanks) (“That was the bottom number, the threshold that the Board of Directors gave us that we had to receive in order to have this bid approved by them and make it to Boston Edison.”). Mr. Keuter’s testimony was to the same effect. See Tr. 2050:6-9 (Keuter) (“So we were using the NRC minimum as a floor that we wouldn’t go below because we didn’t want to have to top off the fund.”). However, the Entergy board resolution approving the purchase contravenes this assertion. See BX 62 (Entergy board resolution), quoted supra. Indeed, Mr. Keuter’s own testimony regarding the revised terms of sale as approved by the Entergy board on October 30, 1998, indicates that he recommended to the board the revised offer with $466 million for the decommissioning fund:

Q. Would you bring up BX-62 please. Sir, this is a two-page exhibit, this is BX-62. Have you ever seen it before?
A. Yes.
Q. And did you see it on or about October 30,1998?
A. Yes.
Q. And how did you come to see this on October 30,1998?
A. I was involved in its preparation.
Q. And explain how you were involved in its preparation, please.
A. This is a presentation that was made to a meeting of the Board of Directors.
Q. When you say this is a presentation, are you referring to—
A. The second page is the presentation.
Q. Bates page 40-39?
A. Yes.
Q. Who made this presentation to the board?
A. I don’t remember.
Q. But you prepared this document, though?
A. Yes.
Q. This 40-39?
A. Yes.
Q. And you recommended this revised offer?
A. Correct.
Q. And on this page 40-39, in the left-hand column, third bullet from the bottom says, “transfer from seller of a fully-funded decommissioning trust of 466.”
A. Yes.
Q. That’s $466 million, right?
A. Correct.
Q. And in 1999 dollars, right?
A. Yes.

Tr. 1982:10 to 1983:23 (Keuter); see also BX 29 (Entergy’s Pilgrim Acquisition Analysis) at 13028 (“Due to delays in constructing the DOE spent fuel repository, the necessity of on-site spent fuel storage is now reflected in decommissioning costs.”); Tr. 1964:20 to 1965:19 (Keuter).

Lastly, the Purchase and Sale Agreement plainly states that a total amount of $466 million was to be transferred, with any reduction from that amount to be based upon obtaining a favorable tax ruling from the Internal Revenue Service:

5.21. Funding of the Decommissioning Trust and Provisional Trust.
(a) On the Closing Date, Seller shall fully fund and transfer to Buyer in accordance with this Section 5.21 an aggregate amount equal to or greater than the minimum amount required by the Nuclear Regulatory Commission regulations for the decommissioning of Pilgrim. Such funding and transfer is intended to occur in as tax efficient manner as possible in order to minimize the rate impact on Seller’s ratepayers. Accordingly, Seller shall have or establish as of the Closing Date a Decommissioning Trust and, if necessary, a Provisional Trust. Absent any pre-clos-ing change in the tax law, rule or regulation as in existence on the Effective Date, or an IRS ruling issued to either the Seller or Buyer, the aggregate amount to be funded for decommissioning in both the Decommissioning Trust and the Provisional Trust shall be based upon the assumption that the Decommissioning Trust and the Provisional Trust will be treated upon transfer to the Buyer as one hundred percent (100%) “non-qualified” pursuant to Section 468A of the Code. If the Closing Date is April 1, 1999, and no Pre-Closing Change (as defined below) has occurred, the Decommissioning Trust Closing Amount shall be $396 million, and the amount of funding for the Provisional Trust shall be $70 million. If the Closing Date is June 30, 2000, and no Pre-Closing Change has occurred, the Decommissioning Trust Closing Amount shall be $418 million, and the amount of the funding for the Provisional Trust shall be $70 million. If the Closing Date occurs on a date between April 1, 1999 and June 30, 2000, the Parties shall determine the Decommissioning Trust Closing Amount by computing a daily adjustment factor determined on the basis of the difference in the funding amount necessary for such two closing dates and the amount of funding for the Provisional Trust shall be $70 million.
(b) If before the Closing Date there is an amendment of Section 4.68A of the Code or the Treasury regulations promulgated thereunder, or the IRS’s interpretations thereof, which has the effect of causing the funds of the Decommissioning Trust to accumulate more rapidly than possible under the federal tax laws as of the Effective Date (e.g., the applicability of a lower tax rate) (a “Pre-Closing Change”), the funding amount for the Provisional Trust described above shall be decreased in accordance with Schedule 5.21; provided, that if such amount is decreased to zero, no Provisional Trust shall be established.
(c) If on or after the Closing Date and before December 31, 2002, there is an amendment of Section J/.68A of the Code or the Treasury regulations promulgated thereunder, or the IRS’s interpretations thereof, which has the effect of causing the funds of the Decommissioning Trust to accumulate more rapidly than possible under the federal tax laws as of the Closing Date (e.g., the applicability of a lower tax rate) (the “PosU-Closing Change”), the amount of the funds in the Provisional Trust shall be reduced in accordance with Schedule 5.21 and such reduction shall be rebated in accordance with the Provisional Trust; provided, however, that any such reduction and rebate shall be accomplished in a manner consistent with the Atomic Energy Act, the Code and other applicable law. Under no condition shall Buyer be personally liable for any payments or refunds except to the extent permitted to be paid from the Provisional Trust under applicable law.

DX 265 (Purchase and Sale Agreement, § 5.21) at 0208-09.

The Purchase and Sale Agreement as executed provided that Entergy would pay Boston Edison $80 million as the purchase price for the plant, its fuel, inventory, and land. DX 265 (Purchase and Sale Agreement, § 2.5(a)) at 0179. This amount was allocated to $67 million for the fuel in the core, $8 million for the inventory, $5 million for the land, and nothing for the plant itself. Tr. 1296:22 to 1299:8 (Shanks); BX 43 (Minutes of Entergy Board Nuclear Committee Special Meeting (Oct. 1, 1998), with attached DCF analysis (“Entergy Board Minutes”)) at RFP-21-3054, 3057.

E. Regulatory Approvals for the Sale

After executing the Agreement, Boston Edison and Entergy worked together to obtain regulatory approval from the NRC for the transfer of Pilgrim’s operating license and from the Massachusetts DTE for the Pilgrim transaction. Tr. 193:7-13 (Reed), 557:14-24, 535:16-22 (Lubbock). In the context of these approval processes, the federal and state regulatory bodies found that the decommissioning fund amount was premised upon site-specific studies of the Pilgrim plant, rather than on a calculation using the NRC’s general formula, and, so tailored, included the costs of SNF storage and returning the site to a green-field condition, items not embraced by NRC regulations governing decommissioning funds. See BX 155 (Reed Report) at 3989; 10 C.F.R. § 50.75.

To acquire the necessary approval from the NRC for the transfer of Pilgrim’s operating license, Tr. 194:9-14 (Reed), 808:19 to 809:6 (Wood), Boston Edison and Entergy jointly submitted a License Transfer Application in December 1998, in which the two parties certified that the total amount of the decommissioning fund to be transferred was a “calculated” amount that was “higher than the NRC minimum due to the inclusion of [SNF] storage costs and costs to remove non-radioactive structures” and was based upon “independent decommissioning cost studies.” Tr. 809:10 to 810:23 (Wood); BX 192 (License Transfer Application) at 3505-06, 3517-18. The NRC sent Boston Edison a Request for Additional Information on January 22, 1999, regarding the potential effect on the decommissioning trust fund of Revision 8 of NUREG 1307, which had reduced the NRC’s minimum decommissioning-cost formula. Tr. 816:4 to 819:3 (Wood); BX 181 (Request for Additional Information (Jan. 22, 1999)). A response drafted by Entergy and approved by Boston Edison, Tr. 207:11-16, 210:20 to 211:3 (Reed), confirmed that the transfer-fund amount was independent of the formula-based NRC minimum because it included the cost of removal and disposal of SNF and non-radioactive structures, such that Revision 8 of NUREG 1307 had no effect on that amount. BX 1 (Response to Request for Additional Information) at email-7.

In due course, the NRC developed a Safety Evaluation Report approving the license transfer and finding that the decommissioning amount “[wa]s based on a site-specific cost estimate performed for Pilgrim in 1998” that exceeded the NRC minimum amount “due to the inclusion of spent fuel storage costs.” BX 184 (Safety Evaluation) at 9056; see also Tr. 825:9-17, 826:12 to 828:20 (Wood). The NRC issued a concurrent order approving the license transfer on April 29, 1999. Tr. 214:19-24 (Reed); BX 215 (NRC’s Order Approving License Transfer).

Upon Boston Edison’s filing of an application for approval by the Massachusetts DTE, hearings before that body took place in January 1999. Tr. 14:6-18 (Reed), 546:2-20 (Lubbock). Both Boston Edison and Entergy participated in the hearings, at which Messrs. Reed and Lubbock were asked about the relationship between the amount of decommissioning funding being transferred to Entergy and the NRC minimum decommissioning cost estimate. Tr. 230:2-11 (Reed), 692:15 to 696:23 (Lubbock). Mr. Reed testified that there was no relationship but rather that the amount being transferred exceeded the NRC minimum because Enter-gy’s decommissioning bid included costs associated with long-term on-site spent fuel storage. Tr. 106:13 to 109:18, 257:2-15 (Reed). Lubbock likewise testified that there was no relationship between the amount transferred and the NRC minimum. Tr. 673:1-7 (Lubbock). The Massachusetts DTE approved the sale on March 22, 1999, after determining that the sale process was competitive and had produced a value for Pilgrim consistent with the intent of the Massachusetts restructuring act. Tr. 551:15-24 (Lubbock); BX 101 (Mass. DTE Opinion). The Massachusetts DTE opinion stated that “[u]nder the terms of the divestiture transaction, Boston Edison retains its claim against US-DOE and amounts recovered from US-DOE would be credited to Boston Edison’s customers to lower the effective net amount paid for decommissioning.” BX 101 (Mass. DTE Opinion) at 5410-11. It also noted that while Revision 8 to NUREG 1307 would decrease the NRC minimum decommissioning cost estimate, the funds being transferred to Entergy exceeded the NRC minimum, largely due to the provision of funds for long-term SNF storage. Id. at 5413-14.

