ML20220A666
| ML20220A666 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 08/07/2020 |
| From: | Sterdis A Holtec Decommissioning International |
| To: | Document Control Desk, Office of Nuclear Material Safety and Safeguards, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML20220A666 (14) | |
Text
Krishna P. Singh Technology Campus, 1 Holtec Blvd., Camden, NJ 08104 Telephone (856) 797-0900 Fax (856) 797-0909 Page 1 of 3 August 7, 2020 10 CFR 50.80 10 CFR 50.90 10 CFR 72.50 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Indian Point Nuclear Generating Units 1, 2 and 3 Docket Nos. 50-3, 50-247, 50-286 and 72-051 Provisional Operating License No. DPR-5 Renewed Facility Operating License Nos. DPR-26 and DPR-64
Subject:
Response to NRC Request for Additional Information
References:
[1]
Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments for Indian Point Nuclear Generating Units 1, 2 and 3, dated November 21, 2019 (ADAMS Accession No. ML19326B953).
[2]
Letter from Andrea L. Sterdis, (Holtec Decommissioning International) to U.S. Nuclear Regulatory Commission - Post Shutdown Decommissioning Activities Report including Site-Specific Decommissioning Cost Estimate for Indian Point Nuclear Generating Units 1, 2 and 3, dated December 19, 2019 (ADAMS Accession No. ML19354A698).
[3]
Letter from Andrea L. Sterdis, (Holtec Decommissioning International) to U.S. Nuclear Regulatory Commission - Request for Exemptions from 10 CFR 50.82(a)(8)(i)(A) and 10 CFR 50.75(h)(1)(iv) for Indian Point Nuclear Generating Units 1, 2 and 3, dated February 12, 2020 (ADAMS Accession No. ML20043C539).
[4]
Email from Richard Guzman, (U.S. Nuclear Regulatory Commission) to Ronald W. Gaston (Entergy Nuclear Operations, Inc)RAI -1 and -2 Indian Point Nuclear Generating Station, Units 1, 2, and 3Application for Order Consenting to Transfers of Control of Licenses and Approving Conforming License Amendments, dated July 8, 2020 (ADAMS Accession No. ML20190A234).
Please find attached the responses to the NRC Request for Additional Information (RAI) regarding the request for Indian Point Nuclear Generating Units 1, 2, and 3 License Transfers, RAI-1 and -2 prepared and submitted herein by Holtec Decommissioning International, LLC (HDI).
By letter dated November 21, 2019 (Reference 1), Entergy Nuclear Operations, Inc. (ENOI), on behalf of itself, Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, Holtec International, and Holtec Decommissioning International, LLC (HDI) (together, Applicants),
Krishna P. Singh Technology Campus, 1 Holtec Blvd., Camden, NJ 08104 Telephone (856) 797-0900 Fax (856) 797-0909 Page 2 of 3 requested that the U.S. Nuclear Regulatory Commission (NRC) consent to: (1) the transfer of control of Provisional Operating License No. DPR-5 and Renewed Facility Operating License Nos.
DPR-26 and DPR-64 for Indian Point Nuclear Generating Station, Units 1, 2 and 3 (referred collectively as the Indian Point Energy Center or IPEC), as well as the general license for the IPEC Independent Spent Fuel Storage Installation (ISFSI) (collectively the Licenses), to Holtec subsidiaries to be known as Holtec Indian Point 2, LLC (Holtec IP2) and Holtec Indian Point 3, LLC (Holtec IP3); and (2) the transfer of ENOIs operating authority (i.e., its authority to conduct licensed activities at IPEC) to HDI. The Applicants also requested that the NRC approve conforming administrative amendments to the Licenses to reflect the proposed transfer of the Licenses from ENOI to HDI, Holtec IP2 and Holtec IP3; and deletion of certain license conditions to reflect satisfaction and termination of certain obligations after the license transfers. The proposed conforming license amendments would be approved, but not issued, until consummation of the proposed transaction. ENOI and HDI proposes to notify the NRC at least two business days prior to the expected closing date, so that the conforming license amendments can be issued concurrently with the transaction closing.
On December 19, 2019, HDI submitted, Post Shutdown Decommissioning Activities Report (PSDAR) including Site-Specific Decommissioning Cost Estimate (DCE) for Indian Point Nuclear Generating Units 1, 2, and 3, (Reference 2).
