ML21204A131

Comment (1) of Herschel Specter on Holtec Decommissioning International, LLC Indian Point Nuclear Generating, Unit Nos. 1, 2, and 3 Post-Shutdown Decommissioning Activities Report

ML21204A131
Person / Time
Site:	Indian Point
Issue date:	03/01/2021
From:	Specter H Micro-Utilities
To:	Office of Administration
References
86FR37346 00001, CLI-21-01, NRC-2021-0125
Download: ML21204A131 (86)

Text

7/23/2021 blob:https://www.fdms.gov/216da6c3-5c91-4558-a126-7034e79b8606 SUNI Review Complete Template=ADM-013 As of: 7/23/21 2:55 PM E-RIDS=ADM-03 Received: July 22, 2021 PUBLIC SUBMISSION ADD: Richard Guzman, Mary Neely Status: Pending_Post Tracking No. krf-llc4-55ij Comment (1)

Publication Date: Comments Due: October 22, 2021 7/15/2021 Submission Type: Web Citation: 86 FR 37346 Docket: NRC-2021-0125 Holtec Decommissioning International, LLC Indian Point Nuclear Generating, Unit Nos. 1, 2, and 3 Post-Shutdown Decommissioning Activities Report Comment On: NRC-2021-0125-0002 Holtec Decommissioning International, LLC; Indian Point Nuclear Generating, Unit Nos. 1, 2, and 3; Post-Shutdown Decommissioning Activities Report Document: NRC-2021-0125-DRAFT-0001 Comment on FR Doc # 2021-15068 Submitter Information Email: mhspecter@verizon.net Organization: Micro-Utilities, Inc.

General Comment See attached file(s)

Attachments Comments on NRC-2021-0125 Critique of NRC's Memorandum and Order CLI-21-01-2 blob:https://www.fdms.gov/216da6c3-5c91-4558-a126-7034e79b8606 1/1

Cover Sheet Critique of the NRCs Memorandum and Order CLI-21-01 HERSCHEL SPECTER mhspecter@verizon.net March 1, 2021

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.

Acknowledgements The author wishes to thank Mr. Michael Shatzkin, Dr. Leonard Rodberg, Dr. Dietmar Detering, and Mr. C.J. Milmoe for their valuable contributions to this document.

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

TABLE OF CONTENTS Table of Contents 1.0 EXECUTIVE

SUMMARY

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.0 Is the NRC Staff in Violation of its Own Regulations? . . . . . . . . . . . . . . . . . . . . . . . . 3 3.0 A Citizens Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 4.0 Structure of this Critique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 FIGURE A-1 Cumulative Savings at IP2 Based on HDI Data, $ in Millions - - - - - - - - - - 6 5.0 PART ONE - Is the IP2 DTF Underfunded? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 5.1. The Active Years 2021-2029 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 7 5.1.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 7 5.1.2. Unsupported HDI IP2 Cost Savings, Years 2021 to 2029 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 5.1.2.1. Savings Through Efficiency Improvements - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 5.1.2.2. Need for a Crane for IP3 Only - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 8 5.1.2.3. Class A Wastes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 9 5.1.2.4. Reactor Segmentation, Dismantling, and Demolition - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 9 5.1.2.5. Spent Fuel Heat Load - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 9 5.1.2.6. Wet Storage at IP2 and IP3 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 10 5.1.2.7. Other Potential IP2 Cost Reductions - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 10 6.0 PART TWO - Is the IP2 DTF Underfunded? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6.1. The Passive Years 2030-2061 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 6.2. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 6.3. Description of the Passive Phase - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 6.4. Historical Data - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 11 6.5. DOE Fuel Acceptance Priority Ranking (APR) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 12 6.5.1. Impact of APR on IP1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 12 6.5.2. Impact of APR on Indian Point 2 and Indian Point 3 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 12 TABLE A-1 DOE Annual Allocations (MTU) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 13 6.5.3. Further Analysis of HDI Spent Fuel Management Charges - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 13 TABLE A-2 IP2 and IP3 Spent Fuel Assembly-Years, Costs - - - - - - - - - - - - - - - - - - - - 14 6.6. Four Possibilities - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 6.7. Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 7.0 PART THREE - Exploring NRC and HDI Methodologies . . . . . . . . . . . . . . . . . . . . 17 7.1. Systemic Issues - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 7.1.1. NRC Staff Systemic Issues - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 7.1.1.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 7.1.1.2. Unheeded Warnings - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 17 7.1.1.3. Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 19 7.1.2. HDI Systemic Issues - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 19 7.1.2.1. Issues Not Dealt With - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 19 7.1.2.2. Impact of Market Forces - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 19 7.1.2.3. Predicting Future Efficiency Improvements - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 20 7.1.2.4. Contingency Allowances - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 20 FIGURE A-2 HDIs Decommissioning Schedule- - - - - - - - - - - - - - - - - - - - - - - - - - - - - 21 7.2. Exploring HDI Methodology - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22 7.2.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22 Table of Contents, page i of iii

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

TABLE OF CONTENTS 7.2.2. Description of the Three HDI Scenarios and the Eleven Alternative Scenarios - - - - - - - - - - - - - - - - 22 7.2.2.1. Scenarios #1a, #1b, and #1c - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22 7.2.2.2. Alternative Scenarios #2a, #2b, and #2c - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22 7.2.2.3. Alternative Scenarios #3a and #3b - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 23 7.2.2.4. Alternative Scenarios #4a, #4b, and #4c - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 24 7.2.2.5. Alternative Scenario #5 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 24 7.2.2.6. Alternative Scenario #6 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 25 7.2.2.7. Alternative Scenario #7 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 25 7.2.3. Results From the HDI and Alternative Sequences - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 26 TABLE A-3 Results of HDI and Alternative Scenarios - - - - - - - - - - - - - - - - - - - - - - - - 26 7.3. General Observations About the HDI methodology - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 26 7.3.1. The HDI Analysis is Incomplete - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 26 7.3.2. The HDI Analysis is Unrealistic - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 28 7.3.3. The HDI Analysis is Unstable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 29 7.4. DTFs, Inflation, Goods and Services, and the Market - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 30 7.4.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 30 7.4.2. Inflation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 30 7.4.3. Goods and Services - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 31 7.4.4. Market Effects - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 31 FIGURE A-3 Dow Jones Daily Average During 01/01/2019-12/31/2020 - - - - - - - - - - - - 33 7.5. Other Issues of Interest - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 34 7.5.1. Compensatory Actions - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 34 7.5.2. Financial Surpluses - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 34 7.5.3. Major Decommissioning Periods - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 35 7.5.4. Treasury Payments - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 35 7.5.5. Contingency Allowance and Discrete Risk Events - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 36 7.5.5.1. Contingency Allowance - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 36 FIGURE A-4 Contingency Allowances - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 38 TABLE A-4 External Contingency Allowances - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 38 7.5.5.2. Discrete Risk Events - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 39 7.5.6. Transmission Lines - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 39 8.0 PART FOUR - Protecting the Public . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 8.1. Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 40 8.2. Establishing the Initial Funds in the FAM - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 41 TABLE A-5 Estimated Initial Funds in a FAM - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 41 9.0 Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 9.1. Scenarios #1a, #1b, and #1c - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 42 9.2. Scenario #2a: Impact of Shifting the IP1 Starting Date on the IP1 Initial DTF - - - - - - - - - - - - - - - - - - - 42 TABLE A-6 IP1, 12/31/2018 DTF, HDI IP1 Withdrawal Rate, $ in Thousands - - - - - - - 43 9.3. Scenario #2b: Impact of Shifting the IP2 Starting Date on the IP2 Initial DTF - - - - - - - - - - - - - - - - - - - 45 TABLE A-7 IP2, 12/31/2018 DTF, HDI IP2 Withdrawal Rate, $ in Thousands - - - - - - - - 45 9.4. Scenario #2c: Impact of Shifting the IP3 Starting Date on the IP3 Initial DTF - - - - - - - - - - - - - - - - - - - 47 TABLE A-8 IP3, 12/31/2018 DTF, HDI IP3 Withdrawal Rate, $ in Thousands - - - - - - - 47 9.5. Scenario #3a: Finding the IP2 DTF Level That Turns Success into Failure - - - - - - - - - - - - - - - - - - - - - 49 TABLE A-9 Initial IP2 DTF Level 5.4% Less, $ in Thousands - - - - - - - - - - - - - - - - - - 50 9.6. Scenario #3b: Finding Initial IP2 DTF Level That Turns Success into Failure, 4.0% Change - - - - - - - - - 52 Table of Contents, page ii of iii

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

TABLE OF CONTENTS TABLE A-10 Initial IP2 DTF Level 4.0% Less, $ in Thousands - - - - - - - - - - - - - - - - - 52 9.7. Scenario #4a: Impact of an Annual 5% Increase in IP3s Withdrawal Rate - - - - - - - - - - - - - - - - - - - - - 54 TABLE A-11 5% Annual Increase in IP3s Withdrawal Rate, $ in Thousands - - - - - - - - - 54 9.8. Scenario #4b: Impact of an Annual 10% Increase in IP3s Withdrawal Rate - - - - - - - - - - - - - - - - - - - - 56 TABLE A-12 10% Annual Increase in IP3s Withdrawal Rate, $ in Thousands - - - - - - - - 56 9.9. Scenario #4c: Impact of an Annual 10% Increase in the IP2 Withdrawal Rate - - - - - - - - - - - - - - - - - - - 58 TABLE A-13 10% Annual Increase in IP2s Withdrawal Rate, $ in Thousands - - - - - - - - 58 9.10. Scenario #5: IP2 with IP3 Withdrawal Rates - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 60 TABLE A-14 IP2, 10/31/2019 DTF, HDIs IP3 Withdrawal Rate, $ in Thousands - - - - - - 60 9.11. Scenario #6: Combination of Two Effects - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 62 TABLE A-15 IP2, 12/31/2018 DTF, HDIs IP3 Withdrawal Rate, $ in Thousands - - - - - - 62 9.12. Scenario #7: Impact of Inflation on IP2 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 64 TABLE A-16 Impact of Inflation on IP2, $ in Thousands - - - - - - - - - - - - - - - - - - - - - - - 64 9.13. Analyzing HDIs Claim of $301 Million Dollars Less to Decommission IP2 - - - - - - - - - - - - - - - - - - - 66 TABLE A-17 Cumulative Savings at IP2 Based on HDI Data, $ in Thousands - - - - - - - - - 66 9.14. HDI Cost Estimating Approach - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 68 Table of Contents, page iii of iii

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

1.0 EXECUTIVE

SUMMARY

Nuclear Regulatory Commission Memorandum and Order CL1-21-01 denied all requests for a hearing and all petitions to intervene in the matter of decommissioning the Indian Point (IP) nuclear power facility. The NRC rightfully enjoys a very high reputation for its technical work, but the NRC Indian Point decommissioning Safety Evaluation (SE) and this Memorandum and Order are well below this standard. This Memorandum and Order puts New Yorkers at risk.

This Memorandum and Order rejected petitions submitted by NY State, local elected officials, and others because these petitions were judged to be either not based on plausible assumptions and/or did not demonstrate a material impact on the decommissioning trust funds (DTFs). Meet-ing such requirements is a heavy burden for local groups to carry. However, if this is the standard to be applied for admissibility, then both HDIs (Holtec Decommissioning International) Post Shutdown Decommissioning Activities Report (PSDAR) and the NRC Staffs SE should also be rejected.

When the NRC staff examines the radiological risk a nuclear plant presents to the public it starts with a huge number of potential initiating events and, using the rigor of probabilistic risk assess-ment technology, determines which scenarios might cause offsite consequences, their probabili-ties, and the magnitude of these potential consequences. By looking at a range of success and failure scenarios the staff determines if it has reasonable assurance that the radiological risk is acceptably low. No such process was used by the NRC staff to estimate decommissioning finan-cial risks borne by the public and if such financial risks were acceptable. Instead, the staff just looked at one success scenario that starts with a date chosen by the applicant. Start dates are quite important because decommissioning trust fund levels vary from day-to-day as market conditions vary. After selecting a start date which had favorable market and DTF conditions, HDI shut out the influence of the market for the next 40 years in its analysis. Had a petitioner presented such a financial model, would the staff have considered it plausible? The HDI financial model is the antithesis of what the Memorandum and Order stated on page 54: Over time, market fluctuations that may temporarily affect the value of decommissioning trusts are to be expected, and some fluc-tuations could potentially be significant enough to raise a dispute about the adequacy of the decommissioning funding presented in the license transfer application. Evaluating potential market fluctuations is a fundamental issue in estimating financial risks. The fact that petitioners were not capable of quantifying the importance of market fluctuations does not relieve the staff from making such calculations. Instead of just analyzing a single favorable day, 10/31/2019, as HDI did, this critique also examined 12/31/2018, just 10 months earlier, using precisely the same methodology as HDI used. This supplemental analysis found that the DTFs of IP1, IP2, and IP3 all became insolvent with a combined shortfall of $300.6 million dollars after having depleted

$2.104 billion dollars from the DTFs from these three units. Yet Entergy had informed the staff of the IP1, IP2, and IP3 DTF levels on 12/31/2018, and this did not precipitate any regulatory action.

The staff is fully capable of performing the same 12/31/2018 analysis as is presented in this cri-tique. What would the staff have done if it too calculated that all three IP DTFs would become insolvent if the 12/31/2018 data were used as input to the HDI methodology? Would the staff look closer and detect the fundamental shortcomings of the HDI methodology? The petitioners were rejected for not providing a type of analysis that the staff itself should have done.

Neither the NRC staff nor HDI examined the full range of plausible scenarios and their potential consequences, thereby creating an incomplete basis to reach a conclusion of reasonable assur-ance.This lack of completeness is further aggravated by an HDI methodology that does not model page 1

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

fluctuations in the market realistically, yet serious market fluctuations were identified as impor-tant issues in both the SE and in the Memorandum and Order.

Most concerning is HDIs decommissioning cost analysis for IP2 compared to the decommission-ing cost analysis for IP3. Everyone agrees that the designs of these two units are virtually identi-cal. The only major differences between these two units is that (a) IP2 has $262 million dollars less money in its DTF than IP3s DTF and (b) HDIs claim that it can adequately decommission IP2 for $301 million dollars less than it calculated it needs to decommission sister plant IP3. The NRC staff probed this disparity; a number of HDI justifications are listed in the SE. This critique examined each of these HDI justifications and they dont survive close scrutiny. Many of the HDI justifications are refuted in this critique using data from HDIs own PSDAR. However, the NRC staff states that it did not review HDIs PSDAR. As written on page 26 of the staffs SE The staff will only review the HDI PSDAR itself if and when the proposed license transfer is consummated.

Pursuant to 10CFR 50.82(a)(4)(ii), this review would involve an opportunity for public comment and a public meeting. How can the staff judge the accuracy of the HDI IP2 to IP3 cost difference claims if it hasnt reviewed the PSDAR in detail? How can the staff be confident of the site spe-cific cost estimates for the Indian Point units without thoroughly examining the very document, the HDI PSDAR, that is the source of the numbers in these site specific cost estimates? The HDI claim about IP2 decommissioning costs being so much less than IP3s is unique. Neither the NRC nor any utility which has completed site specific decommissioning cost estimates of sister plants on the same site claim major cost differences as does HDI. The HDI claim is contrary to common sense.

If the staff had generated alternative scenarios, as was done in this critique, the staff might have avoided making misstatements about compensatory sources of funding if there were cost over-runs. When a DTF becomes insolvent there are no surplus dollars to offset cost overruns. Unless alternative scenarios are calculated, one does not know how large a shortfall might be or when it might occur. Without such information there is no way to know if possible DOE reimbursements would be large enough or timely. Further, there may not be any DOE reimbursements after 2030 if the HDI DOE spent fuel removal assumptions turn out to be correct, whereas the alternative sce-narios calculated in this critique show some insolvencies would take place after 2030. If the staff had reviewed the PSDAR it might have found issues with HDIs analysis of the Contingency Allowance, shortfalls in the IP1 DTF, and many other defects listed in this critique. It is clear that additional financial mechanisms are needed to protect the public from HDI shortfalls. This cri-tique provides an analysis of what is needed to financially protect the public if decommissioning goes forward.

The SE lists hundreds of public comments in its Addendum D. Of these, some 152 entries are on the subject of the sufficiency of the HDI PSDAR, which also is the subject of this critique. When the Memorandum and Order rejected the petitions of NY State, local elected officials, and others it inadvertently rejected the possibility of a hearing during which the authors of these hundreds of comments would have been afforded the opportunity to express their concerns. This is unjust.

Unlike the point-by-point commentary in the Memorandum and Order on why the NY State and local elected petitioners were rejected, this opportunity for a large group of citizens was nullified without a stated reason or justification. If this critique is any measure of the contribution members of this large public group can make, these voices need to be heard.

Has this larger public, beyond the State of New York, local petitioners, and others, been treated fairly in this Memorandum and Order?

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2.0 Is the NRC Staff in Violation of its Own Regulations?

This Memorandum and Order immediately raises the question of whether the NRC staff is in vio-lation of its own regulations. NRC regulation 10CFR50.82(a)(4)(ii) states The NRC shall also schedule a public meeting in the vicinity of the licensees facility upon receipt of the PSDAR.

(Emphasis added). Holtec Decommissioning International (HDI) issued its PSDAR (Post Shut-down Decommissioning Activities Report) to the NRC on December 19, 2019. When and where did the NRC staff hold its required meeting?

It appears that no such public meeting was ever held. Such a meeting is not mentioned in the SE.

To the contrary, Addendum D of the SE lists hundreds of unanswered comments, of which 152 are on comment topic #6, the sufficiency of the HDI PSDAR. On page 26 of the NRC staffs Safety Evaluation (SE) it is stated The staff will only review the HDI PSDAR if and when the proposed license transfer transaction has been consummated. This SE statement might not have appeared in the SE if the requirements of 10CFR50.82(a)(4)(ii) had been implemented. We noted that the NRC staff has recognized the special importance of comment # 6. Of the 17 comment categories in Addendum D, only comment category 6 is discussed in the body of the SE.

The NRCs handling of the HDI PSDAR has been incoherent. The SE, on page 26, emphasizes the importance of the site-specific decommissioning cost estimate information included in the PSDAR: Regarding comment submission topic 6 concerning the sufficiency of the HDI PSDAR, the NRC staff treated the PSDAR as a supplement to the LTA on the determination that the site-specific decommissioning cost estimate information in the PSDAR was necessary to complete the review of the LTA.(emphasis added).

The site-specific decommissioning cost estimate information the NRC staff is referring to is PSDAR Tables 5-1a, 5-1b, and 5-1c, which are the decommissioning cost estimates for IP1, IP2, and IP3, respectively. On one hand the SE identifies these three PSDAR tables as necessary to complete the review of the license transfer application and on the other hand the NRC staff has not committed to reviewing the very document that these three tables come from. To further com-pound this confusion about the treatment of the PSDAR, the recent Memorandum and Order fre-quently refers to specific items in the PSDAR in defense of its conclusions. It cannot be that the NRC Commissioners have carefully reviewed the PSDAR and the NRC staff has not. The only common thread in all these different NRC statements is the refusal to listen to the publics justi-fied concerns about the HDI PSDAR.

This Memorandum and Order not only denies hearing requests by the most senior elected officials from the State of New York and by local officials near Indian Point, it appears to prevent a staff meeting with the citizens at large to resolve the 152 comments on topic # 6.

This critique deals precisely with the many defects in the HDI PSDAR, the inadequacy of the NRC staffs SE, and their impact on Memorandum and Order CL1-21-01.

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3.0 A Citizens Perspective For almost five decades the people (the rate payers) have contributed to the Indian Point decom-missioning trust funds (DTFs). The money in these DTFs is the peoples money, it is not Entergys money, it is not HDIs money, and it is not the NRCs money. This money was collected from the ratepayers to assure that after Indian Point stopped operating it would be decommissioned in a manner that met all federal, state, and local regulatory requirements. It has been reported that, out-side of a temporary bridge loan by Energy during the Great Recession, neither Entergy nor Holtec has contributed to any of these DTFs. Neither Entergy nor Holtec has publicly expressed any interest in remaining in New York and in contributing to the general welfare of people in this State. However, the people will remain and, if the NRC has made a poor decision on this decom-missioning effort, it is the people who will bear the consequences. New Yorkers need a much greater degree of assurance that they will not be faced with a nuclear waste dump on the Hudson or the need to spend additional large sums of money to finish the decommissioning process. Since neither Entergy nor Holtec has put any of their own money into these DTFs nor expressed any interest in continuing to be part of the New York community, it places special responsibilities on the NRC to protect the public during this long decommissioning process. Unfortunately, the present SE does not provide reasonable assurance and this Memorandum and Order undermines public confidence in the NRC.

Missing from this whole process is the contractual requirement to return all DTF surpluses to the people, since it is the peoples money that is paying for the decommissionings. In turn, this means than any DOE reimbursements, past and future, are placed into the DTFs. These reimbursements do not belong to either Entergy or HDI. This means that if DOE removes the spent fuel by 2030 or so, all unnecessary charges by HDI from that date onward would cease and the unused money would remain in the DTFs until returned to the people. This means that all unused money in the Contingency Allowance is returned to the DTFs.

The review of the HDI PSDAR revealed two major weaknesses, one in methodology and the other in the analysis of the funding level for IP2. The HDI methodology for estimating the costs to decommission IPEC was found to be incomplete, unrealistic, and unstable. With regard to IP2, the DTF may be severely underfunded. If IP2 has decommissioning costs similar to its sister plant IP3 there could be a shortfall of about $300 million dollars, and radiological decommissioning might not be completed. A detailed review of the HDI PSDAR did not produce any justification for HDIs claimed lower costs to decommission IP2; in fact it defies common sense and decommis-sioning estimates the NRC itself made.

The nation is facing very difficult economic times.No one, including the NRC, can assure the pub-lic that a future economic turndown wont severely reduce the amount of money in the DTFs to the point that the decommissioning process would be stopped, leaving a partially destroyed site and largely depleted DTFs. HDI makes it clear that it does not account for inflation in its analyses.

Well, it doesnt account for deflation of the DTFs either. Since small changes in the DTFs can cause wide swings from surpluses to deficits, from success scenarios to failure scenarios, starting this Indian Point decommissioning program in May, 2021 is very risky.

Citizens are primarily interested in preventing failure scenarios from occurring and secondarily interested that their money is wisely spent and that any surpluses are returned to the people. Turn-ing over the peoples money to HDI is totally counter to the best interests of the people.

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4.0 Structure of this Critique This critique is divided into four parts. Parts One and Two focus on the issue of the $301 million dollar cost difference between decommissioning IP2 versus IP3. If the cost to decommission IP2 is similar to IP3s cost to decommission, then the IP2 DTF is severely underfunded and the IP2 DTF could be empty and insolvent around year 2031, leaving a shortfall of about $298.6 million dollars. Conversely, if the cost to decommission IP3 matches that of IP2, the public would have been significantly overcharged. More fundamentally, if HDI cannot convincingly demonstrate that this large cost difference is justified, it raises doubts about all the analyses HDI has presented.

Part One concentrates on the years 2021 to 2029. This is the time period of the highest activity at the Indian Point site where actions like pressure vessel segmentation, dismantlement, and demoli-tion are to take place. This is also the time period for which the NRC staff asked HDI to explain this very large cost difference between IP2s and IP3s decommissioning costs. HDIs response to this NRC inquiry is reviewed in this report and is refuted.

