ML20303A337
| ML20303A337 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 10/30/2020 |
| From: | Specter H Micro Utilities |
| To: | Office of Nuclear Reactor Regulation |
| Poole, Justin | |
| Shared Package | |
| ML20303A322 | List: |
| References | |
| OEDO-20-00434 | |
| Download: ML20303A337 (21) | |
Text
Cover Sheet Decommissioning Indian Point One October, 2020 HERSCHEL SPECTER mhspecter@verizon.net
About the Author ABOUT THE AUTHOR Herschel Specter, President of Micro-Utilities, Inc., holds a BS in Applied Mathematics from the Polytechnic Institute of Brooklyn and a MS from MIT in Nuclear Engineering. He is a Licensed Professional Engineer in the State of New York. He has had a long association with the Indian Point nuclear power plants starting as a member of the Atomic Energy Commission (now the Nuclear Regulatory Commission) where he was the Licensing Project Manager for the original licensing of the Indian Point 3 nuclear plant in the 1970s. In the 1980s the New York Power Authority hired Mr. Specter to manage the defense of Indian Point 3 in a federal adjudicatory trial in the wake of the Three Mile Island nuclear accident in Pennsylvania. Prior to joining NYPA, Mr.
Specter served at diplomat rank for 5 years at the International Atomic Energy Agency in Vienna, Austria where he headed up an international effort writing design safety standards for nuclear power plants.
Mr. Specter has been Chairman of two national committees on emergency planning and was a guest lecturer for several years on emergency planning at Harvards School of Public Health. He led an effort as a consultant to Entergy analyzing emergency responses during a hypothetical ter-rorist attack on Indian Point. Mr. Specter has presented testimony at the National Academy of Sci-ences on the Fukushima accident and on other nuclear safety matters and has been a guest speaker at many universities on matters of energy policy. Today he is one of 14 Topic Directors in Our Energy Policy Foundation, a group of about 1500 energy professionals who seek to bring unbi-ased and comprehensive energy information to our political leaders and members of the public.
Mr. Specter has been active on social and environmental matters. He has been a Big Brother and in 1971 had the honor of being selected as Big Brother of the Year for all of the USA and Can-ada. He also received a personal letter of commendation from the President of the United States for his work with the Youth Conservation Corps.
Mr. Specter was born in White Plains, NY and lives there now.
DECOMMISSIONING INDIAN POINT ONE Micro-Utilities, Inc.
TABLE OF CONTENTS Table of Contents 1.0 EXECUTIVE
SUMMARY
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.0 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3.0 Sources of Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 4.0 Financial Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 4.1. Funding Level Differences Between HDI and Entergy - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2 TABLE A-1 Entergy and HDI Funding Levels, Millions of Dollars , - - - - - - - - - - - - - - - - 3 4.2. Funding Level Differences Between HDI and the NRC - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3 4.3. Contingency Allowance - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4 4.4. Non-Radiological Decommissioning of IP1 and New York State - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4 4.5. Comparison of Potential IP1 Shortfalls - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 5 TABLE A-2 Entergy and HDI Potential IP1 Shortfalls - - - - - - - - - - - - - - - - - - - - - - - - - 5 5.0 Decommissioning Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 5.1. Definitions - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 5 5.2. Entergys Use of SAFSTOR - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 6 5.3. HDIs Proposed Use of DECON - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 6 5.4. Investing in the Indian Point Site - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 7 6.0 Comparisons to Other Cost Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 TABLE A-3 Cost Comparison of SAFSTOR and DECON Approaches - - - - - - - - - - - - - - 8 7.0 Indian Point Site Challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 8.0 Social Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 8.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 10 8.2. Duke Energys Crystal River 3 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 10 8.3. Commonwealth Edisons Zion Station - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 8.4. Three Mile Island Nuclear Station, Unit 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 8.5. Entergy and Indian Point - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 8.6. Summary - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 12 9.0 In the Interests of the People . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 10.0 Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 EXHIBIT A-1 NRC IP1 Radiological Decommissioning Cost Estimate - - - - - - - - - - - - - - 14 EXHIBIT A-2 Entergy IP1 SAFSTOR DTF Balances, Page One - - - - - - - - - - - - - - - - - - - 15 EXHIBIT A-3 Entergy IP1 SAFSTOR DTF Balances, Page Two - - - - - - - - - - - - - - - - - - 16 EXHIBIT A-4 HDI IP1 DECON DTF Balances, Page One - - - - - - - - - - - - - - - - - - - - - - - 17 EXHIBIT A-5 HDI IP1 DECON DTF Balances, Page Two - - - - - - - - - - - - - - - - - - - - - - 18 Table of Contents, page i of i
DECOMMISSIONING INDIAN POINT ONE Micro-Utilities, Inc.