F. Transfer of Ownership and Subsequent Decommissioning Fund Reports by Entergy

Following regulatory approval, the Pilgrim sale closed on July 13, 1999, with Entergy paying Boston Edison $80,964,410 million for the plant and its associated land, fuel inventory, and non-fuel inventory. Tr. 571:10 to 572:8 (Lubbock); BDX 1 (Pilgrim Sale Price); BX 86, BX 87, BX 88 (Closing Binders). Pursuant to the Purchase and Sale Agreement, Boston Edison transferred decommissioning trust funds to Entergy totaling $401,218,181.82, plus an additional $70 million in a provisional trust, in return for Entergy’s acceptance of full responsibility for decommissioning the plant and earing for the SNF that had been generated. BDX 2 (Summary of Decommissioning Fund Transferred); Tr. 574:7-16 (Lubbock). Boston Edison notified DOE of the transfer of the Standard Contract to Entergy, pursuant to Article XIV of the Contract, noting that the “sale include[d] the transfer and assignment of Boston Edison’s rights and obligations ... with the exception of any claims against [DOE] accrued prior to the date of transfer.” BX 97 (Letter to DOE (July 13, 1999)); Tr. 557:14 to 562:12 (Lubbock).

Following the closing, Entergy was required to provide annual reports to the NRC regarding the status of the decommissioning trust fund. Initially, Entergy reported only a portion of the total fund available to it, explaining by a footnote that “[t]he NRC formulas and the calculated fund amounts herein exclude the cost of dismantling or demolishing non-radiological systems and structures as well as costs to manage and store spent fuel until transfer to DOE.” BX 367 (1999 Decommissioning Funding Assurance Report (March 20, 2000)) at email-45; Tr. 832:13 to 848:5 (Wood), 2569:8 to 2574:11 (Test, of Donald R. Denton, a former Enter-gy employee), 3358:16 to 3362:14 (Test, of Charles Minott, Senior Project Manager, En-tergy); see also BX 359 (2000 Decommissioning Funding Assurance Report (March 20, 2001)) at RFP-3-755 (same). Shortly after the decommissioning fund report for 2000 was submitted, however, Entergy officials suggested that the fund report for Pilgrim be revised to “look like [those for] the N.Y. plants.” BX 219 (E-mail from Minott (March 30, 2002)). The requesting officials’ “logic [wa]s the 466M initial was to grow to meet the NRC minimum.” Id. Mr. Minott noted that “no one from Entergy ... knew what the split between fuel and decom $ was in the trust or the sale amount.” Id. After consideration of the suggestion, Entergy decided at that time not to redo the decommissioning fund report because “we want to keep $ to the extent we can in the fuel side so we could fund this if necessary. If in the decom, it cannot be used for its intended purpose.” Id. Nonetheless, beginning in 2003 Entergy began reporting the entirety of its decommissioning trust fund as being designated solely for NRC minimum purposes. Tr. 2562:11 to 2566:3 (D.Denton); Tr. 3365:10 to 3366:13 (Minott); BX 354 (2002 Decommissioning Funding Assurance Report (March 31, 2003)) at email-8. Entergy’s funding reports for 2002 indicate that Pilgrim’s decommissioning trust fund when escalated both for costs and growth to December 2015 would exceed the NRC minimum funding requirement by more than a quarter of a billion dollars. BX 354 (2002 Decommissioning Funding Assurance Report) at email-8; Tr. 3366:14-22 (Minott).

Entergy argues that subsequent to its decommissioning fund submissions to the NRC in March 2001, a teleconference among employees including Ms. Connie Wells, who had been involved Entergy’s bid preparation for Pilgrim, caused it to adopt her view that the entire $466 million in the decommissioning trust fund was intended to meet the NRC minimum funding requirements set forth in 10 C.F.R. § 50.75. See Entergy’s Posh-Trial Br. at 17-18. The implicit factual assertion is that none of the Pilgrim decommissioning trust fund was intended for spent fuel storage costs. The court does not so find. Rather, SNF storage costs and greenfielding costs were included in the decommissioning fund transferred to Entergy by Boston Edison. The pertinent question is how much money was transferred by Boston Edison to Entergy to cover future SNF storage costs.

STANDARDS FOR DECISION

The remedy for a partial breach of an express 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 Dish v. United States, 111 F.3d 1557, 1562 (Fed.Cir.1997)); see also System Fuels, 79 Fed.Cl. at 51; Tennessee Valley Auth. v. United States, 69 Fed.Cl. 515, 522 (2006), appeal dismissed, 188 Fed.Appx. 1004 (Fed.Cir.2006). “[T]he general principle is that all losses, however described, are recoverable.” Indiana Michigan, 422 F.3d at 1373 (quoting Restatement (Second) of Contracts § 347 cmt. c (1981)).

To recover damages, Boston Edison must show that “(1) the damages were reasonably foreseeable by the breaching party at the time of contracting; (2) the breach is a substantial causal factor in the damages; and (3) the damages are shown with reasonable certainty.” Indiana Michigan, 422 F.3d at 1373 (citing Energy Capital Corp. v. United States, 302 F.3d 1314, 1320 (Fed.Cir.2002)). Damages must also be directly caused by defendant’s breach and not be too remote. See Wells Fargo Bank, N.A. v. United States, 88 F.3d 1012, 1021 (Fed.Cir.1996) (“‘[Rjemote and consequential damages are not recoverable in a common-law suit for breach of contract ... especially ... in suits against the United States for the recovery of common-law damages.’ ”) (quoting Northern Helex Co. v. United States, 207 Ct.Cl. 862, 524 F.2d 707, 720 (1975)). Causation must be directly established, but the breach need not be the sole cause of the damages. California Fed. Bank v. United States, 395 F.3d 1263, 1267-68 (Fed.Cir.2005).

This court has previously noted that damages awarded in home- and facility-construction cases may provide an instructive analogy in this suit where Boston Edison seeks recovery of the diminution in the value of Pilgrim at the time of its sale to Entergy. See Boston Edison I, 64 Fed.Cl. at 182. The Restatement (Second) of Contracts provides an alternative to damages based on the cost of remediating defective or failed performance in a construction situation: “[i]f a breach results in defective or unfinished construction and the loss in value [of performance] to the injured party is not proved with sufficient certainty, he may recover damages based on (a) the diminution in the market price of the property caused by the breach.” Restatement (Second) of Contracts § 348(2).

The Restatement’s comments provide that diminution in market value is assessed in the construction context when the cost of repairing defective construction far exceeds the actual loss in value of performance to the injured party, such that of the two alternatives—cost of repair or diminution in market price—the more reasonable damage assessment is the diminution in market price. Restatement (Second) of Contracts § 348 cmt. c. Diminution in market price is measured as “the difference between the market price that the property would have had without the defects and the market price of the property with the defects.” Id.

An analogue is found in tort law, where diminution in market value is the basic rule for the measure of damages for injury to a chattel. See American Serv. Center Assoc. v. Helton, 867 A.2d 235, 241 (D.C.2005) (“We begin with the proposition ... that diminution in value is the ‘basic’ rule for the measure of damages for injury to a chattel, thus suggesting that other relief may sometimes be appropriate.”). In Helton, an automobile repair case, the District of Columbia Court of Appeals held that “when a plaintiff can prove that the value of an injured chattel after repair is less than the chattel’s worth before the injury, recovery may be had for both the reasonable cost of repair and the residual diminution in value after repair, provided that the award does not exceed the gross diminution in value.” Id. at 243. The court provided the example of a car worth $40,000 originally but only $25,000 after being damaged, thereby suffering a $15,000 gross diminution in value. Id. at n. 10. “If after repairs of $10,000, the car is worth $30,000, the residual diminution in value is $10,000. Although the cost of repairs and residual diminution in value total $20,000, the award is capped at $15,000, the gross diminution in value.” Id. In short, the remedy may include the cost of repair and the diminution in market price, provided the total award does not exceed the gross diminution in value. See also Rakich v. Anthem Blue Cross and Blue Shield, 172 Ohio App.3d 523, 531-32, 875 N.E.2d 993, 998-1000 (2007) (applying the rationale of Helton, quoting Restatement

(Second) of Torts § 928 (1979), and collecting precedents from other jurisdictions).

In the case at hand, the value of Boston Edison’s property allegedly declined because the government failed in its duty to dispose of SNF. Boston Edison I, 64 Fed.Cl. at 183. Moreover, Boston Edison had no mitigating “repair” alternative to DOE’s failure to collect Pilgrim’s SNF; instead, it had to address DOE’s failure through self-help by means of re-racking and on-site dry storage. Id. (“The option of getting another contractor to repair the damage is unavailable to Boston Edison because there is no other approved provider of disposal services in this highly regulated industry.”) Diminution in value is left as the appropriate damage assessment. Id.

In the circumstances, this case involves mitigation, but at a level one step removed from the actual measure of damages. Because of the terms of the competitive auction involved in this case, the bidders for Pilgrim took future self-help SNF storage costs into account in formulating their bids, particularly respecting the decommissioning cost element. The principles applied in a contract-mitigation case thus have a secondary role in the analysis.

ANALYSIS

Boston Edison seeks damages measured by diminution in value reflected in three specific aspects of its sale of Pilgrim Entergy: (1) the additional amount required for the decommissioning fund to cover on-site storage of SNF that was not being picked up by DOE as required under the Standard Contract, (2) a reduction in Pilgrim’s purchase price due to the projected capital cost of installing additional storage racks in the spent fuel pool at Pilgrim, and (3) a reduction in price made by Entergy due to the added risk of operating Pilgrim in the absence of DOE’s performance.