Part Two covers the time period from 2030 to 2062 when cost differences between IP2 and IP3 are dominated by different spent fuel management charges. This 2030 to 2062 time period is critical to showing that the much lower costs to decommission IP2 relative to IP3 are justified, During this time period the cost difference between IP2 and IP3 is $186.9 million dollars, considerably larger than the $113.7 million dollars cost difference between IP2 and IP3 during the 2021 to 2029 years.

Part Two is further divided into years 2030 to 2046 and 2047 to 2062 to better correlate with HDIs Table 3-6, titled IPEC DOE Fuel Acceptance Allocation. Part Two can be characterized as a long passive time period, which is contrary to Part One which is very active. This is a time period when the Indian Point site would be so inactive that HDI concluded that, by 2033, the site would be ready for a partial release to some purchasing entity. This is a time period when very few people would be required to be on the Indian Point site, a time when only minor tasks like site sur-veying and report writing would remain, a time when passive spent fuel holding canisters would quietly sit on a concrete slab as the Department of Energy slowly retrieved them. During the pas-sive years from 2032 to 2061 HDI would seek a total payment of about $646.8 million dollars from the three IP DTFs, mainly to provide spent fuel management. FIGURE A-1 displays these three different time periods and is based on HDI Tables 5-1b and 5-1c. TABLE A-17 in the Appendix was created by subtracting the withdrawal rates from the IP2 DTF from the withdrawal rates from the IP3 DTF, year by year. These subtractions are the measure of how much money must be saved at IP2, relative to IP3, in order to match HDIs $301 million dollar lower IP2 decommissioning cost. Figure A-1 is a plot of the cumulative IP2 savings, derived from the data in TABLE A-17 in the Appendix.

Part Three explores the HDI methodology through the use of 11 different alternative scenarios.

These scenarios identify a number of sequences that could lead to insolvency in one or more Indian Point DTFs. Such alternative scenarios should have been generated by the NRC staff as a check on the HDI analyses. Part Three also examines other decommissioning-related subjects like compensatory actions, major decommissioning periods, U.S. Treasury payments, inflation, the contingency allowance, and discrete risk events.

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Part Four draws upon decommissioning experiences from other sites that offer the public greater assurance that they will not be left with a partially decommissioned site or pressed to supply even more public money to finish the job. One strategy would require Entergy to establish a high qual-ity Financial Assurance Mechanism which would be administered by the New York Public Ser-vice Commission combined with a written contractual commitment that decommissioning will be satisfactorily completed without any further decommissioning financial burden on the public.

FIGURE A-1 Cumulative Savings at IP2 Based on HDI Data, $ in Millions Phase Phase Phase One Two Three 300 Millions of Dollars 200 100 2021 2029 2046 2061 Year page 6

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5.0 PART ONE - Is the IP2 DTF Underfunded?

5.1 The Active Years 2021-2029 5.1.1 Introduction As of October 30, 2019, the Indian Point 2 DTF that was smaller than the IP3 DTF by $262 mil-lion dollars. Nonetheless, HDI claims it can decommission IP2 for $301 million dollars less than what it costs to decommission IP3, and end up with a surplus of $72.7 million dollars. A review of the HDI PSDAR did not provide support for this claim. Nor was there a detailed accounting for this large cost difference provided in the SE. The NRC requested additional information (RAI) on this topic from HDI, but neither this RAI nor HDIs responses have been fully shared with the public. When the SE listed potential IP2 cost savings relayed to the NRC staff by HDI, it did not quantify what each of these claimed savings were or if the total savings accounted for the $301 million dollar difference. This critique refutes all of the claimed IP2 savings listed in the SE.

The HDI claim that it can decommission IP2 for $301 million dollars less that it takes to decom-mission its sister plant, IP3, defies common sense. It is also inconsistent with HDIs PSDAR and other HDI documents. No other site in the entire USA that has sister PWRs on it has produced sig-nificantly different decommissioning costs from one unit to another. Further, the NRC has esti-mated radiological decommissioning costs for many pairs of PWRs on the same site and has published these results in SECY-18-0078. The NRC did not identify large cost differences between any pairs of PWRs in this SECY report. The NRC also made radiological decommission-ing cost estimates specifically for IP2 and IP3 and they are identical. The HDI claim of large sav-ings between IP2 and IP3 is unique.

The very nature of these claimed cost savings also is puzzling. Savings cannot be achieved for IP2 compared to IP3 because of design differences. Everyone is in agreement that the two units have virtually the same design. Savings cannot be claimed for greater efficiency from Lessons Learned first from IP3 and then used to reduce costs at IP2. HDI goes to considerable lengths to show that it is well prepared to decommission IPEC (Indian Point Energy Center). (See HDI PSDAR pages 90-92, copied in the Appendix). It seems totally inconsistent for HDI to be very well prepared and then learn major things on the job, year-after-year. Further, it seems implausible for HDI to know on December 18, 2019 when it issued its PSDAR what cost savings might be achieved through greater efficiency that might benefit IP2 many years before these cost savings might occur. If HDI knew enough to quantify these future cost reductions through greater effi-ciency on December 18, 2019 why didnt HDI apply these insights to IP3 first?

Further, not only does this critique refute HDIs claimed IP2 savings listed in the SE, the HDI claimed savings would only apply to years 2021-2029. HDI did not offer any explanation about the IP2 to IP3 cost differences in years 2030 to 2062. Yet HDI projects even greater IP2 cost sav-ings relative to IP3 costs during this later time period than during the 2021-2029 time period. It appears that the NRC staff did not ask HDI to justify the larger IP2 to IP3 differences in this later period, and no justifications were given.

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5.1.2 Unsupported HDI IP2 Cost Savings, Years 2021 to 2029 The SE provides several examples of HDIs claimed justifications for the much lower IP2 decom-missioning cost. Many of these claimed justifications are refuted by cost data in HDIs own PSDAR, the Post Shutdown Decommissioning Activities Report.

5.1.2.1 Savings Through Efficiency Improvements One claimed cost reduction justification is that there will be savings at IP2 through greater effi-ciencies gained because the IP3 decommissioning somewhat precedes that of IP2. These effi-ciency savings would have to go on year after year, but are not described in any detail in the PSDAR or in the SE. How can HDI claim on December 19, 2019 that it will apply yet unknown efficiency savings, calculated with six to nine significant figure precision, years into the future? If HDI actually had such knowledge back on December 19, 2019, why wouldnt it apply it to IP3 first to reduce its costs? On the other hand, if the potential savings from efficiency improvements years ahead were unknown at the time the HDI report was issued, then there would not be any basis for the numbers HDI listed in its Table 5-1b.

The largest cost difference between IP2 and IP3 occurs between 2048 and 2062 and amounts to

$170.1 million dollars. This IP2 cost reduction was not achieved by greater efficiency since IP2 and IP3 would have long since been demolished. The real reason that HDI calculates a much small cost for IP2, relative to IP3, in this time period is the method that HDI uses to determine DOEs removal of spent fuel assemblies from the ISFSI. Table 3-6 of the PSDAR shows that all the spent fuel assemblies from IP2 would be removed before any of the IP3 assemblies would even begin to be removed. Since HDI charges the DTFs, year-by-year, for spent fuel remaining in the ISFSI, the late removal of IP3 spent fuel assemblies runs its costs up. These lower IP2 rental costs have nothing to do with achieving greater efficiency. Had HDI based its cost analysis of the IP3 spent fuel assemblies being removed before the IP2 spent fuel being removed, the calculated IP3 surplus would have been considerably larger and the IP2 DTF would have become insolvent.

As discussed later in this critique, the HDI scheme for removing spent fuel assemblies from the Indian Point site appears to be in conflict with guidance issued by the Department of Energy.

5.1.2.2 Need for a Crane for IP3 Only Page 12 of the SE states HDI also provided clarifying information in its response to the NRC staff RAI regarding the differences in spent fuel management costs between IP2 and IP3. HDI indicated that the differences in spent fuel heat load between IP2 and IP3 and the allocation of specific costs, such as those related to the use of a crane for IP3 only, were the primary factors that explain the differences in spent fuel cost estimates between IP2 and IP3. (Emphasis added)

On page 92 of the HDI PSDAR it is stated that the reactor building overhead crane and the turbine building overhead crane will be available and are adequate. What is the purpose of an additional crane for IP3 and how much would it cost? This question is answered on page 40 of the Commis-sioners Memorandum and Order, CLI-21-01. The applicants state that certain activities related to the crane are already underway and that these activities are being funded by Entergy from sources outside the decommissioning trusts. They argue that HDI therefore did not need to factor page 8

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these activities into its cost estimates. Therefore the SE statement on page 12 is wrong and this primary cost factor for an additional IP3 crane is zero.

5.1.2.3 Class A Wastes On page 11 of the SE it is stated Specifically, HDI indicated that its schedule and sequence for performing the major decommissioning activities, including reactor segmentation, dismantling and demolition at the IPEC and differences in the estimated Class A waste volumes, accounted for much of the differences in the radiological costs between the units as depicted in the SSCE.

As to Class A wastes Table 3-1b of the PSDAR lists a cost of $13,978,756 for IP2 for the manage-ment of decommissioning low level wastes. The comparable number for IP3 is $15,176,111, a

$1,197,355 difference. If ~$1.2 million dollars represents much of the differences in the radio-logical costs between the units as depicted in the SSCE, then there cannot be a $301 million dol-lar total cost difference between IP2 and IP3 This example highlights the page 26 SE statement The staff will only review the HDI PSDAR itself if and when the proposed license transfer is consummated. If the NRC staff did not review the PSDAR, it could not have determined that the Class A waste costs are actually a very small contributor to the differences between the IP2 and IP3 cost estimates. If HDI cannot show that the differences between IP2 and IP3 decommissioning costs are justified, then the calculations pre-sented in their PSDAR should be rejected.

5.1.2.4 Reactor Segmentation, Dismantling, and Demolition The reactor segmentation, dismantling, and demolition of IP2 and IP3 are all actions that are pro-jected to be concluded by 2029 and would have no bearing on the differences in IP3 versus IP2 costs beyond that date. The cost difference between IP2 and IP3 for Conventional Dismantling, Demolition, and Site Restoration is only $25.8 million dollars (See HDI Tables 3-1b and 3-1c),

according to HDI. As to dismantling of reactor internals, WBS code #01.02.04.05.01, both IP2 and IP3 have exactly the same costs, of $38,350,000. (See HDI Tables 6-1b and 6-1c). As stated in the HDI PSDAR1 Due to the similarities in the design of the IP2& IP3 reactors, the same tool-ing will be used to segment each of the IP2 and IP3 reactor vessels and reactor vessel internals.

Therefore this task does not support a claim that IP2 can be decommissioned for $301 million dol-lars less than IP3.

5.1.2.5 Spent Fuel Heat Load Page 12 of the SE attributed spent fuel heat load as one of the contributors to the cost differences between IP2 and IP3, but did not describe the basis for this claim or quantify its cost impact.

HDIs spent fuel heat load statement is reflected in HDIs Figure 3-1 which shows that fuel removal from IP2, comes earlier than IP3 fuel removal. This eliminates any claim for lower IP2 costs due to lessons learned through greater efficiency when IP3 tasks precede IP2 tasks. It is also noted that there are more IP2 fuel assemblies, 1,988, compared to IP3 with its 1,870 fuel assem-1 See Page 11 of the HDI PSDAR.

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blies. All other things being equal, the IP2 cost to load 1,988 fuel assemblies into canisters and move these 1,988 canisters to the ISFSI should be more expensive than loading IP3s 1,870 fuel assemblies into canisters and moving these canisters to the ISFSI.

For both IP2 and IP3, during years 2021 to 2024, it is assumed that the oldest and coldest spent fuel would be loaded into canisters first. This means that the heat load issue would not be of con-cern for IP3 until all cooler spent fuel assemblies have been placed into canisters. During the time that the cooler spent fuel assemblies are being loaded into canisters, the most recently irradiated spent fuels heat load would be decreasing. By delaying the transfer of the last fuel to be irradiated into canisters, the importance of initially higher heat loads is diminished.

Therefore it is assumed that the importance of heat load is negligible between IP2 and IP3 for the first three years of spent fuel removal from the IP3 spent fuel pool. Any additional spent fuel heat load expenses for IP3 should be restricted to an additional cost for IP3s last year, 2024, of placing spent fuel into canisters. However, this fourth year, 2024, at IP3 should resemble the third year at IP2. Accordingly, the additional cost for the higher spent fuel heat load at the IP3 spent fuel pool should not exceed some fraction of the $11.4 million dollars assigned to the third year at IP2. (See year 2023 in HDI Table 5-1b). Clearly, the cost of dealing with a higher spent fuel load for the last batch of fuel to be irradiated at IP3 is a small fraction of the $301 million dollar difference.

5.1.2.6 Wet Storage at IP2 and IP3 Page 12 of the SE states that among the primary factors affecting the cost difference between IP2 and IP3 is ...differing amounts of spent fuel stored in wet storage between IP2 and IP3. Once again no specific dollar amounts are given to quantify this claim. What is peculiar about this state-ment is that the number of spent fuel assemblies for IP2 is 1,998 and 1,870 for IP3, according to Table 3-6 of the PSDAR. If anything, the costs for wet storage should be higher at IP2 compared to IP3.

5.1.2.7 Other Potential IP2 Cost Reductions Other potential cost reductions for IP2 relative to IP3 are too small to explain the claimed $301 million dollar lower cost for decommissioning IP2. Site restoration costs between the two sister plants only differ by about $3.8 million dollars. Referring to Table 2-1 of HDIs PSDAR, only one WBS element has a start date that was earlier for IP3 than IP2. Unless a WBS element in IP3 pre-cedes the same WBS element in IP2, it is difficult to explain how an efficiency based improve-ment in IP2 cost reduction might be possible.

Other areas can be eliminated as possible sources of IP3 to IP2 cost reductions. According to HDI there will not be problems in a variety of areas like local ventilation, the availability of adequate cranes in the reactor building and in the turbine building, nor problems caused by the use of spe-cialized subcontractors for water sampling, or by plant systems to carry out the spent fuel to ISFSI pad transfer campaign which are in an operational status. Therefore no improvements in effi-ciency can be claimed in any area that is already covered by HDIs claimed extensive experience or by the availability of existing plant systems or procedures.

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6.0 PART TWO - Is the IP2 DTF Underfunded?

6.1 The Passive Years 2030-2061 6.2 Introduction Section 5 of this critique explored the Indian Point decommissioning active time period from 2021 to 2029 to see if the HDI claims for much lower decommissioning costs at IP2 relative to IP3 could be verified. A review of the HDI PSDAR did not support these HDI claims. This section, Section 6, continues this search into the passive years, 2030 to 2061. The difference between IP2 and IP3 in the passive phase years is dominated by spent fuel management costs. Whereas the NRC issued a request for additional information to HDI to explain why the decommissioning of IP2 and IP3 differed so significantly, the answers it received relate only to the active years. The active period HDI answers were reviewed in Section 5 and were refuted. The staffs SE makes no mention of questioning HDI about this longer passive time period even though the total difference between IP2 and IP3 cost estimates are larger. Specifically, the active time period had a total IP2 to IP3 cost difference of $113.7 million dollars while the total IP2 to IP3 cost difference for the passive time period comes to $186.9 million dollars.

6.3 Description of the Passive Phase In this final passive phase, IP1, IP2, and IP3 will have long been dismantled and demolished and all the spent fuel would now be in passive canisters awaiting removal from the site by the Depart-ment of Energy. The site would be quite empty with no craft laborers and no management laborers and very few professional laborers. Based on the HDI PSDAR, the professional labor costs and full time equivalent hours in the final phase for IP2 is less than one percent of the IP3 professional labor costs and hours. This final passive phase, as shown in HDIs Figure 3-1, is comparatively inactive, with lesser tasks like taking site surveys, writing final reports, and a few other limited actions. Nonetheless, HDI claims that there would be a savings of $186.9 million dollars at IP2 compared to IP3 during this passive phase. This section of the critique concentrates on these HDI spent fuel management charges.

6.4 Historical Data Spent Fuel Management at the Indian Point site is not new. The ISFSI is a simple structure on which the spent fuel canisters sit until removed by the DOE, plus providing a location for low level waste to be held until removal. The ISFSI to be built at IPEC is an extension of an existing ISFSI that Entergy has used to store the present spent fuel canisters on the IPEC site. All the spent fuel functions that would be part of HDIs spent fuel management effort have already been done before by Entergy including constructing an ISFI; loading spent fuel into canisters; transferring these canisters to the ISFSI; unloading these canisters onto the ISFSI; monitoring the performance of these canisters; and providing security. Rather than HDI projecting costs for spent fuel manage-ment far into the future, the first priority should be to review the actual spent fuel management costs that Entergy incurred over many years at the Indian Point site. This Entergy experience should be the basis of the HDI spent fuel management cost estimates. It has not been established if HDI did this or if the NRC staff asked for this to be done.

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The HDI ISFSI dollar amounts appear to be radically different from ISFSI cost figures presented by Entergy to the NRC2. Entergy identifies an ISFSI obligation as of 12/31/19 at $10.45 million dollars3.

6.5 DOE Fuel Acceptance Priority Ranking (APR)

HDIs Table 3-6 is titled IPEC DOE Fuel Acceptance Allocation. The HDI PSDAR also lists DOE/RW-0567 as a reference.4 One might think that HDI used DOE/RW-0567 to develop its Table 3-6. However, the requirements of DOE/ RW-0567 and HDIs Table 3-6 are inconsistent. As stated on page 1 of this DOE report, As required by the Standard Contract, the APR is based on the date the spent nuclear fuel was permanently discharged, with the oldest spent nuclear fuel, on an industry-wide basis, given the highest priority.

6.5.1 Impact of APR on IP1 The oldest spent fuel on the Indian Point site is the 160 fuel assemblies from IP1. Based on the APR these fuel assemblies should get the highest priority in being removed from the Indian Point site. However, this is not the case displayed in HDIs Table 3-6 where 155 IP1 spent fuel assem-blies are to be removed by DOE in 2048 and the remaining 5 in 2049. Based on HDIs Table 3-6 there is enough DOE spent fuel removal capacity to remove all IP1s160 fuel assemblies in 2021.

Based on HDI Table 5-1a, keeping the IP1 spent fuel assemblies on site from 2021 through 2047 results in HDI charges totaling $72,381,000 dollars. If the cost to remove the IP1 spent fuel assemblies equaled the HDI 2021 IP1 spent fuel cost of $2,676,000 dollars, implementing the APR priorities would immediately reduce IP1 costs by $69,705,000 dollars. Further, assuming the same 2% per year real rate of return as HDI has used, this ~70 million dollar savings would grow to about $211 million dollars by 2061.Would this large sum of money belong to Holtec or to the ratepayers in New York? In any case, not removing the IP1 spent fuel first results in unwarranted income for HDI.

6.5.2 Impact of APR on Indian Point 2 and Indian Point 3 HDIs Table 3-6 describes a situation where all of the IP2 spent fuel is removed by DOE before any of the IP3 spent fuel is removed. This arrangement results in the IP2 DTF charges ending in 2047 but with the IP3 charges continuing on to 2062. Even though IP2 has more fuel assemblies than IP3; 1,988 to 1,870, the HDI spent fuel removal arrangement results in higher spent fuel management costs for IP3 compared to IP2. Specifically, HDI would charge the IP2 DTF 2 Entergy letter CNRO2020-00002, March 26, 2020, to the NRC, Enclosure 3, page 1, Note 2.

3 Based on Entergys Decommissioning Funding Plans (10 CFR 72.30) dated December 17, 2018 (Accession No. ML18351A478), escalated at 3% per annum to account for inflation.

4 DOE/RW-0567, Acceptance Priority Ranking & Annual Capacity Report, July 2004.

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$188,278,000 dollars and the IP3 DTF $371,370,000 dollars, or a difference of $183,092,000 dol-lars.

However, the time distribution of IP2 and IP3 spent fuel removal from the Indian Point site, as shown in HDIs Table 3-6, is inconsistent with Table 2 of DOE/ RW-0567, reproduced below in TABLE A-1.

TABLE A-1 DOE Annual Allocations (MTU)

Unit 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Total IP 2 3.0 27.7 32.8 27.1 52.8 33.8 63.5 31.1 33.0 25.8 330.6 1P 3 - - - 29.3 34.7 34.7 33.0 36.1 28.4 33.8 229.9 The main lesson from TABLE A-1 is that application of the DOE annual allocation program would not delay the removal of IP3 spent fuel until all the IP2 spent fuel had been removed. IP2 and IP3 spent fuel assemblies would be removed in a an overlapping mode. If HDIs Table 3-6 were recalculated to show overlapping years where both IP2 and IP3 spent fuel were being removed from the IP3 site, it would take years longer to remove all the IP2 spent fuel, increasing the spent fuel management costs for IP2. It would then have to be determined if this additional cost was enough to cause the IP2 DTF to become insolvent.

HDIs Table 5-1b lists about $76 million dollars left in the IP2 DTF by 2048, out of a starting amount of $654.1 million dollars. According to HDI Table 3-6, it would take until 2048 to remove all the IP2 spent fuel assemblies from the Indian Point site. However, if the spent fuel removal from the Indian Point site was similar to that shown in TABLE A-1 it would take longer than 2048 to remove all the IP2 spent fuel and this would incur further HDI spent fuel management costs.

HDI should recalculate IP2 spent fuel management costs with a removal process manner consis-tent with DOE/ RW-0567. Once this is done it could be determined if there is enough money to cover HDIs additional spent fuel management costs.

HDI needs to answer why its description of spent fuel removal process for IP2 differs from the program laid out in DOE/ RW-0567. Until this issue is resolved the license transfer from Entergy to Holtec should not go forward.

6.5.3 Further Analysis of HDI Spent Fuel Management Charges In order to gain further insights on HDIs spent fuel management charges, three PSDAR tables were combined to produce TABLE A-2, below. Use is made of the PSDAR Table 3-6 to determine the year-by-year number of fuel assemblies remaining on the ISFSI for IP2 and IP3. Cost figures for Spent Fuel Management were taken from PSDAR Tables 5-1b, and 5-1c for IP2 and IP3, respectively. TABLE A-2 also includes the cumulative number of assembly-years for IP2 and IP3 where the number of assembly-years added in any given year is just the product of the number of assemblies from IP2 or IP3 in residence at the Indian Point site for a single year.

The purpose of calculating assembly-years is to test whether the HDI spent fuel management charges are proportional to the number of fuel assemblies still at the Indian Point site for any given year. As expected, the number of assembly-years for IP3, 59,262, exceeds the IP2 number of assembly-years of 29,913. This higher number of assembly-years for IP3 is a direct result of the page 13

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HDI selection to keep the IP3 fuel assemblies on site until all of the IP2 fuel assemblies had been removed. This also shows up in costs with IP2 having a spent fuel management cost of

$188,278,000 dollars while the IP3 spent fuel management cost was listed as $371,370,000 dol-lars, a difference of $183,092,000 dollars. There is very close agreement between IP2 and IP3 in terms of dollars per assembly year, $6,294/assembly year for IP2 and $6,266/assembly-year for IP3. This close agreement is interpreted to mean that the cost difference between IP2 and IP3 is directly determined by the time distribution of the removal of spent fuel assemblies from the Indian Point site. If DOE requirements force a different time distribution where IP2 fuel assem-blies remain longer on the Indian Point site, the HDI decommissioning cost estimate presented in HDI Table 5-1b would be too low for IP2.

