LR-N08-0032, Request for Exemption from 10 CFR 50.82(a)(8)(i) and (Ii), NRC Regulations to Permit the Immediate Withdrawal of Certain Funds from Nuclear Decommissioning Trust Funds

Request for Exemption from 10 CFR 50.82(a)(8)(i) and (Ii), NRC Regulations to Permit the Immediate Withdrawal of Certain Funds from Nuclear Decommissioning Trust Funds

ML081050556
Person / Time
Site:	Salem
Issue date:	04/07/2008
From:	Braun R Public Service Enterprise Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LR-N08-0032
Download: ML081050556 (102)

Text

PSEG Nuclear LLC P.O. Box 236,, Hancocks Bridge, NJ 08038-0236 0 PSEG NuclearL.L. C.

APRO:*72.8 10 CFR 50.12 A10 CFR 50.82 LR-N08-0037 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 Salem Nuclear Generating Station Unit 2 Facility Operating License No. DPR-75 NRC Docket No. 50-311

Subject:

Request for Exemption from 10 CFR 50.82(a)(8)

In accordance with the provisions of 10 CFR 50.12, PSEG Nuclear, LLC (PSEG Nuclear) hereby requests an exemption from Nuclear Regulatory Commission (NRC) regulations to permit the immediate withdrawal of certain funds from the nuclear decommissioning trust funds (DTF) maintained by PSEG Nuclear for the Salem Nuclear Generating Station Unit 2 (the "Facility"). Specifically, PSEG Nuclear requests an exemption from provisions of 10 CFR 50.82(a)(8)(i) and (ii) which may restrict the withdrawal of funds from DTF until after permanent plant shutdown.

The purpose of this exemption request is to permit the use of DTF, not to exceed $5.47 million',

in order to pay for the prompt disposal of certain major radioactive components (MRCs). These MRCs are the four steam generators that are scheduled to be removed from Salem Unit 2 during the Spring 2008 outage. PSEG Nuclear desires to remove these MRCs from the site during the Summer of 2008. Arrangements have been made with the State of South Carolina for shipment of the MRCs to Barnwell during the third quarter of 2008.

If left on-site until the Facility is decommissioned, the disposal of these MRCs would be covered by the DTF. A similar exemption request was previously submitted by the STP Nuclear Operating Company on September 19, 2007 and is currently pending before the NRC for disposition.

$5.47 million is the PSEG Nuclear share of the disposal costs. Decommissioning costs of Salem Unit 2 are shared by both PSEG Nuclear and Exelon Corporation; $10 million is estimate for the total cost of the disposal, including contingency funding. The PSEG share is 54.71% ($10 million x 54.71% =

$5.47 million).

Document Control Desk LR-N08-0032 PSEG Nuclear requests that the NRC grant the exemption because:

• The exemption is "authorized by law, will not present an undue risk to the public health and safety, and [is] consistent with the common defense and security," in accordance with 10 CFR 50.12(a)(1), and

" Special circumstances are present that satisfy 10 CFR 50.12(a)(2). of this submittal documents that the request satisfies these provisions. Enclosure 2 provides the Decommissioning Cost Analysis for the Salem Generating Station Unit 2 Granting this exemption will be consistent with the NRC decommissioning regulations (10 CFR 82(a)(6)) as it: (1) would not foreclose release of the site for possible unrestricted use (in fact, it would enhance PSEG Nuclear's ability to achieve unrestricted release); (2) would not result in significant environmental impacts not previously reviewed by the NRC; and (3) would not undermine the existing and continuing reasonable assurance that adequate funds will be available for decommissioning. Prompt disposal of the MRCs would facilitate eventual unrestricted release of the Facility, thus improving environmental conditions. In addition, authorizing the use of DTF to provide for prompt disposal would give PSEG Nuclear the ability to take advantage of cost effective disposal alternatives that are currently available and thereby eliminate the uncertainty associated with the future cost and availability of disposal capacity.

Prompt disposal of MRC source terms is prudent and consistent with the underlying purpose of the Commission's decommissioning regulations. Finally, assurance of the adequacy of the availability of funds for Facility decommissioning is supported by a site-specific decommissioning cost estimate and the associated funding program.

PSEG Nuclear recognizes that on May 29, 2007, a rulemaking petition was submitted to the NRC (RM 50-88) seeking to amend the NRC's regulations to provide a process for NRC approval of the use of decommissioning trust funds for the disposal of MRCs by licensees for operating reactors. The NRC provided Notice regarding this pending petition and an opportunity for public comment on August 21, 2007 (72 FR 46569). It is unlikely that the time required to complete the NRC's rulemaking process will accommodate PSEG Nuclear's schedule for removal of the MRCs. Therefore, PSEG Nuclear is submitting this exemption request now, because granting this request will facilitate removing the MRCs from the site consistent with the current steam generator replacement schedule. PSEG Nuclear requests that NRC grant this request by 'November 1, 2008.

This letter and enclosures contain no new commitments.

Should you have any questions regarding this submittal, please contact Mr. Jeff Keenan at (856) 339-5429.

Sincerely, Robert C. Braun Site Vice President Salem Generating Station

Enclosures:

(2)

Document Control Desk LR-N08-0032 cc:

Mr. Samuel Collins, Administrator - Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 U. S. Nuclear Regulatory Commission Attn: Mr. R. Ennis, Licensing Project Manager - Salem Mail Stop 08B1 Washington, DC 20555-0001 USNRC Senior Resident Inspector - Salem (X24)

Mr. P. Mulligan, Manager IV Bureau of Nuclear Engineering P.O. Box 415 Trenton, NJ 08625

ENCLOSURE 1 EXEMPTION REQUEST LR-N08-0037 SALEM NUCLEAR GENERATING STATION UNIT 2

1. EXEMPTION REQUEST In accordance with the provisions of 10 CFR 50.12, "Specific Exemptions," PSEG Nuclear LLC (PSEG Nuclear) the holder of operating license DPR-75 for the Salem Nuclear Generating Station Unit 2 ( the "Facility") requests that the Nuclear Regulatory Commission (NRC) grant an exemption from provisions of 10 CFR 50.82, "Termination of License." Specifically, PSEG Nuclear requests an exemption from the requirements of 10 CFR 50.82(a)(8)(i) and (ii), to the extent required in order to permit the immediate withdrawal of funds from the nuclear decommissioning trust funds (DTF) maintained by PSEG Nuclear for Salem Nuclear Generating Station Unit 2.

The purpose of this exemption request is to permit the use of DTF, not to exceed $5.47 million, in order to pay for the disposal of certain major radioactive components (MRCs). These MRCs are the four steam generators that are scheduled to be removed from Salem Unit 2 during the Spring 2008 outage. PSEG Nuclear desires to remove these MRCs from the site during the Summer of 2008. Arrangements have been made with the State of South Carolina for shipment of the MRCs to Barnwell during the third quarter of 2008.

Prompt disposal will result in a number of benefits: (1) the inventory of radioactive waste and associated source term at the site will be reduced; (2) the costs and inconveniences associated with maintaining the MRCs on-site will be avoided; (3) the overall cost to decommission the site will be reduced; (4) uncertainty regarding future disposal cost and capacity for these MRCs will be eliminated; and (5) assurance of adequate funds to decommission the reactors at the time the reactors cease operation will be maintained. Assurance of the adequacy of the availability of funds for Facility decommissioning is supported by a site-specific decommissioning cost estimate and the associated funding program for Salem Unit 2.

Authorization of the use of DTF for prompt disposal of the MRCs is in the public interest, because it will immediately reduce on-site waste inventories, eliminate risks associated with future disposal, and reduce the eventual cost and complexity of decommissioning the Facility.

Consequently, authorization to expend DTF for prompt disposal of the MRCs would be entirely consistent with the underlying intent and purpose of 10 CFR 50.82(a)(8), which is to provide reasonable assurance that the decommissioning trust funds will be adequate to accomplish their intended purpose.

I1. REQUIREMENTS 10 CFR 50.82(a)(8)(i) provides that decommissioning trust funds may be used by licensees if:

(A) The withdrawals are for expenses for legitimate decommissioning activities consistent with the definition of decommissioning in section 50.2; (B) The expenditure would not reduce the value of the decommissioning fund below an amount necessary to place and maintain the reactor in a safe storage condition if unforeseen conditions or expenses arise; and 1

LR-N08-0037 (C) The withdrawals would not inhibit the ability of the licensee to complete funding of any shortfalls in the decommissioning trust needed to ensure the availability of funds to ultimately release the site and terminate the license.

NRC has further conditioned the withdrawal of decommissioning trust funds by limiting the withdrawal rate from the trust. Section 50.82(a)(8)(ii) provides:

Initially, 3 percent of the generic amount specified in § 50.75 may be used for decommissioning planning. For licensees that have submitted the certifications required under § 50.82(a)(1) and commencing 90 days after the NRC has received the [post-shutdown decommissioning activities report] PSDAR, an additional 20 percent may be used. A site-specific decommissioning cost estimate must be submitted to the NRC prior to the licensee using any funding in excess of these amounts.

Section 50.82 refers to the definition of "decommissioning" in section 50.2, which defines the term "decommission" rather than "decommissioning." By that definition, the term "decommission" means:

to remove a facility or site safely from service and reduce residual radioactivity to a level that permits (1) release of the property for unrestricted use and termination of the license; or (2) release of the property under restricted conditions and termination of the license.

In the absence of an exemption by the NRC, these provisions may be construed to restrict the ability of PSEG Nuclear to use DTF for the disposal of MRCs prior to permanent cessation of operation at the Facility, even though removal of the MRCs would reduce the level of radioactivity at the Salem site and would not adversely impact the ability to fund future decommissioning.

A request for an exemption from these requirements must satisfy the requirements of 10 CFR 50.12. As demonstrated below, this exemption request satisfies the provisions of Section 50.12.

Ill. BACKGROUND In the Statements of Consideration for the 1996 amendments to 10 CFR 50.82, the NRC stated in response to a comment as follows:

The NRC has concluded that allowing decommissioning trust funds withdrawals for disposals by nuclear power plants that continue to operate is not warranted.

These activities are more appropriately considered operating activities and should be financed that way.

(61 FR 39278, 39293).

Consequently, licensees have been precluded from using decommissioning trust funds for prompt disposal of radioactive waste, including MRCs that are prematurely removed from service and effectively "decommissioned." Unlike other waste routinely generated during normal plant operations, replacement of MRCs is not an anticipated operating activity, but rather these MRCs were originally expected to remain in service throughout the life of the plant.

2 LR-N08-0037 Significantly, NRC's rules do not address the reality that MRCs need to be removed from service during plant operating life. For example, the definition of "major decommissioning activities" in 10 CFR 50.2 includes removal of "major radioactive components," which specifically includes reactor vessels and steam generators. 10 CFR 50.82(a)(5) contemplates, however, that "major decommissioning activities," i.e., removal of MRCs, would not be performed by licensees until after permanent cessation of operations. This regulatory scheme implicitly acknowledges that removal and disposal of MRCs such as steam generators and RPV heads is not a routine operational activity, but rather is a decommissioning activity. Further support for this conclusion is found in the 1996 rulemaking history where NRC stated that removal and disposal of some "large components" would be considered "routine operations," but specifically excluded from such routine operations the removal of any large components that fall within the definition of "major radioactive component" (61 FR 39286). In fact, the response to comments made clear that a definition of "major radioactive component" was added for this very purpose, i.e., to distinguish the removal and disposal of certain equipment during normal operations from the removal of components such as steam generators and reactor pressure vessel heads that would constitute "major decommissioning activity" per se.

PSEG Nuclear has elected to improve plant operations and long term performance by replacing in 2008 the specified MRCs with components made of improved materials. PSEG Nuclear has considered storing them on-site as other licensees have as it appreciates that if it left these steam generators on-site until the facility ceases operations, it could without question use the funds from the DTF at that time. However, PSEG Nuclear, based on the factors discussed earlier, has decided to remove them from the site. Disposing them now would comply with 10 CFR 50.82(a)(6) in that such disposal: (1) would not foreclose release of the site for possible unrestricted use (in fact, it would enhance PSEG Nuclear's ability to achieve unrestricted release); (2) would not result in significant environmental impacts not previously reviewed by the NRC; (3) would be consistent with the Facility's stakeholder views, and (4) would not undermine the existing and continuing reasonable assurance that adequate funds will be available for decommissioning. Moreover, PSEG Nuclear has an opportunity to enter into favorable contractual arrangements for disposal of the existing steam generators, eliminating risks associated with future changes in disposal cost and/or availability of disposal capacity. The PSEG Nuclear share of the disposal cost of the steam generators is estimated to be about $

4.8M (total cost is estimated at $8.8 million).

PSEG Nuclear recognizes that by using DTF to pay for prompt disposal, the PSEG Nuclear will be paying in current dollars to eliminate this future cost of decommissioning, and as a consequence will forgo future earnings on these funds. However, the loss of the benefit of future earnings is off-set by the elimination of future risk and uncertainty relating to the cost and availability of disposal capacity, as well as the benefits of eliminating the burdens associated with on-site storage and reducing the on-site inventory of waste. Moreover, the remaining funds will be sufficient to fully decommission the site consistent with the activities planned in the site-specific estimate. In that regard, it is particularly significant that PSEG Nuclear intends to seek renewal of the Facility license that will provide additional time for accumulation of the funds.

IV. BASIS FOR GRANTING THE EXEMPTION The permanent disposal of an MRC is a decommissioning activity. Such disposal involves the removal of a "major radioactive component" or large item of capital equipment from service.

However, the NRC definition of "decommission" implies that an entire reactor facility must be removed from service before related activities fall within NRC-sanctioned decommissioning 3

LR-N08-0037 (See 10 CFR 50.2). Further, when the NRC promulgated the decommissioning rule in 1988, it noted in the Statements of Consideration to the final rule that "decommissioning activities are initiated when a licensee decides to terminate licensed activities" (53 FR 24,018, at 24,019).

The MRCs at issue here will have been removed from service well in advance of the rest of the Facility. Accordingly, an exemption with respect to 10 CFR 50.82(a)(8)(i)(A) is needed because the Facility and site are not being removed from service, and therefore, payment for MRC disposal falls outside the definition "decommissioning activity" as the NRC Staff has interpreted 10 CFR 50.82(a)(8)(i)(A). It should be noted, however, that the regulations and this interpretation appear to be internally inconsistent, because 10 CFR 50.2 also provides that the permanent removal of "major radioactive components" is a "major decommissioning activity" and steam generators and RPVs are included as examples in the definition of "major radioactive component."

An exemption also is needed because Section 50.82(a)(8)(ii) provides only for planning costs to be paid from decommissioning trust funds in advance of submittal of a PSDAR, implying that no other pre-PSDAR decommissioning costs are allowed. The expenditures for which the exemptions are being requested are not planning activities. Rather, they are necessary to remove the MRCs from the plant site and dispose of them, and the exemption request is to permit the funds necessary for that purpose to be withdrawn from the DTF to fund current disposal activities irrespective of the 10 CFR 50.82(a)(8)(ii) restrictions.

A. Facility Decommissioning Trust Fund

1. Status of the Decommissioning Trust Fund The DTF maintained by PSEG Nuclear are currently robustly funded and fully meet NRC's decommissioning financial assurance requirements. As reflected in PSEG's decommissioning funding status report dated March 30, 2007, and submitted to NRC in accordance with 10 CFR 50.75(f), the minimum decommissioning fund estimate required for PSEG's 54.71%

portion of the Facility based on the NRC formula in 10 CFR 50.75, is approximately $204.4 million or $356.0 for the total liability for Unit 2. The reported DTF balance for PSEG's portion, as of December 31, 2006 totaled $224.8 million for Unit 2. Thus, without projected earnings taken into account as permitted by NRC's rules, the DTF balance already substantially exceeds NRC minimum requirements and is sufficient to be considered fully "pre-paid" for purposes of compliance with 10 CFR 50.75(e)(1)(i). If earnings are credited, as permitted by NRC's rules, the $224.8 million value would be escalated to be $301.3 million as expressed for purposes of comparison to the current $204.4 million minimum funding requirement.

2. Site-Specific Decommissioning Cost Estimate Is Comprehensive The NRC requires in 10CFR50.75(f)(2) that each licensee prepare and submit a Decommissioning Cost Estimate (DCE) at least five years prior to the projected end of operations. As noted above, however, even though operations are projected to continue for at least 30 years, PSEG Nuclear already has a detailed DCE. The most recent DCE update, which was done in 2003, adjusted to 2008 dollars, resulted in a total estimated cost, including spent fuel storage and Greenfield costs, of $378.2 million for Unit 2, or $206.9 million for PSEG Nuclear's share. The total spent fuel costs are estimated to be $124.8 million, of which the PSEG Nuclear share is $71.6 million.

The current site-specific estimates reflect the significant industry experience with the conduct of decommissioning as of 2002. By that time, there were several commercial nuclear power plants 4

Encloure 1LR-N08-0037 undergoing decommissioning, including Maine Yankee, Connecticut Yankee, Yankee Rowe, Trojan, and Big Rock Point. These projects were building on the lessons learned from other completed decommissioning projects such as Elk River and Shippingport. This experience included some generally acknowledged missteps made in the beginning stages of the current projects that led to additional costs beyond what had been projected. By 2004 these problems had been resolved, the projects were proceeding rapidly toward license termination, and the causes of the early-stage problems were well understood.

The PSEG Nuclear cost estimates take into account the industry lessons learned. For example, the 2002 update includes an improved Greater than Class C (GTCC) segmentation analysis, reducing the assumed volume of this waste. It also assumes that the reactor vessel and reactor vessel internals would be removed by an outside contractor, which is consistent with current decommissioning practices.

The PSEG Nuclear cost estimates take into account site-specific parameters that affect the total cost. .These parameters include site-specific equipment and material inventories, PSEG Nuclear staffing costs, projected spent fuel inventories, and site-specific spent fuel storage and shipping schedules. The end result is a site-specific decommissioning cost estimate in which PSEG Nuclear has a high degree of confidence.

3. The Site-Specific Decommissioning Cost Estimate Is Reliable As discussed above, the DCE contains a thorough and comprehensive analysis of the costs of decommissioning. The reliability of current industry DCEs is demonstrated by recent decommissioning experience. Data for the three large PWRs that have been fully demolished (Connecticut Yankee, Maine Yankee, and Trojan) show that final decommissioning costs were less than projected in the DCE for two (Maine Yankee and Trojan) and 24% higher for one (Connecticut Yankee). Despite the Connecticut Yankee experience, a table top review of the data indicates that the DCEs are reliable planning tools.2 Furthermore, the cause. of the difference in the case of Connecticut Yankee is now well understood, as explained below.

Both Maine Yankee and Connecticut Yankee started the decommissioning process after an unplanned shutdown. Maine Yankee shut down in December of 1996 and made the decision to decommission in August of 1997. Maine Yankee decided on a Decommissioning Operations Contractor (DOC) approach, with a DOC selected in August of 1998, approximately 20 months after shutdown. Connecticut Yankee shut down in December of 1996 after the decision was made to decommission. Connecticut Yankee also elected to utilize a DOC approach, selecting a DOC in April 1999, more than two years after shutdown.

Connecticut Yankee experienced problems with the selected DOC, and terminated the contract in 2003. These management problems significantly increased the decommissioning costs, resulting in an actual cost some 24 percent higher than the Connecticut Yankee DCE. While management problems also could cause future decommissioning costs to be unnecessarily high, it is likely that such significant problems will be avoided.

The experience of Maine Yankee shows that the cost associated with the type of problems experienced by Connecticut Yankee can be adequately mitigated if they occur in future decommissioning projects. Maine Yankee also had problems with its selected DOC and 2 Table Top Review - Decommissioning Costs for Power Reactors, CAF and Associates, April 2007.

5 Encloure 1LR-N08-0037 decided to terminate its contract. Maine Yankee, however, acted more quickly than Connecticut Yankee. While Connecticut Yankee terminated its DOC contract four years after DOC selection, Maine Yankee did so after only two years. As a result, Maine Yankee was able to quickly return its decommissioning project to schedule and budget and complete decommissioning within the DOE. The Maine Yankee experience shows that significant management problems can be overcome if promptly recognized and addressed.

The industry experience with decommissioning plants over the last decade contributes significantly to the reliability of current industry DOEs and provides a knowledge base that will result in more cost-efficient decommissioning in the future. Future decommissioning projects will be able to avoid mistakes and reduce costs through lessons-learned. Since the Facility Operating License (OL) is very likely to be renewed and consequently will be in operation longer than most plants, it will be able to benefit from the decommissioning experiences of dozens of much older plants that will be decommissioned during the remaining operating life of Salem Units 1 & 2. The predictable result will be further lessons learned and opportunities for more efficiency.

B. Withdrawal of Funds Now From the Decommissioning Trust Fund Will Not Jeopardize PSEG Nuclear's Ability to Fully Decommission the Facility

1. There Will Be Sufficient Funds Available To Decommission Facility As noted above the DTF balance for Unit 2 was $224.8 million as of December 31, 2006. If the Unit 2 balance was reduced by a total of $4.8 million in 2008, the adjusted DTF balance would be $220.0 million for Unit 2. The NRC minimum value in 2006 dollars was estimated to be

$204.4 million. As such, even after the withdrawal of funds to pay for the MRC disposal, the DTF balance is sufficient to meet the NRC requirements without considering projected earnings or license extension. Taking credit for earnings as permitted by the NRC rules, the balance would be expected to grow to $ 301.3 million expressed in current dollars (2% per year for the remaining current license, plus 3.5 years). If we assume a twenty year license extension, and future earnings, the DTF balance for Unit 2 is projected to grow to $421 million.

The credit for earnings on existing trust fund balances illustrates the adequacy of the existing trust funds to fund both the NRC minimum funding requirement and spent fuel management costs. For example, if PSEG Nuclear's share of spent fuel management costs of $71.6 million is deducted from $301.3 million value (taking credit for earnings based upon the current license without license renewal), the remaining balance of $229.7 million still exceeds PSEG Nuclear's share of the NRC minimum amount which is $204.4 million. If license renewal could be taken into account the value the remaining value would be $349.4 million ($421 million less $71.6 million) as compared to $204.4 million.

2. The Withdrawal Will Not Reduce the Value of the Decommissioning Fund Below an Amount Necessary to Place and Maintain the Reactor in a Safe Storage Condition If Unforeseen Conditions or Expenses Arise The use of DTF funds for the requested purpose will not reduce the value of the DTFs below an amount necessary to place and maintain the reactors in a safe storage condition. As discussed in Section IV.B3.1 above, the remaining DTF balances (after withdrawal of $8.8 million was made) would continue to exceed the NRC minimum requirements for financial assurance for decommissioning.

6 LR-N08-0037 Moreover, even with the requested withdrawals, PSEG would have sufficient funds to complete the NRC-required radiological decommissioning based on the site specific decommissioning cost estimate. In addition, the funds will be sufficient to manage the post-shutdown storage of spent fuel as estimated as well as provide for complete site restoration.

3. Decommissioning Funding for Salem Unit 2 Is Assured Even in the Event of Any Shortfall in Available Funds The current status of DTF funding and program of continued contributions provide reasonable assurance that the DTF will continue to be adequate to fund decommissioning after the requested withdrawals are made.

V. JUSTIFICATION FOR EXEMPTION AND SPECIAL CIRCUMSTANCES 10 CFR 50.12, "Specific Exemptions," provides that the NRC may grant exemptions from the requirements of the regulations if three conditions are met: (1) the exemption is authorized by law; (2) the exemption will not present an undue risk to the public health and safety; and (3) the exemption is consistent with the common defense and security. In addition, Section 50.12 provides that the NRC will not consider granting an exemption unless special circumstances are present. As demonstrated below, each of these conditions is satisfied and special circumstances are present.

A. The Requested Exemption is Authorized by Law The NRC has the authority under the Atomic Energy Act to grant exemptions from its regulations if doing so would not violate the requirements of law. This exemption is authorized by law as is required by 10 CFR 50.12(a)(1). No law exists that precludes the activities covered by this exemption request. The provisions of 10 CFR 50.82 were adopted at the discretion of the Commission consistent with its statutory authority. No statute required the NRC to adopt the specific provisions from which PSEG Nuclear seeks an exemption. Rather, the NRC may determine that alternative means are adequate to provide reasonable assurance of safety.

B. The Requested Exemption Will Not Present an Undue Risk to the Public Health and Safety This exemption will not present an undue risk to the public health and safety. To the contrary, granting this exemption will result in increasing the protection to the public health and safety as multiple source terms will be removed from the site and properly disposed of decades in advance of the time the MRCs would be removed if they were stored on-site until the reactor ceases operation. This will provide for permanent disposal of the MRCs and eliminate any risk of future exposures from these sources at the site. Moreover, ample decommissioning funding assurance will continue to be provided after withdrawals are made to pay for the near-term MRC disposal activity.