Additionally, by letter dated February 12, 2020, HDI submitted to the NRC, a Request for Exemption from 10 CFR 50.82(a)(8)(i)(A) and 10 CFR 50.75(h)(1)(iv) for IP1, IP2, and IP3 to allow the use of a portion of the Nuclear Decommissioning Trust (NDT) funds for management of spent fuel and site restoration activities, respectively (Reference 3). The submittal also requests, pursuant to 10 CFR 50.12, exemptions from 10 CFR 50.75(h)(1)(iv) to allow disbursements from the IP1, IP2, and IP3 NDT funds for spent fuel management and site restoration costs to be made without prior notice, similar to withdrawals in accordance with 10 CFR 50.82(a)(8). These exemption requests are based on HDIs December 19, 2019, DECON PSDAR and DCE.
In Reference 4, The NRC provided ENOI with a request for additional information (RAI -1(a), -
1(b) and -2). The HDI responses to the RAI are provided in the Enclosures to this letter.
This letter contains no new regulatory commitments.
In the event that the NRC has any questions about the transactions described in this letter or needs to obtain any additional information, please contact the undersigned at 724-493-1833 or a.sterdis@holtec.com.
I declare under penalty of perjury that the foregoing is true and correct. Executed on August 7, 2020.
Respectfully, Andrea L. Sterdis Vice President Regulatory and Environmental Affairs Holtec Decommissioning International, LLC Digitally signed by Andrea L. Sterdis DN: cn=Andrea L. Sterdis, c=US, o=HDI, ou=Holtec Decommissioning International, email=andrea.sterdis@holtec.com Date: 2020.08.07 15:37:22 -04'00' Andrea L.
Sterdis
Krishna P. Singh Technology Campus, 1 Holtec Blvd., Camden, NJ 08104 Telephone (856) 797-0900 Fax (856) 797-0909 Page 3 of 3
Enclosure:
HDI Responses to NRC Requests for Additional Information (RAI) Regarding the Request for Indian Point Nuclear Generating Station Units 1, 2 and 3 License Transfers, RAI 1 and -1 and -2 cc (w/Enclosure):
Regional AdministratorNRC Region 1 NRC Senior Resident InspectorIndian Point Energy Center NRC Project Manager, NRRIndian Point Nuclear Generating Units 2 & 3 New York State (NYS) Public Service Commission President and CEO, NYSERDA
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-1 HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers Enclosure HDI Response to U.S. NRC Requests for Additional Information Regarding the Request for Indian Point 1, 2 & 3 License Transfers
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-2 Background Information - RAI 1 - Reasonable Assurance that Funds Will Be Available for Decommissioning; Consideration of All Significant Decommissioning Costs a) In both the LTA and the HDI PSDAR, estimated license termination (i.e., radiological decommissioning) costs and spent fuel management costs are listed as $469,456,000 and
$188,278,000, respectively, for IP2, and $583,168,000 and $371,370,000, respectively, for IP3. Also, the LTA provides that HDIs funding plan for spent fuel management and site restoration activities relies on the use of NDT funds[1] and the HDI PSDAR indicates that decommissioning will include the expansion of the existing ISFSI pad for 65 additional casks.[2] However, the HDI PSDAR work breakdown structure (WBS) identifies Construction of ISFSI costs of just under $6 million, for IP1 only, under line item 01.02.10.02.01, with no additional WBS line items identified for this activity throughout the remainder of the document.
b) The HDI PSDAR states, [b]ased on an integrated evaluation of estimate uncertainty and discrete risk events utilizing industry accepted risk modeling tools and techniques in addition to a review of industry experience with similar decommissioning projects, a Contingency Allowance of 18 percent was determined to be reasonable for the IPEC decommissioning project.[3] NUREG-1713, Standard Review Plan for Decommissioning Cost Estimates for Nuclear Power Reactors (ADAMS Accession No. ML043510113), provides that a site-specific cost estimate should provide costs for contingency and also states that the site-specific cost estimate may summarize the results of the detailed analyses with the underlying detail submitted as supplementary information. However, [t]he summary data should be sufficiently detailed to demonstrate that the licensee has considered all significant decommissioning costs, and should reference the detailed cost estimate.[4]
RAI 1 - Reasonable Assurance that Funds Will Be Available for Decommissioning; Consideration of All Significant Decommissioning Costs a) With IP2 and IP3 each having similar thermal capacity and each having similar spent fuel inventory as depicted in the HDI PSDAR, Table 3-6, IPEC DOE Fuel Acceptance Allocation, explain the features of the cost estimating techniques and/or the decommissioning assumptions that account for the approximate $114 million difference in the license termination costs forecast for IP2 and IP3 and the approximate $183 million difference in the spent fuel management costs forecast for IP2 and IP3. Additionally, identify within the LTA and/or the HDI PSDAR the costs associated with the expansion and/or construction of additional ISFSI capacity, the units from which the spent fuel to be stored in the additional ISFSI capacity originate, and the NDT from which such expenses will be funded.