TABLE A-2 IP2 and IP3 Spent Fuel Assembly-Years, Costs End Number of Cumula- IP2 Annual Number of Cumula- IP3 Annual of IP2 spent tive Num- Cost in IP3 spent tive Num- Cost in Year fuel ber of IP2 Thousands, fuel ber of IP3 Thousands, assemblies Assembly- Spent Fuel assemblies Assembly- Spent Fuel remaining Years Manage- remaining Years Manage-at the ISFSI ment, HDI at the ISFSI ment, HDI Table 5-1b Table 5-1c 2023 1,988 1,988 11,439 0 0 N/A 2024 1,988 3,976 4,337 1,870 1,870 30,858 2025 1,988 5,964 1,608 1,870 3,740 1,421 2026 1,988 7,952 1,636 1,870 5,610 1,407 2027 1,988 9,940 1,635 1,870 7,480 1,451 2028 1,988 11,928 1,548 1,870 9,350 1,638 2029 1,988 13,916 1,553 1,870 11,220 1,638 2030 1,988 15,904 6,857 1,870 13,090 1,638 2031 1,838 17,742 6,857 1,870 14,960 1,638 2032 1,766 19,508 5,905 1,870 16,830 1,561 2033 1,642 21,150 7,701 1,870 18,700 4,763 2034 1,449 22,599 5,990 1,870 20,570 3,607 2035 1,298 23,897 6,000 1,870 22,440 3,607 2036 1,086 24,983 6,014 1,870 24,310 3,612 2037 939 25,922 6,000 1,870 26,180 3,607 2038 805 26,727 5.990 1,870 28,050 3,607 2039 676 27,403 6,000 1,870 29,920 3,607 2040 597 28,000 6,005 1,870 31,790 3,612 2041 510 28,510 6,000 1,870 33,660 3,607 2042 421 28,931 6,000 1,870 35,530 3,607 page 14

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2043 421 29,352 6,000 1,870 37,400 3,607 2044 251 29,603 6,005 1,870 39,270 3,612 2045 179 29,782 5,990 1,870 41,140 3,607 2046 110 29,892 3,152 1,870 43,010 4,433 2047 21 29,913 749 1,870 44,880 7,453 2048 0 29,913 0 1,870 46,750 11,953 2049 0 29,913 0 1,697 48,447 11,917 2050 0 29,913 0 1,605 50,052 11,927 2051 0 29,913 0 1,508 51,560 11,917 2052 0 29,913 0 1,322 52,882 11,953 2053 0 29,913 0 1,226 54,108 11,927 2054 0 29,913 0 1,130 55,238 11,927 2055 0 29,913 0 952 56,190 11,917 2056 0 29,913 0 856 57,046 11,943 2057 0 29,913 0 764 57,810 11,927 2058 0 29,913 0 579 58,389 11,927 2059 0 29,913 0 487 58,876 11,927 2060 0 29,913 0 386 59,262 11,943 2061 0 29,913 0 0 59,262 11,912 Total N/A 29,913 0 N/A 59,262 2,459 Although there is good agreement between IP2 and IP3 in terms of dollars per assembly-year, there are unexplained anomalies too. For example, in TABLE A-2, IP2 has the same spent fuel management cost of $6,000,000 for years 2035 and 2043. Yet in 2035 there are 1,298 IP2 spent fuel assemblies remaining at the ISFSI. For 2043 there are only 421 IP2 spent fuel assemblies remaining at the ISFSI, about a third of the number that were at the ISFSI in 2035, yet HDI charges the same $6,000,000 per year. If spent fuel management costs are proportional to the num-ber of remaining spent fuel assemblies on the Indian Point site, then the HDI charge to IP2 for 2043 should be $1,946,000, not $6,000,000. Similar observations have been made for IP3. Years 2054 and 2059 both have a spent fuel management cost of $11,927,000. However, there are 1,605 IP3 spent fuel assemblies in the ISFSI in 2054, but only 487 in 2059. These seemingly inconsis-tent numbers need to be explained and justified.

Starting in 2048 and for 14 years in a row, HDI would charge the IP3 DTF a constant ~$11.5 mil-lion dollars/year for spent fuel management, or about a total of $161 million dollars. While the HDI charges were held essentially constant over these 14 years, the number of IP3 remaining spent fuel assemblies decreased from 1,870 to zero. It seems implausible that HDIs charges for spent fuel management are not related to the number of spent fuel assemblies remaining on site in any given year. If spent fuel management charges are not related to the number of spent fuel assemblies still on site, what then is the basis of HDIs spent fuel management charges? One observation is that in 2048 the IP3 DTF, according to HDI, had $285.1 million dollars in it while the IP2 DTF in 2048 only had $77.2 million dollars in it. HDI has to prove that the $161 million page 15

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dollars it would deplete from the IP3 DTF in these 14 years is justified and not just a drawdown of the IP3 DTF because that is where the money would be.

6.6 Four Possibilities Since neither HDI nor the NRC staff has shown that there are justifiable decommissioning cost differences between IP2 and IP3, three possibilities arise:

a. The IP3 DTF is being overcharged, or

b. The IP2 DTF is underfunded, or

c. Combinations of a and b above, or

d. Neither the IP2 nor the IP3 decommissioning cost estimates are correct.

6.7 Conclusion Neither HDI nor the NRC staff has provided an adequate explanation of why IP2s decommission-ing should cost $301 million dollars less than IP3s decommissioning. Until this is done it is pru-dent to assume that decommissioning IP2 would cost the same as decommissioning IP3. That being the case, IP2s DTF would become insolvent in 2031 with a $298.6 million dollar shortfall.

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7.0 PART THREE - Exploring NRC and HDI Methodologies 7.1 Systemic Issues Both the NRC staff and HDI have systemic issues in their analysis of the decommissioning costs for the three Indian Point nuclear plants that need to be addressed.

7.1.1 NRC Staff Systemic Issues 7.1.1.1 Introduction The central purpose of the NRC is to protect the public. In radiological risk assessments, such as potential core melt accidents, the NRC staff looks for scenarios that might lead to reactor core damage. For each potentially damaging scenario the probability of such a scenario is estimated as are the possible consequences. Radiological risk is then defined as the product of multiplying the estimated probability of occurrence times the calculated consequences. Then a judgement has to be made whether this level of risk is acceptable. To make such a judgement the idea of what con-stitutes acceptable risk has to be established.

Radiological risk assessment is a more advanced mathematical process for decision-making than the process used to determine Reasonable Assurance in the domain of decommissioning. None-theless, portions of this more advanced decision-making process can be utilized when judgements are based on acts of Reasonable Assurance. The NRC staff needs to search for scenarios that would potentially lead to IPEC DTFs becoming insolvent. It does not appear that the staff took this approach.

7.1.1.2 Unheeded Warnings The NRC staff had many warnings that should have resulted in a more comprehensive and ques-tioning review of HDI and the HDI PSDAR. It appears that the HDI DECON analysis for IP1 does not agree with the Entergy SAFSTOR analysis for IP1. Entergys analysis showed that it would take decades before the IP1 DTF, in a SAFSTOR decommissioning mode, could accumu-late enough funds just to achieve radiological decommissioning. By contrast, the HDI analysis claims that both radiological and non-radiological decommissioning of IP1 could be accom-plished by the DECON method starting in 2021, even though the DECON method would rapidly deplete the IP1 DTF, thereby reducing the funds that the DTF itself might generate during the decommissioning process. Page 15 of the NRCs SE lists a HDI IP1 radiological decommission-ing cost estimate of $485,015,000 in 2019 dollars.The HDI estimate also does not agree with the Entergy estimate of $592.89 million dollars based on SAFSTOR expenditures5. This seeming HDI DECON/Entergy SAFSTOR disparity on IP1 is not the only early warning. Table 2 of the NRCs SECY-18-0078 lists an estimated remaining cost to complete radiological decommission-ing for IP1 of $560,500,000 in 2016 dollars. Updating the NRCs SECY estimate to 2019 dollars would bring the NRCs IP1 radiological decommissioning cost estimate to $597,045,000 dollars, very similar to Entergys IP1 estimate. Comparing the updated NRC radiological decommission-5 Entergy letter CNRO2020-00002, March 26, 2020, to the NRC, Enclosure 1, page 1.

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ing estimate for IP1 to HDIs IP1 cost estimate leaves an unexplained $112.0 million dollars dis-crepancy. It appears that the HDI DECON analysis for IP1 does not agree with the NRC SECYs cost estimate to complete IP1s radiological decommissioning.

Another warning is contained in the October 29, 2020 letter to the NRC staff from Micro-Utilities, Inc. about HDIs claim that it could decommission IP2 for $301 million dollars less than the cost to decommission sister plant IP3. Since these are nearly identical sister plants on the same site this HDI claim defies common sense. The SE shows that further information on this subject was requested by the staff on this subject and replies were received from the Applicant. Neither this NRC staffs request for additional information nor HDIs responses have been shared with the public. This critique looked into this issue more closely and found that the Applicants responses, as broadly described in the SE, appear to be inconsistent with information in the PSDAR. If IP2 costs as much as HDI claims it costs to decommission IP3, there would be a shortfall around $300 million dollars. HDIs claim that there could be very large cost differences between two sister plants on the same site is unique. No other pair of sister PWRs on the same site exhibits the cost differential that HDI claims for IP2 and IP3 and that alone should have been a warning to the NRC staff.

Micro-Utilities also compared the estimated decommissioning costs per megawatt-electric for 16 different nuclear units in TABLE A-3 of its October, 2020 report, Decommissioning Indian Point One, which was sent to the NRC prior to the issuance of the staffs SE. The HDI dollars/MWe for IP2 and IP3 are lower than all but one other unit. How does HDI, with no experience in decom-missioning large PWRs on a crowded site, come up with lower costs per MWe than all of these other nuclear plants? This question is especially concerning for IP2 with its dollars per MWe about one third that of the nearly identical two Diablo Canyon PWRs. Did this warning in the Micro-Utilities document cause the NRC staff to investigate such wide differences?

The NRC staff recognized that there can be large fluctuations in the market, both up and down.

These fluctuations directly affect the amounts of money in the DTFs. Having made this correct observation, it is not apparent that the NRC staff pursued the implications of this market variabil-ity, yet such a pursuit is possible, as shown in this critique. Recalculating HDIs Tables 5-1a, 5-1b, and 5-1c with the IPEC DTFs on December 31, 2018 would result in IP1, IP2, and IP3 calculated to become insolvent prior to the completion of all radiological decommissioning tasks. Such recalculations also identify what year a DTF would run out of money and how large the shortfall would be. All such Micro-Utilities recalculations employ exactly the same input data, assump-tions, and methodology that HDI used. All that is required is to substitute the DTFs on 12/31/2018 for HDIs DTFs 10/31/2019, the base date for HDIs Tables 5-1a, 5-1b, and 5-1c and then calcu-late the annual numbers. Such recalculations appear in the Appendix of this critique, Sections 9.2, 9.3, and 9.4 for IP1, IP2 and IP3, respectively. The start date of 12/31/2018 is not unique, as other start dates could have been chosen and additional recalculations could have been made. The result of some recalculations, each at a start date when the market was higher than it was on October 31, 2019, would be larger surplus than the surpluses HDI calculated. However, other dates, when the market was below that on October 31, 2019, may engender failure scenarios similar to that calcu-lated for 12/31/2018. Had multiple recalculations been made covering 2019 and 2020, the NRC staff would have ended up with a distribution of results, some being success scenarios and others being failure scenarios. The method for determining reasonable assurance when there is a distri-page 18

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bution of success and failure scenarios has not been demonstrated in the SE. While analyzing many scenarios with different start dates is more laborious than what HDI did, the result would be far more realistic than letting HDI choose a single start date which has favorable DTF conditions.

By only looking at HDIs single selected start date of 10/31/2019 the NRC staff lost an opportu-nity to estimate how sensitive the initial amounts of money in the DTFs are to market fluctuations.

This too has been calculated and is reported in this critique. It is now known that the initial DTFs are fairly sensitive to changing market conditions, with IP1, IP2, and IP3 having somewhat differ-ent sensitivities. It is estimated that for each one percent decrease in the market there would be a calculated aggregate decrease of about $25 million dollars in the total DTF dollars at IPEC.

The largest missed opportunity for the NRC staff is not holding a hearing prior to issuing the SE, in order to directly learn more from the 152 commenters identified in the SEs Addendum D on Comment Topic Reference Number 6 Concerns About the Sufficiency of the HDI PSDAR. To be able to respond to these 152 commenters, the NRC staff would have to read and analyze the PSDAR. However, on page 26 of the SE it is stated The staff will only review the HDI PSDAR itself if and when the proposed license transfer transaction is consummated.

7.1.1.3 Conclusion It would be beneficial if the processes to reach a conclusion of Reasonable Assurance more closely followed the processes used in decision making in the area of radiological risk assessment.

However, developing this capability could be a time consuming effort. Further, radiological risks are so very low, reaching a conclusion of acceptable radiological risk is comparatively easy.This may not be the case for financial risk assessments for decommissioning because of the anticipated wide bands of uncertainty and because calculated mean values may be too high to achieve wide-spread acceptance.

7.1.2 HDI Systemic Issues HDIs Tables 5-1a, 5-1b, and 5-1c are all estimates of future decommissioning costs at IP1, IP2, and IP3, respectively. These estimates reach far into the future, possibly until 2063 or later. How-ever, multiple issues arise on how well HDI deals with long range cost projections.

7.1.2.1 Issues Not Dealt With In some situations future costs and their impacts on Tables 5-1a, 5-1b, and 5-1c are just not dealt with at all. Three examples of this are the effects of inflation, the rising costs for goods and ser-vices, and the potential impact of discrete risk events.

7.1.2.2 Impact of Market Forces Perhaps the largest long term systemic cost issue for HDI is how it deals with the relationship between the stock market and the amounts of money in the IPEC DTFs. There are two parts to this issue. The first part is HDIs selection of a single day, October 31, 2019, as the sole connection between the market and the Indian Point decommissioning trust funds. How does a single days DTFs represent the impact of market forces over a 40 year time span when it is known that mar-page 19

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kets go up and markets go down? What was the process for selecting this favorable start date?

Where is the NRC guidance on start dates? The second part to this start date issue, is that once it is selected (by HDI) no further interactions between the market and the monies in the DTFs are con-sidered. So the HDI methodology places extreme importance on the market and its DTF impacts for just one day and then does not consider any market forces for the next 40 years.

7.1.2.3 Predicting Future Efficiency Improvements The HDI methodology also creates issues dealing with future unknown costs. Two examples of this are cost reductions at IP2 based on improved efficiencies by lessons learned from the decom-missioning of IP3 and Contingency Allowances. The HDI PSDAR was issued on December 19, 2019. How is it possible for HDI to quantify, sometimes to 6 or 9 place precision, unknown effi-ciency improvements years into the future? If the ability to decrease decommissioning costs at IP2 through improved efficiency was precisely known on December 19, 2019, why wouldnt these recognized efficiencies be applied to IP3 first? If, on the other hand, these future efficiencies were not known on December 19, 2019, how can HDI quantify their cost benefits and insert these num-bers into Tables 5-1a, 5-1b, and 5-1c?

7.1.2.4 Contingency Allowances The most important observation about HDIs use of a Contingency Allowance is the analysis pre-sented in Section 7.5.5.1 of this critique. It appears that HDIs application of its 18% figure results in a zero Contingency Allowance.

HDI claims it uses an 18% allowance, except for the ISFSI (the Independent Spent Fuel Storage Installation) where the allowance is 25%. The purpose of the Contingency Allowance is to deal with the inherent uncertainties in HDIs cost analyses. This 18% allowance is at a 85% confidence level. This is interpreted to mean that 85% of the time the effects of unknown events will have a cost impact equal to or less than 18% of the cost to implement the task at hand. When this happens there should be money left over out of the Contingency Allowance, which should be returned to the DTF that funded the completion of these tasks.

Over the span of forty years, many tasks will need to be carried out. The nature of these tasks will vary significantly from major physical actions like reactor vessel and internals undergoing seg-mentation and containment building demolition in the first 12 years, to far fewer active events in later years when there are tasks like site surveys and report writing. Therefore the uncertainty components that were considered in the generation of the 18% Contingency Allowance, at an 85%

confidence level, will change over time. Because the design of IP1 differs from the design of IP2 and IP3, it has its own set of uncertainties. It seems appropriate for HDI to set an 18% Contin-gency Allowance but inappropriate to claim that this 18% Contingency Allowance will be fully consumed for each and every task, year after year. When HDI issued its PSDAR on December 19, 2019 it had no way of knowing which situation dependent events would occur in the future, their costs, and which ones might fully consume the Contingency Allowance. From a public protection point of view, all unused monies in the Contingency Allowance should be returned to the respec-tive DTFs. This return of unused monies should be done task by task and closely monitored by independent inspectors. All of the above HDI issues have this in common: they work to HDIs benefit.

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FIGURE A-2 HDIs Decommissioning Schedule page 21

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7.2 Exploring HDI Methodology 7.2.1 Introduction Part One is a review of the process that HDI used to calculate its proposed financial decommis-sioning scheme. The NRC staff used the HDI results to reach a conclusion of reasonable assurance that IPEC could be adequately decommissioned while meeting all federal regulatory require-ments. Part One concludes that the present HDI decommissioning assessment process is incom-plete, unrealistic, and unstable. Because of these defects, NRC staffs approval of the IPEC license transfers and exemptions places New York citizens at considerable risk.

Part One used the same material the NRC staff relied on in its SE, HDIs Tables 5-1a, 5-1b, and 5-1c from HDIs PSDAR, plus Decommissioning Trust Fund (DTF) data provided by Entergy to the NRC. HDIs own data, assumptions, and methodology were used to generate eleven alternative scenarios that demonstrated that HDIs methodology is incomplete, unrealistic, and unstable.

These alternative scenarios exposed multiple pathways that can end with fully depleted DTFs prior to completing all radiological decommissioning tasks, along with significant financial short-falls that the public might be burdened with.

7.2.2 Description of the Three HDI Scenarios and the Eleven Alternative Scenarios 7.2.2.1 Scenarios #1a, #1b, and #1c These three scenarios can be found in HDIs PSDAR Tables 5-1a, 5-1b, and 5-1c for IP1, IP2, and IP3, respectively. These three HDI scenarios are based on the amounts of money in the IP1, IP2, and IP3 DTFs on October 31, 2019, less pre-closure deductions. The initial dollar amounts HDI used in these scenarios were $533,532,000, $654,078,000, and $916,100,000 for IP1, IP2, and IP3, respectively.

7.2.2.2 Alternative Scenarios #2a, #2b, and #2c Alternative scenarios #2a, #2b, and #2c analyze IP1, IP2, and IP3, respectively. These three HDI scenarios are based on the amounts of money in the IP1, IP2, and IP3 DTFs on December 31, 2018, less the same pre-closure deductions assumed by HDI. The December 31, 2018 date was selected because the respective DTF holdings on that date were available from reports that Entergy had submitted to the NRC. The dollar amounts in the IP1, IP2, and IP3 DTFS on Decem-ber 31, 2018, less pre-closure costs, were $411,900,000, $583,262,000, and $765,443,000, respectively. All three of these scenarios are failure scenarios because their DTFs become insol-vent prior to 2062.

One-to-one detailed comparisons can be made between the HDI based #1a, #1b, and #1c scenarios and the #2a, #2b, and #2c scenarios to provide assessments of the impacts of selecting a different start date than the one HDI chose. For case #2a on IP1, the impact of moving the start date from 10/31/2019 to 12/31/2018, just 10 months earlier, resulted in a successful scenario becoming a failure scenario with the IPI DTF becoming insolvent in 2031. Instead of the $20.0 million dollar surplus that HDI calculated, this earlier date would have produced a $139.9 million dollar deficit, a swing of $159.9 million dollars.

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For the scenario #2b analysis of IP2, its DTF would become insolvent in 2043 with this change in start dates. Compared to the HDI analysis, instead of a surplus for IP2 of $72.7 million dollars, there would be a deficit of $45 million, a swing of $117.7 million dollars.

For IP3, as analyzed by scenario #2c, the IP3 DTF would become insolvent in 2054 creating a def-icit of $115.7 million dollars and a swing from the HDI calculations of $286.3 million dollars.

The total swing for the IPEC site by choosing an earlier start date of 12/31/2018 would be $563.9 million dollars. This total swing is larger than the whole IP1 DTF on 10/31/2019. After decades of saving and investing to implement decommissioning, a change in start dates less than one year apart is sufficient to cause three success scenarios to become failure scenarios and to shift sur-pluses to deficits in the amount of $563.9 million dollars, if one accepts the HDI methodology. Yet the 12/31/2018 date is not remarkable, with total DTFs about 16% smaller than the total DTFs on 10/31/2019. 16% is less than HDIs Contingency Allowance of 18% and far less than the 32% to 36% declines in the market during the COVID pandemic that the SE has pointed out.

The HDI financial model creates a situation where any shortfall in any year is reflected in reduc-ing DTF holdings in every subsequent year, further magnified by reduced earnings in the trust fund, year-after-year. The HDI financial model structure is very sensitive to market levels at the start dates and also to market levels even after the start date. Whereas the NRCs SE makes a point of the variability (fluctuations) of the stock market and therefore the DTFs, the HDI financial model structure does not begin to capture this reality.

7.2.2.3 Alternative Scenarios #3a and #3b The purpose of these two scenarios is to estimate what decrease in the initial funding for IP2 would prevent the completion of the final radiological decommissioning tasks, i.e., the IP2 DTF would become insolvent before 2062. An initial estimate, scenario #3a, of $618,700,000, or 5.4%

less than the HDI number was selected. With this assumption the IP2 DTF was calculated to become insolvent around 2059 with a shortfall of $11.8 million dollars. To gain further precision a second estimate, scenario #3b, was calculated assuming an initial DTF of $627,915,000 or 4%

less than the HDI initial DTF. This resulted in a calculated surplus of $20.8 million dollars. These results were cross plotted and a decrease of around 4.8% of the initial HDI DTF would result in a zero dollar DTF balance. This meant that for IP2 any event or combination of events that led to an initial IP2 DTF smaller than the HDI DTF by 4.8% or more, would result in the IP2 becoming insolvent before 2062.

One immediate application of this 4.8% figure is to develop a sense of how many days in 2019 and 2020 might produce IP2 DTFs with insufficient funds. This is discussed later in this critique, in Section 7.4.4 Market Effects. Another use of these analyses can be found in scenario #3a. For example, if one compares the year 2025 HDI DTF level of $380,777,000 dollars to the alternative scenario #3a, the DTF for 2025 is $343,150,000, a difference of $37,627,000 dollars. However, if there was a three year long event for 2022, 2023, and 2024 that depleted the DTFs in each of these three years by one third of $37,627,000 dollars, or $12,542,000 dollars, year 2025 in the HDI would also be around $343,150,000. From year 2025 onward the HDI financial analysis and the alternative scenario financial analysis would be the same. The average DTF for years 2022-2024 is $501,009,000 dollars. $12,542,000 represents just 2.5%/year of this three year average value page 23

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and would be sufficient to convert HDIs success scenario for IP2 to a projected failure scenario.