C. The Requested Exemption is Consistent with the Common Defense and Security This exemption is consistent with the common defense and security because the use of DTF to dispose of the MRCs will have no effect on the physical security of the site or the protection of special nuclear material from theft. Moreover, to the extent that residual radioactivity in the MRCs maintained in storage represents any potential threat, near-term permanent disposal enhances security.

7 LR-N08-0037 D. Special Circumstances This exemption is justified based on five of the six special circumstances enumerated in 10 CFR 50.12(a)(2):

1. Application of the regulation in the particular circumstances would not serve the underlying purpose of the rule or is not necessary to achieve the underlying purpose of the rule. (10 CFR 50.12(a)(2)(ii))

The underlying purpose of the rule is to provide assurance that there will be adequate funds for the ultimate decommissioning of the site. The application of the regulation restricts the expenditure of decommissioning trust funds in this circumstance, which is unnecessary to achieve the underlying purpose of the rule. The purpose of the restrictions on fund withdrawal is to protect the health and safety of the public by assuring that there will be adequate funds available to complete NRC-required decommissioning activities following termination of the operating license. The analysis in Section IV of the site-specific decommissioning cost estimate and the status of the DTF amply demonstrates that funding will, be adequate to complete decommissioning even if funds are withdrawn for early disposal of the MRCs.

This conclusion is further supported by the fact that the NRC regulations recognize that a site-specific decommissioning cost estimate provides a reasonable basis for not restricting licensee expenditure of decommissioning funds. Under 10 CFR 50.82(a)(8)(ii), after a licensee ceases operations, its expenditure of decommissioning funds is restricted until it has submitted a site-specific decommissioning cost estimate. Once this cost estimate is provided to the NRC, a licensee may withdraw unlimited funds without obtaining prior NRC approval. This interpretation of the regulation was specifically stated in the 1996 Statements of Consideration. ("Response.

The NRC's intent in the proposed rule was not to use a formal approval mechanism for decommissioning expenditures once the licensee submits its site-specific decommissioning cost estimate. The final rule has been modified as suggested by the commenter."). (61 FR 39285):

Since PSEG's site-specific decommissioning cost estimate is being submitted with this exemption request, the NRC is being provided with reliable information, which is the equivalent to that required by 10 CFR 50.82(a)(8)(ii).

The NRC's regulatory scheme relies in large part on the ability of licensees to effectively plan for and manage the decommissioning activity. The above discussion demonstrates that PSEG Nuclear has an adequate basis upon which to make informed decisions regarding the effect and timing of activities and expenditure of funds. Further, it shows that PSEG Nuclear has a reasonable basis for determining that it is prudent from both a safety and economic sense to use DTF to dispose of these MRCs in the near-term, when permanent disposal can be accomplished on reasonable financial terms. In these circumstances, it is not necessary for NRC to prevent the licensees from exercising their sound business judgment regarding the timing of decommissioning expenditures.

2. Compliance would result in undue hardship or other costs that are significantly in excess of those contemplated when the regulation was adopted, or that are significantly in excess of those incurred by others similarly situated.

(10 CFR 50.12(a)(2)(iii))

If PSEG Nuclear elected to not remove the MRCs from the site, costs would be incurred unnecessarily to build, maintain, and decommission at least one on-site storage facility. These are unnecessary regulatory burdens that were never contemplated when the regulation was 8

LR-N08-0037 adopted, because the rule never fully addressed the possibility of MRCs being removed during the operating life of the plant. For example, as discussed above in Section III, the definition of "major decommissioning activities" assumed to occur after permanent cessation of operations includes removal of MRCs.

As noted above in Section IV.B.1, use of DTF would not have an adverse impact of the ability to decommission the site to unrestricted use standards. In fact, plans and funding for future decommissioning would be enhanced by reducing future risks and uncertainties. Consequently, application of the rule without granting this exemption results in unnecessary and avoidable costs and burdens to PSEG Nuclear and the consumers of the electricity produced from this site that were not anticipated when this rule was adopted.

3. The exemption would result in benefit to the public health and safety that compensates for any decrease in safety that may result from the grant of the exemption. (10 CFR 50.12(a)(2)(iv))

While PSEG Nuclear clearly is capable of maintaining protection of the public health and safety if the MRCs end up stored on-site, the exemption would result in benefit to the public health and safety, because removal of the MRCs would provide a permanent disposal solution. This eliminates any potential future risk associated with on-site storage, even if such risk is low.

Furthermore, there is no associated decrease in safety. Thus, allowing the exemption will result in a net benefit to the public health and safety.

Prompt disposal of these MRCs furthers the objective of maintaining radiation exposures as low as reasonably achievable pursuant to 10 CFR 20.1101(b) by eliminating the potential for any future exposure from storing waste on-site. In addition, disposing of waste prior to the permanent cessation of operations is consistent with NRC policy to minimize the costs and complexity of decommissioning, which can only improve safety.

4. There is present any other material circumstance not considered when the regulation was adopted for which it would be in the public interest to grant an exemption. (10 CFR 50.12(a)(2)(vi))

As promulgated, the rule has never required that site-specific DCEs be developed during the operating life of the plant, but instead assumed that such estimates would be developed around the time a plant ceases operation. See 10 CFR 50.75(f)(2). In the absence of site-specific information, there may be an understandable preference for preserving funds in the DTF, because it would be difficult to make informed decisions regarding the sequencing of decommissioning activities and expenses. However, where detailed information is available through a site-specific DCE (as is the case here), the NRC and the licensees have the ability to evaluate the cost and benefits of prompt disposal versus deferring expenditures. Having DCEs is a changed circumstance that provides NRC with the ability to determine if there is reasonable assurance that sufficient funds will be available at the time of decommissioning if funds are withdrawn to cover the disposal costs for these MRCs.

The exemption request also satisfies the special circumstance criterion of 10 CFR 50.12(a)(2)(vi) in that, when this rule was adopted, the NRC did not consider that MRCs would be removed from the Facility long before permanent cessation of operation, and that the MRCs might be stored on-site because DTF did not include sub-accounts to address disposal of large components.

9 LR-N08-0037 The NRC's rulemaking history makes clear that licensees may maintain sub-accounts in DTF that might be used for purposes unrestricted by NRC, such as covering the disposal costs for MRCs. In one example, American Electric Power Company set aside funds that were dedicated for disposal of steam generators from DC Cook. However, some state utility commissions do not favor the use of sub-accounts. In adopting the regulation, the NRC anticipated that sub-accounts would be used to separate the funds collected for NRC-jurisdiction decommissioning from other decommissioning uses, and did not contemplate that funds collected for non-NRC decommissioning purposes would be commingled with the NRC-required decommissioning funds (61 FR 39285).

In this case, the funds for NRC-jurisdictional decommissioning and other decommissioning are commingled in the DTF. The NRC did not intend to prevent the use of those funds solely because they are commingled, and to do so would create an unnecessary regulatory burden without any corresponding safety benefit. This is especially true in the current situation where the adequacy of decommissioning funding can be readily assessed based upon a site-specific decommissioning cost estimate that sets out the costs for the different elements of decommissioning (including the disposal of MRCs) in order to determine whether there are adequate funds to fulfill NRC decommissioning requirements.

5. Application of the regulation in the particular circumstances conflicts with other rules or requirements of the commission. (10 CFR 50.12(a)(2)(i))

Application of the regulations in 10 CFR 50.82(a) would conflict with the NRC philosophy favoring the timely disposition of nuclear waste; under circumstances where doing so is practicable. For example, materials licensees of the NRC are subject to the 1994 Decommission Timeliness Rule, 10 CFR 30.36, 40.42, 70.38, and 72.54, which require those licensees to decontaminate and decommission certain unused portions of operating nuclear materials facilities. Allowing contaminated land, buildings or equipment to remain on-site was seen as a possible public and environmental liability, and the NRC looked for ways to achieve early decommissioning of unused portions of materials facilities. For valid and sound reasons, reactor licensees are not subject to this rule and, in fact, are allowed the SAFSTOR option under 10 CFR 50.82. Nevertheless, the NRC should look favorably upon efforts to pursue near-term permanent disposal of MRCs where justified.

Another example of the NRC's preference for minimizing the on-site inventory of waste is reflected in 10 CFR 20.1406 which was added along with modifications to NRC's license termination rule in 1997 (62 FR 39058). This regulation provides:

Applicants for licenses, other than renewals, after August 20, 1997, shall describe in the application how facility design and procedures for operation will minimize, to the extent practicable, contamination of the facility and the environment, facilitate eventual decommissioning, and minimize to the extent practicable, the generation of radioactive waste.

The intent of 10 CFR 20.1406 is to diminish the occurrence and severity of site contamination by taking measures that will control contamination and facilitate eventual decommissioning.

Consistent with this philosophy, early removal of large components is consistent with 10 CFR 20.1406. In contrast, storage of MRCs on-site until permanent cessation of operations will increase the complexity of decommissioning and volume of waste to be disposed at the end of plant life. Moreover, this complexity will be exacerbated by the inventory of MRCs stored on-site at multiple plants. Thus, permitting the phased disposal of large components over time will 10 LR-N08-0037 reduce the inventory of waste material and eliminate this future decommissioning activity, consistent with the philosophy underlying 10 CFR 20.1406.

Though not required to do so, reactor licensees should be permitted to utilize DTF to pay for the permanent disposal of MRCs prior to cessation of operations. This is justified where sufficient funds are being accumulated in DTF (as is the case here), especially where early removal could take advantage of favorable disposal pricing. If the use of DTF is not permitted, MRCs could remain on-site for additional decades though out the industry, particularly given current trends towards license renewal.

Finally, delaying disposal introduces risks associated with potential changes in future disposal costs and availability of disposal capacity.

VI. CONCLUSION Granting this exemption will be entirely consistent with the NRC decommissioning regulations as it: (1) would not foreclose release of the site for possible unrestricted use (in fact, it would enhance PSEG Nuclear's ability to achieve unrestricted release); (2) would not result in significant environmental impacts not previously reviewed by the NRC; and (3) would not undermine the existing and continuing reasonable assurance that adequate funds will be available for decommissioning. Disposal of the MRCs now would facilitate eventual unrestricted release of the Facility, thus improving environmental conditions. In addition, authorizing prompt disposal would give PSEG Nuclear the ability to take advantage of cost effective disposal alternatives and thereby eliminate the uncertainty associated with the future cost and availability of disposal capacity and allow it to fund important capital projects. It will also permit important projects to be funded that would need to be deferred or canceled if the funds for those projects were used to fund the disposal of these MRCs. Assurance of the adequacy of the availability of funds for the Facility decommissioning is supported by a site-specific decommissioning cost estimate and the associated funding program.

Granting this exemption encourages the prompt disposal of MRC source terms which is prudent and consistent with the underlying purpose of the Commission's decommissioning regulations.

PSEG Nuclear's application for an exemption is in the public's interest.

11 LR-N08-0037 ENCLOSURE 2 DECOMMISSIONING COST ANALYSIS for the SALEM NUCLEAR GENERATING Station Unit 2 12

Document P07-1425-003,Rev. 0 02 DECOM[MISSIONING COST ANALYSIS for the SAL]EM GENERATING STATION, UNITS 1 AND 2

~J preparedfor PSEG NUCLEAR, LLC preparedby TLG Services, Inc.

Bridgewater, Connecticut December 2002

Salem GeneratingStation Document P07-1425-003,Rev. 0 DecommissioningCost Analysis Page ii of xii 03 APPROVALS Project Manager DZ/tV/O e

William A. Cloutier, Jr. Date Project Engineer Albert A. Koehl Date Technical Manager Geofz M. Griffitl*U Date Quality Assurance Manager CarolyrA. Palmer TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

04 Salem Generating Station Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis page iii of xii TABLE OF CONTENTS SECTION PAGE EXECUTIVE SUMMVARY .............................................................. i3f

i. INTRODUCTION.......................................................................... 1-1 1.1 Objective of Study..............................................................  :......1-1 1.2 Site Description....................................................................... 1-1 1.3 Regulatory Guidance ................................................................ 1-2 1.3.1 Nuclear Waste Policy Act................................................... 1-4 1.3.2 Low-Level Radioactive Waste Policy Amendments Act................ 1-6 1.3.3 Radiological Criteria for License Termination.......................... 1-6

2. DECOMMISSIONING ALTERNATIVE ............................................... 2-1 2.1 Period 1 - Preparations .............................................................. 2,1 2.1.1 Engineering and Planning .................................................. 2-1 2.1.2 Site Preparations ............................................................ 2-3 2.2 Period 2 - Decommissioning Operations.......................................... 2-3 2.3 Period 3 - Site Restoration.....................:..................................... 2-6 2.4 Post Period 3 - ISFSI Operations.................................................. 2-7

3. COST ESTIMATE ................. a......................................................... 3-1 3.1 Basis of Estimate..................................................................... 3-1 3.2 Methodology .......................................................................... 3-1 3.3 Financial Components of the Cost Model ........................................ 3-3 3.3.1 Contingency .................................................................. 3-3 3.3.2 Financial Risk ............................................................... 3-5 3.4 Site-Specific Considerations........................................................ 3-7 3.4.1 Spent Fuel..................................................................... 3-7 3.4.2 Reactor Vessel and Internal Components................................ 3-8 3.4.3 Primary System Components ............................................ 3-10 3.4.4 Main Turbine and Condenser ............................................ 3-11 3.4.5 Transportation Methods ........................................ .......... 3-11 3.4.6 Low-Level Radioactive Waste Disposal ................................. 3-12 3.4.7 Site Conditions Following Decommissioning........................... 3-12 3.5 Assumptions......................................................................... 3-13 3.5.1 Estimating Basis ........................................................... 3-13 3.5.2 Labor Costs.................................................................. 3-14 3.5.3 Design Conditions.......................................................... 3-14 TLG Services, Inc. TLG ervies, nc.Copyright PSEG Nuclear 199.9/2000

Document P07-1425-003,Rev. 0 Salem GeneratingStation Decommissioning Cost Analysis Page iv of xii TABLE OF CONTENTS (continued)

SECTION PAGE 3.5.4 G eneral ................................................................................................. 3-15 3.6 Cost Estimate Summary ............................................................................... 3-17

4. SCHEDULE ESTIMATE ............................................. 4-1 4.1 Schedule Estimate Assumptions ...................................... 4-1 4.2 Project Schedule ............................................................................................... 4-2

5. RADIOACTIVE WASTES ........................................................................................ 5-1

6. R ESULTS ................................................................................................................ 6-1

7. REFEREN CES .......................................................................................................... 7-1 TABLES Cost Summary ................................................................................................... xii 3.1 Schedule of Annual Expenditures by Period, Unit 1 .................................... 3-18 3.2 Schedule of Annual Expenditures by Period, Unit 2 .................. 3-19 5.1 Decommissioning Waste Summary, Unit 1 ................................................... 5-3 5.2 Decommissioning Waste Summary, Unit 2 .................................................... 5-4 6.1 Summary of Decommissioning Cost Elements, Unit I ................................... 6-4 6.2 Summary of Decommissioning Cost Elements, Unit 2 ................................... 6-5 FIGURES 4.1 Decommissioning Activity Schedule ................................................................. 4-3 4.2 Decommissioning Timeline .............................................................................. 4-6 APPENDICES A. Unit Cost Factor Development .................................................................... ......... A-1 B. Unit Cost Factor Listing ........................................ B-i C. Detailed Cost Analyses ................................................................................... C-i TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

06 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Pagev of xii REVISION LOG No. CRA No. Date Item Revised Reason for Revision 0 12-05-02 Oxiginal Issue TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem GeneratingStation Document P07-1425-003,Rev. 0 DecommissioningCostAnalysis Page vi of xii EXECUTIVE

SUMMARY

This report presents the costs to promptly decommission (decontaminate and dismantle) the Salem Generating Station (Salem Station) following a scheduled cessation of plant operations. The analysis relies upon the site-specific, technical information developed for a previous evaluation prepared in 1995-96, updated to reflect current. plant conditions and operating assumptions. The estimates are designed to provide PSEG Power, LLC with sufficient information to assess its financial obligations as they pertain to the eventual decommissioning of the nuclear station.

The estimates are based on numerous fundamental assumptions, including regulatory requirements, project contingencies, low-level radioactive waste disposal practices, high-level radioactive waste management options, and site restoration requirements.

The estimates incorporate a cooling period of approximately five years for the spent fuel that resides in the plant's storage pools when operations cease. Any residual fuel remaining in the pools after the five-year period will be relocated to an on-site, interim storage facility to await the transfer to a DOE facility. The estimates also include the dismantling of non-essential structures and limited restoration of the site.

Alternatives and Regulations The Nuclear Regulatory Commission (NRC) provided general decommnissioning guidance in the rule adopted on June 27, 1988.11] In this rule the NRC set forth technical and financial criteria for decommissioning licensed nuclear facilities. The regulations addressed planning needs, timing, funding methods, and environmental review requirements for decommissioning. The rule also defined three decommissioning alternatives as being acceptable to the NRC - DECON, SAFSTOR, and ENTOMB.

DECON is defined as "the alternative in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed or decontaminated to a level that permits the property to be released for unrestricted use shortly after cessation of operations. "21 U.S. Code of Federal Regulations, Title 10, Parts 30, 40, 50, 51, 70 and 72 "General Requirements for Decommissioning Nuclear Facilities," Nuclear Regulatory Commission, Federal Register Volume 53, Number 123 (p 24018 et seq.), June 27, 1988.

2 Ibid. Page FR24022, Column 3.

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08 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Pagevii of xii SAFSTOR is defined as "the alternative in which the nuclear facility is placed and maintained in a condition that allows the nuclear facility to be safely stored and subsequently decontaminated (deferred decontamination) to levels that permit release for unrestricted use."[53 Decommissioning is to be completed within 60 years,. although longer time periods will be considered when necessary to protect public health and safety.

ENTOMB is defined as "the alternative in which radioactive contaminants are encased in a structurally long-lived material, such as concrete; the entombed structure is appropriately maintained and continued surveillance is carried out until the radioactive, material decays to a level permitting unrestricted release of the property."t4I As with the SAFSTOR alternative, decommissioning is currently required to be completed within 60 years.

The 60-year restriction has limited the practicality of the ENTOMB alternative at commercial reactors that generate significant amounts of long-lived radioactive material. As such, the NRC is currently re-evaluating this option and the technical requirements and regulatory actions that would be necessary for entombment to become a viable option.

In 1996, the NRC published revisions to the general requirements for decommissioning nuclear power plants to clarify ambiguities and codify procedures and terminology as a means of enhancing efficiency and uniformity in the decommissioning process. The amendments allow for greater public participation and better define the transition process from operations to decommissioning. Regulatory' Guide 1.184, issued in July 2000, further describes the methods and procedures that are acceptable to the NRC staff for implementing the requirements of the 1996 revised rule that relate to the initial activities and the major phases of the decommissioning process. The costs and schedules presented in this analysis follow the general guidance and process described in the amended regulations.

Methodology The methodology used to develop the estimates described within this document follows the basic approach originally presented in the cost estimating guidelines[5] developed by the Atomic Industrial Forum (now Nuclear Energy Institute), This reference 3 Ibid.

4 Ibid. Page FR24023, Column 2.

5 T.S. LaGuardia et al., "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," AIF/NESP-036, May 1986.

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09 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Page viii of xii describes a unit factor method for determining decommissioning activity costs. The unit factors used in this analysis incorporate site-specific costs and the latest available information on worker productivity in decommissioning.

The estimates also reflect lessons learned from TLG's involvement in the Shippingport Station Decommissioning Project, completed in 1989, as well as the decommissioning of the Cintichem reactor, hot cells and associated facilities, completed in 1997. In addition, the planning and engineering for the Pathfinder, Shoreham, Rancho Seco, Trojan, Yankee Rowe, Big Rock Point, Maine Yankee, Humboldt Bay-3, Oyster Creek, Connecticut Yankee and San Onofre-1 nuclear units have provided additional insight into the process, the regulatory aspects, and technical challenges of decommissioning commercial nuclear units.

An activity duration critical path is used to determine the total decommissioning program schedule. The schedule is relied upon in calculating the carrying costs, which include program management, administration, field engineering, equipment: rental; and support services such as quality control and security. This systematic approach for assembling decommissioning estimates ensures a high degree of confidence in the reliability of the resulting costs.

Contingency Consistent with industry practice, contingencies are applied to the decontamination and dismantling costs developed as "specific provision for unforeseeable elements of cost within the defined project scope, particularly important where previous experience relating estimates and actual costs has shown that unforeseeable events which will increase costs are likely to occur."[16 The cost elements in the estimates are based on ideal conditions; therefore, the types of unforeseeable events that are almost certain to occur in decommissioning, based on industry experience, are addressed through a percentage contingency applied on a line-item basis. This contingency factor is a nearly universal element in all large-scale construction and demolition projects. It should be noted that contingency, as used in this estimate, does not account for price escalation and inflation in the cost of decommissioning over the remaining operating life of the station.

The use and role of contingency within decommissioning estimates is not a safety factor issue. Safety factors provide additional security and address situations that may never occur. Contingency funds, by contrast, are expected to be fully expended throughout the program. Inclusion of contingency is necessary to provide assurance that sufficient funding will be available to accomplish the intended tasks.

6 Project and Cost Engineers' Handbook, Second Edition, American Association of Cost Engineers, Marcel Dekker, Inc., New York, New York, p. 239.

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10 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Page ix of xii Low-Level Radioactive Waste Disposal The contaminated and activated material generated in the decontamination and dismantling of a commercial nuclear reactor is classified as low-level (radioactive) waste, although not all of the material is suitable for "shallow-land" disposal. With the passage of the "Low-Level Radioactive Waste Disposal Act" in 1980, and its Amendments of 1985,17] the states became ultimately responsible for the disposition of radioactive waste generated within their own borders.

New Jersey is a member of the three-state Atlantic Interstate Low-Level Radioactive Waste Management Compact, formed after South Carolina formally joined the Northeast Regional Compact. The Barnwell Low-Level Radioactive Waste Management Facility, located in South Carolina, is expected to be available to PSEG Nuclear to support the decommissioning of the Salem Station. It is also assumed that PSEG Nuclear could access other disposal sites should it prove cost effective. As such, rate schedules for both the Barnwell and the Envirocare facility in Utah were used:to generate disposal costs.

High-Level Radioactive Waste Management Congress passed the "Nuclear Waste Policy Act"[81 in 1982, assigning the responsibility for disposal of spent nuclear fuel created by the commercial nuclear generating plants to the DOE. This legislation also created a Nuclear Waste Fund to cover the cost of the program, which is funded by the sale of electricity from nuclear reactors since 1993, and an estimated equivalent value for assemblies irradiated prior to 1983. The Nuclear Waste Policy Act, along with the individual disposal contracts with utilities, specified that the DOE was to begin accepting spent fuel by January 31, 1998.

Since the original legislation, the DOE has announced several delays in the program schedule. Operation of DOE's yet-to-be constructed geologic repository is currently scheduled for the year 2010, assuming that the licensing could be completed expeditiously and a national transportation system established. The agency has no plans for receiving spent fuel from commercial nuclear plant sites prior to this date and startup operations may be phased in, creating additional delays.

The NRC requires licensees to establish a program to manage and provide funding for the caretaking of all irradiated fuel at the reactor site until title of the fuel is transferred to the DOE. For estimating purposes, PSEG Nuclear has assumed that the high-level waste repository, or some interim storage facility, will be fully 7 "Low-Level Radioactive Waste Policy Amendments Act of 1985," Public Law 99-240, 1/15/86.

• "Nuclear Waste Policy Act of 1982 and Amendments," U.S. Department of Energy's Office of Civilian Radioactive Management, 1982.

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'Ii Salem Generating Station Documnent P07-1425-003, Rev. 0 Decommissioning Cost Analysis Page xof xii operational by 2015- Interim storage of the fuel, until the DOE has completed the transfer, will be in an. independent facility located on the Artificial Island site. This will allow. PSEG Nuclear to proceed with decommissioning and terminate its operating licenses in the shortest time possible.

The spent fuel storage facility, which is independently licensed and operated, will be sized to accommodate the inventory of spent fuel residing in the plant's storage poois at the cessation of operations, in addition to any operational inventory already in residence. When emptied, the station could be dismantled without maintaining the wet storage pools. Based upon this scenario, and an anticipated rate of transfer, spent fuel is projected to remain on site for approximately 30 years following the cessation of Unit 1 operations.

Site Restoration The efficient removal of the contaminated materials at the site may result-:in damage to many of the site structures. Blasting, coring, drilling, and the other decontamination activities will substantially damage power block structures, potentially weakening the footings and structural supports. Prompt demolition once the license is terminated is clearly the most appropriate and cost-effective option. It is unreasonable to anticipate that these structures would be repaired and preserved after the radiological contamination is removed. The cost to dismantle site structures with a work force already mobilized is more efficient and less costly than if the process were deferred. Experience at shutdown generating stations has shown that plant facilities quickly degrade without maintenance, adding additional expense and creating potential hazards to the public and the demolition work force.