b) Provide additional detail to demonstrate that the Contingency Allowance of 18 percent considers all significant decommissioning costs.
[1] LTA, cover letter, page 4 of 6.
[2] HDI PSDAR, pages 13 and 65.
[4] NUREG-1713, pages 20 and 26-27.
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-3 HDI Response to RAI 1(a)
As stated in the HDI IPEC Site-Specific Decommissioning Cost Estimate (DCE) included in the HDI PSDAR (Reference 1), the cost estimates in the DCE were determined based on HDIs selection of the DECON method for decommissioning. These estimates are based on current and/or assumed regulatory requirements, site conditions, key assumptions, low-level radioactive waste disposal standards, high-level radioactive waste management options, and site restoration requirements. The cost estimates are also based on HDIs detailed decommissioning project plan and schedule for implementing the DECON method. As further documented in the DCE, the schedule and cost estimates are based on the International Structure for Decommissioning Costing (ISDC) for Nuclear Installations Work Breakdown Structure (WBS) and corresponding WBS dictionary (Reference 2). The tables providing the DCE estimate breakdowns align with this WBS structure and the Master Summary Schedule provided in Figure 5-1 of the DCE.
The HDI cost estimates for IP1, IP2 and IP3 were developed in accordance with the requirements in 10 CFR 50.75, as modified by HDIs request for exemption from the requirements of 10 CFR 50.82(a)(8)(i)(A) (Reference 3), which if approved, would permit HDI to use NDT funds for IP1, IP2 and IP3 to cover spent fuel management costs and site restoration costs for their respective units. In addition, HDI has developed the cost estimates by carefully allocating costs for each unit throughout the decommissioning process. In accordance with applicable regulatory requirements, the detailed tables provided in the DCE show the cost estimates for each unit segregated into the license termination, spent fuel management and site restoration cost categories.
The cost estimates for each unit include those decommissioning costs (including license termination, spent fuel management and site restoration costs) for those activities that are specifically linked to the unit (e.g., costs to segment the IP2 reactor vessel and internals are included in the IP2 segmentation cost estimate). The cost estimates for each unit also include an allocation of site-wide estimated costs for ongoing work in a given time period based on the planned distribution of work activities for that unit (e.g., site programmatic costs including estimated costs for site security, NRC fees, and tax payments are distributed across IP1, IP2 and IP3 according to the planned work for each unit in the given year as shown in Tables 3-2a, b and c of the DCE).
Explanation for Different License Termination Cost Estimates for IP2 and IP3 The differences between the IP2 and IP3 License Termination Costs are driven by two primary factors:
- 1) HDIs schedule and sequence for performing the major decommissioning activities including reactor segmentation, dismantling and demolition; and
- 2) Differences in estimated Class A waste volumes The Schedule on Figure 5-1 of the DCE drives differences in cost estimates for each unit that are schedule-dependent. For example, common mobilization efforts, infrastructure improvements, and site modifications needed to support the specific decommissioning activities are allocated to the unit that is planned to conduct the activities first. The units that conduct
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-4 those same activities second and third do not require the same work to be repeated. The resulting multi-unit efficiencies result in differences in the cost estimates. For example, mobilization of the segmentation team to execute reactor vessel and internals segmentation on IP3 avoids similar mobilization costs for IP2 and IP1 since these projects are scheduled to occur back-to-back.