This small decrease of 2.5% over each of these three years takes on special importance in Part Two of this critique. If HDIs assumed savings over this three year period by gains in efficiency, is in error by a cumulative amount of $37,627,000 dollars, the IP2 DTF would eventually become insolvent. Once again, small differences can lead to very different end points, i.e., insolvency before the radiological decommissioning is completed.

Similar alternative scenarios could readily be made for IP1 and IP3 about minimum initial DTF levels that are needed to prevent their DTFs from becoming insolvent. IP1 and IP3 can also be analyzed to determine the size of the decrease in the DTF during 2022 to 2024 that would cause IP1 and IP3 to become insolvent. The point here is that even if the USA avoids a recession in the next few years, small DTF reductions, on the order of a few percent, for just a few years could lead to all the IPEC units eventually becoming insolvent. Based on the HDI methodology, nei-ther a full scale depression nor a recession is needed to turn the IPEC decommissioning into failure sequences; just an economic slowdown over a few years might do this as well.

Neither HDI nor the NRC staff has expressed this observation, likely because they did not gener-ate these alternative scenarios.

7.2.2.4 Alternative Scenarios #4a, #4b, and #4c In Scenarios #3a and #3b, changes in the DTF levels were only made to the first year. In Scenarios

1. 4a,#4b, and #4c it was assumed that a fixed percentage, 5% or 10%, higher withdrawal costs were used year-by-year than what HDI calculated. These percentages are less than the 18% Con-tingency Allowance that HDI claims it is using. These analyses are useful in evaluating systemic problems that create higher costs than those considered by HDI. For example, HDI does not account for a systemic issue like inflation or the rising price of goods and services over the course of the decommissioning project. A comparison of Scenario #4b to #4c showed that IP2 is more likely to become a failure scenario than IP3 is. Even with a 10% increase each year in withdrawal rate, IP3 is calculated to still have a surplus of $9.2 million dollars. A 10% annual increase in the annual withdrawal rate for IP2 would leave a calculated deficit of $49.6 million dollars and unfin-ished radiological decommissioning tasks. Scenario #4a, combined with surplus results from Sce-narios #1c and #4b, indicates that IP3 would need an annual increase in withdrawal rate close to 11% before in might become a failure scenario. The lower resilience of IP2 is likely due to the fact that its DTF is considerably smaller than IP3s.

7.2.2.5 Alternative Scenario #5 HDI claims that it can decommission IP2 for about $301 million dollars less than it takes to decommission sister plant IP3. The purpose of alternative Scenario #5 is to estimate the impact of IP2 having withdrawal rates equal to those HDI used for IP3. This alternative scenario repeats the HDI scenario in HDI Table 5-1b, but inserts the IP3 withdrawal rate from HDI Table 5-1c. If IP2 decommissioning costs are the same as those for IP3, the IP2 DTF would become insolvent by 2031, leaving a deficit of about $298.6 million dollars in unfinished decommissioning tasks.

Because such large sums of money are involved as well as the failure to complete radiological decommissioning, HDIs claim of very large savings for IP2 relative to IP3 is examined in Part Two of this critique.

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7.2.2.6 Alternative Scenario #6 All the previous alternative scenarios examined just one event at a time, like a change in the start date. However, there are multiple events that are independent of one another and could happen simultaneously. Alternative Scenario #6 examines one such possibility, IP2 experiencing with-drawal rates equal to that of IP3 and a DTF equivalent to that of a start date of 12/31/2018. This combination of events is calculated to cause the IP2 DTF to become insolvent in 2029 with $375 million dollars of unfinished decommissioning tasks. No estimate has been made on further expenses for IP1 and IP3 that an insolvent IP2 might cause schedule slippage in IP1 and/or IP3.

7.2.2.7 Alternative Scenario #7 This scenario estimated the impact of possible inflation on IP2 to provide some guidance since HDI did not consider the effects of inflation. While future inflation rates are unknown some guid-ance can be gained from historical values. More details are provided in Section 7.4.2. Including estimates of future inflation rates leads to the conclusion that inflation is an important consider-ation. In Scenario #7, inflation reduced the HDI projected surplus for IP2 from $72.7 million dol-lars down to around $7.1 million dollars. One important lesson from Scenario #7 was, when the effects of inflation are considered, a failure scenario can occur with just a small further financial effect. Stated differently, even with a modest assumed inflation rate, IP2s DTF is likely to become insolvent with any other event that depletes the DTF beyond the numbers that HDI pre-sented for IP2 in its PSDAR Table 5-1b.

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7.2.3 Results From the HDI and Alternative Sequences TABLE A-3 provides the results of the HDI and alternative scenarios. Specific alternative sce-nario analyses are provided in the Appendix.

TABLE A-3 Results of HDI and Alternative Scenarios Scenario IP Input Conditions DTF Surplus/ Radiological Unit(s) Deple- Shortfall Decommis-tion $Mil- sioning Date lions Obtained?

1. 1a IP1 Analyses as per Tables 5-1a, 5-1b, and > 2062 +20.0, Yes

1. 1b IP2 5-1c in HDI PSDAR > 2062 +72.7, Yes

1. 1c IP3 > 2062 +170.6 Yes

1. 2a IP1 Impact of changing initial DTF from 2031 -139.9 No

1. 2b IP2 that on 10/31/2019 to DTF on 12/31/ 2043 -45.0 No

1. 2c IP3 2018. No change in withdrawal rates. 2054 -115.7 No Finding the IP2 initial DTF that turns the HDI IP2 results from success to failure.

1. 3a IP2 Initial DTF=$618,670,000 (5.4% less) 2059 -11.8 No

1. 3b IP2 Initial DTF=$627,915,000 (4.0% less) >2062 +20.8 Yes Impact of Higher Withdrawal Rates, Year-After-Year

1. 4a IP3 5% Increase in IP3 Withdrawal Rate >2062 +81.6 Yes

1. 4b IP3 10% Increase in IP3 Withdrawal Rate >2062 +9.2 Yes, barely

1. 4c IP2 10% Increase in IP2 Withdrawal Rate 2043 -49.6 No

1. 5 IP2 IP2 Withdrawals = IP3 Withdrawals 2031 -298.6 No IP2 DTF as of 10/31/2019, but with IP3 10/31/2019 Withdrawal Rate

1. 6 IP2 Combination of two effects 2029 -375.0 No IP2 DTF as of 12/31/2018, but with IP3 10/31/2019 Withdrawal Rate

1. 7 IP2 Effects of Inflation >2062 7.1 Yes 7.3 General Observations About the HDI methodology 7.3.1 The HDI Analysis is Incomplete One of the major flaws in the HDI analysis, and in the NRCs review of the HDI submittals, is that the HDI analysis relies on a specialized success scenario, keyed to a single calendar date, whereas a more comprehensive multi-scenario process that examines both success and failure scenarios over long periods of time is necessary.

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It is now common practice to solve multi-scenario situations. The NRC itself deals with multiple scenarios in its probabilistic risk analyses to determine if an operating nuclear power plant pre-sents an acceptably low level of risk to the public. Investment firms routinely provide financial forecasting services where large numbers of scenarios are considered and outcome distributions are presented that can form the basis for financial decision making.

In fact, HDI is capable of analyzing multi-scenario situations. It did exactly this in its justification for using 18% as its Contingency Allowance and it evaluated Discrete Risk Events (See pages 93-95 of HDIs PSDAR).

The NRC recognized that different stock market conditions affect the amounts of money in the DTFs. As spelled out on page 14 of the Safety Evaluation (SE), equity markets fluctuate with time. Also stated in the SE equity markets declined by 32 to 36 percent between mid-February to mid -March 2020. The SE also points out equity markets can rise, as they have in recent times, giving the example of a 13.2 percent rise between September 2019 and September 2020.

While the SE recognized market fluctuations, which would continuously affect the amounts of money in the DTFs over the long course of the decommissioning process, it appears that the staff did not act on this observation. It appears that the staff did not search for those fluctuation situa-tions that would lead to failure scenarios. Yet failure scenarios are far more important then success scenarios. It is failure scenarios that prevent the completion of all the radiological decommission-ing tasks. It is failure scenarios that place the public at financial risk. Instead, the staffs conclu-sion of reasonable assurance seems to be based on a single successful, static HDI analysis. The dynamic fluctuating market conditions model the SE refers to is the opposite of the model used by HDI to produce Tables 5-1a, 5-1b, and 5-1c which the NRC staff relied upon.

Market fluctuations are not the only pathway to an insolvent DTF. There may be cost overruns due to discrete risk events. Further, the HDI methodology does not account for inflation or the escala-tion of the price of goods and services over the course of the project. Based on data found in Entergy reports, the cost for labor increased by about 9% between 2015 and 2018. What are the long term effects of not estimating the effects of inflation or the escalation of the price for goods and services on a DTF becoming insolvent?

Even without a sophisticated multi-scenario computer program, the NRC staff could have gener-ated simple alternative analyses as was done here. Had this been done the staff might have noticed that perturbations of the HDI analysis that lead to failure scenarios are typically smaller than HDIs 18% Contingency Allowance and much smaller than the fluctuations the staff observed in the market place. The staff might have noticed that combinations of two or more very small per-turbations could lead to a failure scenario. Having identified multiple pathways to failure scenar-ios through the use of a small set of alternative scenarios, would the staff conclude that the single successful scenario that HDI provided was sufficiently complete to support a conclusion of Rea-sonable Assurance?

Another area where the HDI analysis is incomplete relates to the much smaller costs to decommis-sion IP2 compared to IP3. One of the explanations for this lower cost at IP2 is a HDI claim of greater efficiency in that there would be lessons learned from observing the decommissioning of IP3 which, in most cases, precedes the decommissioning of IP2. However, year-after-year the page 27

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cost to decommission IP2 is lower than the cost to decommission IP3. HDI must describe those specific actions that it claims lead to cost savings each year and explain how the savings from these specific actions were translated into dollars saved. This is especially important in the 2047 to 2061 time frame. Even though IP1, IP2, and IP3 would have long been demolished by 2047 with very few people left at the IP site, HDIs analyses indicate that decommissioning IP2 would cost about $170.1 million dollars less than IP3 for this time period.

The HDI analysis of the money in the Contingency Allowance also is incomplete. A constant Contingency Allowance of 18% is assumed over all three plants over a 40 year time span. Even though the tasks to be completed in the first 12 years or so are very different from the tasks to be completed in the last 12 years, the same 18% is assumed. But events that might cause cost increases to be covered by the Contingency Allowance differ from one time period to another and from IP1 to IP2 or to IP3. The only way a flat rate contingency allowance might work for the ben-efit of the public is to return all unused portions of a task based Contingency Allowance back to the DTF. However, HDI did not propose this and did not provide any pathway for an unused por-tion of the Contingency Allowance to be returned to the DTF (the peoples money) from which it had originally come. HDI, instead claimed that all of the Contingency allowance would be fully consumed. That works against the best interests of the people.

7.3.2 The HDI Analysis is Unrealistic The HDI PSDAR analysis starts with the DTF funding level that occurred on a single day, Octo-ber 31, 2019 selected by HDI. If a different start date had been selected, particularly a day between mid-February to mid-March, 2020, the HDI PSDAR would have shown completely dif-ferent results. The only time the HDI model is influenced by market conditions is the DTF level on the selected single first day. This means that year-after-year through 2062, the projected amounts of money in the Indian Point DTFs are not influenced by market conditions. Yet, even out to 2062, DTF funding levels are directly influenced by the selection of a single first days DTF. The HDI computer model generates nine place numbers of the amounts of money in DTFs without accounting for any future effects from the market and without providing any kind of uncertainty analysis.

Subsequent days and years beyond the first starting day and first year may experience significant market downturns, large enough to cause the DTFs to become insolvent then or at a later date as funds continue to be withdrawn from the DTF. Does anyone really know if present severe eco-nomic conditions in the United States wont result in downturns or even recessions in 2021, 2022, or beyond?

It is unrealistic for the HDI financial analysis to first put so much emphasis on the market condi-tion for a single day then ignore the impact of the market during the next 40 years. It is unrealistic for the NRC staff to come to a conclusion of reasonable assurance based on an unrealistic HDI financial model based on a single days favorable market.

It is unrealistic for HDI to project years ahead what cost savings might accrue to IP2 from learning from the execution of IP3 tasks that precede the same tasks at IP2. If HDI can identify and quan-tify more efficient money saving methods that might benefit IP2, why wouldnt these same more economical insights be applied to IP3 first?

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It is unrealistic for HDI to ignore the effects of inflation, the increasing costs for goods and ser-vices, the impacts of discrete risk events, or assume that the same Contingency Allowance applies to all tasks over several decades, and equally for IP1 as it does for IP2 and IP3.

It is noted that all these unrealistic assumptions or unrealistic methods benefit HDI.

7.3.3 The HDI Analysis is Unstable As described before, a system is unstable if a small perturbation can lead to a large change in out-come. In the HDI methodology there are many different sources of small perturbations that can lead to large changes in the outcome. The HDI computer model predicts a combined surplus of

$263 million dollars from the three Indian Point units at the end of the decommissioning process, assuming a start date of October 31, 2019. Change the start date to 12/31/2018, ten months earlier, and there would be a combined shortfall of $299.7 million dollars. This represents a total shift of

$563 million dollars which is very close to the total amount of money in the IP1 DTF, which has taken decades to accumulate.These large swings from surpluses to deficits caused by a small change in the start date meets the definition of instability. Increase the IP3 withdrawal rate by 5%/

year and the HDI projected surplus would shrink from $170.6 million dollars down to $81.6 mil-lion dollars. Note that this 5%/year figure is smaller than HDIs 18% Contingency Allowance fig-ure which is supposed to account for a range of possible perturbations. In another scenario, a 10%/

year increase in IP2s withdrawal rate would cause its DTF to become insolvent by 2043. Instead of a surplus of $72.7 million dollars that HDI estimated for IP2, a 10% increase in the withdrawal rate would cause a $49.6 million dollar deficit. The total surplus to deficit shift for a 10% increase in the IP2 withdrawal rate is $122.3 million dollars.

Not only can many small perturbations result in large shifts between surpluses and deficits, they also can convert success scenarios into failure scenarios where radiological decommissioning would not be completed.

Calculated financial difficulties can occur in other ways besides variations in the DTFs caused by fluctuations in the market place. Discrete risk events, discussed later, could be large enough to push a DTF into insolvency. Discrete risk events that cause the annual IP3 withdrawal rate to be larger by10% would cause the IP3 DTF to become insolvent before 2062. An increase in the with-drawal rate at Indian Point need not come from a single event. There can be combinations of smaller events, like a change in market conditions coinciding with a small discrete risk event like a schedule slip, which together could lead to a failure scenario. One severe combination of events that was investigated was a situation where the costs to decommission IP2 matched those of IP3 and the money in the IP2 DTF matched that on 12/31/2018. This combination of events led to a calculated $375 million dollar shortfall to complete the IP2 decommissioning with the IP2 DTF becoming insolvent in 2029.

In another analysis presented in Section 7.2.2.3 an increase in withdrawal rates of only 2.5% for three consecutive years would be sufficient to bring IP2 to the brink of insolvency.

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7.4 DTFs, Inflation, Goods and Services, and the Market 7.4.1 Introduction The outcomes of the financial scenarios examined in the HDI PSDAR and in the alternative sce-narios presented in this critique are dependent of the dollar levels in a nuclear units DTF.

Decreases in the market can reduce the dollar value of a DTF. Increases in the amounts of money needed to complete specific decommissioning costs that are not accounted for by the Contingency Allowance (Section 7.5.5.1) also decrease a DTF beyond what had been planned for. Using IP2 as a case study, Scenarios #3a and #3b show that a decrease above 4.8% just in the first years DTF could prevent the final radiological decommissioning steps from being completed. Such a small decrease in the DTF could be the result of a decrease in the market. Even if there were no market declines, a limited annual increase in the amounts of money that would be withdrawn to execute the decommissioning process can cause the DTFs to become insolvent. This annual additional cost issue was examined in Scenarios #4a,#4b, and #4c.

It is not necessary to have market declines or even annual increases in the withdrawal rate to pre-vent the radiological decommissioning of IP2. Analyses, described in Section 7.2.2.3, show that an increase around 2.5% for just three years in a row early in the decommissioning process for IP2 could be sufficient to turn the IP2 success scenario into a failure scenario.

Page 95 of HDIs PSDAR states Contingency does not account for inflation or escalation of the price of goods and services over the course of the project. A limited review was conducted as to the potential impact of inflation, goods and services, and of the sensitivity of the DTFs to changes in the market, discussed below.

7.4.2 Inflation The HDI analysis for Indian Point does not account for inflation which is unrealistic. It is also inconsistent with Entergys recognition of the importance of inflation. In its analysis of its ISFSI obligation, Entergy escalated costs at 3% per annum6 to account for inflation. As the SE points out, the bulk of the IPEC decommissioning expenditures would occur between 2021 and 2033, a 12 year span of time. While the inflation rate in the next 12 years is unknown, looking back on the last 12 years is instructive. An item costing $10,000 in 2007 would in 2019, some 12 years later, would cost $12,450 dollars based on consumer price index data.The average inflation rate over this time period was 1.84% per year. This 1.84%/year is close to the 2.5%/year which was shown elsewhere in this critique as sufficient to turn the IP2 success scenario into a failure scenario if this 2.5% increase persisted for just three consecutive years. HDI also assumed a 2% inflation in its Oyster Creek and Pilgrim decommissioning cost estimates.7 An estimate of the effect of inflation on IP2 was made in Scenario #7 in Section 9.12 in the Appendix. The HDI withdrawal rate as taken from Table 5-1b of the HDI PSDAR was increased 6 Entergy letter CNRO2020-00002, March 26, 2020, to the NRC, Enclosure 2, page 1.

7 GreenbergTrauig e-mail to Honorable Michelle Phillips, January 11, 2021, Enclosure 1, page E1-3 and Enclosure 2, page E2-3.

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by the recorded past inflation rates. For 2020 the increase in inflation was 1.2%. Since the HDI DTFs use a start date of 10/31/2019 but decommissioning expenses would start in 2021, at the earliest, the withdrawal rate for 2021 was set at 1.012 time the HDI withdrawal rate for 2021. Dur-ing the years 2022 to 2033 it was assumed that the annual increase matched that of the recorded increases in the previous years, reaching back the same number of years as the financial analyses calculated costs, going forward. For example, for 2022 the assumed inflation rate was increased by the recorded amount in 2019; for 2023 the assumed inflation rate was increased by the same amount recorded in 2018 and so forth. Starting in 2034, the incremental increase in costs due to inflation was assumed to be just 1.00%/year until 2062, well below historical inflation rates and well below Entergys 3%/year rate. These modest rates are likely to underestimate the full effects of inflation.

Even with this modest inflation rate the calculated IP2 surplus by 2061 was $7.1 million dollars in Scenario #7, down from the $72.7 million surplus estimated by HDI for IP2 in Scenario #1b which did not account for inflation. It is clear if Scenario #7 assumed inflation rates closer to 1.84%/year or Entergys 3%/year, these inflation rates would convert HDIs IP2 success scenario into a failure scenario.

7.4.3 Goods and Services The NRC recognizes that goods and services become more expensive over time. Because prices escalate license holders like Entergy have to account for this in the periodic filing with NRC on the status of the DTFs of the nuclear units they own. Entergy filed such a report to the NRC on March 26, 2020.8 Enclosure 4 of this letter is a discussion of the escalation factor which has the purpose of accounting for the changing costs for labor, energy, and waste burial, items that could be considered goods and services. For Indian Point 2 and Indian Point 3 the calculated escalation factor for the 33 years from 1986 through 2019 was calculated to be 5.10838. It is possible to cal-culate an annual average increase percentage for this combination of labor, energy, and waste burial using the formula 5.10838 = (1+x)33 where x is an annual average increase in cost for these three goods and services. Solving this equation one gets x = 0.05357 or ~5.4%. This is interpreted to mean that these goods and services might average an increase about 5.4% per year. Conse-quently the assumed inflation rate used in TABLE A-16 could be too low. HDI calculated an IP2 surplus of $72.7 million dollars by 2062 assuming no inflation. a modest inflation rate was assumed in TABLE A-16 which reduced the surplus to $7.1 million dollars.A somewhat larger inflation rate than the one used in TABLE A-16, but not as large as the 5.4% /year rate above, would likely cause the IP2 to become insolvent.

7.4.4 Market Effects The HDI treatment of market effects is unrealistic and incomplete.

The NRC recognized that different stock market conditions affect the amounts of money in the DTFs. As spelled out on page 14 of the Safety Evaluation (SE) equity markets fluctuate with 8 CNRO02020-00002 Decommissioning Funding Status Report per 10CFR 50.75(f)(1) and 10 CFR 50.82(a)(8)(v).

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time. Also stated in the SE equity markets declined by 32 to 36 percent between mid-February to mid-March 2020. The SE also points out equity markets can rise, as they have in recent times, giving the example of a 13.2 percent rise between September 2019 and September 2020.

While the SE recognized market fluctuations would affect the amounts of money in the DTFs dur-ing the long course of the decommissioning process, it appears that the staff did not act upon this observation. The SE does not mention any NRC staff search for market situations that would lead to failure scenarios.

For example, alternative Scenarios #3a and #3b show that for IP2 a 4.8% decrease in the DTF on 10/31/2019 would change the HDI IP2 scenario in the PSDAR Table 5-1b from success to failure.

Figure A-2 is a plot of the DJA during 2019 and 2020. October 31, 2019 is shown as a single red dot in Figure A-2 It is obvious that there are many success scenarios and many failure scenarios in just this two year span both before and after the date selected by HDI. The HDI analysis choice of a single success day is far from a complete presentation. As presented elsewhere in this critique, if the HDI analysis started with the DTFs on 12/31/2018 (effectively, 01/01/2019) IP1, IP2, and IP3 would all be calculated to become insolvent prior to completing all radiological decommissioning tasks and leaving shortfalls that might become burdens to the public. Further, Figure A-2 shows that there is nothing extreme about 12/31/2018. There were many days after HDIs 10/31/2019 where the market was lower that HDIs selected date and even lower than the DJA on 12/31/2018.

The SE conclusion of reasonable assurance is unsupportable when it is based on such incomplete information and a lack of analysis of the impacts of other possible start dates. Also missing is any description of how the NRC staff would reach a determination of reasonable assurance when it has to consider a large number of scenarios, some being success scenarios and others being failure scenarios.

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FIGURE A-3 Dow Jones Daily Average During 01/01/2019-12/31/2020 It is possible to obtain an approximation of how sensitive each of the three IPEC DTFs is to mar-ket changes. What is known is the DJA on 10/31/2019 and on 12/31/2018. Also known are the DTF levels for all three units on the Indian Point site on both of these dates. For each nuclear unit the percent change in DTFs for a one percent change in the DJA can be estimated. This was done and the results were that a one percent decrease in the DJA would cause a 1.49% decrease in the DTF of IP1, a 0.77% decrease in the DTF for IP2, and a 1.18% decrease in the DTF of IP3. A one percent decrease in the market would have reduced the IPEC DTFs by about $25 million dollars.

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7.5 Other Issues of Interest 7.5.1 Compensatory Actions The SE recognizes the possibility of needing additional sources of funds beyond the monies held in the DTFs on page 16 when it discusses positive ending balances in the IP1, IP2, and IP3 DTFs at license termination. However positive ending balances only occur for successful sce-narios when they would not be needed. Failure scenarios when you do need other sources of money, do not have positive ending balances. So this SE solution to times when additional sources of funds is unworkable Additionally, it is poor practice to wait many years for a possible positive ending balance. As discussed in Part Three of this critique, cost overruns need to be addressed year-by-year and task-by-task.