A. Forseeability

For Boston Edison to recover, its losses must have been “reasonably foreseeable by the breaching party at the time of contracting.” Indiana Michigan, 422 F.3d at 1373. “The mere circumstance that some loss was foreseeable, or even that some loss of the same general kind was foreseeable, will not suffice if the loss that actually occurred was not foreseeable.” Restatement (Second) of Contracts § 351 cmt. a; see also Old Stone Corp. v. United States, 450 F.3d 1360, 1376 (Fed.Cir.2006) (citing Restatement (Second) of Contracts § 351 cmt. a); Landmark Land Co. v. United States, 256 F.3d 1365, 1378 (Fed.Cir.2001) (same). “It is enough, however, that the loss was foreseeable as a probable, as distinguished from a necessary, result of his breach.” Restatement (Second) of Contracts, § 351 cmt. a. Loss is “foreseeable as a probable result of a breach” if it follows from the breach in the ordinary course of events, or results from special circumstances that are beyond the ordinary course of events that the breaching party had reason to know. Id. at § 351(2); see also Landmark Land, 256 F.3d at 1378. A plaintiff must prove that both the magnitude and type of damages were foreseeable. See Landmark Land, 256 F.3d at 1378 (citing 5 Arthur Corbin, Corbin on Contracts, § 1012 at 88 (1964)).

This court previously determined that DOE could have readily foreseen that a diminution in Pilgrim’s market value would result from DOE’s non-performance:

That damages might arise from diminution in value was foreseeable. That sale of nuclear facilities was contemplated by Congress and by DOE is shown by the existence of the assignment provision of the NWPA, 42 U.S.C. § 10222(b)(3), and by Article XIV of the Standard Contract which provides that “[t]he rights and duties of the Purchaser may be assignable •with transfer of title to the SNF and/or HLW involved; provided, however, that notice of any such transfer shall be made to DOE within ninety (90) days of transfer.” Boston Edison complied with the notice requirements and received no objection from DOE.... It is a fair inference that failure to implement the Standard Contract might engender a diminution in the value obtained from a sale. Such a diminution resulting from DOE’s breach of its obligations under the Standard Contract was thus a foreseeable damage.

Boston Edison I, 64 Fed.Cl. at 183-84. The proofs at trial confirm that at the time of contract execution, both Boston Edison and DOE were well aware that Boston Edison could assign its contractual rights and responsibilities in the event that Boston Edison sold Pilgrim. Robert Morgan, who was the first director of the DOE’s Office of Civilian Radioactive Waste Management and was responsible both for the implementation of the NWPA and for the drafting of the Standard Contract on behalf of the DOE, was aware of the NRC’s regulations that addressed license transfer upon sale of a nuclear plant before he executed Boston Edison’s Standard Contract on behalf of DOE. Tr. 3645:18 to 3646:4; 3660:17 to 3661:13 (Morgan). The NRC first promulgated those regulations in the 1960s, more than two decades prior to the execution of DOE’s Standard Contract with Boston Edison. See 10 C.F.R. § 50.80; Tr. 806:7-15 (Wood). By the time of contract execution, numerous sales of nuclear plants had taken place. Tr. 806:16-20 (Wood), 2906:22 to 2907:9 (Reed). Mr. Morgan explicitly testified that at the time he was drafting the Standard Contract, he was aware of the possibility that nuclear power plants could be sold subject to approval by the NRC. Tr. 3656:12 to 3658:11, 3661:24 to 3662:9 (Morgan).

The government nonetheless contends that Boston Edison failed to show that at the time of contract formation in 1983, the DOE foresaw or should have foreseen that a breach by DOE of the Standard Contract would produce a diminution in value of Pilgrim in the following specific respects: (1) a future purchaser of Pilgrim would require a decommissioning trust fund from Boston Edison to cover increased SNF-storage costs associated with DOE’s delay in SNF acceptance; (2) a purchaser would be unable to obtain debt financing for Pilgrim’s purchase, as a result of DOE’s non-performance; or (3) a purchaser would employ a higher internal rate of return or discount rate in formulating its bid for Pilgrim due to DOE’s non-performance. Def.’s Post-Trial Br. at 7. Despite Mr. Morgan’s awareness of the NRC regulations concerning the sales of nuclear power plants, and of the assignment provisions in the NWPA and his drafting of the assignment provisions in the Standard Contract, the government points to Mr. Morgan’s testimony that he had no recollection that DOE ever considered the impact of nuclear power plant sales upon the government’s obligations. Def.’s Post-Trial Br. at 7-8 (citing Tr. 3653:2 to 3655:19, 3661:24 to 3662:9 (Morgan)). This lack of recollection on Mr. Morgan’s part does not, however, show that Boston Edison’s claimed losses on sale were not foreseeable. It was objectively foreseeable at the time of contract formation that Pilgrim could be sold and that its rights and responsibilities under the Standard Contract could and would at that time be transferred to the subsequent owner. It was also objectively foreseeable that if DOE did not perform, nuclear plants would have to provide for SNF storage, resulting in added costs and a detrimental impact on the plant site and operations, all of which could or would engender diminished value. This court has repeatedly held that DOE should have foreseen that its nonperformance under the Standard Contract would cause nuclear power plants to incur significant storage expenses, given that the “avoidance of these costs was an impetus for, and objective of, the NWPA” and the Standard Contract. Southern Nuclear, 77 Fed.Cl. at 404; see also System Fuels, 79 Fed.Cl. at 59 (“DOE’s planning documents cited avoidance of storage costs as a goal for the SNF program from its inception, showing that System Fuels’ damages resulting from the DOE’s non-performance were readily foreseeable.”); Tennessee Valley Auth., 60 Fed.Cl. at 674 n. 10. (“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, i.e., the construction of dry storage facilities for spent nuclear fuel at nuclear power electricity generating plants throughout the United States.”).

The court concludes that Boston Edison’s damages were foreseeable by the DOE both in magnitude and kind.

B. Causation

Boston Edison must also prove that DOE’s breach was a “substantial causal factor” of its claimed losses. Indiana Michigan, 422 F.3d at 1373 (citing Energy Capital Corp., 302 F.3d at 1320). Damages can be recovered provided that a causal connection can be “definitely established” between the breach of contract and the harm to the plaintiffs. See American Fed. Bank, FSB v. United States, 72 Fed.Cl. 586, 598 (2006) (citing California Fed. Bank, 395 F.3d at 1268 (“[T]he causal connection between the breach and the [claimed damages] must be ‘definitely established.’... That is not to say that the breach must be the sole factor or sole cause in the [claimed damages].”)).

When it became apparent that DOE would not meet its obligations under the Standard Contract, Boston Edison took steps to mitigate the anticipated breach. In 1994, DOE announced that it would be unable to begin accepting SNF from Standard Contract holders by January 31, 1998, having secured neither a permanent SNF repository nor an interim SNF storage facility. See DOE, Waste Acceptance Issues, 59 Fed.Reg. 27,-007-08 (May 25, 1994) (announcing that “the Department currently projects that the earliest possible date for acceptance of waste for disposal at a repository is 2010”). And, in a November 1998 letter, DOE informed Boston Edison that it would not be able to act on Delivery Commitment Schedules submitted by Boston Edison. Tr. 434:20 to 437:9 (Oheim); DX 267 (Letter from Beth Tomasoni, Contracting Officer, DOE, to Oheim (Nov. 24, 1998)). Boston Edison was left with the prospect of storing SNF on-site on a long-term basis. Tr. 436:16-23 (Oheim); see Maine Yankee Atomic Power Co. v. United States, 225 F.3d 1336, 1338, 1342 (Fed.Cir.2000).

After considering both dry and wet storage options, Boston Edison chose to increase its fuel storage capacity by installing high-density racks in Pilgrim’s spent fuel pool, Tr. 438:5 to 439:12 (Oheim), obtaining an NRC license in 1994 to install six high density racks. Tr. 444:8 to 445:3 (Oheim); BX 276 (Issuance of Amend. No. 155 to NRC License). Boston Edison installed two racks prior to the sale of Pilgrim and planned to install three additional racks in phases over the course of several years. Tr. 446:19 to 448:6 (Oheim). Dry storage could be added later when necessary either to allow Pilgrim to be shut down or to provide storage after the reracking became insufficient for Pilgrim’s needs. See, e.g., BX 305 (NES Study) at RFP-21-14065-66.

However, as to Boston Edison’s claim for diminution in value, the government argues that remote events bar causation. The government contends that these intervening or remote events include: (1) FERC Order 888, issued in 1996, calling for the restructuring of electric utility markets; (2) the 1997 Massachusetts legislation establishing a deregulation framework for the electric industry at the state level; (3) the Settlement Agreement between Boston Edison and the Office of the Massachusetts Attorney General; (4) Boston Edison’s decision to sell Pilgrim via a competitive auction, rather than using a valuation proceeding to determine its stranded costs; (5) Boston Edison’s decision to transfer a fully-funded decommissioning trust fund as part of the Pilgrim sale, rather than retain the fund after the sale; and (6) the reduction in the NRC minimum following the execution of the Purchase and Sale Agreement by Boston Edison and Entergy. Def.’s Post-Trial Br. at 3-6. The government maintains that “these intervening events have nothing to do with DOE’s partial breach of the Standard Contract, and break the chain of causation between the breach and [Boston Edison’s] claimed damages.” Id. at 6.

The government’s remoteness contention is unavailing. None of the pre-sale events change the effect of DOE’s breach on Pilgrim. Had none of those events occurred, DOE’s breach would still have diminished Pilgrim’s value. Nor do Boston Edison’s decision to transfer a fully-funded decommissioning trust fund and the reduction of the NRC minimum break the chain of causation. Boston Edison transferred a decommissioning fund that encompassed monies projected to be sufficient both for decommissioning the plant and providing for storage of SNF, and with it, all liability for decommissioning and future SNF storage, because Boston Edison’s stranded-cost recovery was based on a need to account fully for all aspects of Boston Edison’s assets and liabilities associated with Pilgrim. See supra, at 475 n. 10; see also Tr. 50:8 to 52:5, 116:1 to 118:2, 148:14-25 (Reed), 554:13 to 555:10 (Lubbock). Finally, the reduction of the NRC minimum was irrelevant to the amount transferred, because Entergy did not base the decommissioning-fund portion of its bid on the NRC minimum. See supra, at 478-81 & n. 14.