Consequently, this study assumes that site structures will be removed to a nominal' depth of three feet below the local grade level wherever possible. The site will then be graded and stabilized.

Summar The DECON decommissioning alternative involves the prompt removal of the contaminated and activated plant components, including structural materials, from the site following permanent shutdown. The facility operator may then have unrestricted use of the site with no further requirement for a license. This study assumes that the remainder of the non-essential plant systems and structures, not previously removed in support of license termination, are dismantled and the site restored.

The scenario analyzed for the purpose of generating the estimates is described in Section 2. T~he assumptions are presented in Section 3, along with schedules of annual expenditures. The major cost contributors are identified in Section 6, with detailed TLG Services, Inc. TLG ervies, nc.Copyright PSEG Nuclear 1999/2000

12 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Pagexi of xii activity costs, waste volumes, and associated manpower requirements delineated in Appendix C. A cost summary is provided at the end of this section for the major cost components.

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13 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Pagexii of xii COST

SUMMARY

(Thousands of 2002 Dollars)

Activity Unit 1 Unit 2 Station Decontamination 13,463 13,577 27,040 Removal 79,587 100,874 180,461 Packaging 11,726 11,746 23,473 Transportation 11,632 11,734 23,366 Waste Disposal 80,911 82,039 162,950 Off-site Waste Processing 16,802 17,175 33,977 Program Management 233,535 272,325 505,860 (including Engineering and Security)

Spent Fuel Pool Isolation 9,060 6,040 15,101 ISFSI Related (including capital) 67,207 53,776 120,983 Insurance and Regulatory Fees 11,464 9,209 20,672 Energy 8,046 7,344 15,390 Characterization and Licensing Surveys 6,440 6,440 12,880 Misc. Equipment and Site Services 6,026 6,423 12,449 Total I 555,899 598,702 1,154,601 License Termination 2 523,818 544,985 1,068,803 Site Restoration 32,081 53,717 85,798

['WColumns may not add due to rounding.

[2] Includes spent fuel management expenditures.

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14 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 1, Page I of 7

1. INTRODUCTION This decommissioning analysis is designed to provide PSEG Power with sufficient information to prepare the financial planning documents for decommissioning, as required by the Nuclear Regulatory Commission (NRC or Commission). It is not a detailed assessment, but a financial analysis prepared in advance of the engineering and planning that will be required to carry out the decommissioning of the Salem Generating Station (Salem Station).

1.1 OBJECTIVES OF STUDY The objectives of this study are to prepare comprehensive estimdtfs of the costs to decommission Salem Station for the scenario outlined in Section 2,. to define a sequence of events, and project the volume of waste produced from the decontamination and dismantling activities.

The Salem Station is jointly owned by PSEG Power, LLC (57%) and Exelon Generation Corporation (43%). However, for purposes of this study, only the undivided decommissioning costs (100%) are presented, since the division of ownership has no effect on the total expenditures required. PSEG Nuclear operates the station.

The Station is comprised of two identical units, constructed concurrently, with the construction permits being issued on the same date. For the purposes of this study, the shutdown dates were taken as August 13, 2016, and April 18, 2020, for Units 1 and 2, respectively. This time frame, which reflects 40 years of operating life for each unit, was used as an input for scheduling the decommissioning activities.

1.2 SITE DESCRIPTION The Salem Station is located on the southern part of Artificial Island on the east bank of the Delaware River in Lower Alloways Creek Township, Salem County, New Jersey. The site is 15 miles south of the Delaware Memorial Bridge, 18 miles south of Wilmington, Delaware, 30 miles southwest of Philadelphia, Pennsylvania, and 7% miles southwest of Salem, New Jersey.

The Nuclear Steam Supply System (NSSS) consists of a pressurized water reactor and a four-loop Reactor Coolant System (RCS). The system was supplied by the Westinghouse Electric Corporation. The licensed ratings for each of the two units is 3,411 MWt. The corresponding net dependable electrical output is 1,115 MWe.

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15 Salem GeneratingStation Document P07-1425-003,Rev. 0 DecommissioningCost Analysis Section 1, Page 2 of 7 The NSSS is housed within a "containment structure," a seismic Category I, reinforced-concrete, dry structure. The containment is a cylinder with a hemispherical dome and a flat, reinforced-concrete foundation mat. A welded steel liner plate anchored to the inside face of the containment serves as a leak-tight membrane.

Heat produced in the reactor is converted to electrical energy by the steam and power conversion system. A turbine-generator system converts the thermal energy of steam produced in the steam generators into mechanical shaft power and then into electrical energy. The plant's turbine-generators are each tandem-compound, four-element units. They consist of one high-pressure, double-flow, and three low-pressure, double-flow elements driving a direct-coupled generator at 1,800 rpm. The turbines are operated in a closed feedwater cycle that condenses the steam; the heated feedwater is returned to the steam generators.

Heat rejected in the main condensers is removed by the circulating- water!

system.

The circulating water system provides the heat sink required for removal of waste heat in the power plant's thermal cycle. The system has the principal function of removing heat by absorbing this energy in the main condenser.

Water is withdrawn from the Delaware River by the circulating water pumps located at the intake structure. After passing through the plant condensers, the discharge is routed back into the Delaware estuary.

1.3 REGULATORY GUIDANCE The NRC provided initial decommissioning guidance in its rule "General Requirements for Decommissioning Nuclear Facilities," issued in June 1988.[11J This rule set forth technical and financial criteria for decommissioning licensed nuclear facilities. The regulation addressed decommissioning planning needs, timing, funding methods, and environmental review requirements. The intent of the rule was to ensure that decommissioning would be accomplished in a safe and timely manner and that adequate funds would be available for this purpose. Subsequent to the rule, the NRC issued Regulatory Guide 1.159, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors,"(2] which provided guidance to the licensees of nuclear facilities on the financial methods acceptable to the NRC staff for complying with the requirements of the rule. The regulatory guide addressed the funding requirements and provided guidance on the

• Annotated references for citations in Sections 1-6 are provided in Section 7.

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Salem GeneratingCost Station DocumentSection 16 Decommissioning Analysis P07-1425-003, 1, PageRev.

3 of 07 content and form of the financial assurance mechanisms indicated in the rule amendments.

The rule defined three decommissioning alternatives as being acceptable to the N-RC: DECON, SAFSTOR, and ENTOMB. It also placed limits on the time allowed to complete the decommissioning process. For SAFSTOR, the process is restricted in overall duration to 60 years unless it could be shown that a longer duration is necessary to protect public health and safety. The guidelines for ENTOMB are similar, providing the NRC with both sufficient leverage and flexibility to ensure that these deferred options are only used in situations where it is reasonable and consistent with the definition of decommissioning. At the conclusion of a 60-year dormancy period (or longer for ENTOMB if the NRC approves such a case), the site would still require significant remediation to meet the definition of unrestricted release and license termination.

The ENTOMB alternative has not been viewed as a viable option for power reactors due to the significant time required to isolate the long-lived radionucides for decay to permissible levels. However, with recent rulemaking permitting the controlled release of a site, the NRC has re-evaluated this alternative. The resulting feasibility study, based upon an assessment by Pacific Northwest National Laboratory, concluded that the method did have conditional merit for some if not most reactors. However, the staff also found that additional rulemaking would be needed before this option could be treated as a generic alternative. The NRC is considering rulemaking to alter the 60-year time for completing decommissioning and to clarify the use of engineered barriers for reactor entombments. Pending completion of such rulemaking, entombment requests will be handled on a case-by-case basis.

In 1996, the NRC published revisions to the general requirements for decommissioning nuclear power plants.i31 When the decommissioning regulations were adopted- in 1988, it was assumed that the majority of licensees would decommission at the end of the operating license life. Since that time, several licensees permanently and prematurely ceased operations without having submitted a decommissioning plan. In addition, these licensees requested exemptions from certain operating requirements as being unnecessary once the reactor is defueled. Each case was handled individually without clearly defined generic requirements. The NRC amended the decommissioning regulations in 1996 to clarify ambiguities and codify procedures and terminology as a means of enhancing efficiency and uniformity in the decommissioning process. The new amendments allow for TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

17 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 1, Page 4 of 7 greater public participation and better define the transition process from operations to decommissioning.

Under the revised regulations, licensees would submit written certification to the NRC within 30 days after the decision to cease operations. Certification would also be required once the fuel was permanently removed from the reactor vessel. Submittal of these notices would entitle the licensee to a fee reduction and eliminate the obligation to follow certain requirements needed only during operation of the reactor. Within two years of submitting notice of permanent cessation of operations, the licensee would be required to submit a Post-Shutdown Decommissioning Activities Report (PSDAR) to the NRC. The PSDAR describes the planned decommissioning activities, the associated sequence and schedule, and an estimate of expected costs. Prior to completing decommissioning, the licensee would be required to submit an application to the NRC to terminate the license, along with a license termination plan (LTP).

1.3.1 Nuclear Waste Policy Act Congress passed the Nuclear Waste Policy Act[4] in 1982, assigning the responsibility for disposal of spent nuclear fuel from the commercial nuclear generating plants to the Department of Energy (DOE). Two permanent disposal facilities were envisioned, as well as an interim facility. To recover the cost of permanent spent fuel disposal, this legislation created a Nuclear Waste Fund through which money was to be collected from the consumers of the electricity generated by commercial nuclear power plants. The Nuclear Waste Policy Act, along with the individual disposal contracts with utilities, specified that the DOE was to begin accepting spent fuel by January 31, 1998.

After pursuing a national site selection process, the Act was amended in 1987 to designate Yucca Mountain, Nevada, as the only site to be evaluated for geologic disposal of high-level waste. Also in 1987, the DOE announced a five-year delay in the opening date for the repository, from 1998 to 2003. Two years later, in 1989, an additional 7-year delay was announced, primarily due to problems in obtaining the required permits from the state of Nevada to perform the required characterization of the site.

Generators have responded to this impasse by initiating legal action and constructing supplemental storage as a means of maintaining necessary operating margins. In a recent decision, the U.S. Court of Appeals for the Federal Circuit reaffirmed the utility position that TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

18 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 1, Page 5 of 7 DOE had breached its contractual obligation. However, even with the August 2000 ruling,[15 DOE's position has remained unchanged. The agency continues to maintain that its delayed performance is unavoidable because it does not have an operational repository and does not have authority to provide storage in the interim.

Consequently, DOE has no plans to receive spent fuel from commercial U.S. reactors before the year 2010.

The NRC requires licensees to establish a program to manage and provide funding for the management of all irradiated fuel at the reactor until title of the fuel is transferred to the Secretary of Energy in 10 CFR 50.54 (bb).J6] This funding requirement is fulfilled through inclusion of certain high-level waste cost elements within the estimates, as described below.

For estimating purposes, PSEG Nuclear has assumed that the high-level waste repository, or some interim storage facility, will be fully operational by 2015. Interim storage of the fuel, until the DOE has completed the transfer, will be in an independent facility located on the Artificial Island site. This will allow PSEG Nuclear to proceed with decommissioning and terminate its operating licenses in the shortest time possible.

Based upon the projected capacity of the spent fuel storage pools, supplemental storage will be required before the current operating licenses expire so as to maintain full core off-load capability. Therefore, this analysis assumes that an on-site independent spent fuel storage installation (ISFSI) will be constructed to support plant operations and will be available to support decommissioning The spent fuel storage facility, which is independently licensed and operated, will be sized to accommodate the inventory of spent fuel residing in the plant's storage pools at the cessation of operations, in addition to any operational inventory already in residence. When emptied, the station could be dismantled without maintaining the wet storage pools. Based upon this scenario, and an anticipated rate of transfer, spent fuel is projected to remain on site for approximately 30 years following the cessation of Unit 1 operations.

Expenditures are included in the analysis for the isolation and continued operation of the spent fuel pools throughout the first five years of decommissioning. Expenses are also included for loading the spent fuel assemblies remaining in the storage pools after the TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

19 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 1, Page 6 of 7 cessation of plant operations into multi-purpose canisters, for canister costs and overpacks, and for the operation of the ISFSI through the year 2046, when all the fuel is expected to be transferred to the DOE.

1.3.2 Low-Level Radioactive Waste Policy Amendments Act Congress passed the "Low-Level Radioactive Waste Disposal Act" in 1980, declaring the states as being ultimately responsible for the disposition of low-level radioactive waste generated within their own borders. The federal law encouraged the formation of regional groups or compacts to implement this objective safely, efficiently and economically, and set a target date of 1986. With little progress, the "Amendments Act" of 19857 extended the target, with specific milestones and stiff sanctions for non-compliance.

New Jersey is a member of the three-state Atlantic Interstate Low-Level Radio.active Waste Management Compact, formed after South Carolina formally joined the Northeast Regional Compact. The Barnwell Low-Level Radioactive Waste Management Facility, located in South Carolina, is expected to be available to PSEG Nuclear to support the decommissioning of the Salem Station. It is also assumed that PSEG Nuclear could access other disposal sites should it prove cost-effective.

As such, rate schedules for both the Barnwell and the Envirocare facility in Utah were used to generate disposal costs.

1.3.3 Radiological Criteria for License Termination In 1997, the NRC published Subpart E, "Radiological Criteria for 8 ] amending Part 20 of Title 10 of the Code of License Termination,"[

Federal Regulations (10 CFR §20). This subpart provided radiological criteria for releasing a facility for unrestricted use. The regulation provides that the site could be released for unrestricted use if radioactivity levels- are such that the average member of a critical group would not receive a Total Effective Dose Equivalent (TEDE) in excess of 25 millirem per year, and provided residual radioactivity has been reduced to levels that are As Low As Reasonably Achievable (ALARA). The decommissioning estimate for the Salem Station assumes that the site will be remediated to a residual level consistent with the NRC-prescribed level.

It should be noted that the NRC and the Environmental Protection Agency (EPA) differ on the amount of residual radioactivity considered acceptable in site remediation. The EPA has two limits TLG Servicesý, Inc. Copyright PSEG Nuclear 1999/2000

20 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Section 1, Page 7 of 7 that apply to radioactive materials. An EPA limit of 15 millirem per year is derived from criteria established by the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or Superfund). An additional limit of 4 millirem per year, as defined in 40 CFR Part 141.16, is applied to drinking water.

On October 9, 2002, the NRC signed an agreement with the EPA on the radiological decommissioning and decontamination of NRC-licensed sites. The Memorandum of Understanding (MOU) provides that EPA will defer exercise of authority under CERCLA for the majority of facilities decommissioned under NRC authority. The MOLT also includes provisions for NRC and EPA consultation for certain sites when, at the time of license termination, (1) groundwater contamination exceeds EPA-permitted levels; (2) NRC contemplates restricted release of the site; and/or (3) residual radioactive soil concentrations exceed levels defined in the MOU.

The MOU does not impose any new requirements on NRC licensees and should reduce the involvement of EPA with NRC licensees who are decommissioning. Most sites are expected to meet the NRC criteria for unrestricted use, and the NRC believes that only a few sites winl have groundwater or soil contamination in excess of the levels specified in the MOU that trigger consultation with EPA. However, if there are other hazardous materials on the site, EPA may be involved in the cleanup. As such, the possibility of dual regulation remains for certain licensees.

TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

21 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 2, Page I of 8

2. DECOMMISSIONING ALTERNATIVE The following section describes the basic activities associated with the DECON decommissioning alternative. Although detailed procedures for each activity identified are not provided, and the actual sequence of work may vary, the activity descriptions provide a basis not only for estimating, but also for the expected scope of work, i.e.,

engineering and planning at the time of decommissioning.

The conceptual approach that the NRC has described in its regulations divides decommissioning into three phases. The initial phase commences with the effective date of permanent cessation of operations and involves the transition of both plant:and licensee from reactor operations, i.e., power production, to facility de-activation and closure. During the first phase, notification is to be provided to the NRC certifying the permanent cessation of operations and the removal of fuel from the reactor vessel. The licensee would then be prohibited from reactor operation.

The second phase encompasses activities during the storage period or during major decommissioning activities, or a combination of the two. The third phase pertains to the activities involved in license termination. The decommissioning estimates developed for the Salem Station are also divided into phases or periods; however, demarcation of the phases is based upon major milestones within the project or significant changes in the projected expenditures.

2.1 PERIOD 1 - PREPARATIONS In anticipation of the cessation of plant operations, detailed preparations are undertaken to provide a smooth transition from plant operations to site decommissioning. Through implementation of a staffing transition plan, the organization required to manage the intended decommissioning activities is assembled from available plant staff and outside resources. Preparations include the planning for permanent defueling of the reactor, revision of technical specifications applicable to the operating conditions and requirements, a characterization of the facility and major components, and the development of the PSDAR.

2.1.1 Engineering and Planning The PSDAR, required within two years of the notice to cease operations, provides a description of the licensee's planned decommissioning activities, a timetable, and the associated financial requirements of the intended decommissioning program. Upon receipt of the PSDAR, the NRC will make the document available to the public for comment in a TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

DocumentSection P07-1425-003, 22 Salem GeneratingCost Decommissioning Station Analysis 2, PageRev.

2 of 80 local hearing to be held in the vicinity of the reactor site. Ninety days following submittal and NRC receipt of the PSDAR, the licensee may begin to perform major decommissioning activities under a modified 10 CFR §50.59 procedure, i.e., without specific NRC approval. Major activities are defined as any activity that results in permanent removal of major radioactive components, permanently modifies the structure of the containment, or results in dismantling components (for shipment) containing Greater-than-Class C waste (GTCC), as defined by 10 CFR

§61. Major components are further defined as comprising the reactor vessel and internals, large bore reactor system piping, and other large components that are radioactive. The NRC includes the following additional criteria for use of the §50.59 process in decommissioning. The proposed activity must not:

• foreclose release of the site for possible unrestricted use,

• significantly increase decommissioning costs,

• cause any significant environmental impact, or

" violate the terms of the licensee's existing license.

Existing operational technical specifications are reviewed and modified to reflect plant conditions and the safety concerns associated with permanent cessation of operations. The environmental impact associated with the planned decommissioning activities is also considered.

Typically, a licensee will not be allowed to proceed if the consequences of a particular decommissioning activity are greater than bounded by previously evaluated environmental assessments or impact statements.

In this instance, the licensee would have to submit a license amendment for the specific activity and update the environmental report.

The decommissioning program outlined in the PSDAR will be designed to accomplish the required tasks within the ALARA guidelines (as defined in 10 CFR §20) for protection of personnel from exposure to radiation hazards. It will also address the continued protection of the health and safety of the public and the environment during the dismantling activity.

Consequently, in conjunction with the development of the PSDAR, activity specifications, cost-benefit and safety analyses, work packages and procedures must be assembled in support of the proposed decontamination and dismantling activities.

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23 Salem Generating Station Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 2, Page 3 of 8 2.1.2 Site Preparations Following final plant shutdown, and in preparation for actual decommissioning activities, the following activities are initiated:

" Characterization of the site and surrounding environs. This includes radiation surveys of work areas, major components (including the reactor vessel and its internals), sampling of internal piping contamination levels, and primary shield cores.

" Isolation of the spent fuel storage pooi and fuel handling systems, such that decommissioning operations could commence on the balance of the plant. Decommissioning operations are scheduled around the fuel handling area to the greatest extent possible such that the overall project schedule is optimized- The fuel will be transferred to the. DOE as it decays to the point that it meets the heat load criteria of the containers and, as such, it is assumed that the fuel pool will remain operational for a minimum of five years following the cessation of plant operations.

" Specification of transport and disposal requirements for activated materials and/or hazardous materials, including shielding and waste stabilization.

• Development of procedures for occupational exposure control, control and release of liquid and gaseous effluent, processing of radwaste (including dry-active waste, resins, filter media, mnetallic and non-metallic components generated in decommissioning), site security and emergency programs, and industrial safety.

2.2 PERIOD 2 - DECOMMISSIONING OPERATIONS Significant decommissioning activities in this phase include:

" Construction of temporary facilities and/or modification of existing facilities to support dismantling activities. This may include a centralized processing area to facilitate equipment removal and component preparations for off-site disposal.

• Reconfiguration and modification of site structures and facilities as needed to support decommissioning operations. This may include the upgrading of roads (on- and off-site) to facilitate hauling and transport. Building TLG Services,Inc. TLG ervies, nc.Copyright PSEG Nuclear 1999/2000

24 Salem Generating Station Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 2, Page 4 of 8 modifications may be required to the Reactor Building to facilitate access of large/heavy equipment. Modifications may also be required to the refueling area of the Reactor Building to support the segmentation of the reactor vessel internals and component extraction.

" Design and fabrication of temporary and permanent shielding to support removal and transportation activities, construction of contamination control envelopes, and the procurement of specialty tooling.

" Procurement (lease or purchase) of shipping canisters, cask liners, and industrial packages.

" Decontamination of components and piping systems as required to control (minimize) worker exposure.

" Removal of piping and components no longer essential to support decommissioning operations.

• Removal of control rod drive housings and the head service structure from reactor vessel head. Segmentation of the vessel closure head.

• Removal and segmentation of the upper internals assemblies. Segmentation will maximize the loading of the shielded transport casks, i.e., by weight and activity. The operations are conducted under water using remotely operated tooling and contamination controls.

" Disassembly and. segmentation of the remaining reactor internals, including core former and lower core support assembly. Some material is Qxpected to exceed 'Class C disposal requirements. As such, the segments will be packaged in a modified fuel canister for geologic disposal.

" Segmentation of the reactor vessel. Install shielded platform for segmentation of reactor vessel. Cutting operations are performed in-air using remotely operated equipment within a contamination control envelope, with the water level maintained just below the cut to minimize the working area dose rates. Segments are transferred in-air to containers that are stored under water, for example, in an isolated area of the refueling canal.

" Removal of thae activated portions of the concrete biological shield and accessible contaminated concrete surfaces. If dictated by the steam generator and pressurizer removal scenarios, those portions of the TLG Services, Inc. PSEG Nuclear 1999/2000 TLG ervies, nc.Copyright

25i Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 2, Page 5 of 8 associated cubicles necessary for access and component extraction are removed.

0 Removal of the steam generators and pressurizer for controlled disposal.

Decontaminate exterior surfaces, as required, and seal-weld openings (nozzles, inspection hatches, and other penetrations). These components can serve as their own burial containers provided that all penetrations are properly sealed and the internal contaminants are stabilized. Steel shields are added to those external areas of the steam generators necessary in order to meet transportation limits and regulations.

At least two years prior to the anticipated date of license termination, a LTP is required. Submitted as a supplement to the Final Safety Analysis Report (FSAR), or equivalent, the plan must include: a site characterization, description of the remaining dismantling activities, plans for site remediation, procedures for the final radiation survey, designation of the end use of the. site, an updated cost estimate to complete the decommissioning, and any associated environmental concerns. 'The NRC will notice the receipt of the plan, make the plan available for public comment, and schedule a local hearing. LTP approval will be subject to any conditions and limitations as deemed appropriate by the Commission. The licensee may then commence with the final remediation of site facilities and services, including:

" Removal of remaining plant systems and associated components as they become nonessential to the decommissioning program or worker health and safety (e.g., waste collection and treatment systems, electrical power and ventilation systems).

" Removal of the steel liners from refueling canal, disposing of the activated and contaminated sections as radioactive waste. Removal of any activated/contaminated concrete.

• Surveys of the decontaminated areas of the containment structure.

" Removal of the contaminated equipment and material from the Auxiliary and Fuel Handling Building and any other contaminated facility. Radiation and contamination control techniques are used until radiation surveys indicate that the structures could be released for unrestricted access and conventional demolition. This activity may necessitate the dismantling and disposition of most of the systems and components (both clean and contaminated) located within these buildings. This activity will facilitate TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

26 Salem Generating Station Document PO7-1425-003, Rev. 0 DecommissioningCost Analysis Section 2, Page 6 of 8 surface decontamination and subsequent verification surveys required prior to obtaining release for demolition.

• Removal of the remaining components, equipment, and plant services in support of the area release survey(s).

" Routing of material removed in the decontamination and dismantling to a central processing area. Material certified to be free of contamination would be released for unrestricted disposition, e.g., as scrap, recycle, or general disposal. Contaminated material will be characterized and segregated for additional off-site processing (disassembly, chemical cleaning, volume reduction, and waste treatment), and/or packaged for controlled disposal at a low-level radioactive waste disposal facility.

Incorporated into the LTP is the Final Survey Plan. This plan identifies the radiological surveys to be performed once the decontamination activities. are completed and is developed using the guidance provided in NUREG/CR-1575, "Multi-Agency Radiation Survey and Site Investigation Manual" (MARSSIM).[9]

This document incorporates the statistical approaches to survey design and data interpretation used by the EPA. It also identifies state-of-the-art, commercially available, instrumentation and procedures for conducting radiological surveys. Use of this guidance ensures that the surveys are conducted in a manner that provides a high degree of confidence that applicable NRC criteria are satisfied. Once the survey is complete, the results are provided to the NRC in a format that can be verified- The NRC then reviews and evaluates the information, performs an independent confirmation of radiological site conditions, and makes a determination on final termination of the license.