Additionally, when one unit completes a task that would make an existing site-wide activity unnecessary for that unit, but the site-wide activity remains necessary for the remaining unit(s) and the associated total costs continue to be incurred, the cost estimated for that activity is reallocated to the remaining unit(s) that require(s) the activity to continue, requiring them to bear a proportionally larger share than before. For example, IP2s schedule for moving spent fuel from the spent fuel pool to the ISFSI pad is planned to be completed by second quarter 2023 and all of IP3s spent fuel is planned to be moved to the ISFSI by second quarter 2024.
Therefore, IP2s program management expenses (e.g., site-wide infrastructure and operations costs, including costs for the emergency planning activities required for wet fuel storage) are reduced after second quarter 2023, because there is no longer fuel in the IP2 spent fuel pool.
After second quarter 2023, all site-wide program management costs required for wet storage are allocated to IP3, rather than split between IP2 and IP3, since only IP3 will have spent fuel remaining in wet storage.
The second primary factor that drives differences in HDIs cost estimates for IP2 and IP3 is the difference in Class A radioactive waste (as defined by 10 CFR 61.55) volumes estimated for each unit. The estimated waste volumes are unit-specific and are estimated by considering which unit generated the waste, known locations of contamination, site topography and expected migration of existing contamination. The difference in the estimated Class A waste volumes, as shown in Table 3-7 of the DCE, drives corresponding differences in the estimates for IP1, IP2, and IP3 waste characterization, waste removal, packaging, transportation, and disposal costs.
These two factors collectively result in a significant portion of the variance in estimated license termination costs between IP2 and IP3. Further, it is important to note that the DCE is an estimate based on planned scope, schedules and expected costs.
Explanation for Different Spent Fuel Management Cost Estimates for IP2 and IP3 For spent fuel management, the difference between the IP2 and IP3 estimated costs is driven by several primary factors:
- 1) Due to the lower IP2 spent fuel heat load, the IP2 spent fuel is planned to be moved from wet storage to dry storage first, which results in the reallocation of all site-wide spent fuel management costs due to wet fuel storage and spent fuel pool-to-pad campaigns to IP3 once the IP2 spent fuel has all been placed on the ISFSI.
- 2) After IP3s shutdown in April 2021, IP3 will have approximately 25% more fuel in wet storage than IP2, which results in a higher allocation of site-wide spent fuel management costs to IP3. In addition, due to this difference in the number of wet fuel storage assemblies, the costs for the transfer of the spent fuel from the spent fuel pools to dry cask storage on the ISFSI pad (including the design, manufacture and loading of the casks) are approximately 25% more for IP3 than for IP2.
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-5
- 3) A crane is planned to be installed for IP3 to facilitate improved fuel pool-to-pad safety and efficiency. Since this crane is only needed for IP3, these costs are allocated to IP3 only.
- 4) The total project costs estimated for the ISFSI expansion are allocated at approximately two-thirds for IP3 and one-third for IP2 based on the number of canisters for each unit expected to be located on the expansion area.
- 5) IP2 fuel and Greater-Than-Class C (GTCC) waste is planned to be removed from the site first, followed by IP1 fuel and GTCC waste, and then finally, IP3 fuel and GTCC waste. This removal schedule results in the reallocation of all site-wide spent fuel management costs to IP3 once IP2 and IP1 fuel has been removed.
Items 1, 2, 3 and 4 are fuel management differences that contribute to the variance in the spent fuel management cost estimates for IP2 and IP3. As noted above, the specific cost estimates that are impacted are the wet storage costs, the ISFSI expansion costs, and the fuel pool-to-pad costs. Program management costs that are tied to fuel on pad completion are also impacted in the cost estimate methodology. The current HDI spent fuel and GTCC storage plan forms the basis for the estimated allocation of ISFSI expansion costs provided in the DCE. However, the cask loading plan for IP2 and IP3 and the final GTCC waste characterization, cut plans and loading plans for all three units are not yet finalized. As these plans are finalized, the estimates will be revised as necessary to allocate the ISFSI expansion costs to the IP1, IP2 or IP3 NDT funds, as appropriate, based on the final planned expansion capacity usage. These revisions will be documented in accordance with 10 CFR 50.75 in the annual decommissioning funding status reports and estimates to complete for IP1, IP2 and IP3.