The court concludes that DOE’s breach is a direct cause of Boston Edison’s diminished value. The breach would have resulted in a lesser value for Pilgrim whether or not a sale occurred. The events cited by the government only affected the timing of the realization of that diminished value; they did not break the causal chain directly linking DOE’s breach to Pilgrim’s diminished value. The impact of DOE’s breach of the Standard Contract was reflected in the purchase price of Pilgrim and the increased amount of funding transferred to compensate for storage-related expanses.

C. Reasonable Certainty

To establish the quantum of its damages with reasonable certainty, Boston Edison need not make a showing of “ ‘absolute exactness or mathematical precision[,]’ [but] recovery for speculative damages is precluded.” Indiana Michigan, 422 F.3d at 1373 (first alteration in original) (quoting San Carlos Irrigation & Drainage Dist., 111 F.3d at 1563); see also Southern Cal. Fed. Sav. & Loan Ass’n v. United States, 422 F.3d 1319, 1336 (Fed.Cir.2005) (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’” (quoting Bluebonnet Sav. Bank v. United States, 266 F.3d 1348, 1357 (Fed.Cir.2001))).

In this vein, the Federal Circuit determined in Indiana Michigan that prospective damages for anticipated future DOE nonperformance could not be recovered: “Because of its highly speculative nature, a claimant may not recover, at the time of the first suit for partial breach, prospective damages for anticipated future nonperformance resulting from the same partial breach.” 422 F.2d at 1376. In this instance, Entergy contests whether any award of damages is permissible because such an award would necessarily reflect a transactional assessment of the future costs of storing SNF because of DOE’s breach. Additionally, both the government and Entergy dispute the amount of any diminution in value realized on the sale.

1. Present realization of diminished value attributable to future costs of storing SNF.

Entergy advances the argument that Boston Edison’s claims are barred by Indiana Michigan’s proscription of prospective damages. See Indiana Michigan, 422 F.3d at 1376. The plaintiffs in Indiana Michigan, however, sought future damages for forecast-ed investment in the construction of a private SNF storage facility. Id. at 1372. Boston Edison’s claims, on the other hand, are for “actual damages it has already suffered as a result of the diminished value that Entergy paid to Boston Edison due to DOE’s breach.” Boston Edison’s Posh-Trial Reply Br. at 7. They do not represent speculative or prospective damages but rather losses that were realized at the time of closing. Because Boston Edison’s claimed damages are for actual rather than prospective loss, they are recoverable if quantum is proven to a reasonable certainty.

2. Amount of diminished value.

a. Added “decommissioning’’ amounts for storage of SNF.

As a factual matter, the court has found that the decommissioning fund transferred by Boston Edison to Entergy was premised upon site-specific studies of the Pilgrim plant, rather than a calculation using the NRC’s general formula, and, so tailored, included the costs of SNF storage and returning the site to a green-field condition. See supra, at 478-81. The final amount transferred in the fund—$396 million plus $70 million deposited in the provisional trust—totaled $466 million, later reduced as a result of the private letter ruling by the IRS. Id. The pertinent question for damages is how much money was transferred by Boston Edison to Entergy to cover future SNF storage costs.

Boston Edison claims that $86.2 million of the decommissioning fund was “solely related to SNF storage costs that would not have been incurred if DOE had performed.” Boston Edison’s Post-Trial Br. at 54 (citing Tr. 2977:25 to 2980:5 (Reed); BX 155 (Reed Report) at 8998-99). Boston Edison asserts that its expert calculation is supported by the fact that Entergy’s decommissioning team from Maine Yankee noted that costs for providing dry storage and ultimately for removing dry storage would exceed $53 million, before the inclusion of annual operating and maintenance costs and property taxes, which Entergy noted could total more than $2 million per year. Id. (citing BX 155 (Reed Report) at 3997; BX 29 (Entergy’s Pilgrim Acquisition Analysis) at 13030). To support the reasonableness of its $86.2 million estimate, Boston Edison cites the testimony of Thomas LaGuardia, who performed the TLG analysis for Entergy and later estimated that his decommissioning cost estimate performed at the time of sale included between $80 to $85 million for SNF storage costs. Boston Edison’s Post-Trial Br. at 54; Tr. 1161:12 to 1162:4 (LaGuardia). The TLG estimate for the decommissioning cost was used by Enter-gy in formulating its winning bid. Tr. 1963:2-19 (Keuter).

Mr. LaGuardia’s amount for SNF storage costs was computed in 1997, not 1999, dollars, and was provided in relation to the TLG cost estimate of $578.1 million for the decommissioning fund. Tr. 1154:1 to 1156:25,1160:9 to 1162:4 (LaGuardia). However, in developing its bid, Entergy removed from that $578.1 million, $6.1 million of pre-planning decommissioning costs and then applied a cost-escalation factor and discount rate for growth of the fund to determine that it would require $466 million in 1999 dollars at closing to yield the $782 million necessary to deeom-mission Pilgrim in 2012. See swpra, at 478-79. At trial, an economic expert witness testifying on behalf of the government, Dr. Jonathan Neuberger, testified that the $80-85 million dollars in Mr. LaGuardia’s calculation must be escalated into the future years in which those dollars would be spent at Entergy’s assumed cost-escalation rate and then discounted back to 1999 at the growth rate used by Entergy. Tr. 3890:9-21 (Test, of Dr. Jonathan Neuberger). Using that present-valuation methodology, Dr. Neuber-ger calculated that $80-85 million in 1997 dollars as developed by Mr. LaGuardia yields a figure of approximately $60 million in 1999 dollars. Tr. 3890:22 to 3891:6 (Neuberger).

However, Dr. Neuberger’s calculated present-value figure of $60 million based upon Mr. LaGuardia’s projection should not be accepted as the appropriate measure of Boston Edison’s damages without a cross-check to other indicia of what Entergy was considering at the time it negotiated the Purchase and Sale Agreement. In particular, in its first “final” bid, Entergy proposed that Boston Edison transfer a decommissioning fund of $535 million to Entergy. DX 241 (Enter-gy’s Final Bid) at RFP-21-2913. In Enter-gy’s winning final-final bid, the decommissioning fund amount was reduced to $466 million. See supra, at 478-80. In addition, the court should ensure that diminished-value damages are limited to an amount that reflects only spent-fuel storage costs, not also greenfielding costs. Entergy’s reliance on TLG’s estimates for both spent-fuel storage costs and greenfielding costs provides a basis for confirming the separation of the two elements. At the bidding stage, Entergy’s formal assessment had not separated those components:

Due to the proximity of the total TLG and EN-MY [Entergy Maine Yankee] cost estimates, EN believes the best estimate for decommissioning Pilgrim (in 1997 dollars) is approximately $578 million. NUREG-1307 outlines the calculation of the NRC required minimum funding amount, which is $514 million for Pilgrim (in 1997 dollars). The NRC required minimum amount does not include the cost of removal and disposal of spent fuel or nonradioactive structures and materials beyond that necessary to terminate the license. These components would add approximately $70 million to the $514 million, bringing the NRC calculated amount in the range of the TLG and EN-MY cost estimates.

BX 29 (Entergy's Pilgrim Acquisition Analysis) at RFP-21-13053. Entergy had separated the decommissioning, spent-fuel storage, and greenfielding costs on a judgmental basis, however, relying on Mr. LaGuardia’s estimates. As Mr. Keuter testified,

Q.... [T]he components referenced [in] the last sentence [of Entergy’s Pilgrim Acquisition Document quoted above] are both spent nuclear fuel and nonradioactive structures and materials, correct?
A. Correct.
Q. And that $70 million you are talking about there, it is your view, is it not, sir, it is about $50 million for spent nuclear fuel and $20 million for greenfield, correct?
A. Yes.

Tr. 1972:15-24 (Keuter).

Taking Entergy’s value of $50 million for SNF storage costs, and then applying the cost-escalation and growth-discounting factors Entergy used, results in a present value in 1999 of $40.03 million for SNF storage costs actually included in the decommissioning fund Entergy received from Boston Edison on closing.

In summation, Boston Edison claims that it “transferred $86.2 million more in decommissioning funding that it would have had DOE performed.” Boston Edison’s Post-Trial Br. at 51 (capitals omitted). The claim has a valid premise because it reflects Mr. LaGuardia’s projection of SNF-storage costs prepared for Entergy, which estimate was used by Entergy in putting forward its winning bid as Mr. Keuter testified. However, the government’s objections to the particular quantum are also well taken insofar as Mr. LaGuardia’s amount did not take present valuation into account. Dr. Neuberger’s present-value calculation using Mr. LaGuar-dia’s projection yielded a present value of $60 million for the amount transferred in the decommissioning fund for SNF storage costs. This present-value amount, however, suffers to some extent from the fact that it represents a reconstruction of information Enter-gy used in deriving its final prevailing bid. More direct evidence of what Entergy contemporaneously used is found in Entergy’s Pilgrim Acquisition Analysis, BX 29, prepared in September 1998, which assigned $70 million to SNF-storage and greenfielding costs, based upon Mr. LaGuardia’s projection and on the comparative evaluation of those who were undertaking the decommissioning of the Marine Yankee facility. Mr. LaGuar-dia had provided details that allowed Enter-gy to make a separation between SNF-decommissioning costs and greenfielding costs, and Mr. Keuter’s testimony that $50 million was assigned to SNF storage and $20 million to greenfielding has credibility. Taking a present value of the $50 million amount assigned by Entergy to SNF storage produces $40.03 million, and this amount represents the best evidence of what Entergy bargained for in the decommissioning fund to account for SNF storage costs stemming from DOE’s breach of the Standard Contract. That this amount corresponds to values obtained by later calculations performed by Mr. Manion provides confirmation that this amount of damages is appropriate.