The NRC will terminate the operating license if it determines that site remediation has been performed in accordance with the LTP, and that the terminal radiation survey and associated documentation demonstrate that the facility is suitable for release.

2.3 PERIOD 3 - SITE RESTORATION Following completion of decommissioning operations, site restoration activities may begin. Efficient removal of the contaminated materials .and verification that residual radionuclide concentrations are below the NRC limits may result in substantial damage to many of the structures. Although performed in a controlled and safe manner, blasting, coring, drilling, scarification (surface removal), and the other decontamination activities will substantially degrade TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

217 Salem GeneratingStation Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 2, Page 7 of 8 power block structures, including the Reactor, Auxiliary, and Fuel Handling Buildings. Verifying that subsurface radionuclide concentrations meet NRC site release requirements may require removal of grade slabs and lower floors, potentially weakening footings and structural supports. This removal activity will be necessary for those facilities and plant areas where historical records, when available, indicate the potential for radionuclides having been present in the soil, where system failures have been recorded, or where it is required to confirm that subsurface process and drain lines were not breached over the operating life of the station.

Prompt dismantling of site structures is clearly the most appropriate and cost-effective option. It is unreasonable to anticipate that these structures would be repaired and preserved after the radiological contamination is removed. The cost to dismantle site structures with a work force already mobilized on site is more efficient than if the process is deferred. Site facilities quickly degrade without maintenance, adding additional expense and creating potential hazards to the public and future workers. Abandonment creates a breeding ground for vermin infestation and other biological hazards.

This cost study presumes that non-essential structures and site facilities will be dismantled as a continuation of the decommissioning activity. Foundations and exterior walls are removed to a nominal depth of three feet below grade. The three-foot depth allows for the placement of gravel for drainage, and topsoil so that vegetation can be established for erosion control. Site areas affected by the dismantling activities are restored and the plant area graded as required to prevent ponding and inhibit the refloating of subsurface materials.

Concrete rubble produced by demolition activities will processed to remove rebar and miscellaneous embedments. The processed material will then be used on-site to backfill voids. Excess materials are trucked off-site for disposal as construction debris.

2.4 POST PERIOD 3 - ISFSI OPERATIONS The ISFSI will continue to operate under a separate and independent license (10 CFR §72) following the relocation of the spent fuel from the plant's storage pools. Transfer of spent fuel to a DOE or interim facility will be exclusively from the ISFSI once the fuel pools have been emptied and the structures released for decommissioning. Assuming initiation of the federal Waste Management System in 2015, transfer of spent fuel from Salem Station is anticipated to continue through the year 2046. Any delay in the transfer process, for example, due to a delay in the scheduled opening of the geologic repository, a slower acceptance rate, or a combination of a delayed start date and lower transfer TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

28 Salem GeneratingStation Document PO7-1425-003,Rev. 0 DecommissioningCost Analysis Section 2, Page 8 of 8 rate, will result in a longer on-site residence time for the fuel discharge from the reactor and therefore additional caretaking expenses.

At the conclusion of the spent fuel transfer process, the ISFSI will be decommissioned. The Commission will terminate the §72 license if it determines that the remediation of the ISFSI has been performed in accordance with an ISFSI license termination plan and that the final radiation survey and associated documentation demonstrate that the facility is suitable for release.

Once the requirements are satisfied, the NRC can terminate the license for the ISFSI.

The currently proposed design for the ISFSI is based upon the use of concrete overpacks for pad storage. For purposes of this cost analysis, it is as&umed that once the inner canisters containing the spent fuel assemblies have been removed and the license for the facility terminated, the modules could be dismantled using conventional techniques for the demolition of reinforced concrete. The concrete storage pad will then be removed, and the area graded and landscaped to conform to the surrounding environment.

TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem GeneratingStation 29 Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page I of 19

3. COST ESTIMATE The cost estimates prepared for decommissioning the Salem Station consider the unique features of the site, including the nuclear steam supply system, power generation systems, support services, site buildings, and ancillary facilities. The bases of the estimates, including the sources of information relied upon, the estimating methodology employed, site-specific considerations and other pertinent assumptions are described in this section.

3.1 BASIS OF ESTIMATE The current estimates were developed using the basic design information originally generated for the decommissioning analysis prepared in 1995-96.1101 The information was reviewed for the current estimate and updated, as deemed necessary. The site-specific considerations and assumptions used in the previous estimate were also revisited. Modifications were incorporated where new information was available or experience from ongoing decommissioning programs provided viable alternatives or improved processes.

3.2 METHODOLOGY The methodology used to develop this cost estimate follows the basic approach originally presented in the AIF/NESP-036 study report, "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates,"["] and the US DOE "Decommissioning Handbook."(121 These documents present a unit factor method for estimating decommissioning activity costs, which simplifies the estimating calculations. Unit factors for concrete removal ($/cubic yard), steel removal (S/ton), and cutting costs ($/inch) were developed using local labor rates. The activity-dependent costs were estimated with the item quantities (cubic yards and tons), developed from plant drawings and inventory documents. Removal rates and material costs for the conventional disposition of components and structures relied upon information available in the industry publication, "Building Construction Cost Data,"

published by R.S. Means.(13]

This estimate reflects lessons learned from TLG's involvement in the Shippingport Station Decommissioning Project, completed in 1989, as well as the decommissioning of the Cintichem reactor, hot cells and associated facilities, completed in 1997. In addition, the planning and engineering for the Pathfinder, Shoreham, Rancho Seco, Trojan, Yankee Rowe, Big Rock Point, Maine Yankee, Humboldt Bay-3, Oyster Creek, Connecticut Yankee, and San Onofre-1 nuclear units has provided additional insight into the process, the TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

30 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page2 of 19 regulatory aspects, and technical challenges of decommissioning commercial nuclear units.

The unit factor method provides a demonstrable basis for establishing reliable cost estimates. The detail provided in the unit factors, including activity duration, labor costs (by craft), and equipment and consumable costs, ensures that essential elements have not been omitted. Appendix A presents the detailed development of a typical unit factor. Appendix B provides the values contained within one set of factors developed for this analysis.

Work Difficulty Factors TLG has historically applied work difficulty adjustment factors (WDFs) to account for the inefficiencies in working in a power plant environment.

WDFs were assigned to each unique set of unit factors, commensurate with the inefficiencies associated with working in confined, hazardous environments.

The ranges used for the WDFs are as follows:

• Access Factor 10% to 20%

• Respiratory Protection Factor 10% to 50%

• RadiationlALARA Factor 10% to 37%

• Protective Clothing Factor 10% to 30%

• Work Break Factor 8.33%

• Productivity adjustable The factors and their associated range of values were developed in conjunction with the AIF/NESP-036 study. The application of the factors is discussed in more detail in that publication.

Scheduling Program Durations The unit factors, adjusted by the WTDFs as described above, are applied against the inventory of materials-to be removed in the radiologically controlled areas.

The resulting man-hours, or crew-hours, are used in the development of the decommissioning. program schedule, using resource loading and event sequencing considerations. The scheduling of conventional removal and dismantling activities relied upon productivity information available from the "Building Construction Cost Data" publication.

An activity duration critical path is used to determine the total decommissioning program schedule. The schedule is relied upon in calculating the carrying costs, which include program management, administration, field TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 3 of 19 engineering, equipment rental, and support services such as quality control and security. This systematic approach for assembling decommissioning estimates ensures a high degree of confidence in the reliability of the resulting costs.

3.3 FINANCIAL COMPONENTS OF THE COST MODEL TLG's proprietary decommissioning cost model, DECCER, produces a number of distinct cost elements. These direct expenditures, however, do not comprise the total cost to accomplish the project goal, i.e., license termination and site restoration.

Inherent in any cost estimate that does not rely on historical data is the inability to specify the precise source of costs imposed by factors Si6ch as tool breakage, accidents, illnesses, weather delays, and labor stoppages. In TLG's DECCER cost model, contingency fulfills this role. Contingency is added to each line item to account for costs that are difficult or impossible to develop analytically. Such costs are historically inevitable over the duration of a job of this magnitude; therefore, this cost analysis includes funds to cover these types of expenses.

3.3.1 Contingency The activity- and period-dependent costs are combined to develop the total decommissioning cost. A contingency is then applied on a line-item basis, using one or more of the contingency types listed in the AIF/NESP-036 study. "Contingencies" are defined in the American Association of Cost Engineers "Project and Cost Engineers' Handbook"[14J as "specific provision for unforeseeable elements of cost within the defined, project scope; particularly important where previous experience relating estimates and actual costs has shown that unforeseeable events which will increase costs are likely to occur." The cost elements in this estimate are based upon ideal conditions and maximum efficiency; therefore, consistent with industry practice, a contingency factor has been applied.

In the AIF/NESP-036 study, the types of unforeseeable events that are likely to occur in decommissioning are' discussed and guidelines are provided for percentage contingency in each category. It should be noted that contingency, as used in this estimate, does not account for price escalation and inflation in the cost of decommissioning over the remaining operating life of the station.

The use and role of contingency within decommissioning estimates is not a "safety factor issue." Safety factors provide additional security and address situations that may never occur. Contingency funds are TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

2 Salem GeneratingStation Document P07-1425-003,Rev.*

DecommissioningCost Analysis Section 3, Page4 of 19 expected to be fully expended throughout the program. They also provide assurance that sufficient funding is available to accomplish the intended tasks. An estimate without contingency, or from which contingency has been removed, could disrupt the orderly progression of events and jeopardize a successful conclusion to the decommissioning process.

For example, the most technologically challenging task in decommissioning a commercial nuclear station will be the disposition of the reactor vessel and internal components, which have become highly radioactive after a lifetime of exposure to radiation produced in the core. The disposition of these highly radioactive components forms the basis for the critical path (schedule) for decommissioning operations. Cost and schedule are inter-dependent and any deviation in schedule has a significant impact on cost for performing a specific activity.

Disposition of the reactor vessel internals involves the underwater cutting of complex components that are highly radioactive. Costs are based upon optimum segmentation, handling, and packaging scenarios. The schedule is primarily dependent upon the turnaround time for the heavily shielded shipping casks, including preparation, loading, and decontamination of the containers for transport. The number of casks required is a function of the pieces generated in the segmentation activity, a value calculated on optimum performance of the tooling employed in cutting the various subassemblies. The risk and uncertainties associated with this task are that the expected optimization may not be achieved, resulting in delays and additional program costs. For this reason, contingency must be included to mitigate the consequences of the expected inefficiencies inherent in this complex activity, along with related concerns associated with the operation of highly specialized tooling, field conditions, and water clarity.

Contingency funds are an integral part of the total cost to complete the decommissioning process. Exclusion of this component puts at risk a successful completion of the intended tasks and, potentially, subsequent related activities. For this study, TLG examined the major activity-related problems (decontamination, segmentation, equipment handling, packaging, transport, and waste disposal) that necessitate a contingency. Individual activity contingencies can range from 0% to 75%, depending on the degree of difficulty judged to be appropriate TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

33 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 5 of 19 from TLG's actual decommissioning experience. The contingency values used in this study are as follows:

Decontamination 50%

Contaminated Component Removal 25%

Contaminated Component Packaging 10%

Contaminated Component Transport 15%

Low-Level Radioactive Waste Disposal 25%

Reactor Segmentation 75%

NSSS Component Removal 25%

Reactor Waste Packaging 25%

Reactor Waste Transport 25%

Reactor Vessel Component Disposal 50%

GTCC Disposal 15%

Non-Radioactive Component Removal 15%

Heavy Equipment and Tooling 15%

Supplies 25%

Engineering 15%

Energy 15%

Characterization and Termination Surveys 30%

Construction 15%

Taxes and Fees 10%

Insurance 10%

Staffing 15%

The overall contingency, when applied to the appropriate components of the estimates on a line item basis, results in an average value of 18.3%.

3.3.2 Financial Risk In addition. to the routine uncertainties addressed by contingency, another cost element that is sometimes necessary to consider when bounding decommissioning costs relates to uncertainty, or risk.

Examples can include changes in work scope, pricing, job performance, and other variations that could conceivably, but not necessarily, occur.

Consideration is sometimes necessary to generate a level of confidence in the estimate, within a range of probabilities. TLG considers these types of costs under the broad term "financial risk." Included within the category of financial risk are:

TLO Services, Inc. Copyright PSEG Nuclear 1999/2000

34 Salem Generating Station Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 3, Page 6 of 19 0Transition activities and costs: ancillary expenses associated with eliminating 50% to 80% of the site labor force shortly after the cessation of plant operations, added cost for worker separation packages throughout the decommissioning program, national or company-mandated retraining, and retention incentives for key personnel.

a Delays in approval of the decommissioning plan dlue to intervention, public participation in local community meetings, legal challenges, and national and local hearings.

• Changes in the project work scope from the baseline estimate, involving the discovery of unexpected levels of contaminants, contamination in places not previously expected, contaminated soil previously undiscovered (either radioactive or hazardous material contamination), variations in plant inventory or configuration not indicated by the as-built drawings.

e Regulatory changes, e.g., affecting worker health and safety, -site release criteria, waste transportation, and disposal.

Policy decisions altering national commitments, e.g., in the ability to accommodate certain waste forms for disposition, or in the timetable for such.

• Pricing changes for basic inputs, such as labor, ener gy, materials, and burial. Some of these inputs may vary slightly, e.g. - 10% to

+ý20%; burial could vary from -50% to +200% or more.

It has been TLG's experience that the results of a risk analysis, when compared with the base case estimate for decommissioning, indicate that the chances of the base decommissioning estimate's being too high is a low probability, and the chances that the estimate is too low is a much higher probability. This is mostly due to the pricing uncertainty for low-level radioactive waste burial, and to a lesser extent due to schedule increases from changes in plant conditions and to pricing variations in the cost of labor (both craft and staff).- This cost study, however, does not add any additional costs to the estimate for financial risk since there is insufficient historical data from which to project future liabilities. Consequently, it is recommended that the areas of TLG Services,Inc. PSEG Nuclear 1999/2000 TLG ervies, nc.Copyright

Salem GeneratingStation Document P07-1425-003, Rev. 0 DecommissioningCost Analysis Section 3, Page 7 of 19 uncertainty or risk be revisited periodically and addressed through repeated revisions or updates of the base estimate.

3.4 SITE-SPECIFIC CONSIDERATIONS There are a number of site-specific considerations that affect the method for dismantling and removal of equipment from the site and the degree of restoration required. The cost impact of the considerations identified below is included in this cost study.

3.4.1 Spent Fuel The cost to dispose of the spent fuel generated from plant operations is not reflected within the estimate to decommission the Salem Station.

Ultimate disposition of the spent fuel is within the province of the DOE's Waste Management System, as defined by the Nuclear Waste Policy Act.

As such, the disposal cost is financed by a 1 mifllkWhr surcharge paid into the DOE's waste fund during operations. However, the NRC requires licensees to establish a program to manage and provide funding for the management of all irradiated fuel at the reactor until title of the fuel is transferred to the Secretary of Energy. This funding requirement is fulfilled thr6ugh inclusion of certain high-level waste cost elements within the estimates, as described herein.

The total inventory of assemblies that will need to be handled during decommissioning is based upon several assumptions. The pickup of commercial fuel is assumed to begin in the year 2015 and will proceed on an oldest fuel first basis. The rate at which the fuel is removed from the commercial sites is based upon an annual capacity at the geologic repository of 3,000 metric tonnes. A delay in the startup of the repository, or a decrease in the rate of acceptance rate, will correspondingly prolong the transfer process and extend the duration that the fuel remains at the site.

For estimating purposes, spent fuel will be removed from the Salem Station site beginning in the year 2020, with the transfer complete by the end of year 2046. Built to support continuing plant operations, an ISFSI will be available to support decommissioning, i.e., the fuel residing in the pools following the cessation of plant operations could be relocated to the ISFSI so that decommissioning can proceed on the Fuel Handling Buildings. The assemblies will be relocated to the ISFSI during the first five years following final shutdown. Costs are included for the purchase MLG Services, Inc. CopyrightPSEG Nuclear1999/2000

Salem Generating Station Document P07-1425-003, Rev- 6)

Decommissioning Cost-Analysis Section 3, Page 8 of 19 of the 94 canisters and overpacks required to empty the 'pool (an additional eight will be used to package the GTCC).

Operation and maintenance costs for the ISFSI are included within the estimates and address the cost for staffing the facility, security, insurance, and licensing fees. Costs are also provided for the final disposition of the facility once the transfer is complete.

ISFSI Design Considerations A multi-purpose (storage and transport) dry shielded storage canister with a vertical, reinforced concrete storage silo is used as a basis for the cost analyses. Approximately 50% of the silos are assumed to have some level of neutron-induced activation as a result of the long-term storage of the fuel, ihe., to levels exceeding free-release limits. Approximately 10%

of the concrete and steel is assumed to be removed from the overpacks for controlled disposal. The cost of the disposition of this material, as well as the demolition o4 the ISFSI facility, is included in the estimate.

3.4.2 Reactor Vessel and Internal Components The NSSS (reactor vessel and reactor coolant system components) will be decontaminated using chemical agents prior to the start of cutting operations. A decontamination factor (average reduction) of 10 is presumed.

The reactor pressure vessel and internal components are segmented for' disposal in shielded, reusable transportation casks. Segmentation will be performed in the refueling canal, where a turntable and remote cutter are installed. The vessel will be segmented in place, using a mast-mounted cutter supported off the lower head and directed from a shielded work platform installed overhead in the reactor cavity.

Transportation cask specifications and transportation regulations will dictate segmentation and packaging methodology.

The dismantling of the reactor internals will generate radioactive waste considered unsuitable for shallow land disposal, i.e., GTCC. Although the material is not classified as high-level waste, DOE ha9 indicated it will accept title to this waste for disposal at the future high-level waste repository.J151 However, the DOE has not been forthcoming with an acceptance criteria or disposition schedule for this material, and numerous questions remain as to the ultimate disposal cost and waste form requirements. As such, for purposes of this study, the GTCC has TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

37 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 9 of 19 been packaged and disposed of as high-level waste, at a cost equivalent to that envisioned for the spent fuel. It is not anticipated that DOE would accept this waste prior to completing the transfer of spent fuel.

Therefore, until such time as the DOE is ready to accept GTCC waste, it is reasonable to assume that this material would remain in storage at Salem Station.

Intact disposal of the reactor vessel and internal components could provide savings in cost and worker exposure by eliminating the complex segmentation requirements, isolation of the GTCC material, and transport/storage of the resulting waste packages. Portland General Electric (PGE) was able to dispose of the Trojan reactor as an intact package. However, the location of the Trojan Nuclear Plant on the Columbia River simplified the transportation analysis since:

• the reactor package could be secured to the transport vehicle for the.

entire journey, i.e., the package was not lifted during transport,

" there were no man-made or natural terrain features between the plant site and the disposal location that could produce a large drop, and

" transport speeds were very low, limited by the overland transport vehicle and the river barge.

As a member of the Northwest Compact, PGE had a site available for disposal of the package, the US Ecology facility in Washington State.

The characteristics of this arid site proved favorable in demonstrating compliance with land disposal regulations.

It is not known whether this option will be available when the Salem Station ceases operation. Future viability of this option will depend upon the ultimate location of the disposal site, as well as the disposal site licensee's ability to accept highly radioactive packages and effectively isolate them from the environment. Consequently, as a bounding condition, the study assumes the reactor vessel will have to be segmented.

TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

38 Salem Generating Station DocumentP07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 3, Page 10 of 19 3.4.3 Primary System Components The following discussion deals with the removal and disposition of the steam generators, but the techniques involved are also applicable to other large components, such as heat exchangers, component coolers and the pressurizer. The steam generators' size, weight, and location within the Reactor Building will ultimately determine the removal strategy.

A potential method for removal (and the one used as the basis in this estimate) is the extraction of the generators through the existing equipment hatch. Sections of the steam generator cubicle walls, adjoining floor slabs, and floor grating may need to be removed to allow for the generators to be maneuvered to the hatch.

Grating within the work area will be decontaminated and removed.

Next, a trolley crane will be set up for removal of the generators. By setting the trolley crane first, it can be used to move portions of the steam generator cubicle walls and floor slabs from the Reactor Building to a location where they can be decontaminated and transported to the material handling area.

The generators will be rigged for removal, disconnected from the surrounding piping and supports, and maneuvered into the open area where they will be lowered onto a dolly. Once each steam generator has been placed in the horizontal position, nozzles and other openings will be welded closed. The lower shell will have a carbon steel membrane welded to its outside surface for shielding, if. required, during transport. The interior volume will be filled with low-density cellular concrete for stabilization of the internal contamination and to satisfy burial ground packaging requirements. When this stage has been completed, each generator will be moved out of containment and lowered onto a multi-wheeled transporter. The generators will be staged at an on-site storage area to await transport to the disposal facility. The pressurizer will be removed using the same technique.

Each component will then be loaded onto a barge for transport to the disposal facility.

Reactor coolant piping will be cut from the reactor vessel once the water level in the vessel (used for personnel shielding during dismantling and cutting operations in and around the vessel) drops below the nozzle zone.

The piping will be boxed and transported by shielded van. The reactor TMG Services, Inc. CopyrightPSEG Nuclear 1999/2000

39 Salem GeneratingStation Document PO7-1425-003, Rev. 0 DecommissioningCost Analysis Section 3, Page 11 of 19 coolant pumps and motors will be lifted out intact, packaged, and transported for disposal.

3.4.4 Main Turbine and Condenser The main turbine will be dismantled using conventional maintenance procedures. The turbine rotors and shafts will be removed to a laydown area. The lower turbine casings will be removed from their anchors by controlled demolition. The main condenser will also be disassembled and moved to a laydown area. Material will then be prepared for transportation to an off-site recycling facility where it will be surveyed and designated for decontamination, volume reduction,. or conventional disposal. Components will be packaged and readied for transport in accordance with the intended disposition.

3.4.5 Transportation Methods Contaminated piping, components, and structural material other than the highly activated reactor vessel and internal components will qualify as LSA-I, II or III or Surface Contaminated Object, SCO-I or II, as described in Title 49 of the Code of Federal Regulations.[161 The contaminated material will be packaged in Industrial Packages' (IP I, 11, or III) for transport unless demonstrated to qualify as their own shipping containers. The reactor vessel and internal components are expected to be transported in accordance with §71, as Type B. It is conceivable that the reactor, due to its limited specific activity, could qualify as LSA II or III. However, the high radiation levels on the outer surface would require that additional shielding be incorporated within the packaging so as to attenuate the dose to levels acceptable for transport.

Transport of the highly activated metal, produced in the segmentation of the reactor vessel and internal components, will be by shielded truck cask. Cask shipments may exceed 95,000 pounds, including vessel segment(s), supplementary shielding, cask tie-downs, and tractor-trailer.

The maximum level of activity per shipment assumed permissible was based upon the license limits of the available shielded transport casks.

The segmentation scheme for the vessel and internal segments are designed to meet these limits.

The transport of large intact components, e.g., large heat exchangers and other oversized components, will be by a combination of truck, barge, and/or multi-wheeled transporter.

TLG Ser'vices, Inc. Copyright PSEG Nuclear 1999/2000

40 Salem Generating Station DocumentP07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 12 of 19 The low-level radioactive waste requiring controlled disposal will be sent to one of two currently available burial facilities. Transportation costs are based upon the mileage to either the Envirocare facility in Clive, Utah, or the Barnwell facility in South Carolina. Memphis, Tennessee will be used as the destination for off-site processing. Transportation costs are estimated using published tariffs from Tri-State Motor Transit.[171 3.4.6 Low-Level Radioactive Waste Disposal To the greatest extent practical, metallic material generated in the decontamination and dismantling processes will be treated to reduce the total volume requiring controlled disposal. The treated material, meeting the regulatory and/or site release criterion, will be released as scrap, requiring no further cost consideration. Conditioning and recovery of the waste stream will be performed off site at a licensed processing center..

Material requiring controlled disposal will be packaged and transported to one of two currently available burial facilities. Very low-level radioactive material, e.g., structural steel and contaminated concrete, will be sent to Envirocare. More highly contaminated and activated material will be sent to Barnwell. Disposal fees are based upon current charges for operating waste with surcharges added for the highly activated components, e.g., generated in the segmentation of the reactor vessel.

3.4.7 Site Conditions Following Decommissioning1 The NRC will terminate (or amend) the site licenses if it determines that site remediation has been performed in accordance with the license termination plan, and that the terminal radiation survey and associated documentation demonstrate that the facility is suitable for release. The NRC's involvement in the decommissioning process will end at this point.

Building codes and environmental regulations will dictate the next step in the decommissioning process, as well as PSEG Nuclear's own future plans for the site, e.g., the electrical switchyard will remain in support of the electrical transmission and distribution system.