Item 5 also has a significant impact on HDIs spent fuel cost estimate allocations. Specifically, as discussed in the DCE section discussing Spent Fuel Management (found in the DCE on pages 63 and 64), the schedule for spent fuel removal provided in Table 3-6 of the DCE assumes IP2 fuel is removed from the site first based on HDIs planned use of allocations for DOE pickup available for Indian Point. In accordance with the requirements to reimburse decommissioning costs from the appropriate units NDT fund, common spent fuel management costs (e.g., security costs, fees and insurance) are shared proportionally across all three funds initially (i.e., until partial site release). Once all IP2 fuel has been removed from the site, all of the operational costs for maintaining the site ISFSI are then appropriately allocated to IP1 and IP3 (with none allocated to IP2), since those units have the only remaining fuel on the ISFSI pad. Once all IP1 fuel is removed from the site, all ISFSI operating costs are then allocated to IP3. This allocation of the ISFSI operating costs to IP3 once the IP2 fuel is removed is appropriate and consistent with NRC regulations and accounts for a significant portion of the
$183M difference between the IP2 and IP3 spent fuel management costs shown in Tables 5-1(b) and 5-1(c) of the HDI DCE.
References for HDI Response to RAI 1(a)
- 1) Letter from Andrea L. Sterdis, (Holtec Decommissioning International) to U.S. Nuclear Regulatory Commission - Post Shutdown Decommissioning Activities Report including Site-Specific Decommissioning Cost Estimate for Indian Point Nuclear Generating Units 1, 2 and 3, dated December 19, 2019 (ADAMS Accession No. ML19354A698).
- 2) International Structure for Decommissioning Costing (ISDC) of Nuclear Installations, ISBN 978-92-64-99173-6, Joint NEA/EC/IAEA Publication, 2012.
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-6
- 3) Letter from Andrea L. Sterdis, (Holtec Decommissioning International) to U.S. Nuclear Regulatory Commission - Request for Exemptions from 10 CFR 50.82(a)(8)(i)(A) and 10 CFR 50.75(h)(1)(iv) for Indian Point Nuclear Generating Units 1, 2 and 3, dated February 12, 2020 (ADAMS Accession No. ML20043C539).
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-7 HDI Response to RAI 1(b)
As described in the HDI PSDAR and DCE, based on an integrated evaluation of estimate uncertainty and discrete risk events utilizing industry accepted risk modeling tools and techniques in addition to a review of industry experience with similar decommissioning projects, a Contingency Allowance of 18 percent was determined to be reasonable for the IPEC decommissioning project. This 18% Contingency Allowance is factored into the estimate of License Termination, Spent Fuel Management and Site Restoration costs presented in the DCE. The exception is ISFSI decommissioning costs, which include a 25% Contingency Allowance consistent with the contingency evaluation criteria referenced by the NRC in NUREG-1757.
Uncertainty and discrete risk events were considered based on the extensive site-specific information available for the IPEC site as documented in site, Federal and State records. HDI and CDI performed a due diligence investigation of site operations and history including operational occurrences, radiological and non-radiological environmental reports and analysis and other historical event documentation. For example, HDI and CDI reviewed the extensive set of site records of spills or other unusual occurrences involving the spread of contamination in and around the facility maintained in accordance with 10 CFR 50.75(g). One specific area considered in the HDI and CDI due diligence was the elevated radionuclide activity in a groundwater plume sourced from spills and releases associated with Units 1, 2 and 3, and extending to the Hudson River. The plume was discovered in 2005, investigated in 2006 and 2007, and is being remedied through monitored natural attenuation (MNA). The records associated with this area and the MNA remedy were factored into the HDI evaluation of estimate uncertainty and discrete events.
As noted in the PSDAR, the HDI cost estimate uses a sound risk management approach to establish these levels of cost and schedule contingency reserves for establishing achievable target schedules and budgets and for making well-informed decisions during the decommissioning lifecycle.
Specifically, a Monte-Carlo simulation risk modeling tool is used to quantitatively evaluate the integrated impact of uncertainty and discrete risk events on the project objectives, baseline schedule and costs. Risk analysis tools integrate directly with project schedules and cost estimates and provide techniques to forecast potential cost and schedule impacts. Risk analysis output is then coupled with expert judgement to provide an objective view to validate the integrity of the schedule model, evaluate the effectiveness of risk response plans, identify and prioritize key risk drivers, quantify schedule and cost reserves based on desired levels of confidence, and publish risk-adjusted schedules.