The SE, on page 16, stated Additionally, Holtec IP2 and Holtec IP3 expect to recover from the DOE through litigation or settlement of their claims the spent fuel management costs that they will incur as a result of the DOEs breach of its obligations under the standard contacts. The SE went on to say Therefore the NRC staff concludes that DOE reimbursements provide a reason-able source of funds to cover spent fuel management costs at the IPEC.

Using future DOE reimbursements to cover spent fuel management costs does not address cost overruns. As shown in the alternative scenarios cost overruns vary in amount and in timing, as shown in TABLE A-3. The SE does not discuss the dollar amount of the DOE reimbursements or how this compares to the sizes of these cost overruns or the timing of these reimbursements. More fundamentally, the purpose of these reimbursements is to compensate for delays in the removal of spent fuel from the site and they could not be applied to any other use. The treatment of DOE reimbursements, in the form of Treasury payments, is discussed in the Section 7.5.4 on Treasury Payments.

Any DOE reimbursements should go directly in the IPEC DTFs without any control over this money by HDI. There is no basis for HDI to possibly profit from DOE reimbursements. HDI has not added funds to the DTFs and has no money of its own at risk in this project. Therefore HDI has no standing when it comes to how DOE reimbursements are to be distributed.

HDI assumes that DOE will remove the spent fuel from the site by around 2030. Assuming that happens, any decommissioning shortfalls after 2030 could not be compensated by DOE reim-bursements.

7.5.2 Financial Surpluses Decommissioning success scenarios project surpluses at their end. Since neither Entergy nor HDI has contributed to the DTFs these surpluses, should they occur, belong to the rate payers. The applicants should send a letter to the NY State Public Service Commission clarifying that all sur-pluses will be remitted to NY State, which would then be required to return this money to the rate-payers.

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7.5.3 Major Decommissioning Periods On page 11 of the SE there is a discussion of the NRC staffs review of the five major periods of decommissioning with special emphasis on Period 4, the dismantlement period. The staff calcu-lates that 96 percent, 92 percent, and 95 percent of the estimated radiological decommissioning expenses at IP1, IP2, and IP3 would have been expended by the completion of Period 4. However, these figures are only true for the single success scenario submitted by HDI. Different scenarios will show different expenses over time. Even if the dismantlement period is completed, adequate funding to complete the final radiological tasks must be available. If there are any of the financial perturbations as discussed before, these percentages may not be reached. During most of the decommissioning process there are radiological decommissioning tasks and non-radiological tasks, both of which draw money from the DTFs at the same time. If there is a cost overrun, even in a non-radiological task, this might prevent the completion of a later radiological decommission-ing task because of insufficient funds. While the NRC is just responsible for radiological decom-missioning, it must be mindful of all mechanisms, including non-radiological ones, that affect the DTFs.

To amplify the above paragraph, the chart on page 15 of the SE shows that spent fuel management costs plus site restoration costs, the very areas where HDI has sought exemptions from the NRC, represent one third of the total IPEC decommissioning costs. An overrun in costs in these non-radiological areas would deplete the money in the DTFs needed for radiological decommission-ing. In order to assure that adequate funds are available for radiological decommissioning, the NRC has to prevent unacceptable depletions from the DTFs regardless of whether they are radio-logical related expenses or not.

Even though the NRC staff claims that it is only responsible for radiological decommissioning, implementing this responsibility may require the NRC staff to take actions if there are non-radio-logical activities that might deplete the DTF to the point that some radiological tasks may become underfunded. The NRC staff may have to revisit its position on the scope of its responsibilities in circumstances where actions of a non-radiological manner might affect the money available to carry out radiological decommissioning tasks.

7.5.4 Treasury Payments The SE discussion of Treasury payments to HDI because of DOE not meeting its contractual nuclear waste removal obligations raises important issues. The DOE is obliged to remove the radioactive wastes from nuclear plant sites. Removal of radioactive wastes from nuclear sites like IPEC is a key part of the decommissioning process. Any past reimbursements from the Treasury or DOE related to decommissioning actions should be placed into the IPEC DTFs, less verifiable expenses incurred by Entergy. These reimbursements are the peoples money. Entergy should not profit from DOEs failure to meet its contractual obligations. Any future reimbursements from the Treasury or DOE because of a failure to remove radioactive wastes should go directly into the IPEC DTFs.

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7.5.5 Contingency Allowance and Discrete Risk Events 7.5.5.1 Contingency Allowance HDI has made very detailed cost analyses for IP1, IP2, and IP3. These cost analyses were pre-sented in several ways, such as year-by-year data for each nuclear unit which were then inserted into HDI Tables 5-1a, 5-1b and 5-1c. Cost figures per nuclear unit were also listed according to tasks identified by specific WBS code numbers, and aggregate amounts were presented for differ-ent time periods. Section 4.1 of the PSDAR provides a long list of actions that HDI took to gener-ate these cost estimates. Standing behind all of these cost figures is HDIs claimed expertise in the PSDAR, pages 90-92, reproduced in Section 9.14 in the Appendix. Therefore, in estimating the cost to complete a specific decommissioning task, this extensive capability would produce a best estimate.

However, HDI recognized that in spite of all its expertise Any project has inherent uncertainty in the estimated quantities, unit rates, productivity, pricing, and schedule durations (HDI PSDAR, page 93). The PSDAR goes on to list a number of contributors to this uncertainty:

• Expected site conditions (physical and radiological)

• Decommissioning processes and tools

• New and/or non-familiar technology

• Complexity

• Labor skills and productivity

• Stakeholder/regulatory requirements

• Quality of cost estimating assumptions and data

• Experience and skill level of the estimator

• Pricing

• Estimating techniques

• Time and level of effort allowed to prepare the cost estimate and schedule There are two different actions being considered here. The first action uses HDIs existing exper-tise to arrive at its best estimate to complete a specific task. The second action is to deal with inherent uncertainty. These two actions serve different goals and one is not a substitute for the other.

Using a sophisticated mathematical program, HDI analyzed the above contributors to the overall uncertainty and concluded that an 18% contingency allowance, at an 85% level of confidence, was appropriate for IPEC. This level of confidence is interpreted to mean that 85% of the effects of uncertainty contributors, or combinations thereof, are at or below 18% of the best estimate.

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Since the level of confidence is 85%, most of the time these contributors to the uncertainty will not need to consume all 18% of the Contingency Allowance.

The HDI PSDAR, page 95, stated The Contingency Allowance is an integral part of the cost to complete the IPEC decommissioning and is expected to be fully consumed. Both statements, that the Contingency Allowance being an integral part of the cost to complete the IPEC decommis-sioning and the statement of expecting the Contingency Allowance to be fully consumed, are wrong. As stated above, there are two separate actions going on and they serve different purposes.

One action is to use HDI expertise to come up with a best estimate to complete a specific task. The second action is to deal with inherent uncertainties and the money set aside in the Contingency Allowance is meant to deal with this uncertainty. So the Contingency Allowance is not an integral part of the cost estimate to complete a task, but stands apart to handle uncertain costs. With regard to the expectation that the Contingency Allowance would be fully consumed, there is no way for HDI to know on December 19, 2019 what the costs will be years into the future from uncertain events. In fact, the very nature of these uncertain events would change over the long time period from 2021 to 2061. The earlier years are very active with segmentation, dismantlement, and dem-olition. The later years, from about 2047 onward are very quiet, limited to actions like site survey-ing, report writing, etc. The uncertainty components that the Contingency Allowance is designed to cope with differ dramatically over this 40 year time period. The HDI statement that it expects the Contingency Allowance to be fully consumed is in conflict with HDIs description of the deri-vation of the 18% Contingency Allowance. HDI reports that it used a sophisticated mathemetical analysis to derive the 18% figure and that this figure has an 85% confidence level. However, at an 85% confidence level, 85%, or most of the time, the costs or uncertain events is less than 18%.

About 15% of the time the costs for dealing with uncertain events would exceed 18%, according to HDI. Only 15% of the time would the Contingency Allowance be fully consumed. The majority of the time there would be, task by task, money left over in a tasks Contingency Allowance. This unused money should be returned to the DTF from which it came. This unused money does not belong to HDI.

Figure A-3 was generated to further examine the meaning of the above HDI statement. The striped area represents the 18% contingency allowance. AREA A in Figure A-3 represents this best estimate cost. Area B shows the Contingency Allowance as an integral part of the cost to complete the IPEC decommissioning. Areas A and B are drawn to be the same size, i.e., they both have the same cost to complete the task at hand. However, unless one assumes that the Contin-gency Allowance was set to zero, i.e, did not exist, AREA B is unworkable. AREA B is unwork-able because in order to make the Contingency Allowance and integral part of the cost, the best estimate part would have to shrink. But there cannot be two different best estimates. If AREAS A and B are the same size, then HDIs statement about the Contingency Allowance being an integral part of the cost appears to be illogical.

Area C shows from the best estimate dollars as in AREA A and then adds 18% to it for the Con-tingency Allowance, outside of AREA A. This would raise the total cost to complete tasks by 18%

if the HDI statement that the Contingency Allowance is used. But there is no basis to expect that the Contingency Allowance would be fully consumed. As stated before, most of the time uncer-tainty issues would have impacts less than 18%. Further, HDI cannot know in advance which con-tributors to a myriad of different tasks will consume all of the 18% of the Contingency Allowance.

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While the 18% Contingency Allowance analysis seems reasonable, HDIs application of this analysis does not. As presently applied as an integral part of the costs, the Contingency Allowance appears to be effectively zero.

From a public protection point of view it would be prudent to assume that the Contingency Allow-ance is best represented by Area C where the Contingency Allowance lies outside of the best esti-mate and is available to deal with the inherent uncertainties HDI describes, and that all unused money is returned to the sponsoring DTF once the task is completed. TABLE A-4 lists the dollar impact of having an 18% Contingency Allowance to supplement the best cost estimate.

FIGURE A-4 Contingency Allowances A

B C

TABLE A-4 External Contingency Allowances Plant Decommissioning Cost External 18%

Contingency Allowance IP1 $598,184,000 $107,673,120 IP2 $701,822,000 $126,327,960 IP3 $1,002,378,000 $180,428,040 Total N/A $414,429,120 page 38

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

7.5.5.2 Discrete Risk Events Section 4.5 of the HDI PSDAR discussed Discrete Risk Events. As reported by HDI, Discrete risk events are considered a threat when the risk event may negatively impact the project baseline objectives, such as schedule delays and cost increases. As in the case of establishing the Contin-gency Allowance, sophisticated mathematical tools were used to analyze discrete risk events. This process eventually led to the creation of Risk Allowances. As HDI stated Risk allowance is funds added to the baseline schedule and estimate to account for discrete risk events (both threats and opportunities) that may or may not occur during the decommissioning project life cycle. Since all funds that HDI plans to use come from the DTFs, then these Risk Allowances would also have to be drawn from the DTFs (the peoples money).

No further information is provided by HDI on Risk Allowances. How much money will there be in the Risk Allowances for IP1, IP2, and IP3? Do the annual DTFs in HDIs Tables 5-1a, 5-1b, and 5-1c reflect withdrawals for Risk Allowances? If the discrete risk events used by HDI to generate the Risk Allowances do not happen, will there be surpluses to be returned to the DTFs? Unlike Table A-4 where HDI provided its contributors to the 18% Contingency Allowance, there is no information in the HDI PSDAR available to estimate the magnitude of these Risk Allowances.

Tables 3-2a, 3-2b, and 3-2c in the HDI PSDAR gives very detailed cost figures for IP1, IP2, and IP3. There are 43 WBS code entries for each of these plants. There is no entry for Risk Allow-ances. Where are the funds for the Risk Allowances?

Had the NRC staff reviewed the HDI PSDAR prior to issuing the SE it might have noticed that there is no description of the amounts of money in these Risk Allowances and they are not accounted for in the detailed cost accounting HDI put forth. Yet market fluctuations appears to be an example which fits the description of a discrete risk event.

7.5.6 Transmission Lines There are very expensive transmission lines that connect the Indian Point site to the rest of the grid. In the highly congested area of the lower Hudson Valley such transmission lines are very valuable. However, neither the HDI PSDAR nor the NRC staffs SE mentions these transmission lines and their impact on the cost for decommissioning the Indian Point site. If these transmission lines are to be torn down because Indian Point no longer uses them, who pays for this? If these transmission lines are not torn down who pays the present owner (Likely Consolidated Edison) to maintain them for some yet undescribed future use?

These transmission lines represent an unexplored potential liability for HDI and their future cost impact should be determined immediately.

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8.0 PART FOUR - Protecting the Public 8.1 Introduction This critique shows that there are many defects in the HDI methodology and results. Similarly, the NRC staff in its Safety Evaluation has not justified its conclusion of Reasonable Assurance. The basic safety practice in risk analysis, both radiological risk analysis and financial risk analysis, is to search for possible failure scenarios and then quantify their likelihood and their potential conse-quences, should these scenarios happen. This has not taken place. The SE makes no mention of searching for possible failure scenarios, but seems to rely exclusively on the one scenario selected by HDI. As a result of this very limited scope of the SE, the people of New York have been put at risk.

However, it has become clear that even if HDI and the NRC staff greatly improved their method-ologies to the standards used by the NRC and the nuclear industry in radiological risk analysis, there would still be a very wide set of possible end states, i.e. a wide uncertainty band. Resolving how to proceed with such a wide financial uncertainty band in a relatively new technology, decommissioning of large nuclear facilities, might be a very lengthy process.

The most desirable solution to this situation would be for the NRC to withdraw its Safety Evalua-tion. If this is not to happen then it is recommended that a combination of quantitative and qualita-tive actions be taken to protect the public. The first line of defense would be quantitative. Use would be made of this critique to estimate the amount of money that would be provided by Entergy and placed into some high quality Financial Assurance Mechanism (FAM) and retained by a well regarded financial institution, to be drawn upon year-by-year and task-by-task if there are cost overruns that exceed the funds from the DTFs allotted to pay for these decommissioning tasks.

The need for additional decommissioning financial assurance is recognized by HDI in its Pilgrim Nuclear Power Station report.9 As Section G, Decommissioning Financial Assurance, stated Financial assurance for decommissioning is provided by the prepayment method, coupled with an external trust fund, in accordance with 10 CFR 50.75(e)(1)(i) and 10 CFR 72.30(e)(1) as approved by the NRC in their approval of the license transfer to Holtec Pilgrim, LLC and HDI.

(emphasis added)

There is no guarantee that the amount of money in this FAM would be sufficient. If decommis-sioning went according to plan, then any money left over in this would be returned to Entergy. On the other hand, if the amount of money in this FAM turned out to be insufficient, then, in keeping with the principal of using Defense-in-Depth, a contract signed between Entergy and NY State would state that the people of New York would remain financially risk free under all circum-stances, that all radiological and non-radiological tasks at IPEC would be completed in a timely manner, and that all applicable Federal, State, and local regulations would be met. Entergy would be responsible for full implementation of this contract. The NRC and NY State would be responsi-ble to assure that these contractual obligations are met. To control the costs and quality of this 9

ibid, Enclosure 2, page E2-3, Section G, Decommissioning Financial Assurance.

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CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

very large project, NY State, with NRC input, would have to approve projected expenditures on a year-by-year basis. Once approved by NY State, funds would be withdrawn from the specific unit DTFs. If problems arise requiring additional funds, NY State would withdraw monies from the FAM, if it has determined that such a withdrawal is appropriate. All the DTFs would be held by NY State and subject to NY State audit requirements. These DTFs are not to be used for any other purpose than decommissioning the specific units for which they have been accumulated. If a spe-cific task is completed under budget, the unused funds would be returned to the units DTF at the completion of the specific task. If there is money left over in the DTFs after the completion of all radiological and non-radiological tasks, this money will be returned to the rate payers.

8.2 Establishing the Initial Funds in the FAM The following estimate of the amount of money that should be placed into a FAM, assumes that all previous payments to Entergy because the Department of Energy (DOE) has not removed the spent reactor fuel from the IPEC site, have been placed into the DTFs, less verifiable expenses.

Any subsequent payments by DOE to HDI would be fully transferred to the DTFs in proportion to the tonnage of the spent fuel generated by the specific units.

TABLE A-5 Estimated Initial Funds in a FAM Basis Reference Estimated Amount, Millions IPI Shortfall Relative to NRC Section 7.1.1.2 $112.0 Cost Estimate, Radiological Decommissioning Only IP2 Decommissioning Costs TABLE A-3, Sce- $298.6 Match IP3 Decommissioning nario #5 Costs Impact of Variable Market TABLE A-3 $300.6 Forces Scenarios #2a, #2b, and #2c External 18% Contingency Section 7.5.5.1 $414.4 Allowance, TABLE A-4 Inflation, Goods and Services, TABLE A-16, $74.4 Discrete Events Section 7.4.2, Section 7.5.5.2 Total N/A $1,200.0 page 41

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.0 Appendix 9.1 Scenarios #1a, #1b, and #1c See HDI PSDAR, Tables 5-1a, 5-1b, and 5-1c for IP1, IP2, and IP3, respectively.

9.2 Scenario #2a: Impact of Shifting the IP1 Starting Date on the IP1 Initial DTF Table 5-1a of HDIs PSADAR is a decommissioning financial analysis of IP1 where the assumed starting date was October 31, 2019 and where the funds in IP1s DTF were those at that particular date. However, a different date, December 31, 2018 was examined in Scenario #2a to see how changing the starting date might affect IP1s decommissioning financial analysis. The reason the December 31, 2018 date was selected was because Entergy had reported to the NRC what the DTFs of IP1, IP2, and IP3 were on that particular date. Other than having the specific IP1, IP2 and IP3 DTF levels from Entergy, 12/31/2018 is just an ordinary date.

On 10/31/2019 the IP1 DTF held $533.5 million dollars and on 12/31/2018 IP1s DTF held

$471.9 million dollars. The analysis presented in TABLE A-3 started with the 12/31/2018 DTF of

$471.9 minus HDIs pre-closure deductions of $59.3 million dollars. All other aspects of the HDI analysis in its Table 5-1a, such as the withdrawal rates, were the same. The calculation of the money earned by the DTF during the long decommissioning process in TABLE A-6, below, matched the same percentage increases that HDIs Table 5-1a used year-by-year. All other HDI assumptions, such as no increase in the cost of labor or services during the long decommissioning process, were retained.

The HDI PSDAR analysis of IP1 was a success scenario, funds were sufficient to complete radio-logical decommissioning and a surplus of $20.0 million dollars was calculated. With a start date of 12/31/2018 the outcome is a failure. The IP1 DTF becomes insolvent by 2031 and the shortfall is calculated to be $139.9 million dollars. Shifting the HDI start date to 12/31/2018 resulted in an overall shift of $159.9 million dollars.

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TABLE A-6 IP1, 12/31/2018 DTF, HDI IP1 Withdrawal Rate, $ in Thousands Year Start of year, With- Trust Year Start of Trust Year End Trust Fund drawal Fund End year Fund Trust Balance Rate Earnings Trust Trust Earn- Fund Bal-Fund Fund ings ance HDI HDI HDI Balance Balance PSDAR PSDAR PSDAR HDI Starting Table Table Table PSDAR with 12/

5-1a 5-1a 5-1a Table 31/2018 5-1a Balance 2021 533,532 -32,617 5,844 506,759 411,900 8,238 387,521 2022 506,759 -32,183 9,492 484,068 387,521 7,750 363,088 2023 484,068 -57,397 8,533 435,204 363,088 7,261 312,952 2024 435,204 -71,547 7,273 370,930 312,952 6,259 247,662 2025 370,930 -28,992 6,839 348,777 247,662 4,953 223,623 2026 348,777 -32,586 6,324 322,515 223,623 4,472 195,509 2027 322,515 -40,615 5,638 287,538 195,509 3,910 158,804 2028 287,538 -37,287 5,005 255,256 158,804 3,176 124,693 2029 255,256 -29,410 4,517 230,363 124,693 2,494 97,777 2030 230,363 -53,727 3,533 180,169 97,777 1,956 46,005 2031 180,169 -78,112 2,041 104,097 46,005 920 -31,187 2032 104,097 -49,944 1,183 60,366 -31,187 0 -81,131 2033 60,336 -6,631 1,074 54,779 -81,131 0 -87,762 2034 54,779 -2,870 1,038 52,948 -87,762 0 -90,632 2035 52,948 - 2,870 1,002 51,079 -90,632 0 -93,502 2036 51,079 -2,875 964 49,169 -93,502 0 -96,337 2037 49,169 -2,870 926 47,225 -96,337 0 -99,247 2038 47,225 -2,870 887 45,242 -99,247 0 -102,117 2039 45,242 -2,870 847 43,220 -102,117 0 -104,987 2040 43,220 -2,875 807 41,152 -104,987 0 -107,862 2041 41,152 -2,870 766 39,048 -107,862 0 -110,732 2042 39,048 -2,870 724 36,902 -110,732 0 -113,602 2043 36,902 -2,870 681 34,713 -113,602 0 -116,472 2044 34,713 -2,875 637 32,474 -116,472 0 -119,347 2045 32,474 -2,870 592 30,197 -119,347 0 -122,217 2046 30,197 -5,162 501 25,536 -122,217 0 -127,379 2047 25,536 -4,488 421 21,468 -127,379 0 -131,867 2048 21,468 -386 422 21,503 -131,867 0 -132,253 page 43

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Start of year, With- Trust Year Start of Trust Year End Trust Fund drawal Fund End year Fund Trust Balance Rate Earnings Trust Trust Earn- Fund Bal-Fund Fund ings ance HDI HDI HDI Balance Balance PSDAR PSDAR PSDAR HDI Starting Table Table Table PSDAR with 12/

5-1a 5-1a 5-1a Table 31/2018 5-1a Balance 2049 21,503 -386 422 21,539 -132,253 0 -132,639 2050 21,539 -386 423 21,576 -132,639 0 -133,025 2051 21,576 -386 424 21,613 -133,025 0 -133,411 2052 21,613 -386 425 21,651 -133,411 0 -133,797 2053 21,651 -386 425 21,690 -133,797 0 -134,183 2054 21,690 -386 426 21,730 -134,183 0 -134,569 2055 21,730 -714 420 21,436 -134,569 0 -135,283 2056 21,436 -715 414 21,136 -135,283 0 -135,998 2057 21,136 -715 408 20,829 -135,998 0 -135,713 2058 20,829 -715 402 20,516 -135,713 0 -137,428 2059 20,516 -715 396 20,197 -137,428 0 -138,143 2060 20,197 -715 390 19,871 -138,143 0 -138,858 2061 19,871 -715 383 19,539 -138,858 0 -139,573 2062 19,539 -323 384 19,601 -139,573 0 -139,896 page 44

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.3 Scenario #2b: Impact of Shifting the IP2 Starting Date on the IP2 Initial DTF TABLE A-7 is an analysis of replacing HDIs IP2 10/31/2019 DTF of $654.1 million dollars with the IP2 12/31/2018 DTF of $598.4 million dollars, less pre-closure deductions of $15.15 million dollars, while keeping the same withdrawal rate as in HDIs Table 5-1b. The HDI PSDAR analy-sis of IP2 was a success scenario; funds were sufficient to complete radiological decommissioning and a surplus of $72.7 million dollars was calculated. With an IP2 start date of 12/31/2018 the out-come is a failure. The IP2 DTF becomes insolvent by 2043 and the shortfall is calculated to be

$45.0 million dollars, an overall shift of $117.7 dollars.