The large underground tunnels between the cooling water intake, Turbine Building, and discharge structure will be isolated, sealed, and abandoned in place. Site utility and service piping are abandoned in place. Electrical manholes are backfilled with suitable earthen material and abandoned. Asphalt surfaces in the immediate vicinity of site TLG Services Inc. CopyrightPSEG Nuclear 199.9/2000

41 Salem GeneratingStation DocumentP07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page13 of 19 buildings are broken up and the material used for backfill on site, if needed. The site access road will remain.

The estimate does not assume the remediation of any significant volume of contaminated soil. This assumption may be affected by continued plant operations and/or future regulatory actions, such as the development of site-specific release criteria.

Structures will be removed to a nominal depth of three feet below grade.

Concrete rubble generated from demolition activities will be processed and made available as clean fill. The site will be graded following the removal of non-essential structures to conform to the adjacent landscape, and vegetation will be established to inhibit erosion. This degree of site restoration will constitute compliance with the CAFRA document dated July 9, 1976.

3.5 ASSUMPTIONS The following are the major assumptions made in the development of the estimate for decommissioning the site. Decommissioning activities will be performed in accordance with the current regulations that are assumed to be in place at the time of decommissioning, including the Industrial Site Recovery Act (ISRA), which is mandatory under current New Jersey State Regulations.

3.5.1 Estimatina Basis The study follows the principles of ALJARA through the use of work duration adjustment factors. These factors address the .impact of activities such as radiological protection instruction, mock-up training, and the use of respiratory protection and protective clothing. The factors lengthen a task's duration, increasing costs and lengthening the overall schedule. ALARA planning is considered in the costs for engineering and planning, and in the development of activity specifications and detailed procedures. Changes to worker exposure limits may impact the decommissioning cost and project schedule.

TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

42 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 14 of 19 3.5.2 Labor Costs The craft labor required to decontaminate and dismantle the nuclear units will be acquired through standard site contracting practices. The current cost of labor at the site is used as an estimating basis. Costs for site administration, operations, construction, and maintenance personnel are based upon average salary information provided by PSEG Nuclear.

PSEG Nuclear, as the licensee, will oversee the decommissioning operations and provide site security, radiological controls, and overall site administration. PSEG Nuclear will provide contract management of the decommissioning labor force and subcontractors. Engineering services for preparing the activity specifications, work procedures, activation, and structural analyses, are provided by PSEG Nuclear personnel.

The costs associated for the transition of the operating organization to decommissioning, e.g., separation packages, retraining, severance, and incentives are not included in this estimate and are considered to be ongoing operating expenses.

3.5.3 Design Conditions Any fuel cladding failure that occurred during the lifetime of the plant is assumed to have released fission products at sufficiently low levels that the buildup of quantities of long-lived isotopes (e.g., cesium-137, strontium-90, or transuranics) has been prevented from reaching levels exceeding those that permit the major NSSS components to be shipped under current transportation regulations and disposal requirements.

The curie contents of the vessel and internals at final shutdown are derived from those listed in NUREG/CR-3474.[18) Actual estimates are derived from the curie/gram values in NUREG/CR-3474 and adjusted for the different mass of Salem Station components, projected operating life, and different periods of decay. Additional short-lived isotopes were derived from NUREG/CR-0130[ 19] and NUREG/CR-0672P20) and benchmarked. to the long-lived values from NUREG/CR-3474.

Contamination has been found in the heat exchanger tube sheets at several shutdown U.S. pressurized water reactors (due to primary to secondary side leakage in the steam generators). For purposes of this estimate, selected secondary-side components are designated for off-site processing, including portions of the turbine and condenser.

TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

43 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 15 of 19 Activation of the Reactor Building structure is confined to the biological shield in this estimate. More extensive activation (at very low levels) of the interior structures within containment has been detected at several reactors and the owners have elected to dispose of the affected material at a controlled facility rather than reuse the material as fill on site or send it to a landfill. The ultimate disposition of the material removed from the Reactor Building will depend upon the site release criteria selected and the designated end use for the site.

3.5.4 General Transition Activities Existing warehouses will be cleared of non-essential material and remain for use by PSEG Nuclear and its subcontractors. The warehouses may be dismantled as they become surplus to the decommissioning program. The plant's operating staff will perform the following activities at no additional cost or credit to the project during the transition period:

Drain and collect fuel oils, lubricating oils, and transformer oils for recycle and/or sale.

• Excess acid, caustic, and all chemicals listed (at shutdown) in the New Jersey "Right to Know Report" will be removed and the storage container returned to the vendor. It is assumed that these chemicals will have some value; therefore, the cost for their removal will be compensated through their subsequent sale.

Scrap and Salvage The existing plant equipment is considered obsolete and suitable for scrap as deadweight quantities only. PSEG Nuclear will make economically reasonable efforts to salvage equipment following final plant shutdown. However, dismantling techniques assumed by TLG for equipment in this estimate are not consistent with removal techniques required for salvage (resale) of equipment. Experience has indicated that some buyers wanted equipment stripped down to very specific requirements before they would consider purchase. This required expensive rework after the equipment had been removed from its installed location. Since placing a salvage value on this machinery and equipment would be speculative, and the value would be small in comparison to the overall decommissioning expenses, this estimate TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

44 Salem GeneratingStation Document PO7-1425-003, Rev. 0 Decommissioning Cost Analysis Section 3, Page16 of 19 does not attempt to quantify the value that PSEG Nuclear may realize based upon those efforts.

It is assumed, for purposes of this estimate, that any value received from the sale of scrap generated in the dismantling process would be more than offset by the on-site processing costs. The dismantling techniques assumed in the decommissioning estimate do not include the additional cost for size reduction and preparation to meet "furnace ready" conditions. For example, the recovery of copper from electrical cabling from a facility currently being decommissioned has required the removal and disposition of the PCB-contaminated insulation, an added expense. With a volatile market, the potential profit margin in scrap recovery is highly speculative, regardless of the ability to free release this material. This assumption is an implicit recognition of scrap value in the disposal of clean metallic waste at no additional cost to the project.

Furnit ure, tools, mobile equipment such as forklifts, trucks, bulldozers, and other such items of personal property owned by PSEG Nuclear will be removed at no cost or credit to the decommissioning project.

Disposition may include relocation to other generating facilities. Spare parts will also be made available for alternative use.

Ener~v For estimating purposes, the plant is assumed to be de-energized, with the exception of those facilities associated with spent fuel storage.

Replacement power costs are used for the cost of energy consumption during decommissioning for tooling, lighting, ventilation, and essential services.

Insurance Costs for continuing coverage (nuclear liability and property.

insurance) following cessation of plant operations and during decommissioning are included and based upon current operating premiums. Reductions in premiums, throughout the -decommissioning process, are based upon the guidance and the limits for coverage defined in the NRC's proposed rulemaking "Financial Protection Requirements for Permanently Shutdown Nuclear Power Reactors."

The NRC's financial protection requirements are based on various reactor (and spent fuel) configurations.

TLG Services, Inc. CopyrightPSEG Nuclear199.9/2000

45 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 3, Page 17 of 19 Property Taxes Property tax payments will cease upon shutdown of each unit.

Site Modifications The perimeter fence and in-plant security barriers will be moved, as appropriate, to conform to the Site Security Plan in force during the various stages of the project.

3.6 COST ESTIMATE

SUMMARY

The costs projected for the decommissioning of Salem Station are provided in Tables 3.1 and 3.2. Decommissioning costs are reported in the year of projected expenditure; however, the values are provided in thousands of 2002 dollars.

Costs are not inflated, escalated, or discounted over the period of expenditure.

The annual expenditures are based upon the detailed activity costs reported in Appendix C, along with the schedule discussed in Section 4. Since the common plant systems and services will be needed to support Unit 2 operations (with several needed to support post shutdown fuel storage and decommissioning),

the cost to decontaminate, dismantle, and dispose of the common systems is included within the decommissioning cost for Unit 2.

TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

TABLE 3.1 SCHEDULE OF ANNUAL EXPENDITURES BY PERIOD UNIT 1 P

(Thousands, 2002 Dollars)

Period 2 Period 3 Period 4 Period 5 Period 1 Decommissioning Site Dry Fuel ISFSI Year Preparations Operations Restoration Storage Decommissioning Totals Cf 2016 19,764 19,764 2017 65,091 65,091 2018 10,691 87,654 98,345 2019 94,939 94,939 2020 77,754 77,754 2021 77,541 77,541 2022 35,518 35,518 2023 4,680 4,680 2024 4,693 4,693 2025 4,680 4,680 2026 15,889 15,889 2027 3,374 20,847 24,221 2028 9,434 332 9,766 2029 644 544 2030 544 544 2031 544 544 2032 545 545 2033 544 544 2034 544 544 00 2035 544 544 2036 545 545 2037 544 544 2038 544 544 e2, 05 2039 544 544 2040 545 545 2041 544 544 2042 544 544 to 2043 544 544 2044 545 545

'N. 2045 14,311 14,311 23,350 [Unit 2] 555,899 95,546 406,722 30,281 406,722 30,281 .23,350 [Unit 2) 555,899

TABLE 3.2 SCHEDULE OF ANNUAL EXPENDITURES BY PERIOD UNIT 2 C0 (Thousands, 2002 Dollars)

Period 2 Period 3 Period 4 a Period 5 0-I Period 1 Decommissioning Site Dry' Fuel ISFSI Year Preparations Operations Restoration Storage Decommissioning Totals 0,.,.

2020 24,791 24,791 2021 43,611 20,369 63,980 2022 ,100,471 100,471 0 2023 86,380 86,380 2024 74,298 74,298 2025 68,497 68,497 2026 37,888 37,888 2027 3,978 37,022 40,999 2028 16,754 2,186 18,939 2029 3,577 3,577 2030 3,577 3,677 2031 3,577 3,577 2032 3,587 3,587

ý0 2033 3,577 3,577 2034 3,577 3,577 2035 3,577 3,577 2036 3,587 3,587 2037 3,577 3,577 2038 3,577 3,577 2039 3,577 3,577 2040 3,587 3,587 2041 3,577 3,577 2042 3,577 3,577 2043 o c~

3,577 3,577 2044 3,587 3,587 2045 3,577 .9,677 2046 15,611 5,997 21,607 68,402 391,880 53,775 .78,648 5,997 598,702

'-.4,

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 4, Page I of 6

4. SCHEDULE ESTIMATE The schedule for the decommissioning scenarios considered in this study follows the sequence presented in the AIFINESP-036 study, with minor changes to reflect recent experience and site-specific constraints. In addition, the scheduling has been revised to reflect the required cooling period for the spent fuel.

A schedule or sequence of activities is presented in Figure 4.1. The schedule reflects the prompt decommissioning alternative and the start date consistent with a scheduled shutdown in 2016 for Unit 1 and 2020 for Unit 2. The sequence assumes that fuel will be removed from the spent fuel pool within the first five years. The key activities listed in the schedule do not reflect a one-to-one correspondence with those activities in the Appendix C cost table, but reflect dividing some activities for clarity and combining others for convenience. The schedule was prepared using the '¶Microsoft Project 2000" computer software.S21]

4.1 SCHEDULE ESTIMATE ASSUMPTIONS The schedule was generated using a precedence network and associated software. Activity durations are based upon the actual man-hour estimates calculated for each area. The schedule was assembled by sequencing the work areas, considering work crew availability and material access/egress. The following assumptions were made in the development of the decommissioning schedule:

" The Fuel Handling Building will continue to serve as the spent fuel storage/transfer facility until such time that all spent fuel has been removed from site. The Fuel Handling Building is expected to operate for approximately five years after the cessation of operations.

" All work (except vessel and internals removal activities) will be performed during an 8-hour workday, 5 days per week, with no overtime. There are eleven paid holidays per year.

• Reactor and internals removal activities are performed by using separate crews for different activities working on different shifts, with a corresponding backshift charge for the second shift.

" Multiple crews work parallel activities to the maximum extent possible, consistent with: optimum efficiency; adequate access for cutting, removal TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

49 Salem GeneratingStation Document PO07-1425-003, Rev. 0 DecommissioningCost Analysis Section 4, Page 2 of 6 and laydown space; and the stringent safety measures necessary during demolition of heavy components and structures.

For plant systems removal, the systems with the longest removal durations in areas on the critical path are considered to determine the duration of the activity.

4.2 PROJECT SCHEDULE The period-dependent costs presented in Appendix C are based upon the durations developed in the schedule for the decommissioning of Salem Station.

Durations are established between several milestones in each project period; these durations are used to establish a critical path for the entire project. In turn, the critical path duration for each period is used as the basis for determining the period-dependent costs.

Project. timelines are shown in this section as Figure 4.2. Milestone dates are based on a 40-year plant operating life from the issuance of the operating license, a five-year wet storage period for the last core discharge, and continued operation of the ISFSI until DOE can complete the transfer.

TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

,0t, Salem GeneratingStation Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 4, Page3 of 6 FIGURE 4.1 DECOMMISSIONING ACTIVITY SCHEDULE ITask Name '161'171'1811191'201'211'221'231'241'251'261'27 ['28 Salem Unit 1 & 2 schedule ... =, : . .*::::

Sýu*down-.Unit 1 Period Is Unit I - Shutdown through transition Certificate of permanent cessation of operations submitted Fuel storage pool operations Dry fuel storage operations DReconfigure plant Prepare activity specifications 4<........

Perform site characterization PSDAR submitted Written certificate of permanent removal of fuel submitted Site specific decommissioning cost estimate submitted A:

DOC staff mobilized Period lb Unit I - Decommissioning preparations Fuel storage pool operations Reconfigure plant (continued)

Dry fuel storage operations Prepare detailed work procedures Decon NSSS Isolate spent fuel pool Period 2a Unit 1 - Large component removal Fuel storage pool operations Dry fuel storage operations Preparation for reactor vessel removal Reactor vessel & internals Remaining large NSSS components disposition Non-essential systems Main turbine/generator

=iii Main condenser License termination plan submitted Period 2b Unit 1 - Decontamination (wet fuel)

Fuel storage pool operations Dry fuel storage operations Mlestone Summary task m

Ciitial Path Task Performed During Pecitd TLG Services, Inc. Copyright PSEGNuclear 1999/2000

51 Salem GeneratingStation ' Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 4, Page 4 of 6 FIGURE 4.1 (continued) t

%elr Nnm~ tl6i~17IIl8ISl9lI2O 121 I'22I 23P24P25P26I27128 4-61..17..... A l...4....J....i - -J--L...41 ....- J - I -

Ta Name Remove systems not supporting wet fuel storage Decon buildings not supporting wet fuel storage License termination plan approved Fuel storage pool available for decommissioning Period 2c Unit 1 - Decontamination following wet fuel storage Dry fuel storage operations Remove remaining systems

.01<8.

Decon wet fuel storage area license termination Period 2d Unit 1 - Delay before Un---it 2 Op-e r-a-t~i ons Shutdown Unit 2 Period la Unit 2 - Shutdown through transition Certificate of permanent cessation of operations submitted Fuel storage pool operations Dry fuel storage operations Reconfigure plant Prepare activity specifications Perform site characterization a:1 PSDAR submitted Written certificate of permanent removal of fuel submitted Site specific decommissioning cost estimate submitted .tEHK.

DOC staff mobilized Period lb Unit 2 - Decommissioning preparations .712E]::

Fuel storage pool operations Reconfi.gure plant (continued)

Dry fuel storage operations Prepare detailed work procedures Decon NSSS Isolate spent fuel pool Period 2a Unit 2 - Large component removal Fuel storage pool operations Dry fuel storage operations Preparation for reactor vessel removal Mfleslone Summary task m Critical Path Task = PM Performed During Period TLG Services, Inc- Copyright PSEG Nuclear.1999/2000 ,

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Section 4, Page 5 of 6 FIGURE 4.1 (continued)

Task Name 1'1611718['191-201'211'221'231-241'25 1261'21 ITS Reactor vessel & internals Remaining large NSSS components disposition Non-essential systems Main turb;ne/generator Main condenser License termination plan submitted Period 2b Unit 2 - Decontamination (wet fuel)

Fuel storage pool operations Dry fuel storage operations Remove systems not supportig wet fuel storage Decon buildings not supporting wet fuel storage License termination plan approved V4 Fuel storage pool available for decommissioning Period 2c Unit 2 - Decontamination following wet fuel storage Dry fuel storage operations Remove remaining systems Decon wet fuel storage area Pexiod 2e Unit 1 &2 - Plant license termination Dry fuel storage operations Final Site Survey NRC review & approval Part 50 license terminated Period 3b Unit 1 & 2 - Site restoration Dry fuel storage operations Building demolitions, backfill and landscaping Miestone summary task Cnbca Path Task Performed During Period TLG Services, Inc. Copyright PSEG Nuclear 199912000

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 4, Page6 of 6 FIGURE 4.2 DECOMMISSIONING TIMELINE (not to scale)

Unit 1 Shutdown 08/1312016 I la lb 2a 2b 2c 2d 2e 3b 3.c and 3d 11.9m 6.2m 19.8m i28.m 7.8m 44.3m 8.2mn15.m 206.6m 8/16 8/17 2/18 10/19 2/22 10/22 6/26 2/27 5/28 8/45 Preparations Decommissioning Operations Site ISFSI Operations Restoration Wet Fuel Storage Dry Fuel Storage Unit 2 Shutdown "04/18/2020 I la lb I 2a 2b 2c 2e I 3b 3c through 3f I I r I 12.0m j 6.Om 20.Om 27.9m 8.Om 8.2m 15.1m I 220.6m 4/20 4/21 10/21 6/23 10/25 6/26 2/27 5/28 10/46 Preparations Decommissioning Operations Site ISFSI Operations Restoration Wet Fuel Storage TLG Services, Inc. Copyright-PSEGNuclear 1999/2000

54 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 5, Page1 of 4

5. RADIOACTIVE WASTES The objectives of the decommissioning process are the removal of all radioactive material from the site that would restrict its future use and the termination of the NRC license(s). This currently requires the remediation of all radioactive material at the site in excess of applicable legal limits. Under the Atomic Energy Act,[22] the NRC is responsible for protecting the public from sources of ionizing radiation. Title 10 of the Code of Federal Regulations delineates the production, utilization, and disposal of radioactive materials and processes. In particular, 10 CFR §71 defines radioactive material and 10 CFR §61 specifies its disposition.

Most of the materials being transported for controlled burial are categorized as Low Specific Activity (LSA) or Surface Contaminated Object (SCO) materials containing Type A quantities, as defined in 49 CFR §173-178. Shipping containers axe required to be Industrial Packages (IP-1, IP-2 or IP-3). For this study, commercially available steel containers are presumed to be used for the disposal of piping, small components, and concrete. Larger components can serve as their own containers, with proper closure of all openings, access ways, and penetrations.

The volumes of radioactive waste generated during the various decommissioning activities at the site are shown on a line-item basis in Appendix C and summarized in Tables 5.1 and 5.2. The quantified waste volume summaries shown in these tables are consistent with §61 classifications. The volumes are calculated based on the exterior dimensions for containerized material. The volumes are calculated on the displaced volume of components serving as their own waste containers.

The reactor vessel and internals are categorized as large quantity shipments and, accordingly, will be shipped in reusable, shielded truck casks with disposable liners. In calculating disposal costs, the burial fees are applied against the liner volume and the special handling requirements of the payload. Packaging efficiencies are lower for the highly activated materials (greater than Type A quantity waste), where high concentrations of gamma-emitting radionuclides limit the capacity of the shipping canisters.

No process system containing/handling radioactive substances at shutdown is presumed to meet material release criteria by decay alone, i.e., systems radioactive at shutdown will still be radioactive over the time period during which the decommissioning is accomplished, due to the presence of long-lived radionuclides.

While the dose rates decrease with time, radionuclides such as 13 7Cs will still control the disposition requirements.

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Salem GeneratingStation Document P07-1425-003,Rev. 0 55 Decommissioning Cost Analysis Section 5, Page 2 of 4 The waste material generated in the decontamination and dismantling of Salem Station will primarily be generated during Period 2. Material considered potentially contaminated when removed from the radiologically controlled area will be sent to processing facilities for conditioning and disposal at a unit cost of $2.00 per pound.

Heavily contaminated components and activated materials will be routed for controlled disposal. The disposal volumes reported in the tables reflect the savings resulting from reprocessing and recycling.

For purposes of constructing the estimate, the rate schedule for the Barnwell facility was used as a proxy for the higher activity waste. This schedule was used to estimate the disposal fees for the majority of plant components and activated concrete deemed unsuitable for processing or recovery. An average disposal rate of $415 per cubic foot was used, with additional surcharges for activity, dose rate and/or handling added, as appropriate for the particular package.

The remaining volume of contaminated metallic and concrete debris will be disposed of.

at the Envirocare facility. This includes lower activity material such as miscellaneous steel, metal siding, scaffolding and structural steel. A rate of $298 per cubic foot was used for containerized waste, $70 per cubic foot for disposal of DAW, and approximately $20 per cubic foot for bulk material, e.g., concrete.

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56 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 5, Page3 of 4 TABLE 5.1 DECOMMISSIONING WASTE

SUMMARY

- UNIT 1 Waste Volume Weight Class' (cubic feet) (pounds)

Low-Level Radioactive Waste Barnwell, South Carolina (contaminated/activated metallic waste and concrete)

A 67,763 6,908,944 B 13,149 1,959,703 C 459 48,448 Envirocare, Utah (miscellaneous steel, contaminatedlactivated concrete)

Containerized/DAW A 5,186 444,519 Bulk A 18,219 863,724 Geologic Repository (Greater-than Class C) 613 126,165 Total 2 105,389 10,351,503 Processed Waste (Off-Site) 72,765 Scrap Metal 96,278,000 1 Waste is classified according to the requirements as delineated in Title 10 CFR, Part 61.55 2

Columns may not add due to rounding.

TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem Generating Station Document P07-1425-003,Rev.*

p Decommissioning Cost Analysis Section 5, Page 4 of 4 TABLE 5.2 DECOMMISSIONING WASTE

SUMMARY

- UNIT 2 Waste Volume Weight Class1 (cubic feet) (pounds)

Low-Level Radioactive Waste Barnwell, South Carolina (contaminated/activated metallic waste and concrete)

A 68,016 6,930,802 B 13,167 1,961,982 C 459 48,448 Envirocare, Utah (miscellaneous steel, contaminatedlactivated concrete)

ContainerizedlDAW A 12,184 1,244,448 Bulk A 18,276 885,906 Geologic Repository (Greater-than Class C) 613 126,165 Total 2 112,714 11,197,751 Processed Waste (Off-Site) 74,384 Scrap Metal 108,886,000 1 Waste is classified according to the requirements as delineated in Title 10 CFR, Pat 61.55 2 Columns may not add due to rounding.

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5i8 Salem GeneratingStation Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Section 6, Page 1 of 5

6. RESULTS Costs were developed to decommission the Salem Station following a scheduled cessation of plant operations. The analysis relied upon the site-specific, technical information developed for a previous analysis prepared in 1995-96, then updated to reflect current plant conditions and operating assumptions. While not an engineering study, the estimates do provide PSEG Power with sufficient information to assess its financial obligations as they pertain to the eventual decommissioning of the nuclear station.

The estimates described in this report are based on numerous fundamental assumptions, including regulatory requirements, project contingencies, low-level radioactive waste disposal practices, high-level radioactive waste management options, and site restoration requirements. The decommissioning scenario assumes continued operation of the plant's spent fuel pool for approximately five years following the cessation of operations for continued cooling of the assemblies. An ISFSI will be used to safeguard the spent fuel, once sufficiently cooled, until such time that the DOE can complete the transfer of the assemblies to its repository. The scenarios also include the costs for the dismantling of non-essential structures and limited restoration of the site.

The costs projected to promptly decommission Salem Station are estimated to be

$1,154.6 million. The majority of this cost (approximately 92.6%) is associated with the physical decontamination and dismantling of the nuclear units and caretaking of the spent fuel, so that the license could be terminated. The remaining 7.4% is for the demolition of the remaining structures and limited restoration of the site.

'The primary cost contributors, identified in Tables 6.1 and 6.2, are either labor-related or associated with the management and disposition of the radioactive waste.

Program management is the largest single contributor to the overall cost. The magnitude of the expense is a function of both the size of the organization required to manage the decommissioning' and the duration of the program. It is assumed, for purposes of this analysis, that PSEG Nuclear will oversee the decommissioning prbgram, managing the decommissioning labor force and the associated subcontractors. The size and composition of the management organization varies with the decommissioning phase and associated site activities. However, once the operating licenses have been terminated, the staff is substantially reduced for the conventional demolition and restoration of the site, and the long-term care of the spent fuel.

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59 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 6, Page2 of 5 As described in this report, the spent fuel pools will remain operational for approximately five years following the cessation of plant operations. The pools will be isolated and independent spent fuel islands created. This will allow decommissioning operations to proceed in and around the Fuel Handling Building.