The government and Entergy raise several other objections to Mr. LaGuardia’s projection and Mr. Manion’s calculations, but these criticisms and dissertations have no merit. Among other things, the government argues that Mr. LaGuardia’s estimate reflected total SNF storage costs, not the incremental SNF storage costs attributable to DOE’s delay. Def.’s Post-Trial Br. at 31. Presumably, what the government means is that Pilgrim would have incurred some costs in delivering SNF to DOE containers when and if DOE were to perform. However, Entergy itself had eliminated $6.1 million of preparatory and planning costs from its projections, and those costs respecting dry storage (which would not have been needed had DOE performed) would be recoverable. In addition, the court has opted to apply a further reduction in effect, by taking the lower $50 million value Entergy actually used, reduced to present-value, in compiling its winning bid.

The government also contends that Mr. Manion’s analysis was flawed because he used different assumptions in “but for” and “actual world” calculations. Def.’s Br. 27-29. The assumptions to which the government points bear on the rate at which DOE would accept SNF from Pilgrim. Id. at 27. This criticism is unavailing for two salient reasons. First, whatever DOE’s rate would have been, Pilgrim could have operated through 2012 by using its spent-fuel pool for storage and would not have needed any dry storage. Dry storage comes into play only upon decommissioning, because the SNF had to be removed from the pool and stored to allow such decommissioning. The length of the time the SNF would have had to remain in dry storage would have been affected by the ultimate rate of DOE’s acceptance, but the effect is limited to somewhat different cumulative operating and maintenance costs for the dry storage units during their later years of use, which would have only a modest effect on a present-value calculation as of 1999. Moreover, Mr. Manion’s rebuttal report provided a detailed sensitivity analysis of the contested rate assumptions, and the court has used the results of that analysis as a confirmation of the actual amounts Entergy used. See supra, at 490 n. 22. Moreover, even Mr. Manion’s rebuttal, revised to counter the government’s critique, was used only for confirmation.

Finally, the parties debated at trial the effect of the somewhat favorable IRS private letter ruling on a diminished-value damage determination. The court principally raised this issue during the trial, although it also was addressed briefly by Dr. Neuberger in his testimony. See Tr. 3884:5-12 (Neuber-ger). In rebuttal testimony, Mr. Reed explained that the tax effects would have a negligible impact on the diminished-value damages due Boston Edison, and, if anything, would result in a slight increase in the amount of damages that would be due. For purposes of calculating the decommissioning funding requirement, Entergy had assumed a particular growth rate assuming that the decommissioning fund was not qualified for the lower tax rate on income provided by I.R.C. § 468A. After the IRS private letter ruling had been issued, 37 percent of the fund was deemed qualified and 63 percent non-qualified. Tr. 4019:3 to 4023:14 (Reed). As a result, a higher after-tax growth rate could be achieved and the initial funding requirements would be slightly smaller to achieve the same end result. Tr. 4022:3 to 4023:2 (Reed). The tax effect of the IRS private letter ruling thus does not provide a basis for reducing the diminished-value damages.

Accordingly, diminished-value damages of $40.03 million are due to Boston Edison for SNF storage costs included in the decommissioning fund Entergy received from Boston Edison upon the sale of Pilgrim.

b. Cost of additional racks.

Boston Edison seeks damages for the alleged reduction in Pilgrim’s purchase price due to the projected capital cost of installing additional storage racks in the spent fuel pool at Pilgrim. See Boston Edison’s Post-Trial Br. at 57. The Entergy due-diligence team identified a need for installation of additional racks in Pilgrim’s spent fuel pool to provide interim storage of SNF before longer-term dry storage would become necessary. Tr. 1027:22 to 1028:18, 1036:2-19 (Harrington); BX 47 (Entergy’s due-diligence field notes) at RFP-21-787; cf. Tr. 446:19 to 448:6 (Oheim). AmerGen likewise determined that Pilgrim would need additional storage racks for its spent fuel pool to provide interim storage of SNF. Tr. 1752:3 to 1755:9, 1809:23 to 1810:8 (Fetters); BX 76 (AmerGen Due-Diligence Report) at 818; see also BX 78 (BFNL Study) at 1264. Boston Edison installed two high-density racks in Pilgrim’s spent fuel pool prior to the sale of Pilgrim and planned to install three additional racks in phases as needed over the course of several years. Tr. 446:19 to 448:6 (Oheim); see supra, at 474 n. 7 & 474-75 n. 9.

Boston Edison avers that Entergy calculated that these racks would cost approximately $600,000 per rack for a total of $2.4 million for four racks and that this cost was incorporated in Entergy’s DCF model that was used to develop the purchase price for Pilgrim. See Boston Edison’s Post-Trial Br. at 57-58. To calculate the economic harm associated with the need for additional spent fuel racks, Boston Edison’s expert, Mr. Reed, re-created Entergy’s DCF valuation model and, keeping all other factors the same, excluded the projected capital expenditures for four spent fuel racks. Tr. 3030:17 to 3032:21 (Reed). Reed determined that the net present value for Pilgrim would have been $947,000 greater in a DCF model that excluded the costs of the additional racks, id., such that DOE’s breach caused Boston Edison to incur an additional $0.947 million of diminished-value damages. See Boston Edison’s Post-Trial Br. at 58.

Entergy’s DCF model for Pilgrim included a general allocation for capital additions of $[* * *] million per year. See BX 29 (Enter-gy’s Pilgrim Acquisition Analysis), at RFP-21-13033; Tr. 1076:1-21 (Harrington). At trial, Entergy’s former president, Donald Hintz stated that “[a]ll costs [were] generally put in the price,” Tr. 3629:1-3 (Hintz) (emphasis added), but Entergy’s model did not include any specific line item associated with the rack additions. Tr. 1073:2-5 (Harrington). The $[* * *] million per-year figure was “static, and ... derived by projecting all the potential costs that would be necessary to operate Pilgrim through the end of its operating life.” Def.’s Post-Trial Br. at 57; Tr. 1076:22 to 1078:10 (Harrington); BX 43 (En-tergy Board Minutes (Oct. 1, 1998), with attached DCF analysis), at RFP-21-3045 (capital expenditures row). Although Enter-gy’s due-diligence field notes indicate specific years in which each rack would be added, the figure allotted in its DCF model for “unknown projects,” Tr. 2198:13-24 (Keuter), holds constant at $[* * *] million annually, rather than spiking or increasing during the years associated with projected rack additions. Tr. 1078:11-22 (Harrington). Consequently, Boston Edison’s proofs at trial do not demonstrate that the cost of additional racks affected the price paid for the plant. Therefore, no diminished-value damages for the projected cost of additional spent pool fuel racks can be recovered.

c. Reduction in price.

Finally, Boston Edison asserts that it received $36.4 million less for Pilgrim due to price reductions made by Entergy to account for risks associated with the prospect of indefinite storage of SNF not otherwise addressed in the decommissioning trust fund transfer. See Boston Edison’s Post-Trial Br. at 58. It contends that the decommissioning fund transfer accounted for the costs associated with SNF storage at Pilgrim until 2043, but not for storage beyond that time or for increases beyond Entergy’s storage cost estimates through 2043. Id. at 58-59. “Consequently, Entergy increased its required rate of return, in part, to account for these SNF-related risks.” Id. at 59.

Entergy’s Board offered a total purchase price for Pilgrim of $80 million, low enough to result in an NPV of tens of millions of dollars and an IRR that exceeded twenty percent. Tr. 1044:23 to 1045:11 (Harrington); BX 43 (Entergy Board Minutes (Oct. 1, 1998)). at RFP-21-3054, 3057. Boston Edison contends that the Entergy Board’s requirement of a substantial NPV in effect decreased the price Entergy was willing to pay for Pilgrim, Tr. 3015:18 to 3016:18 (Reed), and that the price would have been higher absent the significant unmitigated risk associated with DOE’s breach of Pilgrim’s Standard Contract. Tr. 3017:3 to 3021:7 (Reed), 1046:2-14 (Harrington); BX 155 (Reed Report) at 4007. Had Pilgrim been “a non-nuclear generation asset, a valuation based upon a return on equity of [* * *]%, rather than a risk-adjusted discount rate of [* * *], would have been appro-priate____ The risk premium that Entergy utilized in valuing Pilgrim above its [* * *]% cost of equity reflected, in large part, the risks associated with the storage and disposal of SNF.” Boston Edison’s Post-Trial Br. at 32-33 (citing Tr. 1049:2 to 1050:14 (Harrington), 3017:3 to 3021:7 (Reed)).

Boston Edison further asserts that “risk associated with long-term on-site SNF storage created by DOE’s breach was also a substantial factor in Entergy’s need for 100% equity financing to acquire Pilgrim.” Boston Edison’s Post-Trial Br. at 59. Boston Edison argues that a more “conventional” mix of 50% equity and 50% debt financing was unavailable due in part to lenders’ recognition of the extent of SNF-related risks caused by DOE’s delay. Id. at 59, 34. Boston Edison relies upon the expert testimony and report of Mr. Reed, who sought to re-create and recalibrate the DCF model used by Entergy for its Pilgrim bid. BX 155 (Reed Report) at 4005-15; Tr. 3014:12 to 3030:16 (Reed). By Mr. Reed’s calculations, the price Entergy was willing to pay for Pilgrim was $38.7 million less than it otherwise would have been if Entergy had applied a more typical NPV and IRR. Id. Additionally, Mr. Reed calculated that Entergy’s valuation of Pilgrim was $34.1 million less than it otherwise would have been as a result of Entergy’s need to use 100% equity financing instead of 50% debt and 50% equity. Id. Thus, Boston Edison claims that Pilgrim’s value was diminished by a total of $72.8 million due to Enter-gy’s perceived need for a higher rate of return and the lack of debt financing. Id. Mr. Reed also concluded that the magnitude of the risks and costs associated with long-term on-site storage of SNF represented the largest nuclear-related risk to a potential purchaser of Pilgrim, to the point that 50% of the $72.8 million in diminished value should be attributed to DOE’s breach. Tr. 3002:4 to 3030:16, 3097:21-24 (Reed); BX 155 (Reed Report) at 4007-15. This determination was, in Boston Edison’s words “based on Mr. Reed’s extensive knowledge of the nuclear industry and discussions with individuals that participated in nuclear auctions on the buy-side, as well as Mr. Reed’s professional judgment based on his unparalleled experience with nuclear transactions that is unmatched in the United States.” Boston Edison’s Post-Trial Br. at 60. Boston Edison accordingly argues that the purchase price it received for Boston Edison was decreased by $36.4 million due to DOE’s breach. Id.