TABLE A-7 IP2, 12/31/2018 DTF, HDI IP2 Withdrawal Rate, $ in Thousands Year Begin- With- Trust Year Start of Trust Year ning of drawal Fund Ending year Fund Ending year, Rate Earnings Trust Trust Earnings Trust Trust Fund Fund Fund Fund Balance Balance Balance Balance Starting HDI HDI HDI HDI with 12/

PSDAR PSDAR PSDAR PSDAR 31/2018 Table Table Table Table Balance 5-1b 5-1b 5-1b 5-1b 2021 654,078 -70,024 6,814 590,868 583,262 11,665 524,903 2022 590,868 -105,834 9,701 494,735 524,093 10,498 428,757 2023 494,735 -85,496 8,185 417,424 428,757 8,575 351,836 2024 417,424 -44,113 7,466 380,777 351,836 7,037 314,760 2025 380,777 -43,993 6,736 343,520 314,760 6,295 277,062 2026 343,520 -40,373 6,063 309,210 277,062 5,541 242,230 2027 309,210 -39,697 5,390 274,903 242,230 4,845 207,378 2028 274,903 -55,164 4,395 224,134 207,378 4,147 156,361 2029 224,134 -53,960 3,403 173,577 156,361 3,127 105,528 2030 173,577 -15,449 3,163 161,291 105,528 2,110 92,190 2031 161,291 -15,449 2,917 148,758 92,190 1,844 78,585 2032 148,758 -18,646 2,602 132,714 78,585 1,572 61,510 2033 132,714 -9,623 2,462 125,553 61,510 1,230 53,117 2034 125,553 -5,990 2,391 121,954 53,117 1,062 48,189 2035 121,954 -6,000 2,319 118,274 48,189 964 43,152 2036 118,274 -6,014 2,245 114,505 43,152 863 38,001 2037 114,505 -6,000 2,170 110,675 38,001 760 32,761 2038 110,675 -5,990 2,094 106,779 32,761 665 27,426 2039 106,779 -6,000 2,016 102,795 27,426 549 21,975 page 45

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Begin- With- Trust Year Start of Trust Year ning of drawal Fund Ending year Fund Ending year, Rate Earnings Trust Trust Earnings Trust Trust Fund Fund Fund Fund Balance Balance Balance Balance Starting HDI HDI HDI HDI with 12/

PSDAR PSDAR PSDAR PSDAR 31/2018 Table Table Table Table Balance 5-1b 5-1b 5-1b 5-1b 2040 102,795 -6,005 1,936 98,725 21,975 439 16,409 2041 98,725 -6,000 1,855 94,580 16,409 328 10,737 2042 94,580 -6,000 1,772 90,352 10,737 215 4,952 2043 90,352 -6,000 1,687 86,040 4,952 99 -949 2044 86,040 -6,005 1,601 81,636 -949 0 -6,949 2045 81,636 -5,990 1,513 77,158 -6,949 -12,954 2046 77, 158 -3,152 1,480 75,486 -12,954 0 -16,106 2047 75,486 -894 1,482 76,084 -16,106 0 -17,000 2048 76,084 -386 1,514 77,212 -17,000 0 -17,386 2049 77,212 -386 1,537 78,362 -17,386 0 -17,772 2050 78,362 -386 1,560 79,535 -17,772 0 -18,158 2051 79,535 -386 1,583 80,731 -18,158 0 -18,544 2052 80,731 -386 1,607 81,952 -18,544 0 -18,930 2053 81,952 -386 1,631 83,196 -18,930 0 -19,316 2054 83,196 -386 1,656 84,446 -19,316 0 -19,702 2055 84,446 -3,274 1,624 82,816 -19,702 0 -22.976 2056 82,816 -3,285 1,591 81,121 -22.976 0 -26,261 2057 81,121 -3,285 1,557 79,393 -26,261 0 -29,546 2058 79,393 -3,285 1,522 77,629 -29,546 0 -32,831 2059 77,629 -3,285 1,487 75,831 -32,831 0 -36,116 2060 75,831 -3,285 1,451 73,996 -36,116 0 -39,401 2061 73,996 -3,285 1,414 72,125 -39,401 0 -42,866 2062 72,125 -2,270 1,397 71,252 -42,866 0 -44,956 page 46

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.4 Scenario #2c: Impact of Shifting the IP3 Starting Date on the IP3 Initial DTF TABLE A-8 is an analysis of replacing IP3s 10/31/2019 DTF of $916.1 million dollars with the IP3 12/31/2018 DTF of $780.6 million dollars, less pre-closure costs of $15.15 dollars, while keeping the same withdrawal rate as in HDIs Table 5-1c. The HDI analysis of IP3 was a success scenario; funds were sufficient to complete radiological decommissioning and a surplus of $170.6 million dollars was calculated. With a start date of 12/31/2018 the outcome is a failure. The IP3 DTF becomes insolvent by 2054 and the shortfall is calculated to be $115.7 million dollars. Just moving the start dates for IP3 resulted in a shift of $286.3 million dollars.

TABLE A-8 IP3, 12/31/2018 DTF, HDI IP3 Withdrawal Rate, $ in Thousands Year Begin- With- Trust Year Start of Trust Year ning of drawal Fund Ending year Fund Ending Year Rate Earnings Trust Trust Earn- Trust Trust Holtec Fund Fund ings Fund Fund Balance Balance Balance Balance HDI Starting HDI HDI HDI PSDAR with 12/

PSDAR PSDAR PSDAR Table 31/2018 Table Table 5-1c Table 5-1c 5-1c Balance 5-1c 2021 916,100 -110,773 9,395 814,722 765,443 15,309 669,979 2022 814,722 -124,235 13,810 704,297 669,979 13,340 559,144 2023 704,297 -107,740 11,391 608,488 559,114 11,183 462,587 2024 608,488 -85,924 10,451 533,016 462,587 9,252 385,915 2025 533,016 -54,171 9,577 488,421 385,915 7,718 339,462 2026 488,421 -57,084 8,627 439,964 339,462 6,789 289,167 2027 439,964 -48,119 7,837 399,682 289,167 5,783 246,831 2028 399,682 -32,164 7,350 374,868 246,831 4,937 219,625 2029 374,868 -32,142 6,855 349,581 219,625 4,393 191,880 2030 349,581 -32,138 6,349 323,792 191,880 3,838 163,570 2031 323,792 -32,138 5,833 297,487 163,570 3,271 134,703 2032 297,487 -31,679 5,316 271,124 134,703 2,694 105,718 2033 271,124 -7,343 5,276 269,057 105,718 2,114 100,490 2034 269,057 -3,607 5,309 270, 759 100,479 2,009 98,881 2035 270,759 -3,607 5,343 272,494 98,881 1,978 97,251 2036 272,494 -3,612 5,378 274,260 97,251 1,945 95,584 2037 274,260 -3,607 5,413 276,066 95,584 1,911 93,888 2038 276,066 -3,607 5,449 277,907 93,888 1,878 92,159 2039 277,907 -3,607 5,486 279,786 92,159 1,843 90,395 page 47

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Begin- With- Trust Year Start of Trust Year ning of drawal Fund Ending year Fund Ending Year Rate Earnings Trust Trust Earn- Trust Trust Holtec Fund Fund ings Fund Fund Balance Balance Balance Balance HDI Starting HDI HDI HDI PSDAR with 12/

PSDAR PSDAR PSDAR Table 31/2018 Table Table 5-1c Table 5-1c 5-1c Balance 5-1c 2040 279,786 -3,612 5,523 281,697 90,395 1,808 88,890 2041 281,697 -3,607 5,562 283,652 88,890 1,772 87,055 2042 283,652 -3,607 5,601 285,646 87,055 1,741 85,189 2043 285,646 -3,607 5,641 287,679 85,189 1,704 83,286 2044 287,679 -3,612 5,681 289,748 83,286 1,666 81,340 2045 289,748 -3,607 5,723 291,864 81,340 1,627 79,360 2046 291,864 -4,433 5,749 293,179 79,360 1,587 76,514 2047 293,179 -7,453 5,715 291,441 76,514 1,530 70,591 2048 291,441 -11,953 5,590 285,078 70,591 1,412 60,050 2049 285,078 -11,917 5,463 278,624 60,050 1,201 49,334 2050 278,624 -11,927 5,334 272,030 49,334 987 38,393 2051 272,030 -11,917 5,202 265,315 38,393 768 27,244 2052 265,315 -11,953 5,067 258,429 27,224 545 15,816 2053 258,429 -11,927 4,930 251,432 15,816 316 4,205 2054 251,432 -11,927 4,790 244,294 4,205 84 -7,638 2055 244,294 -14,805 4,590 234,079 -7,638 0 -22,443 2056 234,079 -14,842 4,385 223,622 -22,443 0 -37,285 2057 223,622 -14,826 4,176 212,972 -37,285 0 -52,111 2058 212,972 -14,826 4,393 202,198 -52,111 0 -66,937 2059 202,198 -14,826 3,746 191,028 -66,937 0 -81,763 2060 191,028 -14,842 3,524 179,709 -81,763 0 -96,605 2061 179,709 -14,811 3,298 168,196 -96,605 0 -111,416 2062 168,196 -4,238 3,279 167,237 -111,416 0 -115,654 2063 167,237 0 3,345 -115,654 0 page 48

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.5 Scenario #3a: Finding the IP2 DTF Level That Turns Success into Failure The purpose of this analysis is to estimate at what dollar level initially in the IP2 DTF would turn the HDI analysis of IP2 from success into a failure scenario. Failure is defined as not having enough money in the DTF to complete all the radiological decommissioning tasks, some of which occur at the very end of decommissioning around 2062. Therefore, any time the IP2 DTF runs out of money prior to 2062, is a failure scenario.

There are multiple ways that the IP DTF could become insolvent. This analysis examines just one of these failure modes, having too small an initial DTF. An initial estimate used to start this analy-sis was $618,670,000 dollars, a $35,400,000 dollars or 5.4% difference from HDIs Table 5-1b starting amount of $654,078,000.This initial estimate turned out to be very close as DTF funds lasted through 2059 with a shortfall of $11.8 million dollars. A somewhat larger initial DTF, around $627,915,000, was then examined in Scenario 3b. Scenario 3b is $26,163,000 dollars, or 4%, less than the HDI IP2 DTF as presented in Table 5-1b of the PSDAR.

The HDI analysis of IP2 resulted in a surplus of $72.7 million dollars. If the initial amount of money in the IP2 DTF was 4% less than what HDI used, the IP2 surplus would be reduced to

$20.8 million dollars. If the initial amount of money in the IP2 DTF was 5.4% less than what HDI used, the IP2 DTF would be calculated to be insolvent with a shortfall of $11.8 million dollars.

Interpolating these results, any initial amount of money in the IP2 DTF more than 4.8% smaller than HDIs initial number would convert the HDI scenario for IP2 from success to failure. The HDI financial model is very sensitive to small changes in the input numbers. It only took a 5.4%

difference in the initial amount of money in IP2s DTF to cause a calculated shift of $72.7 +$11.8

= $84.5 million dollars. It only takes a 4.8% decrease in the IP2 initial DTF to turn this sequence from a success sequence to a failure sequence.

page 49

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

TABLE A-9 Initial IP2 DTF Level 5.4% Less, $ in Thousands Year Begin- Withdraw Trust Year Begin- Trust Year ning of Fund Ending ning of Fund Ending year, Earnings Trust year Earnings Trust Trust Fund Trust Fund Fund Balance, Fund Balance Balance, Balance PSDAR PSDAR PSDAR PSDAR Table Table Table Table 5-1b 5-1b 5-1b 5-1b 2021 654,078 -70,024 6,814 590,868 618,670 6,445 555,091 2022 590,868 -105,834 9,701 494,735 555,091 9,113 458,371 2023 494,735 -85,496 8,185 417,424 458,371 7,583 380,458 2024 417,424 -44,113 7,466 380,777 380,458 6,804 343,150 2025 380,777 -43,993 6,736 343,520 343,150 6,070 305,227 2026 343,520 -40,373 6,063 309,210 305,227 5,387 270,241 2027 309,210 -39,697 5,390 274,903 270,241 4,711 235,254 2028 274,903 -55,164 4,395 224,134 235,224 3,761 183,821 2029 224,134 -53,960 3,403 173,577 183,821 2,791 132,652 2030 173,577 -15,449 3,163 161,291 132,652 2,417 119,620 2031 161,291 -15,449 2,917 148,758 119,662 2,163 106,376 2032 148,758 -18,646 2,602 132,714 106,376 1,860 85,591 2033 132,714 -9,623 2,462 125,553 85,591 1,588 77,556 2034 125,553 -5,990 2,391 121,954 77,556 1,472 73,038 2035 121,954 -6,000 2,319 118,274 73,038 1,389 68,427 2036 118,274 -6,014 2,245 114,505 68,427 1,299 63,712 2037 114,505 -6,000 2,170 110,675 63,712 1,207 58,919 2038 110,675 -5,990 2,094 106,779 58.919 1,115 54,043 2039 106,779 -6,000 2,016 102,795 54,043 1,020 49,063 2040 102,795 -6,005 1,936 98,725 49,063 924 43,982 2041 98,725 -6,000 1,855 94,580 43,982 826 38,808 2042 94,580 -6,000 1,772 90,352 38,808 727 33,535 2043 90,352 -6,000 1,687 86,040 33,535 626 28,161 2044 86,040 -6,005 1,601 81,636 28,161 524 22,680 2045 81,636 -5,990 1,513 77,158 22,680 420 17,110 2046 77, 158 -3,152 1,480 75,486 17,110 328 14,286 2047 75,486 -894 1,482 76,084 14,286 280 13,672 2048 76,084 -386 1,514 77,212 13,672 272 13,558 page 50

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Begin- Withdraw Trust Year Begin- Trust Year ning of Fund Ending ning of Fund Ending year, Earnings Trust year Earnings Trust Trust Fund Trust Fund Fund Balance, Fund Balance Balance, Balance PSDAR PSDAR PSDAR PSDAR Table Table Table Table 5-1b 5-1b 5-1b 5-1b 2049 77,212 -386 1,537 78,362 13,558 270 13,442 2050 78,362 -386 1,560 79,535 13,442 268 13,324 2051 79,535 -386 1,583 80,731 13,324 265 13,203 2052 80,731 -386 1,607 81,952 13,203 263 13,080 2053 81,952 -386 1,631 83,196 13,080 260 12,954 2054 83,196 -386 1,656 84,446 12,954 258 12,826 2055 84,446 -3,274 1,624 82,816 12,826 247 9,799 2056 82,816 -3,285 1,591 81,121 9,799 188 6,702 2057 81,121 -3,285 1,557 79,393 6,702 129 3,546 2058 79,393 -3,285 1,522 77,629 3,546 68 328 2059 77,629 -3,285 1,487 75,831 328 6 -2,951 2060 75,831 -3,285 1,451 73,996 -2,951 0 -6,236 2061 73,996 -3,285 1,414 72,125 -6,236 0 -9521 2062 72,125 -2,270 1,397 71,252 -9,521 0 -11,791 page 51

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.6 Scenario #3b: Finding Initial IP2 DTF Level That Turns Success into Failure, 4.0%

Change TABLE A-10 Initial IP2 DTF Level 4.0% Less, $ in Thousands Year Begin- Withdraw Trust Year Begin- Trust Year ning of Fund Ending ning of Fund Ending year Earnings Trust year Earnings Trust Trust Fund Trust Fund Fund Balance Fund Balance Balance, Balance PSDAR PSDAR PSDAR PSDAR Table Table Table Table 5-1b 5-1b 5-1b 5-1b 2021 654,078 -70,024 6,814 590,868 627,915 6,541 564,432 2022 590,868 -105,834 9,701 494,735 564,432 9,539 468,137 2023 494,735 -85,496 8,185 417,424 468,137 7,911 390,553 2024 417,424 -44,113 7,466 380,777 390,553 6,718 353,158 2025 380,777 -43,993 6,736 343,520 353,158 6,342 315,508 2026 343,520 -40,373 6,063 309,210 315,508 5,584 280,719 2027 309,210 -39,697 5,390 274,903 280,719 4,997 246,019 2028 274,903 -55,164 4,395 224,134 246,019 4,527 195,382 2029 224,134 -53,960 3,403 173,577 195,382 3,475 144,897 2030 173,577 -15,449 3,163 161,291 144,897 2,637 132,085 2031 161,291 -15,449 2,917 148,758 132,085 2,378 119,014 2032 148,758 -18,646 2,602 132,714 119,014 2,130 102,498 2033 132,714 -9,623 2,462 125,553 102,498 2,050 94,925 2034 125,553 -5,990 2,391 121,954 94,925 1,898 90,833 2035 121,954 -6,000 2,319 118,274 90,833 1817 86,650 2036 118,274 -6,014 2,245 114,505 86,650 1,733 82,369 2037 114,505 -6,000 2,170 110,675 82,369 1,647 78,016 2038 110,675 -5,990 2,094 106,779 78,016 1,560 73,586 2039 106,779 -6,000 2,016 102,795 73,586 1,472 69,058 2040 102,795 -6,005 1,936 98,725 69,058 1,381 64,434 2041 98,725 -6,000 1,855 94,580 64,434 1,289 59,723 2042 94,580 -6,000 1,772 90,352 59,723 1,194 54,917 2043 90,352 -6,000 1,687 86,040 54,917 1,098 50,015 2044 86,040 -6,005 1,601 81,636 50,015 1,000 45,010 2045 81,636 -5,990 1,513 77,158 45,010 900 39,920 page 52

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Begin- Withdraw Trust Year Begin- Trust Year ning of Fund Ending ning of Fund Ending year Earnings Trust year Earnings Trust Trust Fund Trust Fund Fund Balance Fund Balance Balance, Balance PSDAR PSDAR PSDAR PSDAR Table Table Table Table 5-1b 5-1b 5-1b 5-1b 2046 77, 158 -3,152 1,480 75,486 39,920 798 37,566 2047 75,486 -894 1,482 76,084 37,556 751 37,413 2048 76,084 -386 1,514 77,212 37,413 748 38,161 2049 77,212 -386 1,537 78,362 38,161 763 38,538 2050 78,362 -386 1,560 79,535 38,538 770 38,923 2051 79,535 -386 1,583 80,731 38,923 778 39,701 2052 80,731 -386 1,607 81,952 39,701 794 40,109 2053 81,952 -386 1,631 83,196 40,109 802 40,525 2054 83,196 -386 1,656 84,446 40,525 811 40,950 2055 84,446 -3,274 1,624 82,816 40,950 819 38,495 2056 82,816 -3,285 1,591 81,121 38,495 770 35,980 2057 81,121 -3,285 1,557 79,393 35,980 720 33,415 2058 79,393 -3,285 1,522 77,629 33,415 668 30,798 2059 77,629 -3,285 1,487 75,831 30,798 616 28,129 2060 75,831 -3,285 1,451 73,996 28,129 562 25,407 2061 73,996 -3,285 1,414 72,125 25,407 508 22,630 2062 72,125 -2,270 1,397 71,252 22,630 453 20,8135 page 53

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.7 Scenario #4a: Impact of an Annual 5% Increase in IP3s Withdrawal Rate TABLE A-11 5% Annual Increase in IP3s Withdrawal Rate, $ in Thousands Year IP3 With- Withdrawal Beginning of Trust Year End-drawal Rate, Rate X 1.05 year Trust Fund Fund ing Trust PSDAR Table Balance, First Earn- Fund Bal-5-1c Year Equal to ings ance DTF on 10/31/

2019 2021 -110,773 -116,312 916,100 9,395 809,183 2022 -124,235 -130,446 809,183 13,675 692,412 2023 -107,740 -113,127 692,412 11,702 590,987 2024 -85,924 -90,220 590,987 10,165 510,932 2025 -54,171 -56,880 510,932 9,176 463,228 2026 -57,084 -59,938 463,228 8,199 411,489 2027 -48,119 -50,525 411,489 7,325 368,289 2028 -32,164 -33,772 368,289 6,777 341,294 2029 -32,142 -33,749 341,294 6,246 313,791 2030 -32,138 -33,745 313,791 5,711 285,757 2031 -32,138 -33,745 285,757 5,144 257,156 2032 -31,679 -33,263 257,156 4,603 228,496 2033 -7,343 -7,710 228,496 4,470 225,256 2034 -3,607 -3,787 225,256 4,505 225,974 2035 -3,607 -3,787 225,974 4,519 226,706 2036 -3,612 -3,793 226,706 4,534 227,447 2037 -3,607 -3,787 227,447 4,549 228,209 2038 -3,607 -3,787 228,209 4,564 228,986 2039 -3,607 -3,787 228,986 4,580 229,779 2040 -3,612 -3,793 229,779 4,596 230,582 2041 -3,607 -3,787 230,582 4,612 231,407 2042 -3,607 -3,787 231,407 4,628 232,248 2043 -3,607 -3,787 232,248 4,645 233,106 2044 -3,612 -3,793 233,106 4,662 233,795 2045 -3,607 -3,787 233,795 4,680 234,688 2046 -4,433 -4,655 234,688 4,694 234,727 2047 -7,453 -7,857 234,727 4,695 231,565 2048 -11,953 -12,551 231,565 4,631 223,654 page 54

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year IP3 With- Withdrawal Beginning of Trust Year End-drawal Rate, Rate X 1.05 year Trust Fund Fund ing Trust PSDAR Table Balance, First Earn- Fund Bal-5-1c Year Equal to ings ance DTF on 10/31/

2019 2049 -11,917 -12,513 223,654 4,473 215,614 2050 -11,927 -12,523 215,614 4,312 207,403 2051 -11,917 -12,513 207,403 4,148 199,038 2052 -11,953 -12,551 199,038 3,981 190,467 2053 -11,927 -12,524 190,467 3,809 181,752 2054 -11,927 -12,524 181,752 3,635 172,863 2055 -14,805 -15,545 172,863 3,457 160,775 2056 -14,842 -15,584 160,775 3,216 148,406 2057 -14,826 -15,567 148,406 2,968 135,807 2058 -14,826 -15, 567 135,807 2,716 122,956 2059 -14,826 -15, 567 122,956 2,459 109,848 2060 -14,842 -15, 584 109,848 2,197 96,461 2061 -14,811 -15,552 96,462 1,929 82,839 2062 -4,238 -4,450 82,839 1,657 80,045 2063 0 0 80,045 1,601 81,646 page 55

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.8 Scenario #4b: Impact of an Annual 10% Increase in IP3s Withdrawal Rate TABLE A-12 10% Annual Increase in IP3s Withdrawal Rate, $ in Thousands Year IP3 With- IP3 Beginning of Trust Year End-drawal Rate, year Trust Fund Fund ing Trust PSDAR, Table Withdrawal Balance, First Earn- Fund Bal-5-1c Year Equal to ings ance Rate X 1.10 DTF on 10/31/