1.0 EXECUTIVE
SUMMARY
Decommissioning Indian Point presents major challenges. New Yorkers must not be faced with depleted decommissioning trust funds, the major eyesore of a partially dismantled site, and new jobs and additional tax revenues delayed for decades. This report, the first of a three part series, raises questions about the ability of HDI, Holtec Decommissioning International, to successfully decommission Indian Point One (IP1). The next report reviews Indian Point Two (IP2) and Indian Point 3 (IP3). The third report addresses Where do we go from here? These reports support actions to prevent the granting of exemptions and/or transfers of any of the Indian Point licenses to HDI.
The myriad facts and figures in this report can be replaced by a simple observation: Entergy calcu-lates indicate that it will take IP1 many years, using the SAFSTOR program, to accumulate suffi-cient additional funds in the Decommissioning Trust Fund (DTF), in order to match the radiological funding level calculated by the Nuclear Regulatory Commission (NRC). HDI appears to claim that it can, years earlier, accomplish both radiological and non-radiological decommis-sioning and even have a small amount of money left over using the DECON method, even though the DECON method would rapidly deplete the IP1 DTF and its earning power. The HDI analysis seems to be in conflict with Entergys analysis.
There is a striking difference between the DECON and SAFSTOR approaches. By 2032 the HDI DECON approach would have withdrawn $1,553 million dollars from the IP1+IP2 + 1P3 DTFs.
In contrast, by 2032, the DTF holdings for IP1 +IP2 +IP3 would increase by a total amount of about $263.7 million dollars if all three nuclear plants used the SAFSTOR approach.
There is no obvious reason why NY State would want to rush into an HDI DECON process.
This report covers these main subjects:
A. Financial Issues: There appear to be significant differences between HDI and Entergy on the actual funds in the decommissioning trust funds (DTFs). HDI appears to claim $343.2 million more dollars than what Entergy has reported to the NRC for the IP1+ IP2 + IP3 DTFs, of which IP1 accounts for $121.6 million dollars of this difference. There also are significant differences between HDIs analysis of the funding level needed to perform the radiological decommissioning of IP1 and the funding level that the NRC has calculated for IP1. This difference is estimated to be $153.4 million dollars. The difference between the NRCs radiological cost estimate and HDIs added to the difference between HDIs DTF dollars and the DTF levels reported by Entergy comes to a total of $275 million dollars for IP1. Further, HDI does not seem to meet the NRCs requirements for contingency funds and its planned use of contingency funds also raises concerns.
B. Decommissioning processes: Two different decommissioning processes are compared, SAFSTOR and DECON. For Indian Point the SAFSTOR approach presents far less finan-cial risk to the public, C. Comparisons to Other Cost Estimates: With one exception, discussed later, the HDI cost estimates, expressed as dollars per megawatt-electric ($/MWe), for IP2 and IP3 are lower than a long list of site-specific decommissioning cost estimates others have calculated for their nuclear power plants.
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D. Indian Point Site Challenges: Three nuclear plants squeezed onto a 0.4 square mile site present unique decommissioning challenges. Other nuclear sites, with just two nuclear plants similar to IP2 and IP3, have about four times the area of the IP site. One conse-quence of this is that a failure to decommission IP2 and/or IP3 could block the decommis-sioning of IP1.
E. Social Contracts: In that neither Entergy nor Holtec have expressed any long term commit-ment to the people in New York, this separates them from previous owners like Consoli-dated Edison and the New York Power Authority and puts New Yorkers at heightened financial risks. Examples are given where committed utilities which supervise the decom-missioning of their nuclear plants have benefitted the people in their service areas.
F. In the Interests of the People: A brief recommendation is provided on the best near term actions that might be taken for IP1 that could serve the interests of the people.
2.0 Background Indian Point 1 (IP1) is the oldest of three nuclear plants at the Indian Point site in Buchanan, New York. This 275 megawatt-electric plant operated from August, 1962 to October, 1974 when it was shut down because its emergency core cooling system did not meet regulatory requirements. In January, 1976 all the spent fuel was removed from the reactor vessel. The IP1 spent fuel now is in dry storage at the site in five casks. Consolidated Edison of New York was the original IP1 owner/
operator. Entergy, the present owner/operator, has drained and cleaned the IP-1 spent fuel pool.
In January, 1996 the Nuclear Regulatory Commission (NRC) issued an order approving the place-ment of IP1 into a SAFSTOR status. The final decontamination and decommissioning of IP-1 is planned to be part of a comprehensive decommissioning of the Indian Point site which also includes Indian Point 2 and Indian Point 3.