To provide a basis to account for uncertainty in the decommissioning project schedule duration and/or cost, experienced HDI and CDI subject matter experts evaluated segments of decommissioning work and defined the low, expected, and high value estimate uncertainty values. Risks that were deemed very likely to be realized were captured as predicted project expenses in the DCE, thus further introducing conservatism in the calculation of contingency.
The assignment of uncertainty values was based on estimate methodology, available data, and professional judgement. Estimate uncertainty profiles were developed to show the impacts on schedule and costs. These estimate uncertainty profiles were used to establish the schedule and cost Uncertainty Allowance that is added to the decommissioning project baseline schedule
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-8 and cost estimate to address the estimate uncertainty within the defined decommissioning scope of work and execution strategy.
Uncertainty Allowance is included in the baseline cost and schedule to cover ill-defined work scope or elements of costs and schedules expected to be incurred, which cannot be explicitly foreseen or estimated because of a lack of complete, accurate or detailed information that can be available at this time. The amount of time/duration and costs to be included in the schedule and cost baselines for Uncertainty Allowance to account for these uncertainties is derived using the quantitative risk model in @Risk for the 85% probability or level of confidence.
In addition to assessing project uncertainty, HDI also specifically accounts for discrete risk events when it sets its contingency level. Unlike uncertainty, discrete risk events may or may not occur. The risk analysis process used to evaluate discrete risk events is both qualitative and quantitative. HDI uses a risk event scoring matrix to qualitatively grade/prioritize the discrete risk events as extremely high, high, medium, and low based on the probability of occurrence and impacts. This qualitative assessment is used to prioritize the discrete risk events for more detailed risk analysis and risk response planning with primary focus on the medium, high and extremely high-risk events.
In addition to a qualitative analysis of discrete risk events, a quantitative analysis is performed on all the active discrete risk events classified as threats. This quantitative analysis is performed using Stature, a licensed proprietary software from SNC-Lavalin, in combination with @Risk to determine risk and contingency levels for the IPEC facility. Output from the model is then used to run a Monte Carlo simulation in @Risk to determine the P85 or 85th percentile probability of confidence an output contingency value would give. The risk allowance factor is the funds added to the baseline schedule and estimate to account for discrete IPEC Facility Site-Specific Decommissioning Cost Estimate risk events (both threats and opportunities) that may or may not occur during the decommissioning project lifecycle.
Based on an integrated and extensive evaluation of estimate uncertainty and discrete risk events utilizing industry-accepted risk modeling tools and techniques in addition to a review of industry experience with similar decommissioning projects, the 18 percent Contingency Allowance reasonably bounds the universe of risks that are appropriate to be taken into account at the estimate phase (considering industry practice, accepted NRC methodology, and the information that is available today) for the IPEC decommissioning project. The development of the Contingency Allowance as discussed in the HDI DCE, was comprehensive and demonstrates its adequacy.
In addition to the 18% Contingency Allowance that was applied across the IP1, IP2 and IP3 cost estimates, the Cash Flow Analyses in Tables 5-1 (a), (b), and (c) in the DCE identify remaining NDT funds following Partial Site Release of $54.779M for IP1, $125.553M for IP2 and
$269.057M for IP3. Following a subsequent 30 years of ISFSI-only operating costs, fuel removal from the site and final decommissioning of the ISFSI, the Cash Flow Analyses in these tables show $19.993M remaining for IP1, $72.677M for remaining IP2 and $170.582M remaining for IP3 in 2063, when each of the licenses are terminated. These Cash Flow Analyses take no credit for expected DOE reimbursements for spent fuel management costs. If necessary, such reimbursement from DOE could provide additional margin to that provided by the 18% Contingency Allowance for spent fuel management costs and demonstrated in the cash flow analyses.
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-9 Finally, the DCEs submitted by HDI in support of the Oyster Creek and Pilgrim License Transfer Applications included 15% and 17% Contingency Allowances, respectively. While decommissioning is driven by site-specific considerations, the adequacy of these project estimates developed by HDI and the conservatism built into HDIs decommissioning cost estimates have been confirmed in the annual decommissioning funding status reports filed for Oyster Creek and Pilgrim in March 2020. Specifically, the March 2020 reports show total decommissioning costs actually incurred through 2019 for both Oyster Creek and Pilgrim have been lower than originally estimated in their respective DCEs.