Over the five-year period, the spent fuel will be packaged into transportable steel canisters for loading into a DOE-provided transport cask. The canisters will be stored in concrete overpacks at the ISFSI until DOE is able to receive them. Dry storage of the fuel under a separate license provides additional flexibility in the event DOE is not able to meet the current timetable for completing the transfer of assemblies to an off-site facility and minimizes the associated caretaking expenses incurred by PSEG Nuclear.

The cost for waste disposal includes only those costs associated with the controlled disposition of the low-level radioactive waste generated from decontamination and dismantling activities, including plant equipment and components, structural material, filters, resins and dry-active waste. As described in Section 5, disposal of the lower level material, including concrete and structural steel, will be at the Envirocare facility. The more highly radioactive material will be sent to the Barnwell facility, with the exception of selected reactor vessel components. Highly activated components, requiring additional isolation from the environment, are packaged for geologic disposal. The cost of geologic disposal is based upon a cost equivalent for spent fuel.

A significant portion of the metallic waste is designated for additional processing and treatment at an off-site facility. Processing reduces the volume of material requiring controlled disposal through such techniques and processes as survey and sorting, decontamination and volume reduction. The material that cannot be unconditionally released will be packaged for controlled disposal at one of the currently operating facilities. The costs identified for processing are all-inclusive, incorporating the ultimate disposition of the material.

Removal costs reflect the labor-intensive nature of the decommissioning process and the management controls required to ensure a safe and successful program.

Decontamination and packaging costs also have a large labor component that is based upon prevailing union wages. Non-radiological demolition is a natural extension of the decommissioning process. The methods employed in decontamination and dismantling are generally destructive and indiscriminate in inflicting collateral damage. With a work force mobilized to support decommissioning operations, non-radiological demolition can be an integrated activity and a logical expansion of the work being performed in the process of terminating the operating license. Prompt demolition reduces future liabilities and TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

60 Salem Generating Station Document PO 7-1 425-003, Rev. 0 Decommissioning Cost Analysis Section 6, Page 3 of 5 could be more cost-effective than deferral, due to the ultimate deterioration of facilities (and therefore the working conditions).

The reported cost for transport includes the tariffs and surcharges associated with moving large components and/or overweight shielded casks overland, as well as the general expense, e.g., labor and fuel, of transporting material to the destinations identified in this report. For purposes of this estimate, material will be primarily moved overland by truck.

Decontamination will be used to reduce the plant's radiation fields and minimize worker exposure. Slightly contaminated material or material located within a contaminated area will be sent to an off-site processing center, i.e., this estimate does not assume that contaminated plant components and equipment could be economically decontaminated for uncontrolled release in-situ. Centralized processing centers have proven to be a more efficient means of handling the large volumes of material produced in the dismantling of a nuclear unit.

License termination survey costs are associated with the labor intensive and complex activity of verifying that contamination has been removed from the site to the levels specified by the regulating agency. This process involves a systematic survey of all remaining plant surface areas and surrounding environs, sampling, isotopic analysis and documentation of the findings. The status of any plant components and materials not removed in the decommissioning process will also need to be confirmed and will add to the expense of surveying the facilities alone.

The remaining costs include allocations for heavy equipment and temporary services, and other expenses such as regulatory fees and the premiums for nuclear insurance. While site operating costs are greatly reduced following the final cessation of plant operations, certain administrative functions do need to be maintained either at a basic functional or regulatory level.

TLG Servicesý Inc. TLG ervies~,Inc.Copyright PSEG Nuclear 1999/2000

6I1 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 6, Page4 of 5 TABLE 6.1

SUMMARY

OF DECOMMISSIONING COST ELEMENTS UNIT I Cost 2002$ Percent of Work Category (thousands) Total Costs Decontamination 13,462.7 2.4 Removal - 79,587.2 14.3 Packaging 11,726.5 2.1 Transportation 11,632.0 2.1 Waste Disposal 80,910.9 14.6 Off-site Waste Processing 16,802.4 3.0 Program Management (including Engineering and Security) 233,535.0 42.0 Spent Fuel Pool Isolation 9,060.3 1.6 ISFSI Related (including capital) 67,206.7 12.1 Insurance and Regulatory Fees 11,463.9 2.1 Energy 8,045.7 1.4 Characterization and Licensing Surveys 6,439.9 1.2 Misc. Equipment and Site Services 6,025.8 1.1 Total 555,898.9 100.0 Note: Columns may not add due to rounding TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

62 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 6, Page5 of 5 TABLE 6.2

SUMMARY

OF DECOMMISSIONING COST ELEMENTS UNIT 2 Cost 2002$ Percent of Work Category (thousands) Total Costs Decontamination 13,577 2.3 Removal 100,874 16.8 Packaging 11,746 2.0 Transportation 11,734 2.0 Waste Disposal 82,039 13.7 Off-site Waste Processing 17,175 2.9 Program Management (including Engineering and Security) 272,325 45.5 Spent Fuel Pool Isolation 6,040 1.0 ISFSI Related (including capital) 53,776 9.0 Insurance and Regulatory Fees 9,209 1.5 Energy 7,344 1,2 Characterization and Licensing Surveys 6,440 1.1 Misc. Equipment and Site Services 6,423 1.1 Total 598,702 100.0 Note: Columns may not add due to rounding TLG Services, Inc. CopyrightPSEG Nuclear.1999/2000 "

63 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Section 7, Page I of 2

7. REFERENCES

1. U.S. Code of Federal Regulations, Title 10, Parts 30, 40, 50, 51, 70 and 72, "General Requirements for Decommissioning Nuclear Facilities," Nuclear Regulatory Commission, Federal Register Volume 53, Number 123 (p 24018 et seq.), June 27, 1988.

2. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.159, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors," August 1990.

3. U.S. Code of Federal Regulations, Title 10, Parts 2, 50 and 51, "Decommissioning of Nuclear Power Reactors," Nuclear Regulatory Commission, Federal Register Volume 61 (p 39278 et seq.), July 29, 1996.

4. "Nuclear Waste Policy Act of 1982 and Amendments," U.S. Department of.

Energy's Office of Civilian Radioactive Management, 1982.

5. Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company, and Yankee Atomic Power Company v. United States, U.S. Court of Appeals for the Federal Circuit decision, Docket No. 99-5138, -513.9, -5140, August 31, 2000.

6. U.S. Code of Federal Regulations, Title 10, Part 50 - Domestic Licensing of Production and Utilization Facilities, Subpart 54 (bb), "Conditions of Licenses,"

January 2001 Edition.

7. "Low-Level Radioactive Waste Policy Amendments Act of 1985," Public Law 99-240, January 15, 1986.

8. U.S. Code of Federal Regulations, Title 10, Part 20, Subpart E, "Radiological Criteria for License Termination," Federal Register, Volume 62, Number 139 (p 39058 et seq.), July 21, 1997.

9. "Multi-Agency Radiation Survey and Site Investigation Manual (MARSSIM),"

NUREG/CR-1575, EPA 402-R-97-016, December 1997.

10. '"Decommissioning Cost Estimate for the Salem Generating Station," Document No. P07-1180-005, TLG Services, Inc., September 1996.

11. T.S. LaGuardia et al., "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," AIF/NESP-036, May 1986.

TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

64 Salem GeneratingStation Document PO7-1425-003, Rev. 0 Decommissioning Cost Analysis Section 7, Page 2 of 2

7. REFERENCES (continued)

12. W.J. Manion and T.S. LaGuardia, "Decommissioning Handbook," U.S.

Department of Energy, DOE/EV/10128-1, November 1980.

13. "Building Construction Cost Data 2002," Robert Snow Means Company, Inc.,

Kingston, Massachusetts.

14. Project and Cost Engineers' Handbook, Second Edition, p. 239, American Association of Cost Engineers, Marcel Dekker, Inc., New York, New York, 1984.

15. "Strategy for Management and Disposal of Greater-Than-Class C Low-Level Radioactive Waste," Federal Register Volume 60, Number 48 (p 13424 et seq.), March 1995.

16. U.S. Department of Transportation, Section 49 of the Code of Federal Regulations, "Transportation," Parts 173 through 178, 1996.

17. Tri-State Motor Transit Company, published tariffs, Interstate Commerce Commission (ICC), Docket No. MC-109397 and Supplements, 2000.

18. J.C. Evans et al., "Long-Lived Activation Products in Reactor Materials" NUREG/CR-3474, Pacific Northwest Laboratory for the Nuclear Regulatory Commission. August 1984.

19. RlI. Smith, G.J. Konzek, W.E. Kennedy, Jr., "Technology, Safety and Costs of Decommissioning a Reference Pressurized Water Reactor Power Station,"

NUREG/CR-0130 and addenda, Pacific Northwest Laboratory for the Nuclear Regulatory Commission. June 1978.

20. H.D. Oak, et aL, "Technology, Safety and Costs of Decommissioning a Reference Boiling Water Reactor Power Station," NUREG/CR-0672 and addenda, Pacific Northwest Laboratory for the Nuclear Regulatory Commission. June 1980.

21. "Microsoft Project 2000," Microsoft Corporation, Redmond, WA, 1997.

22. "Atomic Energy Act of 1954," (68 Stat. 919).

TLG Services, Inc. CopyrightPSEG Nuclear 199912000

65 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix A, Page 1 of 4 APPENDIX A UNIT COST FACTOR DEVELOPMENT TLG Services, Inc. Copyright PSEGNuclear 1999/2000

66 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix A, Page 2 of 4 APPENDIX A UNIT COST FACTOR DEVELOPMENT Example: Unit Factor for Removal of Contaminated Heat Exchanger < 3,000 lbs.

1. SCOPE Heat exchangers weighing < 3,000 lbs. will be removed in one piece using a crane or small hoist. They will be disconnected from the inlet and outlet piping. The heat exchanger wili be sent to the waste processing area.

2. CALCUIATIONS Act Activity Activity Critical ID Description Duration Duration a Remove insulation 60 (b) b Mount pipe cutters 60 60 c Install contamination controls 20 (b) d Disconnect inlet and outlet lines 60 60 e Cap openings 20 (d) f Rig for removal 30 30 g Unbolt from mounts 30 30 h Remove contamination controls 15 15 i Remove, wrap in plastic, send to the waste processing area 60 60 Totals (Activity/Critical) 355 255 Duration adjustment(s):

+ Respiratory protection adjustment (50% of critical duration) 128

+ RadiationlALARA adjustment (37.08% of critical duration) 95 Adjusted work duration 478

+ Protective clothing adjustment (30% of adjusted duration) 143 Productive work duration 621

+ Work break adjustment (8.33 % of productive duration) 52 Total work duration min. 673 min

• • • Total duration = 11.217 hr

• TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix A, Page 3 of 4 APPENDIXA (continued)

3. LABOR REQUIRED Crew Number Duration Rate Cost (hr) ($/hr)

Laborers 3.00 11.217 40.61 1,366.57 Craftsmen 2.00 11.217 56.29 1,262.81 Foreman 1.00 11.217 60.17 674.93 General Foreman 0.25 11.217 67.66 189.74 Fire Watch 0.05 11.217 40.61 22.78 Health Physics Technician 1.00 11.217 45.90 514.86 Total labor cost $4,031.69

4. EQUIPMENT & CONSUMABLES COSTS Equipment Costs none Consumables/Materials Costs

-Gas torch consumables 1 @ $4.57/hr x 1 hr {1} $4.57

-Blotting paper 50 @ $0.47 sq ft {2} $23.50

-Plastic sheets/bags 50 @ $0.12/sq ft {3} $6.00 Subtotal-cost of equipment and materials $34.07 Overhead & sales tax on equipment and materials @ 16.00 % $5.45 Total costs, equipment & material $39.52 TOTAL COST:

Removal of contaminated heat exchanger <3000 pounds: $4,071.21 Total labor cost: $4,031.69 Total equipment/material costs: $39.52 Total craft labor man-hours required per unit: 81.884 TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

68 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix A, Page 4 of 4

5. NOTES AND REFERENCES

" Work difficulty factors were developed in conjunction with the AIF (now NEI) program to standardize nuclear decommissioning cost estimates and are delineated in Volume 1, Chapter 5 of the "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates,"

AIF/NESP-036, May 1986.

• References for equipment & consumables costs:

1. R.S. Means (2002) Division 01590, Section 400-6360 pg 24

2. McMaster-Carr Ed. 106 pg 1778

3. R.S. Means (2002) Division 01540, Section 800-0200 pg 17

• Material and consumable costs were adjusted using the regional indices for Wilmington, Delaware.

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69 Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning CostAnalysis Appendix B, Page1 of 7 APPENDIX B UNIT COST FACTOR LISTING (DECON: Power Block Structures Only)

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70 Salem Generating Station Document P07-1425-003, Rev. 0 Decommissioning Cost Analysis Appendix B, Page2 of 7 APPENDIX B UNIT COST FACTOR LISTING (Power Block Structures Only)

Unit Cost Factor CostfUnit($)

Removal of clean instrument and sampling tubing, $S/inearfoot 0.46 Removal of clean pipe 0.25 to 2 inches diameter, $/Iinear foot 4.80 Removal of clean pipe >2 to 4 inches diameter, $Slinearfoot 6.93 Removal of clean pipe >4 to 8 inches diameter, $/linear foot 13.70 Removal of clean pipe >8 to 14 inches diameter, $/linear foot 26.29 Removal of clean pipe >14 to 20 inches diameter, $/linear foot 34.03 Removal of clean pipe >20 to' 36 inches diameter, $/linear foot 50.10 Removal of clean pipe >36 inches diameter, $/Iinear foot 59.60 Removal of clean valves >2 to 4 inches 91.18 Removal of clean valves >4 to 8 inches 136.96 Removal of clean valves >8 to 14 inches .262.88 Removal of clean valves >14 to 20 inches 340.30 Removal of clean valves >20 to 36 inches 501.04 Removal of clean valves >36 inches 595.95 Removal of clean pipe fittings >2 to 4 in 101.25 Removal of clean pipe fittings >4 to 8 in 160.64 Removal of clean pipe fittings >8 to 14 in 262.88 Removal of clean pipe fittings >14 to 20 340.30 Removal of clean pipe fittings > 20 to 36 501.04 Removal of clean pipe hangers for small bore piping 28.12 Removal of clean pipe hangers for large bore piping 103.45 Removal of clean pumps, <300 pound 227.86 Removal of clean pumps, 300-1000 pound 640.33 Removal of clean pumps, 1000-10,000 pound 2,542.96 Removal of clean pumps, >10,000 pound 4,906.95 MLG Services, Inc. CopyrightPSEG Nuclear 1999/2000'

71 Salem GeneratingStation Document PO 7-1425-003, Rev. 0 DecommissioningCost Analysis Appendix B, Page3 of 7 APPENDIX B (continued)

Unit Cost Factor CostJUnit($)

Removal of clean pump motors, 300-1000 pound 271.14 Removal of clean pump motors, 1000-10,000 pound 1,061.82 Removal of clean pump motors, >10,000 pound 2,389.10 Removal of clean turbine-driven pumps > 10,000 pounds 6,577.50 Removal of clean heat exchanger <3000 pound 1,363.81 Removal of clean heat exchanger >3000 pound 3,417.62 Removal of clean feedwater heater/deaerator 9,646.37 Removal of clean moisture separator/reheater 19,849.31 Removal of clean tanks, <300 gallons 293.47 Removal of clean tanks, 300-3000 gallons 931.33 Removal of clean tanks, >3000 gallons, $/square foot surface area 7.81 Removal of clean electrical equipment, <300 pound 126.22 Removal of clean electrical equipment, 300-1000 pound 441.45 Removal of clean electrical equipment, 1000-10,000 pound 882.90 Removal of clean electrical equipment, >10,000 pound 2,112.91 Removal of clean electrical transformers < 30 tons 1,467.39 Removal of clean electrical transformers > 30 tons 4,225.80 Removal of clean standby diesel-generator, <100 kW 1,498.81 Removal of clean standby diesel-generator, 100 kW to 1 MW 3,345.43 Removal of clean standby diesel-generator, >1 MW 6,925.72 Removal of clean electrical cable tray, $/Iinear foot 11.66 Removal of clean electrical conduit, $/linear foot 5.08 Removal of clean mechanical equipment, <300 pound 126.22 Removal of clean mechanical equipment, 300-1000 pound 441.45 Removal of clean mechanical equipment, 1000-10,000 pound 882.90 Removal of clean mechanical equipment, >10,000 pound 2,112.91 Removal of clean HVAC equipment, <300 pound 126.22 TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem Generating Station Document P07-1425-003, RevTd Decommissioning Cost Analysis Appendix B, Page 4 of 7 APPENDIX B (continued)

Unit Cost Factor Cost/Unit($)

Removal of clean HVAC equipment, 300-1000 pound 441.45 Removal of clean HVAC equipment, 1000-10,000 pound 882.90 Removal of clean HVAC equipment, >10,000 pound 2,112.91 Removal of clean HVAC ductwork, $/pound 0.48 Removal of contaminated instrument and sampling tubing, $/linear foot 1.42 Removal of contaminated pipe 0.25 to 2 inches diameter, $/linear foot 18.49 Removal of contaminated pipe >2 to 4 inches diameter, $/linear foot 32.88 Removal of contaminated pipe >4 to 8 inches diameter, $/linear foot 52.70 Removal of contaminated pipe >8 to 14 inches diameter, $/linear.foot 103.92 Removal of contaminated pipe >14 to 20 inches diameter, $/Iinear foot 125.17 Removal of contaminated pipe >20 to 36 inches diameter, $/]linear foot 174.16 Removal of contaminated pipe >36 inches diameter, $/linear foot .206.34 Removal of contaminated valves >2 to 4 inches .409.23 Removal of contaminated valves >4 to 8 inches 491.64 Removal of contaminated valves >8 to 14 inches 1,004.93 Removal of contaminated valves >14 to 20 inches 1,279.12 Removal of contaminated valves >20 to 36 inches 1,707.42 Removal of contaminated valves >36 inches 2,029.16 Removal of contaminated pipe fittings >2 to 4 inches 222.48 Removal of contaminated pipe fittings > 4 to 8 inches 562.42 Removal of contaminated pipe fittings > 8 to 14 inches 1,004.93 Removal of contaminated pipe fittings > 14 to 20 inches 1,279.12 Removal of contaminated pipe fittings >20 to 36 inches 1,707.42 Removal of contaminated pipe hangers for small bore piping 96.90 Removal of contaminated pipe hangers for large bore piping 317.71 Removal of contaminated pumps, <300 pound 872.56 Removal of contaminated pumps, 300-1000 pound 2,038.66 Removal of contaminated pumps, 1000-10,000 pound 6,721.04 TLG Services, Inc. Copyright PSEG Nuclear 1999/2000

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix B, Page 5 of 7 APPENDIX B (continued)

Unit Cost Factor Cost/Unit($)

Removal of contaminated pumps, >10,000 pound 16,369.44 Removal of contaminated pump motors, 300-1000 pound 856.70 Removal of contaminated pump motors, 1000-10,000 pound 2,726.06 Removal of contaminated pump motors, >10,000 pound 6,120.23 Removal of contaminated turbine-driven pumps < 10,000 pounds --18,918.88 Removal of contaminated heat exchanger <3000 pound 4,071.21 Removal of contaminated heat exchanger >3000 pound 11,752.21 Removal of contaminated feedwater heater / deaerator 28,760.26 Removal of contaminated moisture separator 1 reheater 63,002.71 Removal of contaminated tanks, <300 gallons 1,448.59 Removal of contaminated tanks, >300 gallons, $/square foot 28.80 Removal of contaminated electrical equipment, <300 pound 684.21 Removal of contaminated electrical equipment, 300-1000 pound 1,664.73 Removal of contaminated electrical equipment, 1000-10,000 pound 3,204.54 Removal of contaminated electrical equipment, >10,000 pound 6,299.81 Removal of electrical transformers < 30 tons 5,079.02 Removal of electrical transformers > 30 tons 12,470.88 Removal of standby diesel-generator, < 100 kW 4,387.47 Removal of standby diesel-generator, 100 kW to 1 M-W 9,471.87 Removal of standby diesel-generator, >1 MW 20,474.76 Removal of contaminated electrical cable tray, $/linear foot 32.93 Removal of contaminated electrical conduit, $/linear foot 14.92 Removal of contaminated mechanical equipment, <300 pound 761.89 Removal of contaminated mechanical equipment, 300-1000 pound 1,841.14 Removal of contaminated mechanical equipment, 1000-10,000 pound 3,538.42 TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem Generating Station Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix B, Page 6 of 7 APPENDIX B (continued)

Unit Cost Factor Cost/Unit($)

Removal of contaminated mechanical equipment, >10,000 pound 6,299.81 Removal of contaminated HVAC equipment, <300 pound 761.89 Removal of contaminated HVAC equipment, 300-1000 pound 1,841.14 Removal of contaminated HVAC equipment, 1000-10,000 pound 3,538.42 Removal of contaminated HVAC equipment, >10,000 pound 6,299.81 Removal of contaminated HVAC ductwork, $/pound 3.03 Removal of clean standard reinforced concrete, $/cubic yard 72.07 Removal of grade slab concrete, $/cubic yard 204.33 Removal of clean heavily rein concrete w/#9 rebar, $/cubic yard 211.46 Removal of clean heavily rein concrete w/#18 rebar, $/cubic yard 267.46 Removal of below-grade suspended floors, $/cubic yard 316.55 Removal of clean monolithic concrete structures, $/cubic yard 1,897.58 Removal of.clean foundation concrete, $/cubic yard 626.97 Removal of clean hollow masonry block wall, $/cubic yard 75.24 Removal of clean solid masonry block wall, $/cubic yard 75.24 Placement of concrete for below-grade voids, $/cubic yard 99.90 Removal of subterranean tunnels/voids, $/ linear foot 141.76 Backfill of below grade voids, $/cubic yard 17.31 Excavation of clean material, $cubic yard 3.05 Removal of clean building metal siding, $/square foot 1.34 Removal of standard asphalt roofing, $/square foot 2.15 Removal of Galbestos panels, $/square foot 2.19 Scarifying contaminated concrete surfaces (drill & spall), $/square foot 12.54 Scabbling contaminated concrete floors, $/square foot 7.42 Scabbling contaminated concrete walls, $/square foot 8.15 Scabbling contaminated ceilings, $/square foot 73.38 Removal of clean overhead cranes/monorails < 10 ton capacity, each 623.14 Removal of contaminated overhead cranes/monorails < 10 ton capacity, ea. 1,734.71 TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

75 Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix B, Page 7 of 7 APPENDIX B (continued)

Unit Cost Factor Cost/Unit($)

Removal of clean overhead cranes/monorails >10-50 ton capacity, each 1,495.51 Removal of contaminated overhead cranes/monorails >10-50 ton capacity, 4,162.61 each Removal of polar cranes > 50 ton capacity, each 6,286.50 Removal of gantry cranes > 50 ton capacity, each 26,411.28 Removal of clean structural steel, $/pound 0.35 Removal of clean steel floor grating, $/square foot 3.19 Removal of contaminated steel floor grating, $/square foot 9.69 Removal of clean free-standing steel liner, $/square foot . 33.75 Removal of clean concrete-anchored steel liner, $/square foot 5.85 Removal of contaminated concrete-anchored steel liner, $/square foot 39.31 Placement of scaffolding in clean areas, $/square foot 13.73 Placement of scaffolding in contaminated areas, $/square foot 22.10 Removal of chain link fencing, $Jlinear foot 2.10 Removal of asphalt pavement, $/square foot 1.05 Core drilling 2 to 4 inch diameter, linear foot 354.68 TLG Services, Inc. CopyrightPSEG Nuclear 1999/2000

Salem GeneratingStation Document P07-1425-003,Rev. 0 Decommissioning Cost Analysis Appendix C, Page I of 22 APPENDIX C DETAILED COST ANALYSES

/ Page Uniti1.......................................................................................... C-2 Unit 2 .......................................................................................... G12 TLG Services, Inc. PSEG Nuclear 1999/2000 TLG ervies, nc.Copyright

87 Salem GeneralingStation Doenment P07-1425-02 . Rie. 0 Deeeamsassslonlii Cest Anntysis Appendix C, Page12 of-2 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands of 2002 Dlolar*s)

Off-,1to LLRW NRC SpentFuel site Processed SurialVolumes BuSatl tUfJlity-d Activity Defon Remoral Packaging Transport Procesling Disposal Other Total Total Llc.Teoa Manogenoent Restoration Volume Class A Class B Clos C GTCC Weight Craft Contr*ctor Index AcI*t G unarlon Cost Cost Casio Costs Colst Cast. Costs Con nisenc" Costs Coast Costs Costs Cu.Feet Cu. Feet Cu. Foet Co. Feet Cs. Feet Lts. Mosnhlurs Mtohours PERIOD Is - Shutdown through Transition Period]. D1iect Decommissioning Adieltles lu..1 Pnrpeu prl-mi*sa* decommissionnlg cst - - 41 6 47 47 - . . 1.220 lo.1.2 ltfaicatien o f Cesuation of Operat*ons a 1.1.3 Remove fuel & snoau eeat'einl Ia.4A Notifiatioan sfPe-rmaonaDfehear1 1L1.9 DIaoestaL pnt & pee.sse emstsse waste m.1I6 P*epn osumit PSDAR 62 o 1. 72 2.000 I1..7 Rteview pla=t dwgs &-as;e. 144 22 125 i,5 4.60n 1.1-8 PSa, detai1l sad sa-ree I.1.9 Estimate by-prodact iocney LOO0 o;000 I.1.10 Eod prd.ut defpe*on la.LI Detaied by-pod.aa insentary At 47 41 - . 1.800 1.1.12 De.ne maer wooe sequ ae 2'34" 31 209 209 7,5600 Ia..13 Perm SEE and EA 97 1s ill ill 3.100 1.1-14 Pufde S U.s-Sp.es. Cas tR.ady 23 179 17I - ,096 1.1-15 Pepeiaosbit Lijeess Toesinntio plan 128 1i 147 147 l"l.16 Receive NRC appeeaalotoetetrinanoa plan ActivitySpecificatious lo117.1 Plant & tempoeray faciti*-t 23 177 150 - 4.910 lJ.1.17.2 Plant soyals. 20 10O 131 4.167 16 2 18 to 1.117.3 N10S3Des*o*amnaai.uoo Fl soh JA4..1.4 Retaclr ioieoal " - 222 2s 255 253 - . 7.100 50D ls.1.17, 5 Reatoe e-astl 203 so 233 233 1a,.17.6 Blolegialshield 2 18 10 is 112 112 3,120 a-L17.7 Stinmgeooreatss 97 7 07 10 1.600 1l..1.17.8 Roinmoe cdooute -0 1.L117-9 Tciai & sadenser 28 4 29 29 lu.117.10 Plant t ta & bndg 10 112 00 56 3.120

,197 4,600 1tu.L17.11Wastemanagement

• 144 22 165 162 is 1.117.12 Pacit2y &sit. tloaiate - 28 4 32 10 162 37.827 la-1.17 Tatal - 1.180 172 1.917 2,120 10 a.