3.0 Sources of Information The analyses in this report draw principally upon three main sources of information:
A. The NRC report SECY-18-0078: Summary of Staff Review and Findings of the 2017 Decommissioning Fund Status Reports from Operating Power Reactor Licensees and Power Reactor Licensees in Decommissioning, Table 2, (Exhibit A-1 below),
B. Entergy letter to the NRC: CNRO-2019-00005, Decommissioning Funding Status Report per 10 CFR 50.75 (f)(1) and 10 CFR 50.82(a)(8)(v), March 28, 2019, Table 12-1, Attach-ment 12, (Exhibits A-2 and A-3 below), and C. Holtec Decommissioning Internationals (HDI), Post Shutdown Decommissioning Activi-ties Report (PSDAR), sent to the NRC on December 19, 2019, Table 5-1a, (Exhibits A-4 and A-5 below).
4.0 Financial Issues 4.1 Funding Level Differences Between HDI and Entergy There appear to be significant funding level differences between what Entergy reported in its March 28, 2019 letter to the NRC and the funding levels used by HDI in its PSDAR. The Entergy page 2
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report referenced funding levels as of 12/31/2018 while the HDI funding levels were as of 10/31/
2019, a ten month difference. The HDI dollar numbers come from Tables 5-1a, 5-1b,and 5-1c for IP1, IP2 and IP3, respectively, of HDIs PSDAR. These tables also list various pre-closure deduc-tions that were taken of $59.3, $15.15, and $15.15 millions of dollars for IP1, IP2, and IP3, respectively. TABLE A-1 adds HDIs year 2021 funding levels and the pre-closure deductions.
TABLE A-1 Entergy and HDI Funding Levels, Millions of Dollars ,
Plant Entergys HDIs estimate in its PSDAR @ Approximate Report to the 10/31/2019 + Difference NRC @ Pre-Closure Deductions 12/31/2018 IP1 $471.2. $592.8 -$121.6 IP2 $598.4. $669.3 -$70.9 IP3 $780.6. $931.3 -$150.7 Total $1,850.2 $2,193.4 -$343.2 If the Entergy funding levels are correct, the HDI decommissioning analysis would be invalid.
4.2 Funding Level Differences Between HDI and the NRC The purpose of this section is to compare HDIs estimate to complete the radiological decommis-sioning of IP1 with the amount the NRC has calculated for the IP1 radiological decommission-ing.The NRC calculated, in 2016 dollars, that $560,500,000 dollars would be needed to accomplish the radiological decommissioning of IP1. (See Exhibit A-1). Updated to 2019 dollars, the NRC funding level comes to about $593.7 million dollars. By contrast, HDI claims that $533.5 million (2019) dollars would be sufficient to accomplish both radiological and non-radiological decommissioning of IP1.
The next step is to estimate how much of HDIs $533.5 million dollars is for radiological decom-missioning and how much is the non-radiological portion. It was assumed that the bulk of the radiological decommissioning costs for IP1 occur in HDIs PSDAR periods 3 and 4. Period 3 cov-ers Safe Storage Operations and period 4 covers Dismantlement. According to HDIs PSDAR Table 3-1a, the estimated cost for IP1s Safe Storage Operations is $74,243,932 and for Disman-tlement $366,064,054, for a total radiological portion of $440,307,986. The shortfall on IP1s radiological decommissioning relative to the NRCs estimate is $593.7 -S440.3 = $153.4 million dollars.This very large difference between HDI and the NRC estimates for radiological decom-missioning must be explained.
There also is $121.6 million dollar difference between Entergys reported DTF and HDIs initial funding level in its PSDAR. Combining these two shortfalls yields a total shortfall of $275 million dollars.
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4.3 Contingency Allowance HDI plans to use an 18% Contingency Allowance throughout the whole Indian Point project with the exception of the ISFSI, which will include a 25% contingency allowance1. However, NRC requirements2 are The cost estimate applies a contingency factor of at least 25 percent to the sum of all estimated costs. Since the NRC requirement places a 25% contingency factor on all esti-mated costs, not just the IDFSI, The HDI contingency allowance appears to be inconsistent with NRC requirements.
HDIs contingency does not account for inflation or escalation of the price of goods and services over the course of the project. Yet Entergy accounted for these factors in its March 28, 20193 report to the NRC.