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-10 Background Information - RAI 2 - Reasonable Assurance that Funds Will Be Available for Decommissioning; Segregation of NDTs from Licensee Assets Pursuant to the terms of the Membership Interest Purchase and Sale Agreement (MIPA), closure of the MIPA will result in IPECs transfer to Nuclear Asset Management Company, LLC (NAMCo),
a wholly-owned subsidiary of Holtec. NAMCo will emerge as the direct parent company owner of Holtec IP2 and Holtec IP3, and Holtec IP2 will own the IP1 and IP2 licenses and Holtec IP3 will own the IP3 license. Holtec IP2 and Holtec IP3 will also respectively own each units associated assets and real estate, including each units NDT.
The NRC recently approved the transfers of the Oyster Creek Nuclear Generating Station license from Exelon Generation Co. to Oyster Creek Environmental Protection, LLC, as owner, and HDI, as decommissioning operator, and of the Pilgrim Nuclear Power Station license from ENOI to Holtec International, as owner, and HDI, as decommissioning operator. These license transfer approvals resulted in the transfer of NDTs to Holtec International subsidiaries.
In general, 10 CFR 50.75(h)(1) restricts disbursements from an NDT to decommissioning expenses for the unit associated with the NDT. The LTA states that Holtec IP2 and Holtec IP3 will continue to hold the NDT assets in trusts segregated from their other assets and outside of their administrative control.
RAI 2 - Reasonable Assurance that Funds Will Be Available for Decommissioning; Segregation of NDTs from Licensee Assets Identify the corporate practices, processes, and safeguards that will be in place following the transaction that will ensure that NDT assets of IP1, IP2, and IP3, will remain segregated from one another and from the NDT assets for Oyster Creek and Pilgrim and that decommissioning expenses specific to each unit, including funds used to manage spent fuel, will be accounted for, managed, and expensed from the appropriate NDT.
Response to RAI 2 Consistent with NRC regulations governing Nuclear Decommissioning Trusts (NDTs) including 10 CFR 50.75, Holtec International (Holtec) has established processes, policies, and procedures to manage the NDTs for all decommissioning facilities in the Holtec fleet. In particular, in accordance with NRC and other federal regulations, Holtecs processes, policies, and procedures ensure that each units NDTs are segregated from one another and are only being used to reimburse costs that have been incurred for that particular unit.
Currently, the Holtec nuclear decommissioning fleet includes the Oyster Creek Nuclear Generating Station (owned by Oyster Creek Environmental Protection, LLC (OCEP)) located in Lacey Township, New Jersey and the Pilgrim Nuclear Power Station (owned by Holtec Pilgrim, LLC) located in Plymouth, Massachusetts. The NDTs for Oyster Creek and Pilgrim are managed separately, and all the trust assets are held by each facilitys respective custodian.
Holtec has established a Decommissioning Trust Fund (DTF) Management Board, a Decommissioning Cost Control Committee (DCCC), and a Decommissioning Management Manual for the management and conduct of decommissioning fleet NDT oversight. For each NDT, Holtec has an Investment Policy Statement, conducts ongoing due diligence and oversight of the investment managers who manage the specific NDTs assets, and uses internal and external
HDI Responses to U.S. NRC RAI -1 and-2 Request for Indian Point 1, 2 and 3 License Transfers E-11 controls to govern the distributions from each trust fund. If the proposed license transfers are approved by NRC, upon transaction closure and license transfer, Holtec will oversee the IP1, IP2 and IP3 NDTs in the same manner.
To maintain compliance with applicable NRC regulations, the office of the Holtec Chief Investment Officer (CIO) monitors each NDTs holdings, cash, transactions, and disbursements regularly. If the proposed license transfers are approved by NRC, upon transaction closure and license transfer, the CIO office will employ the same controls on an individual unit basis for IP1, IP2 and IP3.
Holtecs processes, procedures and policies, project management system, invoice processing system and the diligence that these processes are executed with, ensure that decommissioning costs are appropriate for the work performed, are charged to the correct plant or unit, and are confirmed to be reimbursable from the identified NDT fund. The Holtec processes, policies and procedures are comprehensive and ensure that NDT disbursements are made in compliance with all applicable regulations.