The evidence at trial showed that Enter-gy’s Board only considered acquisitions that would add to the company’s shareholder value. Tr. 3302:10-25 (Harlan). Entergy sought a significantly positive NPV from all of its lines of business, including nuclear. Tr. 3313:17 to 3314:8 (Harlan). Entergy’s witnesses also testified that spent nuclear fuel was not a factor Entergy considered in the development of the discount rate for its nonregulated nuclear line of business, Tr. 3311:24 to 3312:4 (Harlan), 1258:5-10 (Shanks), such that the Entergy Board’s NPV and IRR requirements for the Pilgrim acquisition were not related to DOE’s delay. Tr. 3331:3-20 (Harlan), 1259:13-18 (Shanks). In this same vein, Jack Harrington, a former vice president retained as a consultant by Entergy for assistance with due diligence, and relied upon by Boston Edison at trial and in its briefs, Def.’s Post-Trial Br. at 37-39, conceded that he could not identify any express connection between the NPV and IRR Entergy sought for the Pilgrim acquisition and the delay in SNF acceptance. Tr. 1083:14 to 1084:15, 1103:1-10, 1088:16-22 (Harrington). Mr. Harrington also testified that he did not know what factors or risks the Entergy Board considered in developing the criteria employed for the Pilgrim purchase. Tr. 1083:14 to 1087:2 (Harrington).

The proofs at trial showed that non-SNF risks were related to industry-wide perceptions common in the late 1990s about the uncertainty of investment returns in nuclear power plants. Entergy’s September 1998 Pilgrim Acquisition Analysis identified the three primary risks as decommissioning risk, market-price risk, and plant-shutdown risk. See BX 29 (Entergy’s Pilgrim Acquisition Analysis) at RFP-21-13020; see also Tr. 2104:6-9 (Keuter). Within the category of decommissioning risks, Entergy viewed the shutdown date of the plant to be a major concern. In the event of a premature shutdown, cash flows expected from the Pilgrim acquisition would not be realized. Tr. 2107:4-22 (Keuter). Carolyn Shanks testified that the risks that Entergy considered to be the most significant in preparing its bid included immediate plant shutdown, unknown environmental issues, and unexpected catastrophic events that could shut down either Pilgrim or another facility that would affect Pilgrim’s operations. Tr. 1249:10 to 1250:1 (Shanks). She stated that Entergy focused on the fact that Pilgrim was Entergy’s first acquisition of a nuclear plant in a newly-deregulated market, and if the plant prematurely shut down, the owner would have no revenue stream for the investment. Tr. 1248:13 to 1249:1 (Shanks).

Similarly, Mr. Lewis, the lead business person for AmerGen’s bid on Pilgrim and the director of nuclear planning and corporate development for PECO Energy in 1998, who was responsible for leading PECO’s merger activity, Tr. 1849:12-19, 1850:22-25, 1852:1-2 (Lewis), testified that “the most significant risk” that nuclear power plants faced at that time was the price of market power, “because the buyer wasn’t going to be selling energy on a regulated basis so they had to predict the price that they would get for the megawatt hours sold,” and “the second most significant risk” was “the capacity factor at which the plant would run.” Tr. 1880:20 to 1881:2-5,1882:3-12 (Lewis).

The evidence at trial also indicates that Entergy chose equity financing because Pilgrim was one of the first sales of a nuclear plant in a deregulated market, and there then was “no history of or really appetite for project-based financing for a nuclear project.” Tr. 3315:17 to 3316:13, 3305:22 to 3306:19 (Harlan). Ms. Shanks confirmed that Entergy elected to rely upon all-equity financing because “it was a totally different first-time venture,” and because Pilgrim was a single-unit facility with no other source of revenue should it unexpectedly shut down. Tr. 1246:6-13,1253:1-10 (Shanks).

Based upon this evidence, the court concludes that Entergy included spent-fuel storage risks only generally in its assessments and that other risks such as premature shutdown or operating risk and the energy-pricing risk associated with a non-regulated power plant were dominant in Entergy’s determination of the price it was willing to pay for Pilgrim. Decommissioning risks, including those associated with long-term storage of SNF caused by DOE’s breach, were largely taken into account by Entergy in connection with the decommissioning fund it wanted to receive from Boston Edison, as previously described. The remaining residual SNF-related risk played a more marginal role in Entergy’s consideration of price. Mr. Reed’s attempt to assign 50 percent of $72.8 million as Pilgrim’s diminution in value due to DOE’s breach of the Standard Contract, reflected in a demand for a higher rate of return and the lack of debt financing, lacks direct evidentiary support. Experience alone cannot substitute for reliable principles, see Zenith Elec. Corp. v. WH-TV Broad. Corp., 395 F.3d 416, 418 (7th Cir.2005), and the court has no basis upon which to verify or evaluate the accuracy or legitimacy of Mr. Reed’s conclusion. Consequently, in contrast to the decommissioning fund that was transferred in the transaction, the court concludes that Boston Edison did not establish that Pilgrim’s purchase price was diminished by any given amount due to DOE’s breach.

D. Offset

The government argues that to the extent that Boston Edison is awarded any damages for diminution in value, the government “is entitled to a corresponding offset against Entergy with respect to the damages that Entergy seeks in its separate claim against the [government for damages arising from the [government's partial breach of the Standard Contract.” Def.’s Post-Trial Br. at 58 (emphasis added). The government contends that diminution-in-value damages awarded to Boston Edison represent a benefit to Entergy—that is, costs it already recovered for the DOE’s breach as a result of paying less for Pilgrim and receiving a larger decommissioning fund. Id. at 58-59.

The offset sought by the government against Entergy is not recoverable in the action brought by Boston Edison because it does not represent a present claim. Offset, or “setoff,” is typically used to reconcile competing claims between the same parties. See Citizens Bank of Md. v. Strumpf 516 U.S. 16, 18, 116 S.Ct. 286, 133 L.Ed.2d 258 (1995) (“The right of setoff (also called ‘offset’) allows entities that owe each other money to apply their mutual debts against each other, thereby avoiding ‘the absurdity of making A pay B when B owes A.’”). Any offset the government might pursue against Entergy should be addressed in an action or actions brought by Entergy to recover amounts expended by Entergy to mitigate DOE’s breach of Pilgrim’s Standard Contract.

Entergy nonetheless seeks to deflect or obviate any future offset claim that the government might make by contending that any benefit in the form of a lower purchase price that it derived from DOE’s breach is a benefit from a source collateral to the defendant. Entergy characterizes as collateral-source benefits any benefits that Entergy “created ... through its own skillful negotiations.” Entergy’s Post-Trial Br. at 5; see also 1 Dan B. Dobbs, Law of Remedies § 3.8(1), at 313 (2d ed.1993) (stating that collateral damages “may not be used to reduce [a] defendant’s liability”); Landmark Land, 256 F.3d at 1374 (proposed offset not proper where the government was “not responsible” for the alleged benefit to the plaintiff).

The collateral-source principle is not applicable, however. “Consequential damages ... are those damages that ‘result as a secondary consequence of the defendant’s nonperformance.’ ” New Valley Corp. v. United States, 72 Fed.Cl. 411, 414 (2006) (quoting 3 Dan B. Dobbs, Law of Remedies § 12.4(1) at 62). The diminution in value to Pilgrim was not a secondary but rather a direct consequence of DOE’s breach. Boston Edison’s damages are not due in main part to tough negotiating by Entergy; rather, Pilgrim’s diminished value, as expressed in the higher decommissioning fund amount to provide for projected SNF-storage costs, is the foreseeable and measurable result of DOE’s breach. That said, the government must present and pursue its offset claim against Entergy in Entergy’s own action for damages for breach of the Standard Contract.

Entergy also contends that an offset should not be allowed on the basis that the Purchase and Sale Agreement did not preserve Boston Edison’s claim, or, alternatively, that if an offset is awarded, that Boston Edison would be obliged by the Agreement to indemnify Entergy in a separate action. Entergy’s Post-Trial Br. at 23-24. The language of the assignment clause, however, expressly preserves Boston Edison’s claims arising as of the date of the closing. Boston Edison I, 64 Fed.Cl. at 173; see DX 265 (Purchase and Sale Agreement, § 2.2(g)) at 0176-77 (reserving the right to “any claims of Seller related or pertaining to the [DOE’s] defaults under the DOE Standard Contract accrued as of the [closing [d]ate”). That fact distinguishes this case from Delmarva Power & Light Co. v. United States, 79 Fed.Cl. 205, where plaintiffs had no cause of action after assigning their claims against the DOE in a transfer of the Standárd Contract; in Delmarva, plaintiffs assigned “all ... claims of Seller against the [DOE]” that “accrued prior to, on or after the [c]losing [d]ate, whether relating to periods prior to, on or after the [c]losing [d]ate.” Delmarva, 79 Fed.Cl. at 216. Contrastingly, Boston Edison expressly reserved its right to claims against the DOE arising as of the closing date, and it incurred economic loss resulting from Pilgrim’s diminution in value as of that date due to DOE’s breach. Furthermore, as Entergy acknowledges, see Entergy’s Pos1>-Trial Br. at 24, any dispute about indemnity between Boston Edison and Entergy must be resolved in a different forum.

CONCLUSION

For the reasons stated, the court concludes that Boston Edison is entitled to recover $40,030,000 in damages from and against the government. The Clerk shall enter final judgment in favor of Boston Edison for that amount.

Boston Edison is also awarded costs of suit.