According to HDI The Contingency Allowance is an integral part of the cost to complete the IPEC decommissioning and is expected to be fully consumed. (emphasis added) This appears to defeat the purpose of a contingency allowance. The cost analyses performed by HDI for IP1 ends up in 2063 with a trust fund balance of $19,993,000 or about 3.3% of HDIs decommission-ing estimate of $598,184,000. Any event that causes a $20,000,000 dollar or more additional expense would eliminate this final trust fund balance. Since HDI plans to fully consume the con-tingency fund, it appears that the contingency fund would shrink with the completion of each task.
However, any event or collection of events between the start of decommissioning and 2063 that depletes the contingency allowance would inevitably result in insufficient funds in the DTF, which is unacceptable.
The purpose of a Contingency Allowance is to provide greater assurance that a project will be completed without having to turn to other sources of funding. The structure of the HDI contin-gency allowance does not seem to do this. The Indian Point Contingency Allowance should be increased to 25% over and above planned funding of a task and only drawn upon when actual expenses exceed planned expenses. Planned expenses should be as realistic as possible to mini-mize withdrawals from the Contingency Allowance.
4.4 Non-Radiological Decommissioning of IP1 and New York State While NY State has an interest in both radiological and non-radiological aspects of decommis-sioning IP1, it is the lead authority on non-radiological decommissioning matters. Section 4.2 of this report provided an estimate of $440.3 million dollars for HDIs radiological decommissioning costs for IP1 out of an initial amount of $598.2 total dollars. Using these figures, the non-radiolog-ical cost in HDIs estimate then is about $598.2 - $440.3 = $157.9 million dollars. At the very least, NY State must regulate this part of the Indian Point decommissioning.
2 NUREG 1757, Vol. 3, Rev. 1, page 4-11 Consolidated Decommissioning Guidance.
3 See attachment 4, page 1 of this March 28, 2019 Entergy report.
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4.5 Comparison of Potential IP1 Shortfalls The following table compares Entergys4 and HDIs potential shortfalls and the dates the decom-missioning processes would be initiated.
TABLE A-2 Entergy and HDI Potential IP1 Shortfalls Com- Decom. Start Potential Comments pany Method Date of Shortfalls, Decom. Millions of 2019 Dollars Entergy SAFSTOR 2037 $157.9 The 2037 date assumes IP1 remains in SAFSTOR until the DTF equals NRC radiological cost estimate, then a DECON process would begin. Shortfall occurs in non-radiological decommissioning.
Entergy SAFSTOR 2054 $0.00 Year 2054 is the approximate date by which sufficient radiological and non-radiological funds would be in the DTF, then a DECON process would begin.
HDI DECON 2021 $275.0 See Section 4.2 DECON process starts in 2021 5.0 Decommissioning Processes 5.1 Definitions SAFSTOR: After the plant is shut down and defueled, the facility is placed in a safe, stable condi-tion and maintained in that state (safe storage). The facility is decommissioned and dismantled at the end of the storage period to levels that permit license termination. During SAFSTOR a facility is left intact or may be partially dismantled, but the fuel is removed from the reactor vessel, and radioactive liquids are drained from systems and components and then processed. Radioactive decay occurs during the SAFSTOR period, thereby reducing the quantity of contamination and radioactivity that must be disposed of during decontamination and dismantlement.
4 Start dates for Entergy of 2037 and 2054 were derived from Table 12-1 of Entergys March, 2019 report to the NRC.
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DECON: The equipment, structures, and portions of the facility and site that contain radioactive contaminants are promptly removed or decontaminated to a level that permits termination of the license shortly after cessation of operations.
5.2 Entergys Use of SAFSTOR Entergy has considerable experience in the SAFSTOR process with IP1 and more recently since IP2 was closed down. IP1 represents 24 years of safe experience in a SAFSTOR status. During this time decommissioning related activities took place such as moving the spent fuel out of the reactor vessel and eventually into casks (or canisters) and draining and cleaning the spent fuel pool. Similar beneficial actions could take place for the IP2 and IP3 units if they were put into a SAFSTOR status.
In these 24 years radioactive decay has reduced radiation levels which should lead to lower expo-sures to workers who eventually segment the reactor vessel and internals. If the IP1 dismantling and demolition has to be further delayed, some further decreases in decontamination levels should occur and additional cost saving decommissioning methods may come on the market.
Entergy appears to have recognized that the amount of money now in the IP1 DTF is insufficient to accomplish radiological decommissioning. To close this gap Entergy described, in a March 28, 2019 letter to the NRC, a SAFSTOR decommissioning approach for IP1. Using this SAFSTOR approach, IP1s DTF would grow until sufficient funds were available to match the NRCs radio-logical decommissioning funding requirements. Based on this Entergy analysis, the IP1 funding level would reach the $593.7 million dollar level by about 2037. This is the level that matches the NRCs 2016 radiological decommissioning estimate when it is updated to year 2019. By 2054 Entergys SAFSTOR approach may have enough money in the DTF to meet both radiological and non-radiological decommissioning expenses. Entergys analysis showed a peak DTF amount of
$873.1 million dollars for IP1 in year 2064. (See Exhibits A-2 and A-3).