Planning & Site Pr-aoatienn lo.LlS eepe amaotling sequence

• 72 11 86 as 2,400 1a.1.19 Plant psp.& temp. seam -2304 346 2,650 2,650 1.1.20 Design water elo-auap system 44 7 so 50 2.1.21 kieglCanCat 1lEsnlpneaatoolietn. 293 2,243 2,243 l.1t22 P suo M .Aiaer

& ansta.s[ 6 44 44 1,230 la.S Sablotal Peril lhAntieiy Cu.ot 6,555 gas 7539 7.976 1.2 Rahtalt. euiod tsAddit-aaaI Co.at 7 31 Period Is'eelad.Depodent Casts 1o.&I Ins.-touee 73 604 804 1L.12 Property 9axes l.4.3 Health phyasls saplres gal 83 413 413 1.4.4 Heavy eqalpatot rent!l 52 401 401 gee.-ted t0 17 11 61 61 323 - - 10,725 131 ts.4. DliapsolofDAW f

la.4.S Plant energy,hogie 949 142 1,092 1,092 o.t.7 NRC Pees 30 332 - 332 302 1a.4.8 Ea*"ogeucy P,... Pans a 07 - 17 TLG Scruices, Inc.. L S Copyright PSEG Nuclear133211000

88 Document PO 7-1425-003, Rev. 0 Solem GeneratingSWoIoan Appendix C; Page 23 of 22 Denoomaoosoonlnj Cost Anal~sis TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thoussaids,of2002 Dollars)

Packaging Traosport Off-5ft.

Processing LLRW Disposal Other Total To1al LI..NBC Term. Spent Fuel Management sit.

Restoration Pro-Siurd Volume -Class A B~uri2lVue Class B Class C GTCC Burial Weight Cralft Contractor W{iil and Decon Removal IActivity Cost Cost Costa Costs Cosot Coote Costs Cootigesncy Coals Cools Costa Cools Cu. Foet Cu. Feet Cu. Fet Cu. Feet Cu. Feet Lbs. Manhours Manhours I I lndex Acuinitv DescDtmon Peerid 1. Psoioat.DepeuotCota (mointued) 10s4.t Spent Fuel Pool O&M 951 141 1,093 - 1,093 814 122 936 936 1..4.10 ISRAComptiooaStaff 2] 3 26 - 26 1.4.11 Dh. Fuel Stooeo O&M CCost S 327.109 1o.4.12 S-ity Stff*Cot 0a2 79 607 607

- ,.190,902

• 18,800 2,847 21.27 -1,827 1.4.23 UclUty Staff Cast 1,127 SOS - - 10.725 131 314,111 6*0 10 3 27 23,311 3.589 27,630 28A478 1.,4 SouhttalPes*o Costa Fal.Peu*0d-Dependent

- 680 10 3 87 29,8608 4,172 35,188 33.349 '1,157 162 535 10,725 131 B97.924 Ila0 WTAL PERIOD 1. COST PERIOD 16 - Delouamilouonlsg ProPeotloo Period lb Di-tf ct D-frlm al f A iiti*e.

Deltaild Work Pronmlues IbLL" P1u1- dlaty rals 148 .,- 170 1,5 17

,7100 a1 a 38 26 lb.L2,2 M05 De mo.ouaotlon Fouso 78 12 s0 99 ib.Il tseaur natecraa= u 36 42 6 48 12 * - 1.000 lb.1.1.4 ReamarltWg btall*igs 81 5 19 so Ib. LL5 CRD moolag -anaubly - 1 0 30 15 1,000 lbýL.L8 CRD housilp & ICI tubo 8 31 36 - - 1,000 91 1b.3-1.7 I-oialnxtmoetatioo 8.630 113 17 120 130 1b.LL8 Seartuoose! 1,200 117 6 43 22 122 * -

1.0LL9 Faeility aluseost 14 5 16 18 lb.1.L19 9.S5iosleabtela, 1.200 37 - 6 43 41 144 22 165 18. - - 41.000 lb.)..L52 Seu .me.eraonre - 1 9 38 18 18 1.000 J.".1.13 lelnrmrasd monreto 11. - - - 2,120]

07 15 112 -

i21.L14 Turbies & -o.do.asos

• 81 18 098 0 10 1h.LLt6 Aussf buldiong - - 32730 8 13 9 8 2,730 16.03.1 Reactor buslding .24 *3.243

• 1037 . 156 ,193 968 16.31 Totaw 1,067 -

1.134 5097 1V701 1,701 5b.L2 Doss pd-mo-y loop 1,067 33.243 1,1.4 *1037 722 2,893 2,669 224 1b.1 Subtotal Period lbAxvty Costs Peri- It Aadiulosal Coors 1t.2.1 Spent F-uFupol ltianJ - * .- *

• 51212 728 6,040 6.040 104 000 800 t1.2.2 Site C1ao*eoim=tfon 92 8,840 0,840 th.2 SubtotaaPedoludl1alutiaLCuuts - -- - . - .,48 Period lb Collateral Coma 817 817 107 1b.3.1 Dens eqs pa etn 710 1,819 210 003 496 4.799 1,352 7.205 7,205 981,415 11.3.2 Pensuliquid vrasts 17 0 1 1 11.9.' Small ta*olllo*sre, 2.048 911 137 1,048 1b.3.4 Plpe cutali eq uipment - 2.999 210

• 1a RSbtatamlPeelod lb Colaseot Cools 022. 503 496 4.799 1,596 9,070 9,070 7G7-

. PosIes lb Prlod-Depeandent Costa -"

5 27 27 1b.4.1 Dons ouppliet. 22*0 402 37 402 Ib.4 rpetn Ib.4.3 Property taaeý Copyright PSEG Nluclear 1999/2000 TLG Seroiee, Inc.

Salem Gertratitg Station Document P07-1425-003, Bie. 4 89 DeConrm issioning Cost Analysis AppendLt C, Poge 14 of22 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands ot20H9 Dollars) l tn....- ...... R po ul St rcsedBra oursBra tlt n ;ttr of-srte LLKV Di*opsal Otler Total Tatal Lie.HKRC Ter. 5pent Fuel Monagegeut Site Rtestoration P-ce-.ed Volume Class A Boal1 CIas B Veol-r~

Clabs C GTCC Dura Welght Craft Utilityan Cotrsctor l Dorn Removal PFlaglng Transpori Processing IrdOO , Acovrrn ULstPOtWO Cost Cosi Cost. Costs Coats Cotl Coasts Contigency costs Costs Costs costs Cu. Feet Co. Feet CU.Feet Cu. Feet Cs. Fe't Lbs. Mantho-r Manhoumr Period lb Peried-Depeodetc Costs (ountinud) lb.4.4 HeIlth physiusaupplies 170 42 212 212 hi4.5 toavy equipmeat reatal 174 26 2ot 201 Ib.4.6 DtapussloifDAW generated 1 - 2I0 6 32 S2 284 5-.94 70

.b.4.7 Plant eu,"y bdeud. - 949 142 1,092 1,092 19.4.6 NRC Foss 182 13 200 200 "19 -

lb.4.9 Emurluei¢yPln ... Feos 17 2 19 lbA.10 Speot Frel Pool OVA 472 71 242 - 547 lb.4.11 ISRA Crepliace Staff 4117 61 468 468 lb.4.12 Dry Fuel Stoerna O0M Cort. 12 2 1s 12 tb.4.13 Security Staff Cat 40 203 503 11.4.14 Utilty Stuff Cot - - 9,450 1,423 10.913 Ic1ing 148.491 19.4 Subtotal Period lb Period-Depeodeat Costs 29 344 5 11 A1a1i 1.876 14.430 13,851 284, 5,694 70 16--088 579 224 lb.0 TOTAL PERIOD lb COST 1,923 1.,26 BOB 498 4.816 19,147 6,0,6 332.33 32,431 284 5,919 9897109 1,347 195,329 PERIOD I TOTALS t.93 1,936 51 Sot 4.954 49,012 9,658 60,402 06,20 1.735. sea 819 5,919 .197,834 1,478 593.253 PERIOD I1. - Large Component Remrora Period 2s. Diwat DeonmtuoluoludgAtiouie NWoo.* St.amt Supply Suso Removal 2o.LL1 SoadarCol-atPipiag 290 225 20 20 436 1.920 I, 2A.038 185,121 10.107

- 19*

110 2a.L..2 PososRe SliotTank 2o 20 0 3 97 BIt 310 - , 3.553 527 21.LL3 Reactor Coolant Pumps &bfoture 51 90 42 1.843 197 3,379 1,204 6.744 6.744 24- 2,192 698,870 32580 2aL1.4 Pruesmuer 44 56 s11 460 1,487 - 514 2,933 1.933 2,58!9 304,291 2415 2a,.L1 Sts. Generatons 273 2,229 870 5,191 16,002 109 5.942 31.613 - 51.013 21,467 - .459,55 123,32t 2.LI.6 CRDMuIICtulSoo. Structure R.-Inul 152 97 12d 17 220 1.031 1,021 -89022 4,564 -

2a-LI.7 ReactorVoselt rItorual 119 1,971 4.979 237 4,7275 214 5,312 17,907 17,857 1,177 803 459 S B29,828 31.6098 1.390 2.LI noactorVosaet 98 9.432 12.104 293 - 6,672 214 5,955 17.0*3 17,233 -4 4124 2.246 948,723 51.608 1.396 2a.1. Totals 1,168 B.96 7.929 0.600 107 93,668 528 19,550 79,660 79.648 248 51.384 31,56 459 6.0S6.870 98.161 2,773 PReoteeoofMujr Rtripruent 2.L2 Mrial Trbtrl.-nresator 474 58 11 719; 233 1,488 L,438 5,244 -

a.L.3 Main Co -. rs 1,607 93 11 609 511 2,972 2.872 &,446 11,671 -

Dispol flPlant Syotaur 2a.t4.1 Auxiliw*lFeedodator -- 44 - - 7 31 892 2a.4.2 Auxill.ary eedunter 0(FCA) 281_ 2 4 293 i1r 67 697 - 1.460 . 15,323 -

2aUL4.3 SBleedStessu & floater Drains 140 91 162 1O02 2,984 2.L4,4 Croulutio Worex 229 84 904 264 - 4,717" -

2.14.45 Clouo-ttgWauo Scap]og ,5 -

- a 1 a 104 2a.1.4.6 Coudesots Polbisng 804 6 12 761 343 2,025 28 8.806 17,77 2a1.L4.7 CodoriusnrAlriuotIa& .. Priming 125 29 144 144 2,993 20.1.4. Cunn ut horsy ,5 . . 1 6 - S 104 2&.L4.9 CuotaimotSptit (RCs ) 106 4 7 41 100 699 699 2,483 2,075 2o.L4:10 Equipmrnt.Veuta & Diats -Cuoooltnat 6 0 0 0 4 2 19 105 717 115 2.1.4.11 peednterCbhemiaITrea4esut 9 27 -1 1 t1 29 8 182 2a.1.4.12 Geneeator St*tor Cooln Water - 27 4 At 2.1.4.18 HetouerVoon & l[jetttooooua Drains 33 0 0 2 12 72 72 "19 2s.1.4.14 iydreopa & Corboe Dioulde 11 ". 12 4 480 24 46 2 13 235 2.1.4.1 Meta.s& Soboso& Turbis. By-Po. Stoan 8.602 079 4.1398 4,139 15.149 9.343 TLO Servic", Inc. Copyright PSEG Nuclear1$is 9/2000

90 Salem Generating Station Document PO7-1425s-003, Re. 0 Deoommttofontng Cost AnalySIs 'AppendiJxC Poge 12 sf22 TABLE C-2 SALEM GENERATING STATION :UNIT 2 DETAILED COST ANALYSIS (Thousands of 2001 D ollars)

Off-Sit. LLRW NRC SpentFuel Sit. Pro

... cesd BrialVolohnos Burial Utityaort Atjlity Cecao Reronvt Packaging Transport Proceosthg DOlposol Other Total Total LIe, Terme. Management Rtestoratio Volrme Class A Class B Class C GTCC Weight Craft Contractor Index A DoesDlcripon Cost Cost Costa Costs Costs Costs Costs Coogen Costs Coot. Cost C1sts Cc. Feot Co. Feet Ca . Feet Cu. Feet Ca. Feet Lbs. Manhoum Macboon DOhpmcal ot lant Sestea= (coctioowd) 2a1.4.16 MainTurbioc Lobk.ir tg Oil 18 118 817 - 2.099

- 51 - - -. 7 87 57 - 1.051 2&,L4.17 Miscelaoeoos- rodernoate 2a.14,1 Moi"stZr Separa~or Rehtr. Steam & Drans 437 3 3 32M 189 931 931 - 1.038 -8,614 2a.t4t19 Oil Water Seporar 44 . . - 7 51 - 51 . 977 2.1-4.20 Steam GC. Dracns & Blowdon 182 1 2 102 81 348 348 512 3.566 2.1.4.21 Steom GCo Dacos & Blowdoto (RCA)

• 38 8 o 18 - 82 68 68 - So 694 2.L4.22 S .eam Ge Feed -p & TurbioneLu Oil 29 4 33 33 - -11

- 328 - -

2aL,123 Steam.Gecerator Feed & C0ndedsaite 51 334 394 - 7.097 2.1.4.24 Torbl-AuatLtadae Cotng - 168 - - - -

22 193 - 193 , -8,4 4 21.L4.23 T'rbloe Dca.E. 36 0 1 as i8 82 88 - 102 724 2U,1.4.26 Thrtahi Eloccro-SH-yda..c Co-ttat 4 L 4 4 73 2.1.4'27 Turbioe Oland Seallag St-em & teal-Off 75 - - - 11 87 - 87 - - 1654 2.A.4-28 W-ce DOLsosl - Gas 90 5 3 128 99 87 332 392 640 233 20,293 1.803 2.1.4 Ta."ac 3,981 46 81 8,20 103 1.678 113.88 9.473 1,622 28.031 241 21,010 80,312 21.15 Scsildilo in supcport of deaoomisooio; 821 4 1 49 11 2118 1,583 I103 247 34 32CM 188470 2.1 SabrtttalPctt -n Aattlty Coot. 1,168 L4,948 8,088 8,748 8,787 32,781 628 2.18,8 06.206 84,584 1.622 33.547 51.659 3.156 459 6.050.448 237.859 .7093 P2.l Su2c....pMaki C- .1Jv C Pnzi9ai Aditbcasl Ccoss 2a2.41 Cdo Surahrg.e (E.unalg8PV) . 1,374 - 844 1,718 1,718 2a.2 Subtotal Period 2,Additiocal Coat. 1,374 344 1,718 1.718 Perod 2a Collateral Costs 2.3.1 Proneacliquidwasteo 73 - 28 as - 14 - 127 6088 si6 1510 64,227 106 2W.3, Smut tmlaltowanet 219 93 252 227 21 2.3 Sstotlpedod 2.. Coloteral Costa 73 219 28 65 314 150 a5s 833 25 10 84,257 DO*

PF.old fo Peoiod-Depecdeat Cost.

2a.4.1 D.eeo spplies 72 - - - - - 18 93 90 2.4.2 Iasnmtaon 122 J.IM8 1.338 2.,23 Property tlaes 2.4.4 Health physice sapplios - 1.864 . - . . 341 1.703* "75 2.4.35 Hoanequipmeo naetal 3,144 - - 472 3a818 2,615 2&.4.6 Dfltsol otOfDAWgceanrted -8 24 324 93 528 528 4,22 6 9,621 1,12s 2.4.7 Ptante-=o, budget 1,801 2325 1.728 1.728 204.8 NRC Free 523 52 876 578 2a.4.9 Em:*eoeory Pta ning Eeeos 66 6 62 62 2.4.10 ISFS[ T-*nafelr and Capital Costs 2,464 220 1,884 1.884

- . - - - - 1,-82 1,484 2a.4.1.1 Spool Fuel P=1 O&M 237 1.819 - 1,829 2.4.12 tSRA.Cotpltla.tc StoP -- - . 1.884 2903 1.558 1,558 2a.4.13 Dry Foel Sotor; b&-M Coat 38 6 44 44 2,380 0537 .737 2.737 - -- - - - 1.22,870 2aA.14 Secusity Staff Cost 2a.4.15 tlfi'y Sc tCost - 44,673 6,731 11,274 51,374 671,G40 68.853 65,245 3,808 -4622 92,621 L131 794,310 U.4 . Sobt*tl period 2& Peroa-Depesdent Coat. 72 4.601 88 84 324 04.788 0.051 2&.0 TOTAL PEL0UD 2mCOST 1.313 19.675 8,199 8.8 - 6.767 35.7393 85,318 81,744 107,611 388,378 3.G08 1,84 3,547 0281 5%4 3,666 4.39 631722.3 138.994 797.103 TLG Service4 In., Copyright PSEG Nuclear 1999/1000

91 Salemn GeneratingStation Document P07-1425-003, Rev. 0 DPeom tssioning Cost Analysis Append r g Page of22 )5 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS 2

(Thousands sf200 Dollars)

Off-Site .LRW NRC Spent Fuel Site Prosoed Bunao Volumes Burial tility nd Activity Daean Rmrnoovl Ppackglog Transport Pro*zosteg Disposal Other Total Total Uc. Tern. Marngement Restoraoloa Volume Class A Closse Class C GyCC We;iht Craft Contractor otdes Acivity Descripton Cost Coot Costa Costs Costt Cools Cools Coedgsa Cools Cools Coos Casts Cu. Folt CU. Fl Co.Feet Cu. Feot Cu. Foot lam Manhoumr Iohooro PERIOD 2- Sitt DOeoetaoirattioa pood A 21 DrtooDtfl.mmmiusioetog ettt fliopotsolof lnes Systems 2b.Li Boidir: & Equpmo. rtno.Ceooetooo 40 . 4 46 - 46 - 80o 2b.1-1-2 Clam & Vol Ced - Boretk.Acial vory 519 507 41 8 218 845 630 2.7T4 2,774 4- 1,098 0037 17.,866 19,842 21.1.13 Clam & VoI Ctel- Pray Wotor-Rovery 008 947 28 6 153 08 432 1.890 0.890 788 1.633 112,642 13,399 2b.LI.4 Clam & Vol CIt Operation 455 M00 34 6 t1 200 20 Z349 t349 8 234 1,695 143,28S 19,071 2b.1.1.5 Cbitod Water 185 28 213 - 210 4,017 2h.L1.6 Chied Woaer (RCA) 197 1 2 188 70 408 408 689 3.683 01.1-17 Co*mpoeot li is 2 i8 - 18 -

211.1 .8 Componen.t Cooling (RCA) ass 8 1s SS6G 040 1603 1,603 -8 4,928 - 6,029 2A.t.1.1 Coape.soer Ald 17 120 128 2a.1.I.10 Compoo-uodA.(RCA) 78 8 1 980 925 2, 100 - 174 1,55d 2U.1.*11 Cooeol Atr - AsniliuXy Beilo 131 1 2 128 52 a1! 318 640 2,673 23.1.1.112Caosurl Air- Coontotomeolouilding 42 0 1 40 17 99 99 860 2b.A11t Control Air . Poentratla A*% 32 5 37 37 - 673 2b.1.1.14 Coatrol Air - Toebtc GOoooraoor.e 46 7 . 2 565 52 2b.1.1.1 Doodmooolizud Wocor - Iesotrlcte Areal 0 1 is 22 129 10- L123 2b1 .1.16 Deo, olaeo Wotr-Msm-up 43T 66 003 503 9,'O8 21.1.17 DOtsolEogine Auhtolos "128 19 148 148 - .602 2.1.1.18 Rleoi.o 11,421 51.0 3.904 .93 2,28 69,784 2b,1.-1-0 Slootolo (RCA-- Cles) 4 7 448 010 1.247 1,247 11.303 2ILL20 floe1 e{RCA) 190O 1 0 176 74 444 444 - goo - ,808 2b.L11 Flra P-ottian 2O8 09 294 294 21LL22 F-n' Pe otio. (CO2) 2 16 16 - 308 S 14 2b.1.1.23 Ftir Protoeoton (RCA) 61 001 001 ,*849 1 2 log 044 -

2b.LL24 Fl*er D3)tos -Coct-itratd 156 I it1 163 80 429 409 81 072 33,319 3,228.

21.1.1.25 Fresh Water 43 027 227 21.LL.6 Pal OLd 33 203 - 4.452 421.1.2.7 OSVAC-Ao-dlos Boltidg 2 2 18 27 102 587 587 - 941 62 5,534 4.912 21.LLU28 HVAC-CoteoLIAoe. 6 78 4 29 29 - 32 26 2b.1.1.39 ]VAC-Dieol GeoeooatAre*oe 1 7 - 120 21.1.1.30 HVAC - FuIo di Azet 0 1 01 103 48 277 277 2,676 2,268 65 - 440 20 21.l.1.01 IIAC . litoeollsoou. 27 200 3,948 2tL.ML3 HVAC: M-11 1286 203 ato .cnthle* G 8 488 74 263 1,518 1.518 10.1D4 12,013 2b.1.1.32 HeVAC.*StraorCtoemn u - - Z441 169 159 24 183 -- 8,462 2b.1.124 Heatito St-m & CooS Rat (RCA) 1 "8 1 1 86 45 261 061 2,8M2 21,ý.1.124 1e1-tnm W.iuglson&Coolooo Ib.LLI. Htta Wa*tR.* RA 17 008 - Z326 64 00 16 128 1.198 1b.1.1.37 Htog BuloeAWG--. Fl*o & oiotioe Gas 4 1 0 193 - 02 2bL.L.30 Oi.tell** eous R*.ctor Coolont 58 1 0 11 9 10 98 89 34 43 - 1,814 1,247 2b.1.1.539 N04-Rodiu.etie Liquid Wo'o. Dieposal 321 48 369 45 *3G 2b.L L40 Pl..biog.-OHt oad Cold Wae - 7 0.

30 2.L.L41 Pla..big -S.U.7

• 34 71 01 140 1 54 643 2,570 230-393 .6803 2b.1.1,42 Resldusl Heot Reorl 00 00 120 1.126 417 2.029 Z028 703 s.9 1179

-28 564 204,1020 3,623 2b.l. lA Sooty[ejtlo o - 40 10 228 887 -- 694 3.068 0.608 L125 2,713 2b.1.44 S-pHlg 0 1 53 71 57 200 010 267 164 14,718 2.623 856 1 12,604 A2'1.1.45 SOk.m Water - N--k]ao Are. 01 .39 0,621 600 4.037 4,037 - 16.744

- 561 0 71 " - 1.336 2b.1.1.46 oeetmWater - The1,teoo--

2b.01. Total. 1.99.5 L2,50.5 260 130 6.s9" 4.591 0,664 3L049 24,496 838.460 285.358 TLG Services, Inc.. Copyright PSEG Nuclear 1028$.005

92 Salem- Ceseratlng Station Doc-asezat P07-M4-5-003, R- ,

AppendEx C, Pug. 17e 12-Decoseseaý(ning Cost Analysis TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands of2002 Dollars)

Off-She LLRIW NRC Spentfuel Sit. Processed SurfalVetuloes BEMtal UtilItyand Activity Decot Removal Pacslaonoo Transport Processing Disposal Omler Total Total LltcTerm. Maageetetnt Restoration Volut ClassA ClassS ClassC GTCC Weight Craft Cortmctsrr lndex Antis Dec pton.. Cost Cost Costs Costs Costs Casts Costs Contingency costs Costs Costs Costs Co. Foet Ca. Feet Ce. Feet Ca.Feet Cu. Feet Lbs. Manhoour Manhou.