The government’s claim for offset from Entergy Nuclear cannot be resolved in the action brought by Boston Edison, No. 99-447C. Instead, it must be pursued in the action brought by Entergy Nuclear, No. 03-2626C, and, in addition, any subsequent case or cases that may be filed by Entergy Nuclear for breach of the Standard Contract assigned by Boston Edison to Entergy Nuclear attendant to the sale of Pilgrim.

On or before February 20, 2008, the parties are requested to submit proposed redac-tions of any confidential or proprietary information that may be set out in this decision rendered under seal.

It is so ORDERED. 
      
      . Because this opinion and order might have contained confidential or proprietary information within the meaning of Rule 26(c)(7) of the Rules of the Court of Federal Claims ("RCFC”) and the protective order entered in this case, it was initially filed under seal. The parties were requested to review this decision and provide proposed redactions of any confidential or proprietary information on or before February 20, 2008. The resulting redactions are shown by brackets enclosing asterisks as follows: "j"* * "
      
     
      
      . In 2000, Boston Edison merged with Commonwealth Energy Corporation, forming NSTAR Electric and Gas Corporation ("NSTAR"). Tr. 419:22-420:4 (Test, of Henry V. Oheim, NSTAR Project Manager and former Pilgrim senior manager). Effective January 1, 2007, Boston Edison formally changed its name to NSTAR Electric Company.
      Citations to the trial transcript are to "Tr. __” Boston Edison’s exhibits are denoted as "BX,” plaintiff Entergy Nuclear Generation Company’s exhibits are denoted as "NX,” and defendant's exhibits are denoted as "DX." Citations to Boston Edison's demonstrative exhibits are to "BDX” and to the government's demonstrative exhibits are to "DDX.”
     
      
      . The parties jointly stipulated to certain facts, and the Joint Stipulation will be cited as “Stip. V__"
     
      
      . This recitation of facts constitutes the court's principal findings of fact in accord with RCFC 52(a). Other findings of fact and rulings on questions of mixed fact and law are set out in the analysis which follows.
     
      
      . At the time of sale, Pilgrim’s spent fuel pool was licensed for 3,859 assembly-storage locations, although not all of the licensed racks had been installed. See BX 47 (Entergy’s due-diligence field notes) at RFP-21-787. Ten such cells were reportedly not available for use. Id.
      
     
      
      . DTE succeeded to regulatory functions performed by the Department of Public Utilities.
     
      
      . In June 1994, Boston Edison had obtained from the NRC an amendment to its operating license to allow it to install six high-density fuel storage racks. Tr. 446:19-22 (Oheim); BX 276 (NRC’s Amend. No. 155 to Facility Operating License No. DPR-35 (June 22, 1994)). Boston Edison installed two such racks thereafter and planned to install the remaining racks on an as-needed basis. Tr. 446:23 to 447:2 (Oheim).
     
      
      . Some years earlier, beginning in March 1986, Pilgrim had been shut down by action of the pertinent regional office of the NRC, after the plant had suffered three unplanned shutdowns within a period of thirty days. Tr. 508:4 to 509:25 (Oheim). Thereafter, upon starting up again, it remained on the NRC's watch list for several years. Tr. 510:12 to 511:4 (Oheim). Pilgrim’s operating problems had been resolved by the time of the competitive auction, and Pilgrim then had attained a better than average operating record. Tr. 515:21 to 516:2 (Oheim).
     
      
      . Installation of the sixth high-density rack at the pool at Pilgrim was problematic because that rack would have had to be installed in the cask loading area. BX 47 (Entergy’s due-diligence field notes) at RFP-21-787; BX 227 (diagram of Pilgrim spent fuel pool, showing proposed final reracked configuration). Installation of racks in that area would have barred use of the area to load shipping casks with SNF for off-pool storage or for deliveiy to DOE, and thus such use would have impaired Pilgrim’s future performance. Id.
      
      In all events, dry storage would have been an efficient and economic mode of storing SNF at Pilgrim on a longer-term basis after the plant had ceased operations. Tr. 2361:7-11, 2403:9-18 (Manion). A boiling-water reactor can be decommissioned only after all of the SNF has been removed from the spent-fuel pool. Tr. 2339:18 to 2340:16 (Manion). Putting a plant in SAFSTOR, as defined by the NRC, for later dismantling would not be an option to avoid diy storage because "you would have to ... take the fuel out of the pool in a boiling water reactor before you put the plant in SAFSTOR." Tr. 2367:14-17 (Manion).
     
      
      . AmerGen was a joint venture between PECO Energy and British Energy pic. AmerGen's role in the potential transaction was assigned to PECO because of uncertainty over whether British Energy would participate. See BX 384 (Transmittal of Final Bid Proposal of PECO Energy by Michael Egan, Senior Vice President, PECO Energy, to Reed (Oct. 16, 1998)) at 0291.
     
      
      . Entergy also submitted an optional indicative bid premised upon Boston Edison's retention of the decommissioning fund and also the decommissioning and SNF-storage obligations. DX 202 (Entergy’s Indicative Bid) at 157; Tr. 42:5 to 43:22 (Reed). This option was not seriously considered by Boston Edison because it would not have fully resolved the question of stranded costs. Tr. 50:8 to 52:1 (Reed). The Massachusetts restructuring legislation required resolution of the stranded-cost issue, as did Boston Edison's Settlement Agreement with the Office of the Massachusetts Attorney General. See supra, at 472-73. The decommissioning-retention option would in any event have been undesirable from Boston Edison’s perspective because it would have left the buyer in control of an obligation that Boston Edison would have had to fund. Tr. 48:12 to 49:7 (Reed).
     
      
      . In 1997, Massachusetts had commissioned ABZ, Incorporated to develop an independent estimate of the SNF-related storage costs that would be taken into account in a sale, Tr. 735:21 to 736:25 (Newhard); see BX 135 (Review of Decommissioning Cost Estimates for New England Nuclear Power Plants, prepared for the Office of the Massachusetts Attorney General (June 1997) ("ABZ Review”)), and ABZ had estimated those costs for Pilgrim to be $124.46 million in 1997 dollars. BX 135 (ABZ Review) at 0055. ABZ assumed that the SNF generated at Pilgrim would not be fully removed by DOE until 2040. Id. Mr. Warren Brewer, who testified as an expert decommissioning-cost estimator for the government, see Tr. 3663:21 to 3664:17, 3714:3-25 (Test, of Warren Brewer), was the primary author of the study performed by ABZ in June 1997 for the Office of the Massachusetts Attorney General. Tr. 3710:13 to 3711:2 (Brewer); see also Tr. 3789:12 to 3790:2 (the study authored by Mr. Brewer was admitted into evidence).
     
      
      . At the time of the execution of the Purchase and Sale Agreement, Boston Edison and Entergy did not know how much of the trust fund being transferred would be considered by the IRS to be “qualified,” as contrasted to "non-qualified,” for tax-treatment purposes. Tr. 191:9-19 (Reed). The qualified portion would be subject to a preferred, lower tax rate, whereas the non-qualified portion would be taxed at the normal corporate rate. Tr. 233:9-20 (Reed); see 26 U.S.C. [I.R.C.] § 468A(e)(2) (providing that the rate of tax on the income of a qualified fund is 20 percent). Approximately $43 million of the provisional trust was eventually refunded to Boston Edison pursuant to the terms of the Agreement and an IRS Private Letter Ruling. Tr. 574:20 to 575:2 (Lubbock); BDX 2 (Summary of Decommissioning Fund Transferred); see IRS Priv. Ltr. Rul. 199952074, 1999 WL 1268309 (Dec. 29, 1999) (determining that the Service will treat the sale as a disposition qualifying under the general provisions of Treas. Reg. § 1.468A-6, subsection (g) of which allows the Service to "treat any disposition of an interest in a nuclear power plant occurring after December 27, 1994, as satisfying the requirements of the regulations if the Service determines that such treatment is necessary or appropriate to carry out the purposes of [I.R.C. § ] 468A”).
     
      
      . Between the execution of the Purchase and Sale Agreement on November 18, 1998, and the closing on July 13, 1999, "the decommissioning amount prescribed by the NRC formula had decreased to $252 million, pursuant to Revision 8 to NUREG 1307.” Def.'s Post-Trial Br. at 22. The parties disagree over the subsidiary issue of whether Boston Edison and Entergy were aware during their negotiations that the NRC was planning to reduce the minimum formula, and whether those plans were taken into account by Entergy in formulating its bid for the decommissioning-fund aspect of the Pilgrim acquisition. Compare Boston Edison’s Post-Trial Br. at 37 n. 20, with Def.’s Post-Trial Br. at 22 ("|T]here is no evidence in the record to suggest that Entergy was even aware of the fact that the NRC was going to reduce the decommissioning formula after the execution of the P[urchase and] S[ale] Agreement].”).
      This debate is largely irrelevant because the Purchase and Sale Agreement specifies that "[o]n the Closing Date, Seller shall fully fund and transfer to Buyer ... an aggregate amount equal to or greater than the minimum amount required by the Nuclear Regulatoiy Commission regulations for the decommissioning of Pilgrim.” DX 265 (Purchase and Sale Agreement, § 5.21) at 0208-09 (emphasis added) (quoted more fully infra). Thus, the pertinent amount for the NRC minimum formula is $252 million, not $396 million.
      In addition, the record also shows that Entergy was aware of the possible regulatoiy change. The report provided to Entergy by Mr. LaGuar-dia in September 1998, see BX 72 (TLG Study), indicated that the NRC’s NUREG 1307, version 7, did not reflect waste-volume-reduction technologies that had become available, and that the NRC was reevaluating its formula to take those technologies into account. See id. at SUPPL-19; Tr. 1145:9 to 1147:19 (LaGuardia). The TLG Report undercuts Mr. Keuter's testimony that "I kn[e]w that N[uclear] E[ntergy] institute] had been pursuing a reduction, but I was surprised that the NRC actually did. I expected it to go up, not down.” Tr. 2138:2-5 (Keuter). In all events, the government’s and Entergy’s contentions in this regard are contravened by the evidence and are not credited.
     