5.3 HDIs Proposed Use of DECON While Entergy has considerable experience in the SAFSTOR decommissioning process, HDI has not reported any experience in decommissioning three large nuclear power plants on a very com-pact site.
HDI proposes to decommission IP1 using a DECON approach. Instead of slowly building up the DTF through a SAFSTOR type of decommissioning, funds would rapidly be taken from the IP1 DTF. Some $32.6 million dollars would be drawn out of the IP1 DTF as early as 2021, as shown in Table 5-1a of the HDI PSDAR. By 2032 about 80% the original IP1 DTF would be depleted.
The estimated decommissioning trust fund in HDIs PSDARs Table 5-1a never reaches the NRCs published IP1 decommissioning level. Further, the HDI analysis of decommissioning costs excludes cost increases due to escalation over the projects life-cycle. (HDI PSDAR, page 59).
A striking example of the difference between DECON and SAFSTOR is that by 2032 HDI would have withdrawn $1,851 million dollars from the IP1+IP2 + 1P3 DTFs. Whereas, using the Entergy SAFSTOR analysis5 and the reported Entergy 2019 DTF holdings, IP1 +IP2 +IP3 trust finds would increase by a total amount of about $293.3 million dollars.
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HDIs choice of a DECON decommissioning process appears to present larger risks to New York-ers than Entergys SAFSTOR decommissioning process. If things go wrong with the SAFSTOR approach the licensee can delay the dismantlement of the Indian Point units. If things go wrong with the DECON approach, the damage may be irreversible. For New Yorkers, it would be better for IP1 to remain in a SAFTOR status, which it has successfully done since January, 1996. As dis-cussed later in the Crystal River experience, starting off with a SAFSTOR approach and eventu-ally using a DECON approach produced significant benefits.
There is no obvious reason why NY State would want to rush into an HDI DECON process.
5.4 Investing in the Indian Point Site It is noted that claims have been made that HDIs DECON approach would make the Indian Point site available for commercial activity many years sooner than a SAFSTOR approach. This may only be possible if the HDI decommissioning efforts led to successful radiological and non-radio-logical decommissioning of all three nuclear units at the Indian Point site. With the information now at hand, this outcome is not assured.
Neither Entergy nor HDI has presented data that show that new businesses would be willing to invest in a site that still contained radioactive material. However, one can draw upon experiences here in New York State. Have there been any indications of commercial interest in the West Val-ley, NY site where nuclear wastes have long been held in interim storage? An even more extreme situation is the old Shoreham nuclear power plant site on Long Island where there are no stored nuclear wastes. In all the years since Shoreham nuclear power plant stopped operating and its nuclear fuel removed from the site, have any new businesses been established on the Shoreham site? The HDI claimed timing benefit needs to be re-examined.
6.0 Comparisons to Other Cost Estimates In addition to the specific financial analyses of IP1 given above, further insights can be gained from the generic data presented in TABLE A-3, below. No judgements are implied in TABLE A-3 regarding whether or not the monies in the DTFs of these nuclear plants are sufficient to complete decommissioning that meets NRC or State requirements or whether or not the monies actually held in the DTFs match the listed estimated funds in these site specific cost estimates.
TABLE A-3 provides comparisons of DECON and SAFSTOR decommissioning costs for a sig-nificant number of nuclear plants, using decommissioning dollars per MWe basis as a figure-of-merit. The first general observation is that there is a very wide spread of $/MWe in this figure of merit among the listed power plants. This cold be indicative that the technology of decommission-ing has not yet reached a mature state. As further experience is gained and new techniques are developed, costs should come down and the uncertainty in decommissioning cost estimates should narrow.
5 The increase in the IP1 DTF by 2032 can be found in Entergys Table 12-1 of its match, 2019 report to the NRC. This Entergy table is presented as Exhibit A-2. To determine the increase in the DTFs of IP2 and IP3 the same percent increase in IP1 between 2019 and 2032 was used to estimate DTF increases for IP2 and IP3.
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The second general observation, based on the site-specific cost estimates in TABLE A-3, is that the DECON approach is generally more expensive per megawatt-electric than the SAFSTOR approach. This is to be expected in that the DECON approach foregoes the expected growth in the DTFs over time that the SAFSTOR approach provides.