2b.1.2 Seaffli to suppot of dromotiioaino t,027 5 1 02 13 270 1.479 1,579 - 09 43 3.835 G3.W8 -

Dfeetaoloatbo of Site Bildip 2b.1.3.1 -eWtsrConsa-i-o t 1.202 757 124 88 115 L293 1,151 4.743 4.743 576 7.941 738,59 37.987 2b.l.3.2 Asditiort BuIldioz 400 199 32 22 28 71 279 1,033 1.053 151 2.053 -21.223 11.426 as 23 4 a 2 5 36 128 120 8 295 20.374 L474 2lv.2.3 Ceono "ad Fanltles Bueld!e.

2b.1.3.4 Stes m ooeaear Re .ova 12 2 0 a 5 0 - 7 07 27 24 2 142 218 2b.1.3 Totals 1.672 982 161 215 148 1.373 1.480 5.90 5,930 739 10,932 950,604 31,074 2b.1 Subtatal Pceiod 2b .AcstvinyCoats 2,460 14,513 431 2*47 5,053 5"97 - 7,414 25,071 3104 7,053 33.0421 22.133 - " 1,929,902 359.520 Period 2b Collateral Cousr 2b.3.I Piace liquid waste 202 - 05 251 - 83,2 - 632 3.181 3.210 2.652 385.235 315 2b.3.2 SoalI toot alo-astce - S2t1 . . 48 369 309 2b.3 Subtltal Pexiod 21bColatera Costs 202 821 103 281 - ,;83 - 050 3.550 2.500 2.652 385.235 315 Period 2b Perrid.lt-poedot Cota 2bA.1 Demo a.pplea 040 201 803 a03 2,.4." 1-.r-nre -07 69 706 750 2b.4. Propadvty505 2*.4.4 Health phyaia suppils- 499 25,400 2496 essy eqo'ptest reeled - 4,803 684 5.247 5,247 213.4.5 86 24 33 93 52 5 5 4,012 22,423 1,12 2b.4.6 Di-poal o f RAWgon.roted 2b.4.7 Pl.ot eors budget 247 1.897 1,097 2b.4.8 NRC Fees as 748 748 Z54.9 Enet~enyPtatng Fees - 70 8 al -

22,950 5,093 29,048 29,04.

2b. 4.10 =fTiatsferand Capital Costa 21,4.11 Spot Foel Pool O&hf 2.205 330 2.50 - 25323 2b1.4.12 Radwa.e Pt ocs ng EqutlpmeatSefldmee 63 481 481 21.4.13 IS.A C-mpll-s Staff

- 1,009 283 2.169 2169 21 24.14 My Fuel S-nae O&b0 Coots 63 8 61 - 61 2,6s6 080 32.0, 3.055 - - . - 125.091 2b.1.16 SUory Staff Cost 21L4.16 Utilty &.ffC..t - 60,72. 9,108 09.832 09,832 915.840 642 6.500 86 24 323 104.989 17.112 129.725 0.5008 41.721 4,L2 92.423 L132 1,052,731 2b.4 Sobltl Period 2b Perod-Depe-edet Coota 700 551 93,042 28,747 2,52 2b0 TOTAL PERIOD 21, COST 4,51. 21,594 0,020 .103 104,989 2=,207 172.144 128,203 41.712 7,053 - 3287.569 350.900 1.01731 PERIOD 2e -De¢ioatmtrd*.e.o FalorIa g 71et,rol Staoe PeioosoD2c nllteIt nemmiaiasg ncnttvsie 2.1.1 R-ooa ".tloae*lraclo 05 62 132 11 416 144 379 1,638 1,638 2.081 457 41012 L19 DiJspess otPhlat Syaoems 2e.1.2.1 Speste.alColieg 186 38 9 197 021 294 1,575 0.57 010 1.941 174,052 3.764 52 551 45 a 150 934 n2 2,402 2,4U12 901 2,407 191.109 1+/-951 2.,L2:2 Wea. tllopns-t-isoid .

- 61 9 1 49 107 49 267 267 2239 253 21.850 1.2-09 2e1.2.3 WateDlLpo.1-SnliA 352 598 as 19 422 1.891 874 4,244 4,244 Z,110 4.101 -80,019 17.925 2,21.2 Totals Dsnotanatdoa ofSit.Eoldzinga 26 2c.1.3.1 Fuolotadli.g9Bfldlug 517 015 a 7 460 1,848 1,848 -43 468 45.6104 2Z423

.9 7 23 465 1,848 1,848 043 468 45,684 "1-423 2.1.3 Totals 057 815

- 205 1 0 1622 3 54 270 970 02 9 707 4.*51 2.1.4 S*ofoldlat in supportofdemmtoitg Couyright PSEG Maclear 1939.2000 MOGSeruices, Inc.

Salem Generoting Statforn - Document P07-142-002 1 Decsmnealsionlnz Cost Analysis Appendix C, Page 18 ofl22 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands of2002 Dollars) o0f-Site LLXW tRC SpentFooet Sie Processed suri Volumes Burial Utility rod Activity Deson Removal Packaglng Transport Processing Disposal Other Total Total Llc.TTerm. Management Restoration Volume Class A Class B Class C GTCC Weight Craft Contractor index Adivity Deesrtion Cost Cost Costs Costs Costs Costs Costs Contingency Costs Costs Costs Costs Cu. Feet Co. Feet CU. Feet Ca. Feet CrMFeet Lbs. Manhours Manhours 2.1 Suhtotal PeriOdt- *ctivty Costs 1.414 1.470 230 37 1,019 2.093 1,772 a.008 8.006 c,065 95803 474.463 46,155 P.r.nd 2c Colttteoal Costs 2k3*l Preoocs liquid waste 68 - 68 108 618 225 1.107 1.107 635 126.460 145 2c.3.2 Small tool aliownuce 02 Drromm s-ou*-igEqsiptenst Diosip*nion - . 48 15 940 117 117 835 825 2.7011 373- 89.507 739 2et.33 2.2 Subtot period 2s Collateral Conts 98 02 106 121 040 732 850 2,001 2,021 2,700 375 930 159.973 w5 Period 2.Peiod-Dopeodant Coon 5r.4.0 Deasupplo. 97 24 121 121 2.41.2 tuesos.- it 122 122 2c.4.8 Property lat.es 2.L.4 HaUtr pbhysit supplies o 320 95 476 476 2c.4.5 Heavy equipment Tental 1 O20 - 050 1,504 L004 2r.4.6 D1.pQs of DAW ..

e arated . - r 27 155 125 1.359 2-7.233 394 2,4.1 Platonotr budget 22 a6 290 290 2u4.0 NRC Fens 26 312 31.2 2c.4.9 Emerge*cy ptlaring Foes 2 25 25 240 S..t 10 Ra&waoe* PFoce.ist-Equipntolt1Ser.virs B6 25 27S

-40 622 2c.4.11 ISRACooapl~tuttatff- a1 622 Dty Fuel Storao O& f Costs 2 1i - 16 2c.4.12 2U.4.. SssnzStaff* .* 761 114 879 861 3022637 2s.4.14 Utility Sta*Cf t 14.860 2.229 17.089 17,089 3 2 2.7.6,33 2o.4 Subtqttl Period 2l Period-Dependent Costs 67 168 25 7 95 17,085 2.885 21,882 21.840 42 1,3596 . 71,225 834 265,800 2a0 TOTAL PERIOD 2c COST 1.609 9.19) ge1 165 1,559 5,894 17A56t 5,007 31,885 81,847 42 7,706 7,267 630 661.688 47.373 265.564 PERIOD 2o- Lice-se Tero.lalioo Peri-d 2e Direct Docomoniasrnoig Aetivitis 2e.L. ORISE csiooatry survey 122 91 158 ItOs 28.1.2 Ternu nuts *t-i s 2e.1 Subtotal Pe-ro 2e Activity C,*st 121 57 163 008 Portal 2r Additional Costs 2e.2.1 FioalSite SOoro*v 710 5.482 5.495 52092 2S.2 Sltot.ad Perood 2eAddcitioualtosts . 4.767 710 6.482 5.482 89.002 Por.4 So Perod-Dc*podoo+/- C-to 2t..1 insu.-tce 11 125 125 2&.42 Property taxes 2.4.3 Health pbyslcs supples 051 158 686 608 80-0.4 Dioprent eo DAW generated - 7 25 7 41 41 364 7.297 89 2-,4.5 Plant enermv budget a5 237 257 238 90 517 317 2c.4.6 N*C FPro 21 - 25 2e.4.7 E.= osylmatsgn*Fin

.. ts 2 258 2.4.6 ISRACoinyiac SLoE 554 83 637 635 2&4.9 Dry Fuel Storage O&6 Costs 2 16 - 1i 2.4.15 Security Stf Cost 426 64 402 492 2e.4.11 UtiitlyStaffCost 10.411 1,562 11,972 11,872 2..4 Subtotal Period 2e Perid-DoptadeslCosit got 1.95 14.572 14.529 40 au4 7.297 68 0l.877

- 25 02,056 p,,.l.rrnQPflfl,...c.~... rroornror TLC Seretr.-, I.C.

94 Saleom Gnorsttng Station Document d ix CP o se , I Roe.

A p penP07-1425-O73 9 0of 0-.9 .

D e co m m i t o otonin gCo s t A n o lys st TABLE C-2 SALEM GENERATING STATION - UNIT S DETAILED COST ANALYSIS

. (Thousands of 2002 Dollars) off-Sit. LLRW URC Bp.ntFeel Site Processed - Buital Volumes Burial Utility and Actioity Decan Removal Poehaging. Transport Processing Disposal Other Total Total Uc.Tero. Management Restoration Volume Class A Class B Class C GTCC Weight Craft Contractor Index Activnt Des 'seon Cost Coast Costs Costs Costs Costs Costs CDntingenc Coats Costs Costs Coasts Cs.Feet Cu.Feet Cu. Feel C. Feet C. Feet Lbs. Ma-hoe. Manhours 2.0 TOTAL PEROD 2e COST - 59 7 2 - 26 16,944 2,64 20.212 20,160 43 3-4 7,297 K6.281 172,877 PERIOD "20TALS 7,433 44,830 9.267 6,546 14,934 46,895 194,634 94.642 891,880 337.759 45,422 8,.700 74,384 90,669 7,246 469 9,273,U70 742,606 2.288.275 pERIOD 3b - Site Restoration Peris, 2b Direct DeommninosierActivnnlso Dnrotittoc ofrtRooemistg SittBuildi h.LL1 Reactor Coetanirnret 5.750 893 0,818 993 5.626 72,497 31b.L1.2 Aditretlos Rldog 866 04 759 759 10.176 Sb..I.t2 Annilisry BuEding 1,735 260 1.995 200 1,796 b11.,14 Aun yflBuild.g Contsol Aro. 329 49 379 378 4,752 b.1-1.5 As.,Uisy Building IDesel GeerosteArA 105 26 124 124 961 1,1037 10.102 7,269 3b.1.1.6 B-Z, Skip 144 1.193 ab.1,1.7 Clronet Demcial-oel Encos-ue 6 1 7 7 92-b'.L1. i Circuatin Water Inteo Stnructune 169 1.194 1,194 - 6.210 1.873 3,164 MI.L1.9 Circulotr o Water Pipto 261 3,104 $2,524 2b.11,10 CI.- FoottitiesenBuiing 358 64 412 412 2,692 SLUMl condens*ste Potasbg Building 70 11 81 61 9b.L.1.1Z Cootollod Fo liti-estBisg*¢ 292 as 2904 3,780 65 2b.1-1.13 FPie Pump House

• 7 9 68 874 h.21.114 GouardHouse-A Etn

• utn.. 90 13 101 101 1,401 3b.1-.15 Hootlovf ilePloct 91 12 95 90 1,138 bL1.1.50 Win Stk- 1ctsod Structure 104 28 211 211 2,651 21b.-1.17 hlImoolnosus Struc-S 1,894 299 3,167 2,16"/ 24,441 3".1

,16 N-o-t oUd*.q*d Waste COse. T-n e.nt Bldg 81 12 94 94 1,193 3t11.790 Noa-Ro&Liquid Wast. Disposal Des n 14 2 16 16 2 39 6

3b.LUO9 Nto-RadLtqusi Waste Trnsfer House 6 1 6 89 - 4 3b.1.1.21 Penst-oti-oArea 288 49 329 020 - 3.025 3bL.1.22 Srne Bul 820 76 598 - 8.811 06.1.1.23 Ser.vie Water t ale Structure 578 .87 G64 664 3,761 8b,1.1.24 Soage reeatment Facilities 6 1 7 7 3b1.1.25 St.- GeneratormR-l 203 so 221 233 2 ,267 Str,,*L26 Trash -odFIh Rtuloon! Building 18 3 2a 20 269 9b,1,1,27 Trbine Building 3,387 6a8 3,695 3,895 58,328 9b.L.,2 Turbine Pedestal 644 97 741 7441 - 7,217 2.1L29 Wsto PoToseat Building 122 18 140 14a 1.629 3b.LL30 Fuel Hodlg Bildg 2,230 336 2,574 257 2.317 292,63 3bl..I Tetoin 23.544 3,32 27,976 19.53 25,32 821,415 Site ClasocutAct:vities 3b.1.2 ReovelRtbble - 6.866 10,917 8960 079 679 - 1,236 a9.13 . Grade & landscape sitf 5890

, 0 - - 1,806 3b.1L4 FiotlepnmtoklROf 49 7 067 3b.1 ScbtntlaIPeiod 3b Activity Cmto 27.104 49 4,9523 04.6766 2.720 32.937 period 2bAdditioo.l Costs UA2 L Cosete Cruht.sg - * - .S 73 101 77.5 774 - - I - - 4.016 3b.2 S.tuWtol Ped*ai3bAditio u,tt - - - - . 78 661 774 774 4,016 TLG Ser-f..4 Inc. Copyright PSEG Nuclear 1a9'S2000

Salem GeneratingStation Doc.ment P0-1425-I030, A-9 Dedoesetsotontfn Cost Analysts Appendix C, PageBOsf22 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thosisands of 2002 Dollars)

Off-Sis LLRW NRC SpentFuel Site Processed Buria.lVol .s B-ia1 Utililyand Acttsty Decorsn Rem'oval Packgaging Trtnsport Ptoaeostg D~sposal Other Total Total Le. Term. Management Restaetion Volume ClassA Cta.S R Class C GTCC WeIght Craft Cont-actor laden ArtlvtDescription Cost Cost Costs Costs Costs Costs Cate Cotn oss Costs Costs Casht Costs Cs. Feet Cu. Foet Cu. Feet Ca.Feet Cu. Feet Lbs. Manhouse Manbous Period 3b Collateral Costs 8b.3.1 Stol taotttasess-ce 305 46 561 - 123 - - - - -

3b.3 Ssbtot lPeriod 31b Collateral Costs SOS 48 331 - Sot - - - - -

Period 3b Perad-oepenodent Costs 3b,4.t Insroce- 209 21 230 0 207 29 3b.4.2 Property -.- -

3b.4.3 Eeosyoqsippmeo t reslat 3.344 -- 30 3,8430 - 2,41 3b.4.4 Plaot e bgybudget -08 21 237 118a 118 3b,4_5 NRC r5F$2 Frs- IO- 10 110 -10 -

3b.4.6. EirreocyPltssIzrsF 42 4 47 47 1b.,4? Dry FuelStorage O&I Costs ' 29 4 23 33 2t.4.8 Scroity StaffCoot -M9 118 907 (0) 608 299 , . - 40.654 a1.4.9 UttltityStaffCoot 10,926 LOS3 12,565 - 6,283 6.283 156,713 31.4 Subsotaelpeod 31, Pertod-Depeodeat Costs 3.8,44 12,802 2,329 17,975 (9) 7.458 10,669 8b.0 TOTAL PERIOD 8b COST - 33.763 13.024 0.,22 03.773 1,739 7406 44.631 337.647 298,930 PERIOD 3c - Fuel Storage Operattodstshippisg P'eriod.3c flirectflsraooo Isssigrtrte No dirced ati*ities In this period.

Period 3c Perbod.Daeps-det Costs 2.4.1 Insu e 2,604 160 2,864 2.864

-4.2 Property ozes.

2e4.8 tt proo bsdet 48 73 981 1561 0SC.4 NRC LSFSIFees 1,448 145 1,293 1.593

&-,4.5 RaeresryPtsngFees 612 81 673 678 2c4.4 ISFMI Tras~er mad Capital Costs 1.967 290 2.362 2,202 a4.7 DryFoot Stsona O4-0 Costs, 410 68 472 472 3c.4.8 Secouity Stis Cost 7.,594 1.139 8,733 8,733 391.376 3S.4.9 Utiuty StffsCost 40,470 8.102)( 48.770 48,770 586.*95 3a.4 Subtoatl Period 3c Peraod-Depe.dent Costs 55,,27' 8,138 63.929. 69,9299 907.702 63,929 097,769 3.0 TOTAL PERIOD 3. COST Z5,793 8,135 83.929 PERIOD 3- GTCC shipplng Period ad Direct Delo atssioasil Activities Nuclear Steam Supply System Removal 3d.3.1.1 Veassl & Itersls O7CC DipossI - . . . 2f491 1,874 14.364 14,364 613 34.21 Totals - . - . 12.401 1,974 K4.514 14.394 613 3d.1 Subtotal Period. 3, cti,*ity Costs - . . 3Z401 1.874 14.064 14.864 -13 Period 2d Perlod-Daipeodes Costs 3,14.1 45 os sa 1 6 2d.4.2 Property toots 8 Sd3.4. Plant eneo0y budget * - 1 0 1 2,L4.4 N91CISFSI Fees -a 3 3a.4. Emeezeoty Pts..isz Fees 2 0 2 2 24.4-8 SFSI Trsasr sod CpitLi Coots t13 27 Sig 10 21.47 Dry FPol StSaOga 04I[ Costs 0 1 TLG &-kes., rac.

C.opyrigh7t PSEGNuclear 199/52000

Salem GeneratlineStation Doernmat P 7-1425-002, Re. 0 De-onMlisaoning Cast Analysis Appond i Q, Page21 of l3 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands of 2002 Dollars)

UAW tORt Sport~ool silo Processed surialVolumea li3.4.1 Odlltyand ORf-Site Activity Oeaon Removal Packaging Transport Processing Disposal Otrer Total Total Ltc.Terr. Managemroent Res~o-touon Volume Clss A Class 1 Class C- GTCC Weight Claft Contractor lnule.r Activity oesr.ptlion Ctst Cost Coots Corts Coal. Cools Costs Contlinenry Cools Costs Coast Costs Co. FPoo Co. Feat Cu. Foot Co. Foot Ce. Feot Lb.. Manhours Manhours Perioo 3dl Poaid-Depandeaot CrMa (wootir-ud)

X4.8 Seoority StaffCact 17 20 900 3d.4.9 Utility StaffCost 94 14 IDS 108 1.371 I34 Subtotal Period 3d PeriodoDepeadentCosts 09 0- 46 3a% 355 - 271 1d.0 TOTAL PERIOD ad COST A1491 209 1,919 14,719 14,364 358 613 PERIOD 3o - 7 DI eonoto taa).

oo Polodo 3 Direct Dcorrmsoaaioonitg Aotltrts No dlooact ci*-il.s.n tib P*o.&

Pozo*,o3.oAdliotial Cons Ba.al1 ISFSMlLita.sT.esaioatioo

• D11 10 78 312 956 487 2.853 2.655 6.997 789,883 16,537 1.696 aeIt Subtotal Period leAdditkooal Costs 1.311 10 78 312 956 487 2.813 2.65 6.IT - 799,813 16,537 LMSO Period So Collateral Casts 3a.$.1 Small tool allowance 2 15 -s Subtotal Period So Cll.tUrol Coats

• 13 2 is51 ao.3 Period 3e Portod-Depoodoot Costa 1 50 50 10.4.1* prpertytaxes .

3U.4.3 osy rerqtp nt reotat 82 12 94 94 3u.4.4 Plant energy budget '52 8 09 59 8o.4S5 NRCISFEI Fe.s 75 8 83 63 Se.4.6 SorotyStafftCot 67 10 77 77 3.460 30.4.7 Utllitys affCo-t - 85 129 987 987 U*486 3.4 Subtotal Period e Peari-Depedezt Costa 81- - 1.07 171 1.351 1.B50 10.935 30.0 TOTAL PERIOD Be COST 1,106 10 7 - 312 2053 660 4.220 4.220 4.220 6.997 799.883 16,537 17.lial PERIOD 31- 37FS6Site Restorotion Peo Dir. Del"mmlioalog Actities No direct activiti*s In this perlod Period 3fAddhioeual Costs 8212 ISFSI Sit. Reotaorntl 1,075 23 272 1.37-0 170 4,904 I0D

• 1075 320. Subtotal Period 3(Additlooul Casts 272 1,30 1,370 4.904 106 PeriudSColluaterat Costs BE2.9 Sonall toolellowceo 4 - -

s20 Subrtotal Period 3fCollateral Costs Period Sl Poao-f-lo-peadrst Costs 3E4.1 l*s*.r..us 30 2 27 27 324.2 Propertytoseo 314.2 Heary oquiprroeatsootal 32 9 30 306 E4.4 Plant enery budget 28 4 32 32 1EA43. Security SuffCoos 87 6 42 42 1.690 3.830

34. Utility StaffCoon 328 34 264 284 SE4 SubtotalPer.d 36FPertd-oeapo.deot Co*ta 32 Sig 01 402 402 5.2s0 310 TOTAL PERIOD 2! COST 1,110 842 324 1.777 1.777 4.904 5.926 PERIOD S TOTALS 35.969 to 8i 12,903 71.521 18038 128.4.0 16.103 77.686 44.631 6.897 613 709.883 333.029 1221.928 TLC S.r*-, Ine. CupyrlsltPSEGN-clear 199./2000

-97 Salem Generating Station Dccu.nntP07-I406-032, Rev. 0 Deiammissionlng Cost Anafysis Appendi: Q Page 22 f .?2 TABLE C-2 SALEM GENERATING STATION - UNIT 2 DETAILED COST ANALYSIS (Thousands of 2002 Dollars)

Off-Site LLRW NRC Spent Fuel Site Processed 1urial Volumes Bsrial ltilityo Activity Den Rontowal Packaging flTansport Processing Disposal Othar Total Total Uc.Term. Management RPsloratlon Votosna Cls A CbaSS B Cass C GTCC Weight Craft Contractor Inde- Act]tn- riptl.n Cost Cost Costs Costs Costs Costs Costs Contingencv Costs Costs Costs Costs Cs. Feet Cm. Feet Cu. Feet Cu. Foet Cs. Feet Lbs. Manhoum Manhouor TOTALCOSTmo DECOMMISSLON 9,366 86,735 6,735 10,125 14,34 64.541 $14.668 n338 698.702 420,141 124.844 03.717 74.a84 98.47"1 13,167 459 613 l1,071,590 ],103,12 4.093.416 TOTALCOSTTODECOMMISSION VWTH18.24% CONTINGENCY: $596,702 th-ousnds of 1002 dollors TOTAL NRC LICENSE TERMINATION COST IS370.213 OR $d06,II th.oasnd. of 2002 do.11.

SPFNT FUEL MANAOEMEINT COST IS 230.851 OR: $124,844 thoasaads of 2002 dolseas NON÷NUCLEAR DEMOLITIONCOST IS &97% OR: $53,717 thomanssat of 2003 doUscl.

TOTAL PRIMARYSITE RAD WASTE VOLUME BURIED, 801.64 cab. faeet rOTAL SECONDARY SITE RADWASTE VOLUME BURIED: 30,460 cobi. fst TOTAL GREATER THAN CLASS C RADWASTE VOLUME GENERATED: 613 cubto itot TOTAL SCRA]P METAL REMOVED, 54,440 tons TOTAL CRAFT LA.BOR REQUIREMENTS: 1,103,182 m-hours oanNotos sda.indicates thaet this actne-ty -o.haeoed - d-com.tdtonsIprcoao.

a - ndictats that thi adivity perofrmed by leca-issioning staff 0 - Itdicatw tht tehi v1ne is I- th-as 0.5 bht ib os-c.

ocenwtasclingirt dieatos a wo value TLO Services, An. Copyright PSEG Nuclear 199912000