2019 2021 -110,773 -121,850 916,100 9,395 803,645 2022 -124,235 -136,659 803,645 13,581 690,568 2023 -107,740 -118,514 690,568 11,671 583,725 2024 -85,924 -94,516 583,725 10,040 499,249 2025 -54,171 -59,588 499,249 8,967 448,628 2026 -57,084 -62,792 448,628 7,941 393,777 2027 -48,119 -52,931 393,777 7,009 347,855 2028 -32,164 -35,380 347,855 6,400 318,875 2029 -32,142 -35,362 318,875 5,835 289,348 2030 -32,138 -35,356 289,348 5,266 259,258 2031 -32,138 -35,352 259,258 4,640 228,546 2032 -31,679 -34,847 228,546 4,090 197,790 2033 -7,343 -8,077 197,790 3,956 193,669 2034 -3,607 -3,958 193,669 3,873 193,584 2035 -3,607 -3,968 193,584 3,872 193,488 2036 -3,612 -3,973 193,488 3,870 193,385 2037 -3,607 -3,968 193,385 3,868 193,285 2038 -3,607 -3,968 193,285 3,866 193,183 2039 -3,607 -3,968 193,183 3,864 193,079 2040 -3,612 -3,973 193,079 3,862 192,968 2041 -3,607 -3,968 192,968 3,859 192,859 2042 -3,607 -3,968 192,859 3,857 192,748 2043 -3,607 -3,968 192,748 3,855 192,635 2044 -3,612 -3,973 192,635 3,852 192,515 2045 -3,607 -3,968 192,515 3,850 192,397 2046 -4,433 -4,876 192,397 3,848 191,369 2047 -7,453 -8,198 191,369 3,827 186,998 2048 -11,953 -13,148 186,998 3,740 177,590 page 56

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year IP3 With- IP3 Beginning of Trust Year End-drawal Rate, year Trust Fund Fund ing Trust PSDAR, Table Withdrawal Balance, First Earn- Fund Bal-5-1c Year Equal to ings ance Rate X 1.10 DTF on 10/31/

2019 2049 -11,917 -13,109 177,590 3,552 168,032 2050 -11,927 -13,120 168,032 3,361 158,273 2051 -11,917 -13,109 158,273 3,165 148,329 2052 -11,953 -13,148 148,329 2,967 138,148 2053 -11,927 -13,120 138,148 2,763 127,790 2054 -11,927 -13,120 127,790 2,556 117,226 2055 -14,805 -16,286 117,226 2,345 103,285 2056 -14,842 -16,326 103,285 2,066 89,024 2057 -14,826 -16,309 89,024 1,780 74,495 2058 -14,826 -16,309 74,495 1,490 59,676 2059 -14,826 -16,309 59,676 1,194 44,561 2060 -14,842 -16,326 44,561 891 29,126 2061 -14,811 -16,292 29,126 583 13,416 2062 -4,238 -4,662 13, 416 268 9,022 2063 0 0 9,022 180 9,204 page 57

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.9 Scenario #4c: Impact of an Annual 10% Increase in the IP2 Withdrawal Rate TABLE A-13 10% Annual Increase in IP2s Withdrawal Rate, $ in Thousands Year IP2 With- IP2 With- Beginning of Trust Year End-drawal Rate drawal Rate X year Trust Fund Fund ing Trust From PSDAR 1.10 Balance, First Earn- Fund Bal-Table 5-1b Year Equal to ings ance DTF on 10/31/

2019 2021 -70,024 -77,026 654,078 6,814 583,866 2022 -105,834 -116,417 583,866 9,867 477,316 2023 -85,496 -94,046 477,316 8,067 391,336 2024 -44,113 -48,524 391,336 6,731 349,523 2025 -43,993 -48,392 349,523 6,278 307,408 2026 -40,373 -44,410 307,048 5,441 268,079 2027 -39,697 -43,667 268,079 4,772 229,183 2028 -55,164 -60,680 229,183 4,217 172,720 2029 -53,960 -59,356 172,720 3,160 116,524 2030 -15,449 -16,994 116,524 2,121 101,651 2031 -15,449 -16,994 101,651 1,830 86,487 2032 -18,646 -20,511 86,487 1,548 67,534 2033 -9,623 -10,585 67,524 1,350 58,289 2034 -5,990 -6,589 58,289 1,165 52,865 2035 -6,000 -6,600 52,865 1,057 47,322 2036 -6,014 -6,615 47,332 946 41,663 2037 -6,000 -6,600 41,663 833 35,896 2038 -5,990 -6,589 35,896 718 30,025 2039 -6,000 -6,600 30,025 600 24,025 2040 -6,005 -6,606 24,025 481 17,900 2041 -6,000 -6,600 17,900 358 11,658 2042 -6,000 -6,600 11,658 233 5,291 2043 -6,000 -6,600 5,291 106 -1,203 2044 -6,005 -6,606 -1,203 0 -7,809 2045 -5,990 -6,589 -7,809 0 -14,398 2046 -3,152 -3,467 -14,398 0 -17,865 2047 -894 -983 -17,865 0 -18,848 2048 -386 -425 -18,848 0 -19,273 page 58

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year IP2 With- IP2 With- Beginning of Trust Year End-drawal Rate drawal Rate X year Trust Fund Fund ing Trust From PSDAR 1.10 Balance, First Earn- Fund Bal-Table 5-1b Year Equal to ings ance DTF on 10/31/

2019 2049 -386 -425 -19,273 0 -19,698 2050 -386 -425 -19,698 0 -20,123 2051 -386 -425 -20,123 0 -20,548 2052 -386 -425 -20,548 0 -20,973 2053 -386 -425 -20,973 0 -21,398 2054 -386 -425 -21,398 0 -21,823 2055 -3,274 -3,601 -21,823 0 -25,424 2056 -3,285 -3,614 -25,424 0 -29,038 2057 -3,285 -3,614 -29,038 0 -32,652 2058 -3,285 -3,614 -32,652 0 -36,266 2059 -3,285 -3,614 -36,266 0 -39,880 2060 -3,285 -3,614 -39,880 0 -43,494 2061 -3,285 -3,614 -43,494 0 -47,108 2062 -2,270 -2,497 -47,108 0 -49,605 2063 -0 -0 -49,605 0 page 59

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.10 Scenario #5: IP2 with IP3 Withdrawal Rates TABLE A-14 IP2, 10/31/2019 DTF, HDIs IP3 Withdrawal Rate, $ in Thousands Year Beginning Withdraw Trust Year Begin- Trust Year of year, Fund Ending ning of Fund Ending Trust Trust Earnings year Earnings Trust Fund Fund Bal- Bal- Trust Fund ance, ance, Fund Balance Balance, First Year PSDAR PSDAR PSDAR Equal to PSDAR Table Table Table Table DTF on 5-1c 5-1c 5-1c 5-1c 10/31/

2019 2021 916,100 -110,773 9,395 814,722 654,078 6,814 550,119 2022 814,722 -124,235 13,810 704,297 550,119 9,023 434,906 2023 704,297 -107,740 11,391 608,488 434,906 8,698 335,864 2024 608,488 -85,924 10,451 533,016 335,864 6,717 256,657 2025 533,016 -54,171 9,577 488,421 256,657 5,133 207,619 2026 488,421 -57,084 8,627 439,964 207,619 4,152 154,678 2027 439,964 -48,119 7,837 399,682 154.678 3,094 109,653 2028 399,682 -32,164 7,350 374,868 109,653 2,193 79,682 2029 374,868 -32,142 6,855 349,581 79,682 1,594 49,133 2030 349,581 -32,138 6,349 323,792 49,133 983 17,977 2031 323,792 -31,679 5,833 297,487 17,977 359 -12,832 2032 297,487 -31,679 5,316 271,124 -12,832 0 -44,511 2033 271,124 -7,343 5,276 269,057 -44,511 0 -51,854 2034 269,057 -3,607 5,309 270, 759 -51,854 0 -55,461 2035 270,759 -3,607 5,343 272,494 -55,461 0 -59,068 2036 272,494 -3,612 5,378 274,260 -59,068 0 -62,680 2037 274,260 -3,607 5,413 276,066 -62,680 0 -66,287 2038 276,066 -3,607 5,449 277,907 -66,287 0 -69,894 2039 277,907 -3,607 5,486 279,786 -69,894 0 -73,501 2040 279,786 -3,612 5,523 281,697 -73,501 0 -77,113 2041 281,697 -3,607 5,562 283,652 -77,113 0 -80,725 2042 283,652 -3,607 5,601 285,646 -80,725 0 -84,332 2043 285,646 -3,607 5,641 287,679 -84,332 0 -87,939 page 60

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Beginning Withdraw Trust Year Begin- Trust Year of year, Fund Ending ning of Fund Ending Trust Trust Earnings year Earnings Trust Fund Fund Bal- Bal- Trust Fund ance, ance, Fund Balance Balance, First Year PSDAR PSDAR PSDAR Equal to PSDAR Table Table Table Table DTF on 5-1c 5-1c 5-1c 5-1c 10/31/

2019 2044 287,679 -3,612 5,681 289,748 -87,939 0 -91,551 2045 289,748 -3,607 5,723 291,864 -91,551 0 -95,158 2046 291,864 -4,433 5,749 293,179 -95,158 0 -99,591 2047 293,179 -7,453 5,715 291,441 -99,591 0 -107,044 2048 291,441 -11,953 5,590 285,078 -107,044 0 -118,997 2049 285,078 -11,917 5,463 278,624 -118,997 0 -130,914 2050 278,624 -11,927 5,334 272,030 -130,914 0 -142,841 2051 272,030 -11,917 5,202 265,315 -142,841 0 -154,758 2052 265,315 -11,953 5,067 258,429 -154,758 0 -166,711 2053 258,429 -11,927 4,930 251,432 -166,711 0 -178,638 2054 251,432 -11,927 4,790 244,294 -178,638 0 -190,565 2055 244,294 -14,805 4,590 234,079 -190,565 0 -205,370 2056 234,079 -14,842 4,385 223,622 -205,370 0 -220,212 2057 223,622 -14,826 4,176 212,972 -220,212 0 -235,038 2058 212,972 -14,826 4,393 202,198 -235,038 0 -249,864 2059 202,198 -14,826 3,746 191,028 -249,864 0 -264,690 2060 191,028 -14,842 3,524 179,709 -264,690 0 -279,532 2061 179,709 -14,811 3,298 168,196 -279,532 0 -294,343 2062 168,196 -4,238 3,279 167,237 -294,343 0 -298,581 page 61

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.11 Scenario #6: Combination of Two Effects Previous scenarios just examined the impact of a single variable such as the start date of the finan-cial analysis, the impact of different initial amounts of money in the IP2 DTF, the determination of the DTF level that marks the point at which the HDI analysis would turn from being a success sce-nario to a failure scenario and the impact of using the IP3 withdrawal rate as the withdrawal rate for IP2. Scenario #6 describes the impact of having more than one variable affecting the decom-missioning financial analysis. Many combinations of these single variables are possible. Two that were selected for this analysis is when the IP2 withdrawal rate equals that of IP3 and when the IP2 initial DTF matches the funding level that Entergy reported for 12/31/2018.

As expected, this combination is more severe than single variable analyses.

TABLE A-15 IP2, 12/31/2018 DTF, HDIs IP3 Withdrawal Rate, $ in Thousands Year Begin- With- Trust Year Begin- Trust Year ning of drawal Fund Ending ning of Fund Ending year,Trust Rate Earnings Trust year Earnings Trust Fund Bal- Fund Trust Fund ance Balance Fund Balance Balance PSDAR PSDAR PSDAR PSDAR Start Table Table Table Table Date 12/

5-1c 5-1c 5-1c 5-1c 31/2018 2021 916,100 -110,773 9,395 814,722 583,262 11,665 484,154 2022 814,722 -124,235 13,810 704,297 484,154 9,683 369,602 2023 704,297 -107,740 11,391 608,488 369,602 7,392 269,254 2024 608,488 -85,924 10,451 533,016 269,254 5,385 188,715 2025 533,016 -54,171 9,577 488,421 188,715 3,774 138,318 2026 488,421 -57,084 8,627 439,964 138,318 2,766 84,000 2027 439,964 -48,119 7,837 399,682 84,000 1,680 37,561 2028 399,682 -32,164 7,350 374,868 37,561 751 6,170 2029 374,868 -32,142 6,855 349,581 6,170 123 -25,845 2030 349,581 -32,138 6,349 323,792 -25,845 0 -57,983 2031 323,792 -31,679 5,833 297,487 -57,983 0 -89,221 2032 297,487 -31,679 5,316 271,124 -89,221 0 -120,900 2033 271,124 -7,343 5,276 269,057 -120,900 0 -128,243 2034 269,057 -3,607 5,309 270, 759 -128,243 0 -131,850 2035 270,759 -3,607 5,343 272,494 -131,850 0 -135,457 2036 272,494 -3,612 5,378 274,260 -135,457 0 -139,069 2037 274,260 -3,607 5,413 276,066 -139,069 0 -142,676 page 62

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year Begin- With- Trust Year Begin- Trust Year ning of drawal Fund Ending ning of Fund Ending year,Trust Rate Earnings Trust year Earnings Trust Fund Bal- Fund Trust Fund ance Balance Fund Balance Balance PSDAR PSDAR PSDAR PSDAR Start Table Table Table Table Date 12/

5-1c 5-1c 5-1c 5-1c 31/2018 2038 276,066 -3,607 5,449 277,907 -142,676 0 -146,283 2039 277,907 -3,607 5,486 279,786 -146,283 0 -149,890 2040 279,786 -3,612 5,523 281,697 -149,890 0 -153,502 2041 281,697 -3,607 5,562 283,652 -153,502 0 -157,109 2042 283,652 -3,607 5,601 285,646 -157,109 0 -160,716 2043 285,646 -3,607 5,641 287,679 -160,716 0 -164,323 2044 287,679 -3,612 5,681 289,748 -164,323 0 -167,935 2045 289,748 -3,607 5,723 291,864 -167,935 0 -171,542 2046 291,864 -4,433 5,749 293,179 -171,542 0 -175,975 2047 293,179 -7,453 5,715 291,441 -175,075 0 -183,428 2048 291,441 -11,953 5,590 285,078 -183,428 0 -195,381 2049 285,078 -11,917 5,463 278,624 -195,381 0 -207,298 2050 278,624 -11,927 5,334 272,030 -207,298 0 -219,225 2051 272,030 -11,917 5,202 265,315 -219,225 0 -231,142 2052 265,315 -11,953 5,067 258,429 -231,142 0 -243,095 2053 258,429 -11,927 4,930 251,432 -243,095 0 -255,022 2054 251,432 -11,927 4,790 244,294 -255,022 0 -266,949 2055 244,294 -14,805 4,590 234,079 -266,949 0 -281,754 2056 234,079 -14,842 4,385 223,622 -281,754 0 -296,596 2057 223,622 -14,826 4,176 212,972 -296,596 0 -311,422 2058 212,972 -14,826 4,393 202,198 -311,422 0 -326,248 2059 202,198 -14,826 3,746 191,028 -326,248 0 -341,074 2060 191,028 -14,842 3,524 179,709 -341,074 0 -355,916 2061 179,709 -14,811 3,298 168,196 -355,916 0 -370,727 2062 168,196 -4,238 3,279 167,237 -370,727 0 -374,965 page 63

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.12 Scenario #7: Impact of Inflation on IP2 TABLE A-16 Impact of Inflation on IP2, $ in Thousands Year IP2 Inflation Inflation Beginning of Trust Year End-Increment, Adjusted year Fund ing Trust With- Earn- Fund Bal-drawal Cumulative With- Trust Fund ings ance Rate drawal Balance, From Multiplier Rate PSDAR First Year Table 5-1b Equal to DTF on 10/31/2019 2021 -70,024 .012, 1.012 -70,864 654,078 6,814 583,866 2022 -105,834 .018, 1.030 -109,001 583,866 9,867 522,869 2023 -85,496 .024, 1.054 -90,113 522,869 8,836 441,592 2024 -44,113 .021, 1.075 -47,421 441,592 7,595 401,323 2025 -43,993 .013, 1.088 -47,864 401,323 7,208 360,667 2026 -40,373 .001, 1.089 -43,996 360,667 6,384 323,055 2027 -39,697 .016, 1.105 -43,865 323,055 5,750 284,940 2028 -55,164 .015, 1.120 -61,874 284,940 5,243 228,309 2029 -53,960 .021, 1.141 -61,568 228,309 4,178 170,919 2030 -15,449 .032, 1.173 -18,122 170,919 3,111 155,908 2031 -15,449 .016, 1.189 -18,122 155,908 2,806 140,592 2032 -18,646 .004,1.185 -22,096 140,592 2,517 121,013 2033 -9,623 .038, 1.223 -11,769 121,013 2,420 111,664 2034 -5,990 .015, 1.238 -7,416 111,664 2,233 106,481 2035 -6,000 .015, 1.253 -7,518 106,481 2,120 101,093 2036 -6,014 .015, 1.268 -7,626 101,093 2,022 103,115 2037 -6,000 .015, 1.283 -7,698 103,115 2,062 97,479 2038 -5,990 .015, 1.298 -7,775 97,479 1,950 91,654 2039 -6,000 .015, 1.313 -7,878 91,654 1,833 85,609 2040 -6,005 .015, 1.328 -7,975 85,609 1,712 79,346 2041 -6,000 .015, 1.343 -8,058 79,346 1,587 72,875 2042 -6,000 .015, 1.358 -8,148 72,875 1,458 66,185 2043 -6,000 .015, 1.373 -8,238 66,185 1,323 59,270 2044 -6,005 .015, 1.388 -8,335 59,270 1,185 52,120 2045 -5,990 .015, 1.403 -8,404 52,120 1,042 44,758 2046 -3,152 .015, 1.418 -4,470 44,758 895 41,183 page 64

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year IP2 Inflation Inflation Beginning of Trust Year End-Increment, Adjusted year Fund ing Trust With- Earn- Fund Bal-drawal Cumulative With- Trust Fund ings ance Rate drawal Balance, From Multiplier Rate PSDAR First Year Table 5-1b Equal to DTF on 10/31/2019 2047 -894 .015, 1.433 -1,281 41,183 824 40,726 2048 -386 .015, 1.448 -559 40,726 815 40,981 2049 -386 .015, 1.463 -565 40,981 820 41,230 2050 -386 .015, 1.478 -571 41,230 825 41,483 2051 -386 .015, 1.493 -576 41,483 830 41,737 2052 -386 .015, 1.508 -582 41,737 835 41,990 2053 -386 .015, 1.523 -588 41,990 840 42,830 2054 -386 .015, 1.538 -594 42,830 857 43,093 2055 -3,274 .015, 1.553 -5,084 43,093 862 38,871 2056 -3,285 .015, 1.568 -5,151 38,871 777 34,497 2057 -3,285 .015, 1.583 -5,200 34,497 690 29,987 2058 -3,285 .015, 1.598 -5,249 29,987 600 25,338 2059 -3,285 .015, 1.613 -5,299 25,338 507 20,545 2060 -3,285 .015, 1.628 -5,348 20,545 411 15,608 2061 -3,285 .015, 1.643 -5,397 15,608 312 10,523 2062 -2,270 .015, 1.658 -3,764 10,523 210 6,969 2063 -0 6,969 139 7,108 page 65

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.13 Analyzing HDIs Claim of $301 Million Dollars Less to Decommission IP2 TABLE A-17 Cumulative Savings at IP2 Based on HDI Data, $ in Thousands Year IP3 IP2 Annual Cumulative Cumulative Cumulative Savings at With- With- To IP2 Savings, Savings, Savings, drawal drawal Years Years Rate Rate Years PSDAR PSDAR 2021-2029 2030-2046 2047-2062 Table 5- Table 5- $113,698,000 $16,727,000 1c 1b $170,140,000 2021 110,773 70,024 40,749 40,749 2022 124,235 105,834 18,401 59,150 2023 107,740 85,496 22,244 81,394 2024 85,924 44,113 41,811 123,205 2025 54,171 43,993 10,178 133,383 2026 57,084 40,373 16,711 150,094 2027 48,119 39,697 8,422 158,516 2028 32,164 55,164 -23,000 135,516 2029 32,142 53,960 -21,818 113,698 2030 32,138 15,449 16,689 130,387 2031 32,138 15,449 16,689 147,076 2032 31,679 18,646 13,033 160,109 2033 7,343 9,623 -2,280 157, 827 2034 3,607 5,990 -2,383 155,444 2035 3,607 6,000 -2,393 153,053 2036 3,612 6,014 -2,402 150,651 2037 3,607 6,000 -2,393 148,258 2038 3,607 5,990 -2,383 145,875 2039 3,607 6,000 -2,393 143,482 2040 3,612 6,005 -2,393 141,089 2041 3,607 6,000 -2,393 138,696 2042 3,607 6,000 -2,393 136,303 2043 3,607 6,000 -2,393 133,910 2044 3,612 6,005 -2,393 131,517 2045 3,607 5,990 -2,383 129,124 2046 4,433 3,152 1,281 130,405 2047 7,453 894 6,559 136,964 page 66

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

Year IP3 IP2 Annual Cumulative Cumulative Cumulative Savings at With- With- To IP2 Savings, Savings, Savings, drawal drawal Years Years Rate Rate Years PSDAR PSDAR 2021-2029 2030-2046 2047-2062 Table 5- Table 5- $113,698,000 $16,727,000 1c 1b $170,140,000 2048 11,953 386 11,567 148,551 2049 11,917 386 11,531 160,062 2050 11,927 386 11,541 171,613 2051 11,917 386 11,531 183,144 2052 11,953 386 11,567 194,711 2053 11,927 386 11,541 206,252 2054 11,927 386 11,541 217,793 2055 14,805 3,274 11,531 229,324 2056 14,842 3,285 11,557 240,881 2057 14,826 3,285 11,541 252,422 2058 14,826 3,285 11,541 263,963 2059 14,826 3,285 11,541 275,504 2060 14,842 3,285 11,557 287,061 2061 14,811 3,285 11,526 298,587 2062 4,238 2,270 1,968 300,555 page 67

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

9.14 HDI Cost Estimating Approach page 68

CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

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CRITIQUE OF NRCS MEMORANDUM AND ORDER CLI-21-01 Micro-Utilities, Inc.

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Cover Sheet Comments on NRC-2021-0125 HERSCHEL SPECTER mhspecter@verizon.net July 22, 2021

Comments On NRC-2021-0125 Micro-Utilities, Inc.

COMMENTS ON NRC-2021-0125 As announced in the Federal Register, the NRC is seeking comments on Holtec Decommissioning Internationals (HDI) Indian Point PSDAR (Post Shutdown Decommissioning Activities Report).

[federalregister.gov/d/2021-15068]. This submittal responds to this request and attaches a sup-porting document Critique of the NRCs Memorandum and Order CL1-21-01, Micro-Utilities, Inc., March 1, 2021, which was previously submitted to the NRC.

FUNDAMENTALS The most fundamental question about the Indian Point HDI PSDAR is whether the cost analyses in the body of the PSDAR and in the resultant Decommissioning Cost Estimates (DCEs) were derived using realistic engineering cost estimate practices or if the numbers in the PSDAR and DCEs were generated to match the available funds in the Decommissioning Trust Funds (DTFs).

In the latter case, if the holdings in a particular DTF were large, the cost to decommission the associated unit would be large and if the holdings in a particular unit were smaller, the cost to decommission it would also be smaller. Matching the cost to decommission to the amount of money in the DTF instead of taking a best practices cost estimating approach, is unrealistic and unacceptable.

Indian Point represents a unique opportunity to test if best cost estimating practices were used.