HDI IP2 and HDI IP3 are estimates to decommission IP2 and IP3 generated by HDI. With the exception of Crystal River, discussed later, the dollars/MWe estimated for HDI IP2 and HDI IP3 are lower than for any other DECON plant and even lower than for any other SAFSTOR plant.
HDI cost estimates infer that all of the Indian Point decommissioning tasks can be accomplished within the existing trust funds at IP1, IP2, and IP3 with some amounts of money left over. This would seem to indicate that there is no need to put up a letter of credit or any other financial asset to cover possible financial shortfalls. (See Section 4.3 on Contingency Allowance). This report provides a financial analysis of IP1 whereas a financial analysis of HDI IP2 and HDI IP3 are pre-sented in the next document in this three part series. There are additional financial concerns about HDIs analysis of IP2 and IP3.HDI has never owned or operated a nuclear power plant, has never decommissioned a large nuclear power plant like Indian Point, may not have experience in work-ing in a very compact site, and has not put any of its own money into decommissioning Indian Point. Yet the HDI analyses imply that HDI can outperform all others, even if it uses a DECON method.
TABLE A-3 Cost Comparison of SAFSTOR and DECON Approaches Power Plant Type Decom. Power Dollars Needed Dollars/
process Level, MWe to Decommission, MWe (2019) millions Big Rock Point PWR DECON 67 $554. 8.27 Diablo Canyon 1 PWR DECON 1,138 $2,992. 2.62 Diablo Canyon 2 PWR DECON 1.138 $2,992. 2.62 Pilgrim BWR DECON 677 $1,693. 2.50 HDI-IP1* PWR DECON 275 $598.* 2.17 Fort Calhoun PWR DECON 484 $992. 2.05 Oyster Creek BWR SAFSTOR 625 $1,132. 1.81 TMI-1 PWR SAFSTOR 819 $1,252. 1.53 TLG-IP3 PWR SAFSTOR 1,051 $1,339. 1.27 Beaver Valley 2 PWR SAFSTOR 921 $1,046. 1.17 Beaver Valley 1 PWR SAFSTOR 905 $1.077. 1.16 TLG- IP2 PWR SAFSTOR 1,032 $1,135. 1.10 Hope Creek PWR SAFSTOR 1,178 $1,153. 0.979 HDI-IP3* PWR DECON 1,051 $1,002.4* 0.954 HDI-IP2* PWR DECON 1,032 $701.8* 0.686 Crystal River PWR SAFSTOR/ 860 $540. 0.628 DECON page 8
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The three Indian Point plants marked with an asterisk are based on HDI estimates using HDIs assumed initial funding levels. For HDI IP1, it is noted that its DECON cost in dollars per MWe exceeds all those listed as SAFSTOR power plants.
There are additional lessons to be learned beyond the numbers in TABLE A-3. For example, two earlier Indian Point site specific decommissioning cost estimates have been made by TLG Ser-vices, identified as TLG-IP2 and TLG-IP3 in TABLE A-3 TLG Services was hired by Entergy to perform decommissioning cost estimates for IP2 in year 2007 and for IP3 in year 2010. TLG Ser-vices is now part of Entergy and recently performed the decommissioning cost estimates for Entergys Pilgrim nuclear power plant. The 2007 and 2010 TLG Services estimates were updated to 2019 dollars, as shown in TABLE A-3. The TLG Services analyses present a one-on-one com-parison with HDIs cost estimates for IP2 and IP3. TLG-IP2 is 62% larger than HDI-IP2 while the TLG-IP3 is 34% larger than HDI-IP3, in terms of dollars per MWe.
HDI needs to explain why their decommissioning cost estimates for IP2 and IP3 are so much smaller than those produced by TLG Services. Clearly, if the TLG Services estimates are more accurate, there could be large shortfalls in the decommissioning of Indian Point if HDI is allowed to go forward.
Another decommissioning experience of interest is that of the Big Rock Point nuclear plant, now part of the Entergy-Palisades-Big Rock decommissioning package. Big Rock Point ceased operat-ing in August, 1997. The Big Rock Point decommissioning took place prior to Entergy ownership and as shown in TABLE A-3 has, by far, the highest decommissioning cost per MWe. Originally the Big Rock Point plan was to use SAFSTOR decommissioning but later switched to DECON.
The cost for decommissioning Big Rock was then $390 million dollars which in 2019 dollars becomes $554 million dollars. According to Betsy Tompkins6 After the actual closure of the plant, Consumers advised the NRC of its change in plans and revised its decommissioning plan -
its PSDAR- to reflect its desire to immediately decontaminate and dismantle the plant. There may be many reasons for Big Rock Points very high dollars per MWe, but lack of actual decom-missioning experience can not be ruled out. The Big Rock Point experience is not alone. Other utilities have made significant errors when attempting to decommission their nuclear plants and this has been costly. These experiences should serve as a warning to New Yorkers and their elected officials to avoid situations where the peoples money is put at risk by decommissioning companies with little or no relevant experience.