      
      . As a result of the private letter ruling obtained respecting qualification of the decommissioning fund for taxation of the income from the fund at twenty percent rather than the normal corporate tax rates, Boston Edison was refunded $43,338,980.32. See BDX 2 (Summary of Decommissioning Fund Transferred). The net amount of the decommissioning fund transferred by Boston Edison to Entergy thus was $427,879,201.50. Id.
      
     
      
      . Additionally, while speculative damages are not recoverable, " 'where responsibility for damages is clear, it is not essential that the amount thereof be ascertainable with absolute exactness or mathematical precision.’ ” San Carlos Irrigation & Drainage Dist., 111 F.3d at 1563 (quoting Electronic & Missile Facilities, Inc. v. United States, 189 Ct.Cl. 237, 416 F.2d 1345, 1358 (1969)).
     
      
      . If one party to a contract provides notice that it does not intend to perform under the contract, the other, non-breaching party acquires an obligation to mitigate its losses or damages: " '[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.’" Indiana Michigan, 422 F.3d at 1375 (quoting Restatement (Second) of Contracts § 350 cmt. b); see also Tennessee Valley Auth., 60 Fed.Cl. at 674 (same). Other spent nuclear fuel cases regarding breach of the Standard Contract have involved utilities claiming costs incurred in actions taken to mitigate damages resulting from DOE’s breach of the Standard Contracts. See, e.g., System Fuels, 79 Fed.Cl. at 53-55; System Fuels, Inc. v. United States, 78 Fed.Cl. 769, 788 (2007); Northern States Power Co. v. United States, 78 Fed.Cl. 449, 457-59 (2007); Southern Nuclear Operating Co. v. United States, 77 Fed.Cl. 396, 403-04 (2007); Pacific Gas & Elec. Co. v. United States, 73 Fed.Cl. 333, 395 (2006); Sacramento Mun. Util. Dist. v. United States, 70 Fed.Cl. 332, 366-67 (2006); Tennessee Valley Auth., 69 Fed.Cl. at 522.
      The party obligated to mitigate may recover as damages its reasonable costs incurred in doing so. In these cases, the claimant is not barred from recovering damages by the fact that its claim is necessarily for partial breach. "[T]o find a 'total breach would abort the contract, thereby obviating DOE's obligation to collect ... SNF ... in the future and most likely resulting in the forfeiture of [Entergy’s] operating license[] ... pursuant to 42 U.S.C. § 10222(b).’ ” Tennessee Valley Auth., 69 Fed.Cl. at 523 (quoting Tennessee Valley Auth., 60 Fed.Cl. at 677-78); see also Indiana Michigan, 422 F.3d at 1374. The Federal Circuit held in Indiana Michigan that there is "no reason why efforts to avoid damages in contemplation of a partial breach should not ... be recoverable,” just as they are recoverable for mitigation upon a total breach. 422 F.3d at 1375.
      The government bears a concomitant burden of proof in a case involving mitigation, i.e., to eliminate or reduce mitigation-related damages, the government must show that the claimant’s mitigation efforts were unreasonable. See Indiana Michigan, 422 F.3d at 1375. A non-breaching party is " 'not precluded from recovery ... to the extent that [it] has made reasonable but unsuccessful efforts to avoid loss.’ ” Id. (quoting Restatement (Second) of Contracts § 350(2)) (emphasis added); see also First Heights Bank, FSB v. United States, 422 F.3d 1311, 1316-17 (Fed.Cir.2005); Koppers Co. v. Aetna Cas. and Sur. Co., 98 F.3d 1440, 1448 (3d Cir.1996) (applying Pennsylvania law); Southern Nuclear, 77 Fed.Cl. at 403-04; Pacific Gas & Elec., 73 Fed.Cl. at 406; Tennessee Valley Auth., 69 Fed.Cl. at 523. As the Federal Circuit has stated, “ '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).
     
      
      . Had DOE performed under the Standard Contract, Boston Edison would not have needed any additional high density racks. Tr. 447:13-22 (Oheim), 3030:17 to 3032:21 (Reed); BX 155 (Reed Report) at 4000. The proofs at trial demonstrate that Pilgrim’s re-racking efforts were attributable to the government’s breach, and that these costs would have been unnecessary had the government performed its statutory and contractual obligations. Tr. 447:13-22 (Oheim), 3030:17 to 3032:21 (Reed); BX 155 (Reed Report) at 4000.
     
      
      . Because the closing date was slightly deferred from that which was planned, the actual amount of the funds transferred was $471,218,181.82, and $43,338,980.32 was rebated after the IRS ruling. See supra, at 482 n. 15.
     
      
      . In its calculations related to the decommissioning fund, Entergy used a cost-escalation factor that was less than the discount rate, thus in effect reducing the amount needed in 2012, projected as $572 million in 1997 dollars ($578.1 million minus $6.1 million of pre-planning decommissioning costs), or $782 million in 2012, to a present value of $466 million. See BX 69 (Mem. from LaGuardia to Downes, with attached charts and graphs prepared by TLG for Entergy showing site-specific funding requirements as of particular dates); BX 72 (TLG Study).
     
      
      . The government notes that $44 million of the $80-85 million total consisted of annual operating and maintenance costs to be incurred well into the future, specifically, that the $44 million equates to the 22 years of dry storage at $2 million per year, which Mr. LaGuardia assumed would arise during the years 2021 through 2043. See Def.’s Br. at 32, n. 21 (citing BX 69 (Mem. from LaGuardia to Downes, with attached charts and graphs prepared by TLG for Entergy); BX 72 (TLG Study). As Mr. LaGuardia testified, if the annual ■ operating and maintenance costs were first escalated and then discounted, they would have a present value of less than $2 million per year. Tr. 1206:3-17 (LaGuardia)).
     
      
      . This quantification is confirmed by an analysis performed by Mr. Manion, a decommissioning expert retained by Boston Edison. For each such scenario studied, Mr. Manion did a separate breakout of the spent fuel storage costs, the decommissioning costs, and the greenfielding costs. Tr. 2502:11 to 2504:2 (Manion); BX 122 (Man-ion Expert Report) at 4286. However, Mr. Man-ion did not provide a separate net-present-value analysis for the three elements. Tr. 2504:3-6 (Manion). In general terms, the decommissioning activities would be completed well before SNF storage would be able to be terminated. See Tr. 2499:4 to 2501:8 (Manion). As Mr. Man-ion put it:
      The Court: As the court understands your studies, in general terms the decommissioning dollars would be expended faster or earlier than the fuel storage dollars?
      A. Typically, yes. Particularly in a B[oiling] W[ater] R[eactor], if you have extended, say, dry storage, you would be able to complete your dismantlement program long before the fuel was shipped off-site. The Court: And that would have the effect of giving greater weight and net present value dollar terms to the decommissioning dollars than to the fuel storage dollars.
      A. Yes.
      Tr. 2500:18 to 2501:7 (Manion). The present-value calculations are consequently quite important to the analysis. As it happens, Mr. Manion presented an alternative scenario in his rebuttal report that assigned a net present value in 1999 dollars to fuel storage costs of $44.5 million. See Tr. 3883:14 to 3884:4 (Neuberger) (referring to BX 123 (Manion Rebuttal Report)). Mr. Man-ion’s rebuttal alternative adopted an assumption made by a government expert, Mr. Brewer, that one of the NES scenarios had been included as a "but for” case, see BX 123 (Manion Rebuttal Report) at 4317-18 nn. 2-4, although Mr. Man-ion noted that the scenario was not intended to serve in that role. Id.
      
     
      
      . Dr. Neuberger's commentary came in response to a question from the government’s counsel regarding whether Mr. Manion’s rebuttal calculation of $44.5 million would provide an adequate basis for damages.
      Q. And, Dr. Neuberger, do you have an opinion as to whether that $44 and a half million is a correct estimate of decommissioning related damages in this case?
      A. Well, I would just reiterate the point I made at the beginning. It would be necessary to show that Entergy would have demanded 44 and a half million less in its terms and conditions for the Pilgrim acquisition in order for that number to be the correct one, to be a correct measure of damages. I would also note that the decommissioning trust fund was transferred with certain tax benefits, and in order to make this number truly comparable, if, in fact, it can be shown that the bid would have been that much lower for decommissioning, you would have to tax effect that number. And it would take the number down below 44 million.
      Tr. 3883:19 to 3884:12 (Neuberger). Another expert testifying on behalf of the government, Mr. Brewer, also mentioned that the effect of the private letter ruling should be analyzed. See Tr. 3785:3 to 3787:4 (Brewer). Neither Dr. Neuber-ger nor Mr. Brewer proffered such an analysis.
     
      
      . Boston Edison argues that "a DCF analysis ... produces an IRR that reflects the rate at which the future cash flows will produce an NPV of $0. In Entergy's case, since its purchase price for the plant alone was $0, the IRR and the effective discount rate were one and the same,” such that "the IRR represented the minimum return that Entergy was willing to accept for its investment in Pilgrim, and [was] a direct proxy for the adequacy of the rate of return in exchange for the risk of the investment.” Boston Edison's Post-Trial Br. at 31 (citing Tr. 1045:8-16, 1052:4-18 (Harrington), 3301:25 to 3302:9 (Harlan); BX 156 (Reed Rebuttal Report) at 4048; BX 43 (Entergy Board Minutes) at 3057).
     
      
      . Boston Edison submits that comparable transactions involving non-nuclear baseload generation assets at the time of the Pilgrim sale demonstrate that a capital structure for the purchase of a baseload generation facility such as Pilgrim would have been financed using 50% debt and 50% equity in the absence of the nuclear-specific risks such as those imposed by DOE’s breach of its SNF obligations. Boston Edison’s Post-Trial Br. at 59, n. 26 (citing BX 155 (Reed Report) at 4006; Tr. 3022:17 to 3023:9 (Reed)).
     
      
      . The court thus need not address the government’s argument that Boston Edison’s assessment of its damages constitutes double counting when it suggests that Entergy accounted for the same SNF-storage risks in its bids for the decommissioning trust fund transfer and Pilgrim pricing valuation model. Def.’s Post-Trial Br. at 45-49.
     