First, two virtually identical nuclear units, IP2 and IP3, existed on the same site. Other sites like Pilgrim, Vermont Yankee, and Oyster Creek only had one nuclear unit and therefore unit-to-unit cost comparisons were not possible. Second, the Decommissioning Trust Funds at IP2 and IP3 were significantly different. This is quite unusual.The larger DTF at IP3 was likely the result of a different ownership history than that of IP2. Consolidated Edison of New York and Entergy were the only owners of IP2 while IP3 was also owned and operated by the New York Power Authority for a number of years, which possibly contributed funds to the IP3 DTF. As of October 30, 2019, HDIs start date for its Indian Point PSDAR analysis, the IP2 DTF was smaller than the IP3 DTF by $262 million dollars. The HDI PSDAR analysis claims that IP2 could be decommissioned for

$301 million dollars less than it takes to decommission the near identical IP3 unit. In other words, the IP2 DTF is smaller than the IP3 DTF by $262 million dollars and HDIs cost to decommission IP2 is smaller by a rather similar figure, $301 million dollars.

The above situation prompted a review of other pairs of PWRS, like IP2 and IP3, that exist on the same site. This review found no other pair of PWR units on the same site that had decommission-ing cost differences comparable to those claimed by HDI. These PWR-to-PWR comparisons included site specific decommissioning cost estimates and generic radiological decommissioning cost estimates that the NRC has published in SECY-18-0078. In fact IP2 and IP3 have the same radiological decommissioning cost estimate in SECY-18-0078. Page 15 of the staffs Safety Eval-uation (SE) shows that the HDI costs estimate for the radiological decommissioning of IP2 at

$469,456,000 while that for IP3 is at $583,168,000. This portion of the total cost to decommission comes up with IP2 needing about $118 million dollars less than IP3. The HDI different radiologi-cal cost estimate for IP2 compared to IP3 is at odds with the equal cost figures for these two units in SECY-18-0078.

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Comments On NRC-2021-0125 Micro-Utilities, Inc.

These discrepancies resulted in the NRC staff issuing a RAI, Request for Additional Information, as described on page 10 of the staffs Safety Evaluation (SE). Each of the areas probed by the RAI were responded to by HDI were reexamined and refuted in the attached critique, often using data taken directly from the PSDAR. [See Section 5]

Even if there were agreement with the responses sent in by HDI to the RAI, the issue about the large difference between HDIs cost to decommission IP2 compared to IP3 would remain open.

The HDI justifications as to why IP2 costs would be far less than IP3s only apply to events prior to 2031 during which time the reactors are being segmented, buildings are torn down, spent fuel is transferred to canisters and moved to the ISFSI, etc. After this active period there is a long period until 2062 when essentially all that remains on the site are the spent fuel canisters and a small security force and, hopefully, the DOE removing spent fuel. During this later time period HDI would charge IP2 about $185 million dollars less than IP3, yet during this time period neither IP2 nor IP3 structures exist any more, only their trust funds remain. A review of the HDI PSDAR shows that the IP2 DTF has less money in it after 2031 than the IP3 DTF. It appears that HDI charged the IP3 DTF more than it charged the IP2 DTF because that is where the bulk of the remaining money was. If so, that would discredit the DCEs that the NRC exclusively relied upon.

If any or all of the HDI responses to the NRCs RAI are unjustified or incomplete and IP2 costs actually closely resemble those of sister plant IP3, the IP2 DTF could become insolvent by 2031 leaving almost $300 million dollars worth of unfinished decommissioning tasks (See Table A-3 of the critique).

The NRC claimed that it would not review the PSDAR until after the license transfer had been consummated. However, it was not necessary to review the PSDAR to compare the annual with-drawals for IP2 to the withdrawals for the same year for IP3. These annual withdrawals are listed in the DCEs. These annual withdrawal differences can be summed up to give the total withdrawal IP2- to-IP3 difference over a period of time, such as from 2031 to 2062. This addition process was used to establish the $185 million dollar difference listed above. This analysis is presented in the critique. (See Table A-17).

Therefore, not only are the HDI responses to the NRCs RAI refuted for the time period up to 2031 or sooner, the HDI responses are incomplete because they do not address this $185 million dollar lower IP2 costs that HDI wants to charge after 2031. This situation is compounded by the NRC: The NRC has not established a viable financial mechanism to recover from quite plausible scenarios identified in the critique where one or more of the Indian Point trust funds would become insolvent. The NRC should distribute a report to the public at the July 29, 2021 meeting listing all the questions it raised in its RAI, the HDI responses to these questions, an explanation as to why it accepted HDIs responses, with emphasis on the 2031 to 2062 time period.

Additional questions about the PSDARs treatment of the 2031 to 2062 time period appear in the SPECIFIC COMMENTS/QUESTIONS section of this submittal.

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Comments On NRC-2021-0125 Micro-Utilities, Inc.

GENERAL COMMENT

S A. The NRC, by not conducting a public meeting upon receipt of the HDI PSDAR on December 19, 2019, has denied due process to the general public and the most senior elected officials in NY State. It was the publics right to participate, upon the NRCs receipt of HDIs PSDAR, in the decision making effort that led to the transfer of Entergys licenses to HDI for Indian Point One, Indian Point Two, and Indian Point Three. Without the public and its senior elected officials receiving due process, the transfers of the three Indian Point licenses are invalid and must be withdrawn.

B. The HDI PSDAR has numerous defects, omissions, and unrealistic assumptions which were pointed out to the NRC staff and the NRC Commissioners prior to the approval of the License Transfer Applications (LTAs). Some of these defects, omissions, and unrealistic assumptions are discussed in the following SPECIFIC COMMENTS Section.

C. The NRCs handling of the HDI PSDAR has been incoherent. The staffs Safety Evalua-tion (SE), on page 26, emphasizes the importance of the site-specific decommissioning cost estimates (DCEs) included in the PSDAR Regarding comment submission topic 6 concerning the sufficiency of the HDI PSDAR, the staff treated the PSDAR as a supplement to the LTA on the determination that the site specific decommissioning cost estimate infor-mation in the PSDAR was necessary to complete the LTA. Yet the HDI DCEs are part of the PSDAR and depend upon the accuracy, completeness, and use of realistic assump-tions within the whole PSDAR. The NRC staff also states on page 26, The staff will only review the HDI PSDAR itself if and when the proposed license transfer transaction is con-summated. Pursuant to 10 CFR 50.82 (a)(4)(ii) this review would involve an opportunity for public comment and a public meeting On one hand the NRC staff places great empha-sis on the HDI DCEs, claiming that they are necessary to complete the LTA. On the other hand these DCEs are part of the PSDAR and are a product of the analyses and assumptions contained within the PSDAR. If the PSDAR is wrong, incomplete, or uses unrealistic assumptions, then these DCEs are also wrong, incomplete, and/or unrealistic and therefore can not be depended upon to reach a conclusion of reasonable assurance or justify transfer-ring the Indian Point licenses. Since the staff claims that it did not review the HDI PSDAR prior to transferring the Indian Point licenses to HDI, it would not be aware that the PSDAR contains errors, omissions, and unrealistic assumptions which means that the HDI DCEs can not be relied upon as the basis for justifying any Indian Point license transfer.

On the other hand the NRC should be aware of HDI PSDAR errors, omissions, and unreal-istic assumptions because they were pointed out to it through public submittals.

D. The staff has created a bizarre situation. It claims to have intentionally ignored the PSDAR early in its review when such a review was essential to verify the acceptability of the DCEs, while simultaneously rebuffing the publics requests for a meeting that could have led to a comprehensive review of the PSDAR. Then the staff created the present situation calling for a public meeting on the PSDAR at a time after the Indian Point licenses already have been transferred and where such a meeting has no obvious benefit to the public. The NRC is in violation of its own regulations. 10 CFR 50.82 (a)(4)(ii) requires that The NRC shall notice receipt of the PSDAR and make the PSDAR available for public comment.

The NRC shall also schedule a public meeting in the vicinity of the licensees facility upon receipt of the PSDAR. (emphasis added) The purpose of this regulation is to inform and page 3

Comments On NRC-2021-0125 Micro-Utilities, Inc.

enable the public about the PSDAR early on so that the public and its elected officials can provide their input to the NRC staff. Such input may affect the staffs decision making and those of the NRC Commissioners. HDI submitted its PSDAR to the NRC on December 19, 2019. Based on the NRCs own regulations the NRC should have noticed the public at that time and arranged for a meeting to discuss the recently submitted PSDAR soon after December 19, 2019. Instead, the NRC has only recently (June 24, 2021) given notice of the receipt of the HDI PSDAR and also called for this grossly delayed public meeting. In the meanwhile HDI is already on the Indian Point site demolishing these power plants.

This very delayed notice and this very delayed public meeting on the HDI PSDAR defeats the purpose of 10 CFR 50.82 (a)(4)(ii) and serves no public beneficial purpose. The NRC has not presented any explanation as to why it did not take timely action upon receipt of the PSDAR on December 19, 2019. It is clear that the meeting on July 29, 2021 is no substitute for the requirements of 10 CFR 50.82 (a)(4)(ii) which call for a public meeting upon receipt of the PSDAR.

E. In the NRCs Summary Section of the announcement of the July 29, 2021 meeting, the fol-lowing was stated On June 24,2021, the U.S. Nuclear Regulatory Commission (NRC) noticed receipt of and solicited comments on, the post shutdown decommissioning activi-ties report (PSDAR) on the Indian Point nuclear generating Unit Nos. 1,2.and 3 (Indian Point Energy Center (IPEC), submitted by Holtec Decommissioning International, LLC (HDI). The actual date that HDI submitted its PSDAR to the NRC is identified in the sec-ond paragraph of this announcements part II, Discussion, specifically, On December 19, 2019 HDI submitted to the NRC the PSDAR for the IPEC, contingent upon the transfer of the IPEC licenses to HDI (ADAMS Accession No. ML19354A698). Is the NRC now claiming that it first received the HDI PSDAR on June 24,2021 instead of December 19, 2019? Is the NRC claiming that announcing the receipt of the PSDAR on June 24, 2021 is in accordance with the requirements of 10 CFR 50.82 (a)(4)(ii)?

F. Without question the NRC received the HDI PSDAR on December 19, 2019. This PSDAR also soon became available to the public and could be readily obtained through a simple Google search. Additionally, the Staffs own Safety Evaluation (SE), which was published well before the June 24, 2021 date, contained many references to the HDI PSDAR. There is an Attachment D in the staffs SE which contains hundreds of unanswered public com-ments. The staff took these comments and separated them into 17 topics. Topic 6 is titled Concerns about the HDI PSDAR. There were 152 public comments just under Topic 6.

So both the NRC and the public had access to the HDI PSDAR well before June 24, 2021.

In view of this actual history, what does it mean when the Summary Section in this announcement states that the NRC noticed receipt of HDIs PSDAR on June 24, 2021? If the NRC staff only received the HDI PSDAR on June 24, 2021 it would not have had the DCEs that were part of the PSDAR earlier than that date. Without these DCEs the staff would not have been able to write its SE and the NRC Commissioners would not have been able to sign off on their Memorandum and Order, CL1-21-01. What was supposed to have happened on June 24, 2021, with regard to HDI submitting its PSDAR?

G. As long as there is spent fuel on the Indian Point site the NRC has a continuing responsibil-ity to protect the public from radiological risks. The HDI PSDAR assumes that spent fuel could remain on the Indian Point site until 2062 and therefore the NRC responsibility could page 4

Comments On NRC-2021-0125 Micro-Utilities, Inc.

extend to 2062. If any of the three Indian Point decommissioning trust funds became insol-vent prior to 2062, HDI might not have the funds to complete the radiological tasks it is responsible for. Such a situation is an immediate issue for the NRC and therefore the NRC must make every effort to prevent a DTF from being insolvent. Under a condition of insol-vency there would not be any surplus dollars in a decommissioning trust fund to draw upon (which even under favorable conditions would not be available until 2062). Further, HDI can not guarantee that funds will become available from the Department of Energy as pay-ment for not removing the spent fuel from the site. Neither the amounts nor the timing of such DOE payments are known; they might be zero if DOE begins to remove the spent fuel starting 2030, as HDI assumes, and HDI has no control over the size or timing of potential DOE payments. All the money in the IP decommissioning trust funds has come from rate-payers and income generated by these ratepayer deposits. HDI has provided zero dollars of its own money for the Indian Point decommissioning. HDIs PSADAR did not acknowl-edge that it is exclusively counting on other peoples money to complete the Indian Point decommissioning. HDIs PSDAR also did not identify any viable financial mechanism to offset decommissioning shortfalls. Further, the HDI PSDAR did not identify any HDI direct and specific experience in decommissioning three large pressurized water reactors on a very small and crowded site. This lack of experience can increase the probability of cost overruns. HDI indirectly acknowledges its inexperience when it claims that there will be cost savings at IP2 from lessons learned from IP3 when the IP3 decommissioning tasks precede the same tasks at IP2. A fully experienced contractor would not have lessons learned along the way, but would apply his/her knowledge to minimize costs to both IP2 and IP3. Further, it is mysterious how HDI can claim lower costs for IP2 in its December 19, 2019 PSDAR submittal for lessons it has not even yet learned and are assumed to hap-pen in the PSDAR at various times in the future. For example, on page 11 of the PSDAR it is stated Due to the similarities of the IP2 & IP3 reactors, the same tooling will be used to segment each of the IP2 and IP3 reactor vessels and reactor vessel internals. Lessons learned from IP3 segmentation will result in efficiency gains for the IP2 work. How could HDI know in December, 2019 what situations will arise where IP2 cost savings might occur some time in the future from lessons learned? How can HDI quantify these theoreti-cal cost savings out to six or more significant figures, giving the appearance that these yet unrecognized lessons learned are known to great precision?

H. HDI has created, and the NRC staff has accepted, a multi-layered organization of LLCs that stand as financial buffers between the public and HDI itself. The NRC has an obliga-tion to assure that neither radiological nor non-radiological expenditures lead to an insol-vent DTF or that there is a viable financial recovery mechanism so that all radiological tasks can be completed. Regardless of cause, an insolvent DTF prevents the completion of all radiological tasks unless additional sources of funds are made available.Yet several analyses submitted to the NRC, and elaborated on in the attached critique, showed that one or more DTFs could become insolvent under very plausible conditions. For example, the IP2 DTF could become insolvent as early as 2031 after draining the IP2 of its initial fund-ing and then leaving a debt of about $300 million dollars in unfinished decommissioning tasks. All it takes for this to happen is to have the IP2 decommissioning expenses match those that HDI has calculated for its near identical sister plant IP3. The attached document, in Section 5, refutes the HDI explanations as to why Indian Point 2 could be decommis-page 5

Comments On NRC-2021-0125 Micro-Utilities, Inc.

sioned for about $301 million dollars less than Indian Point 3, often using data from the PSDAR to refute HDI claims, the very same PSDAR which the staff has said that it has not reviewed. The staffs failure to review the HDI PSDAR has put New York citizens into financial jeopardy.

I. The NRC has limited its reviews to the DCEs that HDI presented to it, which, in turn, are based on an NRC unreviewed PSDAR which has been shown through public comment and analyses to have significant modeling errors and unrealistic assumptions. The NRC did not generate additional plausible scenarios, some of which would show insolvencies before all decommissioning tasks are completed. Insolvent DTFs mean that the radiological tasks the NRC is responsible for may not be completed. Consequently, the NRC lacks a comprehen-sive basis to arrive at a conclusion of reasonable assurance about decommissioning Indian Point.

J. The NRC has failed to perform its regulatory responsibilities. On July 29, 2021 a simple question needs to be answered by the NRC: If the public identifies a serious error in the HDI PSDAR and/or the HDI DCEs, would the NRC issue a Stop Work Order until this error or omission is resolved?

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Comments On NRC-2021-0125 Micro-Utilities, Inc.

SPECIFIC COMMENTS/QUESTIONS (keyed to the attached critique)

1. IP1 Underfunding For years Entergy kept IP1 in a SAFSTOR configuration. Entergy would regularly submit an IP1 analysis to the NRC showing the slow increase in the IP1 DTF due to an assumed 2% per year real (or net) gain due to investments held by this DTF. Part of this Entergy analysis was the calculated year that this IP1 DTF holdings matched the NRCs estimate of the cost to complete IP1s radio-logical portion of decommissioning. In this Entergy analysis no discussion was presented to cover the costs of non-radiological decommissioning. The NRC accepted these analyses.

HDIs IP1 is based on a very different approach.The HDI PSDAR for IP1 uses the DECON method which starts immediately, thereby rapidly drawing down the IP1 DTF. This rapid draw-down reduces the amount of money the IP1 DTF might generate at 2% per year. Secondly, the scope of the HDI analysis not only included radiological decommissioning, it included the IP1s non-radiological decommissioning. Even though HDI would be working with less money than Entergy assumed and would have a much larger scope, the HDI PSDAR calculates a $20 million dollar surplus by 2062. The attached critique estimates a $112 Million dollar shortfall for IP1 (see the attached critique, Table A-5 and Section 7.1.1.2).

How does the NRC resolve the apparent conflict between the Entergy analysis, which it accepted, and the HDI analysis. which it accepted? Does the NRC agree that IP1 may experience a shortfall of approximately $112 million dollars?]

2. IP2 Underfunding Does the NRC agree with Section 5 of the attached critique that HDI has not presented a defensi-ble argument explaining why IP2 can be decommissioned for $301 million dollars less than IP3?

3. Inflation The HDI PSDAR does not account for inflation. Does the NRC agree that this is acceptable? Note that the critique analyzed the effects of a modest inflation rate on the IP2 DTF and calculated that this modest inflation rate would be sufficient to reduce HDIs calculated IP2 surplus for IP2 from

$72.7 million dollars down to $7.1 million dollars. (Table A-3, scenario #7). A slightly higher inflation rate would have made the IP2 DTF insolvent.

License holders routinely submit to the NRC their analyses of the adequacy of the DTFs for the nuclear plants they operate. These submittals include an analysis of Escalation Factors which include the impacts of changing labor, energy, and waste burial costs, all of which are possible contributors to future expenses HDI will face. For example, Entergys analysis for the Palisades plant for the period ending December 31, 2019 calculated a PWR escalation factor of 4.96762.

Such escalation of costs raised its estimate radiological decommissioning costs in 1986 from

$97,592,000 to $484,700,165 in 2019, some 33 years later. Note that 33 years is shorter than the 41 years between 2021 and 2062, the final year of the HDI PSDAR. The average escalation factor page 7

Comments On NRC-2021-0125 Micro-Utilities, Inc.

over these 33 years is (4.96762)/ 33 = 0.151 or 15.1%. This percentage is far larger than the mod-est percentage of inflation assumed in Table A-1 of the critique.

The HDI PSDAR approach to considering inflation is also inconsistent with the approach Entergy used. In Entergys analysis of its ISFSI obligation, Entergy escalated costs at 3% per annum to account for inflation. [Entergy letter CNRO02020-00002, march 26, 2020, enclosure 2, page 1]. If HDI assumed a 3% inflation rate when calculating its DCEs it would have calculated DTFs that would have become insolvent prior to 2062.

In that the NRC requires an estimation of the effects of rising costs to determine the adequacy of each DTF in the escalation factor analysis, is it acceptable to the NRC for HDI not to account for inflation over the long duration of the PSDAR analysis?

4. Market Effects The HDI PSDAR does not account for the effects of varying market conditions on the amounts of money in the IP DTFs. HDI selected a particular date, October 31, 2019 and used the moneys in the IP DTFs on that date as the bases of its analyses. From that single day forward to year 2062, the HDI PSDAR did not account for any potential impacts of the market on the DCE analyses.

This is unrealistic.

As spelled out on page 14 of the staffs SE equity markets fluctuate with time. Also stated in the SE equity markets declined by 32 to 36 percent between February to mid-March 2020. The SE also points out that equity markets can rise. Similar comments about significant fluctuations in the market and their effects on the DTFs are made in the NRCs Memorandum and Order CL1-21-01.

While there is general agreement that equity markets can move higher and lower, there is no evi-dence that the market will remain unchanged between 2021 to 2062, but that is the essence of the HDI PSDAR model and this is unrealistic. Does the NRC accept this unrealistic model and, if not, how did this affect the NRCs ability to arrive at a conclusion of reasonable assurance?

5. Start Date The NRC allowed HDI to pick the date that its DCE analyses were to start. HDI chose October 31, 2019. It appears that the NRC does not provide guidelines or requirements as to start dates, even though they can result in completely different results. For example, had HDI selected a start date of December 31, 2018 and the DTF funding levels on that date the IP1 DTF would have been cal-culated to become insolvent in 2031, leaving unfinished decommissioning tasks equal to $139.9 million dollars; IP2s DTF would have become insolvent in 2043 leaving a decommissioning shortfall of $45.0 million dollars; and IP3s DTF would have been calculated to become insolvent by 2054 leaving a decommissioning shortfall of $115.7 million dollars. [See Table A-3 of the attached critique] These shortfall figures are all based on the same assumptions, methods and withdrawal rated that HDI used, the only difference being the selected start date and the DTF funding levels on that date.

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In view of the importance of the start date, two questions arise: (1) Should the NRC or the appli-cant establish what the start date should be? and (2) Is any analysis based on a single start date sufficient to establish DCEs? The NRC should be prepared to answer these questions in their report.

6. Spent Fuel Management Listed in the HDI DCEs are unexplained very high HDI charges for spent fuel management during years 2031 to 2062, well after all the structures, except for the ISFSI, have been demolished and all that remains on the site are the canisters, a very small security force, and perhaps some DOE activity removing spent fuel. These charges are disproportionately placed on the IP3 DTF. Starting in 2048 and for 14 years in a row HDI plans to charge the IP3 DTF about $11.5 million dollars per year for a total of about $161 million dollars.

With regard to spent fuel management, Entergy performed this task for many years. Entergy already has built an ISFSI, has loaded IP1 spent fuel into canisters and transported these canisters to the ISFSI. The cost to perform spent fuel management claimed by HDI should be compared to the actual costs Entergy incurred accomplishing the same tasks that HDI will have to do. Adjust-ments to HDI charges should be made if the DTFs are being overcharged.

HDIs Table 3-6, titled DOE Fuel Acceptance Allocation. The sequencing of the removal of spent fuel from the Indian Point site appears to be inconsistent with DOEs report DOE/RW-6567.

If DOE guidance is followed, this could potentially reduce charges to the DTFs by about $69.7 million dollars by giving the removal of IP1 spent fuel first priority. This would be consistent with DOE guidance to remove the oldest fuel first.[See Critique, Section 6.5]

Further savings would take place if HDI arranged to have the maximum number of spent fuel ele-ments removed per year. Table 3-6 of HDIs PSDAR shows that 386 fuel assemblies can be removed in one year. If the rate of removal of fuel assemblies was kept constant at 386 fuel assem-blies per year, the total number of fuel assemblies, 1870, could be removed in just 1870/386 = 4.8 years. At this pace the Indian Point site would be free of radioactive spent fuel by 2036, some 26 years sooner. Not only would this result in significant reductions in the HDI spent fuel manage-ment charges, it would greatly enhance the ability to encourage new commercial activity on the site. Instead, the HDI PSDAR shows a spent fuel removal scheme that maximizes its management fees.

Respectfully submitted, Herschel Specter, President Micro-Utilities, Inc.

July 22, 2021 page 9