The decommissioning experience most important to the Indian Point situation and could serve as a model is that of Duke Energy, owner of the Crystal River nuclear power plant, Quite recently Duke Energy signed a $540 million dollar contract to decommission the 860 megawatt-electric PWR Crystal River plant using a DECON type of response. The Crystal River plant has been shut down since 2009 and in a SAFSTOR status. On a per megawatt-electric basis this Crystal River price for decommissioning is quite attractive. It has the lowest dollars per MWe in TABLE A-3.
6 Big Rock Point: from groundbreaking to greenfield, Betsy Tompkins, Nuclear News, November 2006.
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Several lessons for Indian Point come from this recent Crystal River transaction. First, the original estimate to decommission Crystal River was $1.18 billion dollars, about twice what the present contract is. Had Crystal Rivers decommissioning costs remained at $1.18 dollars, its dollars /
MWe would have been 1.37, well above the HDI numbers. Being in a SAFSTOR status for years had a double benefit for Crystal River. The decommissioning fund grew while the cost of decom-missioning shrank. Second, this is a fixed price contract where Duke Energy will only pay for work that is completed. Third, the decommissioning fund, now at $711 million dollars, exceeds the fixed price for decommissioning, thereby removing any risk to the public of decommissioning shortfalls. Fourth, Duke Energy will return to rate payers any money left once the dry cask stored materials are removed from the site. Fifth, Duke Energy will retain ownership of the plant and the site. It appears that Duke Energy is committed to staying in this Florida area. A long term commit-ment to a service area by a utility reduces the risks to the public. The owner/operator utility con-trols the company that does the actual decommissioning. This is preferable to placing this burden on the host State, like New York State. The present Entergy/HDI arrangement lacks the basic pub-lic protections that Duke Energy has assured.
7.0 Indian Point Site Challenges The Indian Point site may be unique where special considerations must be accounted for when estimating decommissioning costs. There are potential interactions between the decommissioning of IP1 and the decommissioning of IP2 and IP3. The Indian Point site is very compact, only 0.4 square miles in area, with three nuclear plants and associated buildings and equipment on it. By comparison, the Beaver Valley site and the Diablo Canyon site, each has just two large Pressur-ized Water Reactors like IP2 and IP3 on them, yet these sites are about four times larger. IP1 is packed in between IP2 and IP3 and HDI has concluded that the IP1 decommissioning would have to come last. If there are problems with the decommissioning of either IP2 or IP3 or both, it may not be possible to start or complete the decommissioning of IP1. Even if IP1 were fully funded, its decommissioning depends on a successful radiological and non-radiological decommissioning of IP2 and IP3. This unusual situation may require the NRC to expand its normal decommissioning review to assure that non-radiological financial or programmatic aspects of IP2 and/or IP3 do not prevent the radiological decommissioning of IP1.
8.0 Social Contracts 8.1 Introduction When it comes to decommissioning there appears to be a sharp divide between utilities that plan to remain as part of a community or State and those that do not have such plans. Utilities that have long term commitments to the communities they serve appear to establish decommissioning con-tractual arrangements that are more protective of the publics interests. A few examples below support this conclusion. When such long term community protections are absent, the host state should impose special financial requirements, like letters of credit, on the utility.
8.2 Duke Energys Crystal River 3 Duke Energy will remain the Nuclear Regulatory Commissions licensed owner of Crystal River 3s plant, property, and equipment and retain ownership and control of the trust fund that pays for page 10
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the decommissioning. Accelerated Decommissioning Partners will become the Nuclear Regula-tory Commissions licensed operator responsible for decommissioning the plant in compliance with all state and federal regulations.
8.3 Commonwealth Edisons Zion Station Zion Units 1 and 2 were permanently shut down on February 13, 1998. On September I, 2010 the facility license was transferred from Exelon to ZionSolutions for the express purpose of expedit-ing the decommissioning of the site. All of the above grade plant structures have been removed and final site survey and license reduction to the ISFSI, as of November, 2019, was planned for 2020. Over this time period an estimated $150 million dollars in employment compensation was was distributed over a 7 county region in northeastern Illinois.
ZionSolutions assumed the risk and liability to complete the Zion Station decommissioning for the value of the trusts that were transferred from Exelon to ZionSolutions on September 1, 2010.
Ratepayer responsibility for future decommissioning costs were eliminated and If there are excess trust funds at the completion of the project, the excess funds are transferred back to Exelon (for distribution to ratepayers) along with the NRC licenses, land, and spent fuel., according to ZionSolutions.
ZionSolutions additionally provided a $200 Million Letter of Credit and an easement for disposal of low-level waste at EnergySolutions Clive, Utah disposal facility as additional assurances for decommissioning.
8.4 Three Mile Island Nuclear Station, Unit 1 The Three Mile Island Nuclear Station, Unit 1, is a 819 megawatt electric pressurized water reac-tor with an estimated decommissioning cost of $1,228 million dollars, in 2018 dollars, or $1.50 million dollars per megawatt electric. Exelon Generation Company owns this nuclear plant.
Exelon evaluated several decommissioning possibilities including the DECON method and the SAFSTOR method. Exelon selected a variation of the SAFSTOR method it calls Shortened SAF-STOR. This alternative to SAFSTOR would have the spent fuel transferred to the ISFSI and decommissioning is deferred approximately 30 years after permanent shutdown.
Exelon has stated The selection of a preferred decommissioning alternative is influenced by numerous factors at the time of plant shutdown. These factors include the cost of each decommis-sioning alternative, minimization of occupational radiation exposure, availability of a high-level waste (spent fuel) repository or an interim storage facility, regulatory requirements and public concerns. (emphasis added) 8.5 Entergy and Indian Point In the past Entergy offered decommissioning terms that appear to be more protective of the pub-lics interests than those in the present HDI arrangement. Specifically, Entergy intends to fund the expenditures for license termination (comprising approximately 72% of the total cost) from the currently existing decommissioning trust fund. The management of the spent fuel, until it can be transferred to the DOE, may be funded from excess trust fund earnings and from spent fuel litiga-page 11
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tion against the Department of Energy (DOE). Expenditures from the trust fund for the manage-ment of the spent fuel will not reduce the value of the decommissioning trust fund to below the amount necessary to place and maintain the reactor in safe storage.7 8.6 Summary In the cases of Crystal River 3, owned by Duke Energy, and Zion, there appears to be a long term commitment to their local areas, much like the commitment of Consolidated Edison and the New York Power Authority to the greater New York City area. In these cases the decommissioning companies are limited to the decommissioning process, watched over by the utilities that have hired them. Licenses, land, and spent fuel are transferred back to the original utility. Excess funds, if any, are returned to the rate payers. The fact that the original utilities maintain a long term com-mitment to the areas they serve results in a high degree of public protection. This is not the present situation with either Entergy or HDI. The present situation does not even compare favorably with the arrangement Entergy was offering in 2008. Compensatory actions must be taken by NY State to provide public protection comparable to what Entergy offered before.
On the positive side, the Three Mile Island Unit 1 showed that alternative approaches to decom-missioning may be beneficial to various stakeholders, including the public. Beneficial alternative approaches were also shown in the Beaver Valley nuclear plant. The owners of Beaver Valley reversed their previous decision to retire this plant and will now continue to operate it, citing the direction of the Governor of Pennsylvania to deal with climate change by supporting a cap and trade program on greenhouse gases. Continuing power operation has an additional major benefit; it provides an opportunity to increase the size of the Beaver Valley decommissioning fund.
9.0 In the Interests of the People The interests of the people are paramount. No convincing case has been presented that it is in the interests of the people to rush into a DECON decommissioning arrangement, with its rapid deple-tion of the decommissioning funds by an organization that has not identified any experience in decommissioning three large nuclear plants on a very compact site. However, a strong case can be made to start with a SAFSTOR approach and then convert to a final DECON approach when opportunities present themselves for a financially attractive contract. In the meantime the funds in the Indian Point DTFs should increase and technical advances can drive down decommissioning costs.
There are too many IP1 unanswered financial questions on the use of HDI, and other questions associated with IP2 and IP3s decommissioning will only add to this uncertainty. Unless all of these questions are properly answered, it is recommended that no exemptions or license transfers to HDI take place.
7 Indian Point Energy Center, Unit 2, Preliminary Decommissioning Cost Analysis, page 1, TLG Services, Inc., October 2008, Document E11-1583-003.
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10.0 Exhibits page 13
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EXHIBIT A-1 NRC IP1 Radiological Decommissioning Cost Estimate page 14
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EXHIBIT A-2 Entergy IP1 SAFSTOR DTF Balances, Page One page 15
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EXHIBIT A-3 Entergy IP1 SAFSTOR DTF Balances, Page Two page 16
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EXHIBIT A-4 HDI IP1 DECON DTF Balances, Page One page 17
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EXHIBIT A-5 HDI IP1 DECON DTF Balances, Page Two page 18